UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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| (Mark One) | |
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| X | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| | For the Fiscal Year Ended December 31, 20142017 |
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| | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| | For the transition period from ____________ to ____________ |
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Commission File Number | Registrant, State of Incorporation or Organization, Address of Principal Executive Offices, Telephone Number, and IRS Employer Identification No. | | Commission File Number | Registrant, State of Incorporation or Organization, Address of Principal Executive Offices, Telephone Number, and IRS Employer Identification No. |
| 1-11299 | ENTERGY CORPORATION (a Delaware corporation) 639 Loyola Avenue New Orleans, Louisiana 70113 Telephone (504) 576-4000 72-1229752 | | 1-315081-35747
| ENTERGY MISSISSIPPI, INC.NEW ORLEANS, LLC (a Mississippi corporation)Texas limited liability company) 308 East Pearl1600 Perdido Street
Jackson, Mississippi 39201New Orleans, Louisiana 70112
Telephone (601) 368-5000(504) 670-3700 64-020583082-2212934
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| 1-10764 | ENTERGY ARKANSAS, INC. (an Arkansas corporation) 425 West Capitol Avenue Little Rock, Arkansas 72201 Telephone (501) 377-4000 71-0005900 | | 0-05807 | ENTERGY NEW ORLEANS, INC.1-34360
(a Louisiana corporation)
1600 Perdido Street
New Orleans, Louisiana 70112
Telephone (504) 670-3700
72-0273040
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0-20371 | ENTERGY GULF STATES LOUISIANA, L.L.C.
(a Louisiana limited liability company)
4809 Jefferson Highway
Jefferson, Louisiana 70121
Telephone (504) 576-4000
74-0662730
| | 1-34360 | ENTERGY TEXAS, INC. (a Texas corporation) 9425 Pinecroft10055 Grogans Mill Road
The Woodlands, TXTexas 77380 Telephone (409) 981-2000 61-1435798 |
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1-32718
| ENTERGY LOUISIANA, LLC (a Texas limited liability company) 4809 Jefferson Highway Jefferson, Louisiana 70121 Telephone (504) 576-4000 75-320612647-4469646
| | 1-09067
| SYSTEM ENERGY RESOURCES, INC. (an Arkansas corporation) Echelon One
1340 Echelon Parkway Jackson, Mississippi 39213 Telephone (601) 368-5000 72-0752777 |
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1-31508
| ENTERGY MISSISSIPPI, INC. (a Mississippi corporation) 308 East Pearl Street Jackson, Mississippi 39201 Telephone (601) 368-5000 64-0205830 | | | |
Securities registered pursuant to Section 12(b) of the Act:
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| Registrant | Title of Class | Name of Each Exchange on Which Registered |
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| Entergy Corporation | Common Stock, $0.01 Par Value – 179,697,449 180,770,383 shares outstanding at January 30, 2015 31, 2018 | New York Stock Exchange, Inc. Chicago Stock Exchange, Inc. |
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| Entergy Arkansas, Inc. | Mortgage Bonds, 5.75% Series due November 2040 | New York Stock Exchange, Inc. |
| Mortgage Bonds, 4.90% Series due December 2052 | New York Stock Exchange, Inc. |
| | Mortgage Bonds, 4.75% Series due June 2063 | New York Stock Exchange, Inc. |
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Entergy Louisiana, LLC | Mortgage Bonds, 6.0%4.875% Series due March 2040September 2066 | New York Stock Exchange, Inc. |
| | Mortgage Bonds, 5.875% Series due June 2041 | New York Stock Exchange, Inc. |
| Entergy Louisiana, LLC | Mortgage Bonds, 5.25% Series due July 2052 | New York Stock Exchange, Inc. |
| | Mortgage Bonds, 4.70% Series due June 2063 | New York Stock Exchange, Inc. |
| | Mortgage Bonds, 4.875% Series due September 2066 | New York Stock Exchange, Inc. |
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| Entergy Mississippi, Inc. | Mortgage Bonds, 6.0%4.90% Series due November 2032 | New York Stock Exchange, Inc. |
| Mortgage Bonds, 6.20% Series due April 2040 | New York Stock Exchange, Inc. |
| Mortgage Bonds, 6.0% Series due May 2051October 2066 | New York Stock Exchange, Inc. |
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Entergy New Orleans, Inc.LLC | Mortgage Bonds, 5.0% Series due December 2052 | New York Stock Exchange, Inc. |
| Mortgage Bonds, 5.50% Series due April 2066 | New York Stock Exchange, Inc. |
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| Entergy Texas, Inc. | Mortgage Bonds, 5.625% Series due June 2064 | New York Stock Exchange, Inc. |
Securities registered pursuant to Section 12(g) of the Act:
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| Registrant | Title of Class |
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| Entergy Arkansas, Inc. | Preferred Stock, Cumulative, $100 Par Value
Preferred Stock, Cumulative, $0.01 Par Value
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Entergy Gulf States Louisiana, L.L.C. | Common Membership Interests |
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Entergy Mississippi, Inc. | Preferred Stock, Cumulative, $100 Par Value |
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Entergy New Orleans,Mississippi, Inc. | Preferred Stock, Cumulative, $100 Par Value |
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| Entergy Texas, Inc. | Common Stock, no par value |
Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.
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| | Yes | | No |
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| Entergy Corporation | ü | | |
| Entergy Arkansas, Inc. | | | ü |
Entergy Gulf States Louisiana, L.L.C. | | | ü |
Entergy Louisiana, LLC | ü | | |
| Entergy Mississippi, Inc. | | | ü |
Entergy New Orleans, Inc.LLC | | | ü |
| Entergy Texas, Inc. | | | ü |
| System Energy Resources, Inc. | | | ü |
Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
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| | Yes | | No |
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| Entergy Corporation | | | ü |
| Entergy Arkansas, Inc. | | | ü |
Entergy Gulf States Louisiana, L.L.C. | | | ü |
Entergy Louisiana, LLC | | | ü |
| Entergy Mississippi, Inc. | | | ü |
Entergy New Orleans, Inc.LLC | | | ü |
| Entergy Texas, Inc. | | | ü |
| System Energy Resources, Inc. | | | ü |
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrants have submitted electronically and posted on Entergy’s corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ü]
Indicate by check mark whether theeach registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “accelerated filer,” “large accelerated filer,” and“accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Securities Exchange Act of 1934.
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| | Large accelerated filer | | Accelerated Accelerated filer
| | Non- Non-acceleratedaccelerated
filer | | Smaller reporting company |
| | | | | | | | Emerging growth company |
| Entergy Corporation | ü | | | | | | | | |
| Entergy Arkansas, Inc. | | | | | ü | | |
Entergy Gulf States Louisiana, L.L.C. | | | | | ü | | |
| Entergy Louisiana, LLC | | | | | ü | | | | |
| Entergy Mississippi, Inc. | | | | | ü | | | | |
Entergy New Orleans, Inc.LLC | | | | | ü | | | | |
| Entergy Texas, Inc. | | | | | ü | | | | |
| System Energy Resources, Inc. | | | | | ü | | | | |
If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act.) Yes o No þ
System Energy Resources meets the requirements set forth in General Instruction I(1) of Form 10-K and is therefore filing this Form 10-K with reduced disclosure as allowed in General Instruction I(2). System Energy Resources is reducing its disclosure by not including Part III, Items 10 through 13 in its Form 10-K.
The aggregate market value of Entergy Corporation Common Stock, $0.01 Par Value, held by non-affiliates as of the end of the second quarter of 2014,2017 was $14.7$13.8 billion based on the reported last sale price of $82.09$76.77 per share for such stock on the New York Stock Exchange on June 30, 2014.2017. Entergy Corporation is the sole holder of the common stock of Entergy Arkansas, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc. Entergy Corporation is the soledirect and indirect holder of the common stockmembership interests of Entergy Louisiana Holdings, Inc.,Utility Holding Company, LLC, which is the sole holder of the common membership interests inof Entergy Louisiana, LLC and Entergy New Orleans, LLC. Entergy Corporation is the sole holder of the common stock of EGS Holdings, Inc., which is the sole holder of the common membership interests in Entergy Gulf States Louisiana, L.L.C.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders, to be held May 8, 2015,4, 2018, are incorporated by reference into Part III hereof.
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TABLE OF CONTENTS
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| | SEC Form 10-K Reference Number | Page Number |
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| Part II. Item 7. | |
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| Part II. Item 6. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
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| Part II. Item 8. | |
| Part I.II. Item 1.8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Entergy’s Business | | |
| Part I. Item 1. | |
| Part I. Item 1. | |
| Part I. Item 1. | |
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| Part I. Item 1A. | |
| Unresolved Staff Comments | Part I. Item 1B. | None |
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| Entergy Arkansas, Inc. and Subsidiaries | | |
| Part II. Item 7. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 6. | |
Entergy Gulf States Louisiana, L.L.C. | | |
| Part II. Item 7. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
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| Part II. Item 8. | |
| Part II. Item 6. | |
| Entergy Louisiana, LLC and Subsidiaries | | |
| Part II. Item 7. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 6. | |
| Entergy Mississippi, Inc. | | |
| Part II. Item 7. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 6. | |
Entergy New Orleans, Inc.LLC and Subsidiaries | | |
| Part II. Item 7. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 6. | |
| Entergy Texas, Inc. and Subsidiaries | | |
| Part II. Item 7. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
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| Part II. Item 8. | |
| Part II. Item 6. | |
| System Energy Resources, Inc. | | |
| Part II. Item 7. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 6. | |
System Energy Resources, Inc. | | |
| Part II. Item 7. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 6. | |
| Part I. Item 2. | |
| Part I. Item 3. | |
| Part I. Item 4. | |
| Part I. and Part III. Item 10. | |
| Part II. Item 5. | |
| Part II. Item 6. | |
| Part II. Item 7. | |
| Part II. Item 7A. | |
| Part II. Item 8. | |
| Part II. Item 9. | |
| Part II. Item 9A. | |
| Part II. Item 9A. | |
| Part III. Item 10. | |
| Part III. Item 11. | |
| Part III. Item 12. | |
| Part III. Item 13. | |
| Part III. Item 14. | |
| Part IV. Item 15. | |
| Part IV. Item 16. | |
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This combined Form 10-K is separately filed by Entergy Corporation and its sevensix “Registrant Subsidiaries”:Subsidiaries:” Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc.,LLC, Entergy Texas, Inc., and System Energy Resources, Inc. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representations whatsoever as to any other company.
The report should be read in its entirety as it pertains to each respective reporting company. No one section of the report deals with all aspects of the subject matter. Separate Item 6, 7, and 8 sections are provided for each reporting company, except for the Notes to the financial statements. The Notes to the financial statements for all of the reporting companies are combined. All Items other than 6, 7, and 8 are combined for the reporting companies.
FORWARD-LOOKING INFORMATION
In this combined report and from time to time, Entergy Corporation and the Registrant Subsidiaries each makes statements as a registrant concerning its expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Words such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “intend,” “expect,” “estimate,” “continue,” “potential,” “plan,” “predict,” “forecast,” and other similar words or expressions are intended to identify forward-looking statements but are not the only means to identify these statements. Although each of these registrants believes that these forward-looking statements and the underlying assumptions are reasonable, it cannot provide assurance that they will prove correct. Any forward-looking statement is based on information current as of the date of this combined report and speaks only as of the date on which such statement is made. Except to the extent required by the federal securities laws, these registrants undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.
Forward-looking statements involve a number of risks and uncertainties. There are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements, including (a) those factors discussed or incorporated by reference in Item 1A. Risk Factors, (b) those factors discussed or incorporated by reference in Management’s Financial Discussion and Analysis, and (c) the following factors (in addition to others described elsewhere in this combined report and in subsequent securities filings):
resolution of pending and future rate cases, formula rate proceedings and related negotiations, including various performance-based rate discussions, Entergy’s utility supply plan, and recovery of fuel and purchased power costs;
long-term risks and uncertainties associated with the termination of Entergy Arkansas’s participation in the System Agreement, which occurred in December 2013, the termination of Entergy Mississippi’s participation in the System Agreement in November 2015,2016, including the terminationpotential absence of Entergy Texas’s, Entergy Gulf States Louisiana’s,federal authority to resolve certain issues among the Utility operating companies and Entergy Louisiana’s participation in the System Agreement after expiration of the proposed 60-month notice period or such other period as approved by the FERC;their retail regulators;
regulatory and operating challenges and uncertainties and economic risks associated with the Utility operating companies’ move toparticipation in MISO, which occurred in December 2013, including the benefits of continued MISO participation, the effect of current or projected MISO market rules and market and system conditions in the MISO markets, the allocation of MISO system transmission upgrade costs, and the effect of planning decisions that MISO makes with respect to future transmission investments by the Utility operating companies;
changes in utility regulation, including the beginning or end ofwith respect to retail and wholesale competition, the ability to recover net utility assets and other potential stranded costs, and the application of more stringent transmission reliability requirements or market power criteria by the FERC;FERC or the U.S. Department of Justice;
changes in the regulation or regulatory oversight of Entergy’s nuclear generating facilities and nuclear materials and fuel, including with respect to the planned, potential, or potentialactual shutdown of nuclear generating facilities owned or operated by Entergy Wholesale Commodities, and the effects of new or existing safety or environmental concerns regarding nuclear power plants and nuclear fuel;
resolution of pending or future applications, and related regulatory proceedings and litigation, for license renewals or modifications or other authorizations required of nuclear generating facilities;facilities and the effect of public and political opposition on these applications, regulatory proceedings, and litigation;
the performance of and deliverability of power from Entergy’s generation resources, including the capacity factors at itsEntergy’s nuclear generating facilities;
increases in costs and capital expenditures that could result from the commitment of substantial human and capital resources required for the operation and maintenance of Entergy’s nuclear generating facilities;
Entergy’s ability to develop and execute on a point of view regarding future prices of electricity, natural gas, and other energy-related commodities;
prices for power generated by Entergy’s merchant generating facilities and the ability to hedge, meet credit support requirements for hedges, sell power forward or otherwise reduce the market price risk associated with those facilities, including the Entergy Wholesale Commodities nuclear plants, especially in light of the planned shutdown or sale of each of these nuclear plants;
the prices and availability of fuel and power Entergy must purchase for its Utility customers, and Entergy’s ability to meet credit support requirements for fuel and power supply contracts;
volatility and changes in markets for electricity, natural gas, uranium, emissions allowances, and other energy-related commodities, and the effect of those changes on Entergy and its customers;
FORWARD-LOOKING INFORMATION (Concluded)(Continued)
changes in law resulting from federal or state energy legislation or legislation subjecting energy derivatives used in hedging and risk management transactions to governmental regulation;
changes in environmental tax,laws and other laws,regulations, agency positions or associated litigation, including requirements for reduced emissions of sulfur dioxide, nitrogen oxide, greenhouse gases, mercury, particulate matter, heat, and other regulated air and water emissions, requirements for waste management and disposal and for the remediation of contaminated sites, wetlands protection and permitting, and changes in costs of compliance with these environmental laws and regulations;
changes in laws and regulations, agency positions, or associated litigation related to protected species and associated critical habitat designations;
the effects of changes in federal, state or local laws and regulations, and other laws and regulations;governmental actions or policies, including changes in monetary, fiscal, tax, environmental, or energy policies;
uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel and nuclear waste storage and disposal and the level of spent fuel and nuclear waste disposal fees charged by the U.S. government or other providers related to such sites;
variations in weather and the occurrence of hurricanes and other storms and disasters, including uncertainties associated with efforts to remediate the effects of hurricanes, ice storms, or other weather events and the recovery of costs associated with restoration, including accessing funded storm reserves, federal and local cost recovery mechanisms, securitization, and insurance;
effects of climate change;change, including the potential for increases in sea levels or coastal land and wetland loss;
changes in the quality and availability of water supplies and the related regulation of water use and diversion;
Entergy’s ability to manage its capital projects and operation and maintenance costs;
Entergy’s ability to purchase and sell assets at attractive prices and on other attractive terms;
the economic climate, and particularly economic conditions in Entergy’s Utility service area and the Northeast United States and events and circumstances that could influence economic conditions in those areas, including power prices, and the risk that anticipated load growth may not materialize;
federal income tax reform, including the enactment of the Tax Cuts and Jobs Act, and its intended and unintended consequences on financial results and future cash flows, including the potential impact to credit ratings, which may affect Entergy’s ability to borrow funds or increase the cost of borrowing in the future;
the effects of Entergy’s strategies to reduce tax payments;payments, especially in light of federal income tax reform;
changes in the financial markets and regulatory requirements for the issuance of securities, particularly those affecting the availability ofas they affect access to capital and Entergy’s ability to refinance existing debt,securities, execute share repurchase programs, and fund investments and acquisitions;
actions of rating agencies, including changes in the ratings of debt and preferred stock, changes in general corporate ratings, and changes in the rating agencies’ ratings criteria;
changes in inflation and interest rates;
the effect of litigation and government investigations or proceedings;
changes in technology, including with respect to new, developing, or alternative sources of generation;generation such as distributed energy and energy storage, energy efficiency, demand side management and other measures that reduce load;
the potential effects, including increased security costs, of threatened or actual terrorism, cyber-attacks or data security breaches, including increased security costs,natural or man-made electromagnetic pulses that affect transmission or generation infrastructure, accidents, and war or a catastrophic event such as a nuclear accident or a natural gas pipeline explosion;
Entergy’s ability to attract and retain talented management, directors, and directors;employees with specialized skills;
changes in accounting standards and corporate governance;
declines in the market prices of marketable securities and resulting funding requirements and the effects on benefits costs for Entergy’s defined benefit pension and other postretirement benefit plans;
future wage and employee benefit costs, including changes in discount rates and returns on benefit plan assets;
changes in decommissioning trust fund values or earnings or in the timing of, requirements for, or cost to decommission Entergy’s nuclear plant sites;sites and the implementation of decommissioning of such sites following shutdown;
FORWARD-LOOKING INFORMATION (Concluded)
the decision to cease merchant power generation at all Entergy Wholesale Commodities nuclear power plants by mid-2022, including the implementation of the shutdownplanned shutdowns of Vermont YankeePilgrim, Indian Point 2, Indian Point 3, and the related decommissioning of Vermont Yankee;Palisades;
the effectiveness of Entergy’s risk management policies and procedures and the ability and willingness of its counterparties to satisfy their financial and performance commitments;
factors that could lead to impairment of long-lived assets; and
the ability to successfully complete merger, acquisition,strategic transactions Entergy may undertake, including mergers, acquisitions, divestitures, or divestiture plans,restructurings, regulatory or other limitations imposed as a result of merger, acquisition, or divestiture,any such strategic transaction, and the success of the business following a merger, acquisition, or divestiture.any such strategic transaction.
DEFINITIONS
Certain abbreviations or acronyms used in the text and notes are defined below:
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| Abbreviation or Acronym | Term |
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| AFUDC | Allowance for Funds Used During Construction |
| ALJ | Administrative Law Judge |
| ANO 1 and 2 | Units 1 and 2 of Arkansas Nuclear One (nuclear), owned by Entergy Arkansas |
| APSC | Arkansas Public Service Commission |
| ASLB | Atomic Safety and Licensing Board, the board within the NRC that conducts hearings and performs other regulatory functions that the NRC authorizes |
| ASU | Accounting Standards Update issued by the FASB |
| Board | Board of Directors of Entergy Corporation |
| Cajun | Cajun Electric Power Cooperative, Inc. |
| capacity factor | Actual plant output divided by maximum potential plant output for the period |
City Council or Council | Council of the City of New Orleans, Louisiana |
D. C.D.C. Circuit | U.S. Court of Appeals for the District of Columbia Circuit |
| DOE | United States Department of Energy |
| Entergy | Entergy Corporation and its direct and indirect subsidiaries |
| Entergy Corporation | Entergy Corporation, a Delaware corporation |
| Entergy Gulf States, Inc. | Predecessor company for financial reporting purposes to Entergy Gulf States Louisiana that included the assets and business operations of both Entergy Gulf States Louisiana and Entergy Texas |
| Entergy Gulf States Louisiana | Entergy Gulf States Louisiana, L.L.C., a Louisiana limited liability company formally created as part of the jurisdictional separation of Entergy Gulf States, Inc. and the successor company to Entergy Gulf States, Inc. for financial reporting purposes. The term is also used to refer to the Louisiana jurisdictional business of Entergy Gulf States, Inc., as the context requires. Effective October 1, 2015, the business of Entergy Gulf States Louisiana was combined with Entergy Louisiana. |
| Entergy Louisiana | Entergy Louisiana, LLC, a Texas limited liability company formally created as part of the combination of Entergy Gulf States Louisiana and the company formerly known as Entergy Louisiana, LLC (Old Entergy Louisiana) into a single public utility company and the successor to Old Entergy Louisiana for financial reporting purposes. |
| Entergy Texas | Entergy Texas, Inc., a companyTexas corporation formally created as part of the jurisdictional separation of Entergy Gulf States, Inc. The term is also used to refer to the Texas jurisdictional business of Entergy Gulf States, Inc., as the context requires. |
Entergy Wholesale Commodities (EWC) | Entergy’s non-utility business segment primarily comprised of the ownership, operation, and decommissioning of nuclear power plants, the ownership of interests in non-nuclear power plants, and the sale of the electric power produced by its operating power plants to wholesale customers |
| EPA | United States Environmental Protection Agency |
| ERCOT | Electric Reliability Council of Texas |
| FASB | Financial Accounting Standards Board |
| FERC | Federal Energy Regulatory Commission |
| FitzPatrick | James A. FitzPatrick Nuclear Power Plant (nuclear), previously owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment, |
FTR | Financial transmission right which was sold in March 2017 |
| Grand Gulf | Unit No. 1 of Grand Gulf Nuclear Station (nuclear), 90% owned or leased by System Energy |
DEFINITIONS (Continued)
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| Abbreviation or Acronym | Term |
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| GWh | Gigawatt-hour(s), which equals one million kilowatt-hours |
| Independence | Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power, LLC |
| Indian Point 2 | Unit 2 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
DEFINITIONS (Continued)
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Abbreviation or Acronym | Term |
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| Indian Point 3 | Unit 3 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
| IRS | Internal Revenue Service |
| ISO | Independent System Operator |
| kV | Kilovolt |
| kW | Kilowatt, which equals one thousand watts |
| kWh | Kilowatt-hour(s) |
| LDEQ | Louisiana Department of Environmental Quality |
| LPSC | Louisiana Public Service Commission |
| Mcf | 1,000 cubic feet of gas |
| MISO | Midcontinent Independent System Operator, Inc., a regional transmission organization |
| MMBtu | One million British Thermal Units |
| MPSC | Mississippi Public Service Commission |
| MW | Megawatt(s), which equals one thousand kilowatt(s)kilowatts |
| MWh | Megawatt-hour(s) |
| Nelson Unit 6 | Unit No. 6 (coal) of the Nelson Steam Electric Generating Station, 70% of which is co-owned by Entergy Gulf States Louisiana (57.5%) and Entergy Texas (42.5%), and 10.9% of which is owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
| Net debt to net capital ratio | Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents |
| Net MW in operation | Installed capacity owned and operated |
| NRC | Nuclear Regulatory Commission |
| NYPA | New York Power Authority |
OASIS | Open Access Same Time Information Systems |
| Palisades | Palisades PowerNuclear Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
| Parent & Other | The portions of Entergy not included in the Utility or Entergy Wholesale Commodities segments, primarily consisting of the activities of the parent company, Entergy Corporation |
| Pilgrim | Pilgrim Nuclear Power Station (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
| PPA | Purchased power agreement or power purchase agreement |
| PRP | Potentially responsible party (a person or entity that may be responsible for remediation of environmental contamination) |
| PUCT | Public Utility Commission of Texas |
| Registrant Subsidiaries | Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc.,LLC, Entergy Texas, Inc., and System Energy Resources, Inc. |
Ritchie Unit 2 | Unit 2 of the R.E. Ritchie Steam Electric Generating Station (gas/oil) |
River Bend | River Bend Station (nuclear), owned by Entergy Gulf States Louisiana |
RTO | Regional transmission organization |
SEC | Securities and Exchange Commission |
SMEPA | South Mississippi Electric Power Association, which owns a 10% interest in Grand Gulf |
DEFINITIONS (Concluded)
|
| |
| Abbreviation or Acronym | Term |
| | |
| River Bend | River Bend Station (nuclear), owned by Entergy Louisiana |
| RTO | Regional transmission organization |
| SEC | Securities and Exchange Commission |
| System Agreement | Agreement, effective January 1, 1983, as modified, among the Utility operating companies relating to the sharing of generating capacity and other power resources. Entergy ArkansasThe agreement terminated its participation in the System Agreement effective December 18, 2013.August 2016. |
| System Energy | System Energy Resources, Inc. |
System Fuels | System Fuels, Inc. |
| TWh | Terawatt-hour(s), which equals one billion kilowatt-hours |
U.K. | United Kingdom of Great Britain and Northern Ireland |
| Unit Power Sales Agreement | Agreement, dated as of June 10, 1982, as amended and approved by the FERC, among Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, relating to the sale of capacity and energy from System Energy’s share of Grand Gulf |
| Utility | Entergy’s business segment that generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution |
| Utility operating companies | Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas |
| Vermont Yankee | Vermont Yankee Nuclear Power Station (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment, which ceased power production in December 2014 |
| Waterford 3 | Unit No. 3 (nuclear) of the Waterford Steam Electric Station, 100% owned or leased by Entergy Louisiana |
| weather-adjusted usage | Electric usage excluding the effects of deviations from normal weather |
| White Bluff | White Bluff Steam Electric Generating Station, 57% owned by Entergy Arkansas |
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ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.
The Utility business segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operatesoperation of a small natural gas distribution business.
The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. In August 2013, Entergy announced plans to close and decommission Vermont Yankee. On December 29, 2014 the Vermont Yankee plant ceased power production and has entered its decommissioning phase. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” below for discussion of the operation and planned shutdown or sale of each of the Entergy Wholesale Commodities nuclear power plants.
Following are the percentages of Entergy’s consolidated revenues and net income generated by its operating segments and the percentage of total assets held by them. Net income or loss generated by the operating segments is discussed in the sections that follow.
| | | | % of Revenue | | % of Net Income | | % of Total Assets | % of Revenue | | % of Total Assets |
| Segment | 2014 | 2013 | 2012 | | 2014 | 2013 | 2012 | | 2014 | 2013 | 2012 | 2017 | 2016 | 2015 | | 2017 | 2016 | 2015 |
| Utility | 78 |
| 80 |
| 78 |
| | 88 |
| 116 |
| 110 |
| | 82 |
| 82 |
| 82 |
| 85 |
| 83 |
| 82 |
| | 92 |
| 89 |
| 86 |
|
| Entergy Wholesale Commodities | 22 |
| 20 |
| 22 |
| | 31 |
| 6 |
| 5 |
| | 22 |
| 22 |
| 22 |
| 15 |
| 17 |
| 18 |
| | 12 |
| 15 |
| 18 |
|
| Parent & Other | — |
| — |
| — |
| | (19 | ) | (22 | ) | (15 | ) | | (4 | ) | (4 | ) | (4 | ) | — |
| — |
| — |
| | (4 | ) | (4 | ) | (4 | ) |
See Note 13 to the financial statements for further financial information regarding Entergy’s business segments.
Entergy Corporation and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
Results of Operations
20142017 Compared to 20132016
Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 20142017 to 20132016 showing how much the line item increased or (decreased) in comparison to the prior period.
| | | | Utility | | Entergy Wholesale Commodities | | Parent & Other | | Entergy | Utility | | Entergy Wholesale Commodities | | Parent & Other (a) | | Entergy |
| | (In Thousands) | (In Thousands) |
| 2013 Consolidated Net Income (Loss) |
| $846,215 |
| |
| $42,976 |
| |
| ($158,619 | ) | |
| $730,572 |
| |
| 2016 Consolidated Net Income (Loss) | |
| $1,151,133 |
| |
| ($1,493,124 | ) | |
| ($222,512 | ) | |
| ($564,503 | ) |
| | | | | | | | | | | | | | | |
Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits) | 210,893 |
| | 422,147 |
| | (17,519 | ) | | 615,521 |
| 138,617 |
| | (73,433 | ) | | (16 | ) | | 65,168 |
|
| Other operation and maintenance | 12,369 |
| | (25,043 | ) | | (8,724 | ) | | (21,398 | ) | 108,187 |
| | 13,922 |
| | 4,869 |
| | 126,978 |
|
| Asset write-off, impairments, and related charges | 62,814 |
| | (221,809 | ) | | (2,790 | ) | | (161,785 | ) | |
| Asset write-offs, impairments, and related charges | | — |
| | (2,297,265 | ) | | — |
| | (2,297,265 | ) |
| Taxes other than income taxes | 2,760 |
| | 1,709 |
| | (213 | ) | | 4,256 |
| 38,897 |
| | (14,657 | ) | | 814 |
| | 25,054 |
|
| Depreciation and amortization | (2,019 | ) | | 60,053 |
| | (440 | ) | | 57,594 |
| 49,491 |
| | (6,731 | ) | | 31 |
| | 42,791 |
|
| Gain on sale of business | — |
| | (43,569 | ) | | — |
| | (43,569 | ) | |
| Gain on sale of asset | | — |
| | 16,270 |
| | — |
| | 16,270 |
|
| Other income | 1,795 |
| | (23,642 | ) | | (13,272 | ) | | (35,119 | ) | 64,815 |
| | 132,734 |
| | 1,962 |
| | 199,511 |
|
| Interest expense | 22,556 |
| | 323 |
| | 591 |
| | 23,470 |
| (10,245 | ) | | 856 |
| | 5,362 |
| | (4,027 | ) |
| Other expenses | 7,696 |
| | 33,699 |
| | — |
| | 41,395 |
| 24,859 |
| | 12,874 |
| | — |
| | 37,733 |
|
| Income taxes | 106,231 |
| | 254,459 |
| | 2,926 |
| | 363,616 |
| 370,228 |
| | 1,045,783 |
| | (56,182 | ) | | 1,359,829 |
|
| 2014 Consolidated Net Income (Loss) |
| $846,496 |
|
|
| $294,521 |
|
|
| ($180,760 | ) |
|
| $960,257 |
| |
| 2017 Consolidated Net Income (Loss) | |
| $773,148 |
| |
| ($172,335 | ) | |
| ($175,460 | ) | |
| $425,353 |
|
| |
| (a) | Parent & Other includes eliminations, which are primarily intersegment activity. |
Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES” which accompanies Entergy Corporation’s financial statements in this report for further information with respect to operating statistics.
Results of operations for 2017 include: 1) $538 million ($350 million net-of-tax) of impairment charges due to costs being charged to expense as incurred as a result of the impaired value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet; 2) a reduction in net income of $181 million, including a $34 million net-of-tax reduction of regulatory liabilities, at Utility and $397 million at Entergy Wholesale Commodities and an increase in net income of $52 million at Parent and Other as a result of Entergy’s re-measurement of its deferred tax assets and liabilities not subject to the ratemaking process due to the enactment of the Tax Cuts and Jobs Act, in December 2017, which lowered the federal corporate income tax rate from 35% to 21%; and 3) a reduction in income tax expense, net of unrecognized tax benefits, of $373 million as a result of a change in the tax classification of legal entities that own Entergy Wholesale Commodities nuclear power plants. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” below for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet and see Note 14 to the financial statements for further discussion of the impairment and related charges. See Note 3 to the financial statements for further discussion of the effects of the Tax Cuts and Jobs Act and the change in the tax classification.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Results of operations for 2016 include: 1) $2,836 million ($1,829 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values; 2) a reduction of income tax expense, net of unrecognized tax benefits, of $238 million as a result of a change in the tax classification of a legal entity that owned one of the Entergy Wholesale Commodities nuclear power plants; income tax benefits as a result of the settlement of the 2010-2011 IRS audit, including a $75 million tax benefit recognized by Entergy Louisiana related to the treatment of the Vidalia purchased power agreement and a $54 million net benefit recognized by Entergy Louisiana related to the treatment of proceeds received in 2010 for the financing of Hurricane Gustav and Hurricane Ike storm costs pursuant to Louisiana Act 55; and 3) a reduction in expenses of $100 million ($64 million net-of-tax) due to the effects of recording in 2016 the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. See Note 14 to the financial statements for further discussion of the impairment and related charges, see Note 3 to the financial statements for additional discussion of the income tax items, and see Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Net Revenue
Utility
Following is an analysis of the change in net revenue comparing 2017 to 2016.
|
| | | |
| Amount |
| (In Millions) |
| |
| 2016 net revenue |
| $6,179 |
|
| Retail electric price | 91 |
|
Regulatory credit resulting from reduction of the federal corporate income tax rate | 56 |
|
| Grand Gulf recovery | 27 |
|
| Louisiana Act 55 financing savings obligation | 17 |
|
| Volume/weather | (61 | ) |
| Other | 9 |
|
| 2017 net revenue |
| $6,318 |
|
The retail electric price variance is primarily due to:
the implementation of formula rate plan rates effective with the first billing cycle of January 2017 at Entergy Arkansas and an increase in base rates effective February 24, 2016, each as approved by the APSC. A significant portion of the base rate increase was related to the purchase of Power Block 2 of the Union Power Station in March 2016;
a provision recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding;
the implementation of the transmission cost recovery factor rider at Entergy Texas, effective September 2016, and an increase in the transmission cost recovery factor rider rate, effective March 2017, as approved by the PUCT; and
an increase in rates at Entergy Mississippi, as approved by the MPSC, effective with the first billing cycle of July 2016.
See Note 2 to the financial statements for further discussion of the rate proceedings and the Waterford 3 replacement steam generator prudence review proceeding. See Note 14 to the financial statements for discussion of the Union Power Station purchase.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
The regulatory credit resulting from reduction of the federal corporate income tax rate variance is due to the reduction of the Vidalia purchased power agreement regulatory liability by $30.5 million and the reduction of the Louisiana Act 55 financing savings obligation regulatory liabilities by $25 million as a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, which lowered the federal corporate income tax rate from 35% to 21%. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.
The Grand Gulf recovery variance is primarily due to increased recovery of higher operating costs.
The Louisiana Act 55 financing savings obligation variance results from a regulatory charge in 2016 for tax savings to be shared with customers per an agreement approved by the LPSC. The tax savings resulted from the 2010-2011 IRS audit settlement on the treatment of the Louisiana Act 55 financing of storm costs for Hurricane Gustav and Hurricane Ike. See Note 3 to the financial statements for additional discussion of the settlement and benefit sharing.
The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales, partially offset by an increase in industrial usage. The increase in industrial usage is primarily due to new customers in the primary metals industry and expansion projects and an increase in demand for existing customers in the chlor-alkali industry.
Entergy Wholesale Commodities
Following is an analysis of the change in net revenue comparing 2017 to 2016.
|
| | | |
| Amount |
| (In Millions) |
| |
| 2016 net revenue |
| $1,542 |
|
| FitzPatrick sale | (158 | ) |
| Nuclear volume | (89 | ) |
| FitzPatrick reimbursement agreement | 57 |
|
| Nuclear fuel expenses | 108 |
|
| Other | 9 |
|
| 2017 net revenue |
| $1,469 |
|
As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by approximately $73 million in 2017 primarily due to the absence of net revenue from the FitzPatrick plant after it was sold to Exelon in March 2017 and lower volume in the Entergy Wholesale Commodities nuclear fleet resulting from more outage days in 2017 as compared to 2016. The decrease was partially offset by an increase resulting from the reimbursement agreement with Exelon pursuant to which Exelon reimbursed Entergy for specified out-of-pocket costs associated with preparing for the refueling and operation of FitzPatrick that otherwise would have been avoided had Entergy shut down FitzPatrick in January 2017 and a decrease in nuclear fuel expenses primarily related to the impairments of the Indian Point 2, Indian Point 3, and Palisades plants and related assets. Revenues received from Exelon in 2017 under the reimbursement agreement are offset by other operation and maintenance expenses and taxes other than income taxes and had no effect on net income. See Note 14 to the financial statements for discussion of the sale of FitzPatrick, the reimbursement agreement with Exelon, and the impairments and related charges.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Following are key performance measures for Entergy Wholesale Commodities for 2017 and 2016.
|
| | | |
| | 2017 | | 2016 |
| Owned capacity (MW) (a) | 3,962 | | 4,800 |
| GWh billed | 30,501 | | 35,881 |
| | | | |
| Entergy Wholesale Commodities Nuclear Fleet | | | |
| Capacity factor | 83% | | 87% |
| GWh billed | 28,178 | | 33,551 |
| Average energy and capacity revenue per MWh | $50.04 | | $47.31 |
| Refueling Outage Days: | | | |
| FitzPatrick | 42 | | — |
| Indian Point 2 | — | | 102 |
| Indian Point 3 | 66 | | — |
| Pilgrim | 43 | | — |
| Palisades | 27 | | — |
| |
| (a) | The reduction in owned capacity is due to Entergy’s sale of the 838 MW FitzPatrick plant to Exelon in March 2017. See Note 14 to the financial statements for discussion of the sale of FitzPatrick. |
Other Income Statement Items
Utility
Other operation and maintenance expenses increased from $2,360 million for 2016 to $2,468 million for 2017 primarily due to:
an increase of $46 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor, to position the nuclear fleet to meet its operational goals, including additional training and initiatives to support management’s operational goals at Grand Gulf, partially offset by a decrease in regulatory compliance costs. The decrease in regulatory compliance costs is primarily related to additional NRC inspection activities in 2016 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. See Note 8 to the financial statements for a discussion of the ANO stator incident and subsequent NRC reviews;
an increase of $24 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to the prior year;
an increase of $20 million in transmission and distribution expenses due to higher vegetation maintenance costs;
the effects of recording in 2016 final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded included the reimbursement of approximately $19 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
the deferral in the first quarter 2016 of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC in February 2016 as part of the Entergy Arkansas 2015 rate case settlement. These costs are being amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement.
The increase was partially offset by a decrease of $23 million in fossil-fueled generation expenses primarily due to lower long-term service agreement costs.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Taxes other than income taxes increased primarily due to increases in ad valorem taxes, local franchise taxes, state franchise taxes, and employment taxes. Ad valorem taxes increased primarily due to higher assessments, including the assessment of ad valorem taxes on the Union Power Station beginning in 2017. Local franchise taxes increased primarily due to higher revenues in 2017 as compared to the prior year. State franchise taxes increased primarily due to a change in the Louisiana franchise tax law which became effective for 2017.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Union Power Station purchased in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase.
Other income increased primarily due to higher realized gains in 2017 as compared to the prior year on the decommissioning trust fund investments, including portfolio rebalancing in 2017, and an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2017, including the St. Charles Power Station project.
Other expenses increased primarily due to increases in deferred refueling outage amortization costs primarily associated with the most recent ANO plant outages compared to previous outages.
Entergy Wholesale Commodities
Other operation and maintenance expenses increased from $915 million for 2016 to $929 million for 2017 primarily due to:
FitzPatrick’s nuclear refueling outage expenses and expenditures for capital assets being classified as other operation and maintenance expenses as a result of the sale and reimbursement agreements Entergy entered into with Exelon. These costs would have not been incurred absent the sale agreement with Exelon because Entergy planned to shut the plant down in January 2017. The expenses are offset by revenue realized pursuant to the reimbursement agreement and had no effect on net income. See Note 14 to the financial statements for discussion of the sale and reimbursement agreements;
the effect of recording in 2016 final court decisions in litigation against the DOE for the reimbursement of spent nuclear fuel storage costs, which reduced other operation and maintenance expenses in 2016 by $60 million. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
an increase of $37 million in severance and retention costs in 2017 as compared to the prior year due to management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” below for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet.
The increase was partially offset by a decrease due to the absence of other operation and maintenance expenses from the FitzPatrick plant after it was sold to Exelon in March 2017. See Note 14 to the financial statements for discussion of the sale of FitzPatrick.
The asset write-offs, impairments, and related charges variance is primarily due to $538 million ($350 million net-of-tax) of impairment charges in 2017 compared to $2,836 million ($1,829 million net-of-tax) of impairment and related charges in 2016. The impairment charges in 2017 are due to nuclear fuel spending, nuclear refueling outage spending, and expenditures for capital assets being charged to expense as incurred as a result of the impaired value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” below for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet. The impairment and related charges in 2016 were primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2,
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
and Indian Point 3 plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of the impairments and related charges.
Taxes other than income taxes decreased primarily due to the absence of ad valorem taxes from the FitzPatrick plant after it was sold to Exelon in March 2017. See Note 14 to the financial statements for discussion of the sale of FitzPatrick.
The gain on sale of assets resulted from the sale in March 2017 of the 838 MW FitzPatrick plant to Exelon. Entergy sold the FitzPatrick plant for approximately $110 million, which includes a $10 million non-refundable signing fee paid in August 2016, in addition to the assumption by Exelon of certain liabilities related to the FitzPatrick plant, resulting in a pre-tax gain of $16 million on the sale. See Note 14 to the financial statements for a discussion of the sale of FitzPatrick.
Other income increased primarily due to higher realized gains in 2017 as compared to the prior year on the decommissioning trust fund investments, including the result of portfolio rebalancing in 2017, and the increase in value realized upon the receipt from NYPA of the decommissioning trust funds for the Indian Point 3 and FitzPatrick plants in January 2017. See Note 9 to the financial statements for discussion of the trust transfer agreement with NYPA.
Other expenses increased primarily due to increases in decommissioning expenses primarily as a result of a trust transfer agreement Entergy entered into with NYPA in August 2016, which closed in January 2017, to transfer the decommissioning trusts and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy and revisions to the estimated decommissioning cost liabilities for the Entergy Wholesale Commodities’ Indian Point 2 and Palisades plants as a result of revised decommissioning cost studies in the fourth quarter 2016. The increase was partially offset by a reduction in deferred refueling outage amortization costs related to the impairments of the Indian Point 2, Indian Point 3, and Palisades plants and related assets. See Note 9 to the financial statements for discussion of the trust transfer agreement with NYPA and the revised decommissioning cost studies. See Note 14 to the financial statements for discussion of the impairments and related charges.
Income Taxes
See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates, and for additional discussion regarding income taxes.
The effective income tax rate for 2017 was 56.1%. The difference in the effective income tax rate versus the statutory rate of 35% for 2017 was primarily due to the enactment of the Tax Cuts and Jobs Act, signed by President Trump in December 2017, which changed the federal corporate income tax rate from 35% to 21% effective in 2018, partially offset by a change in the tax classification of legal entities that own Entergy Wholesale Commodities nuclear power plants, which resulted in both permanent and temporary differences under the income tax accounting standards. See Note 3 to the financial statements for further discussion of the effects of the Tax Cuts and Jobs Act and the change in tax classification.
The effective income tax rate for 2016 was 59.1%. The difference in the effective income tax rate versus the statutory rate of 35% for 2016 was primarily due to a change in the tax classification of a legal entity that owned one of the Entergy Wholesale Commodities nuclear power plants and the reversal of a portion of the provision for uncertain tax positions as a result of the settlement of the 2010-2011 IRS audit, partially offset by state income taxes and certain book and tax differences related to utility plant items. See Note 3 to the financial statements for additional discussion of the change in the tax classification and the tax settlement.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
2016 Compared to 2015
Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2016 to 2015 showing how much the line item increased or (decreased) in comparison to the prior period.
|
| | | | | | | | | | | | | | | |
| | Utility | | Entergy Wholesale Commodities | | Parent & Other | | Entergy |
| | (In Thousands) |
| 2015 Consolidated Net Income (Loss) |
| $1,114,516 |
| |
| ($1,065,657 | ) | |
| ($205,593 | ) | |
| ($156,734 | ) |
| | | | | | | | |
| Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits) | 350,528 |
| | (123,791 | ) | | (33 | ) | | 226,704 |
|
| Other operation and maintenance | (83,265 | ) | | 15,269 |
| | 9,726 |
| | (58,270 | ) |
| Asset write-offs, impairments, and related charges | (68,672 | ) | | 799,403 |
| | — |
| | 730,731 |
|
| Taxes other than income taxes | (10,229 | ) | | (16,259 | ) | | (432 | ) | | (26,920 | ) |
| Depreciation and amortization | 49,600 |
| | (39,180 | ) | | (509 | ) | | 9,911 |
|
| Gain on sale of asset | — |
| | (154,037 | ) | | — |
| | (154,037 | ) |
| Other income | 15,153 |
| | 8,666 |
| | 4,281 |
| | 28,100 |
|
| Interest expense | 14,414 |
| | (3,930 | ) | | 12,417 |
| | 22,901 |
|
| Other expenses | 19,589 |
| | (15,074 | ) | | — |
| | 4,515 |
|
| Income taxes | 407,627 |
| | (581,924 | ) | | (35 | ) | | (174,332 | ) |
| 2016 Consolidated Net Income (Loss) |
| $1,151,133 |
| |
| ($1,493,124 | ) | |
| ($222,512 | ) | |
| ($564,503 | ) |
Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES” which accompanies Entergy Corporation’s financial statements in this report for further information with respect to operating statistics.
Results of operations for 20142016 include $154$2,836 million ($1001,829 million after-tax)net-of-tax) of impairment and related charges relatedprimarily to Vermont Yankee primarily resulting fromwrite down the effects of an updated decommissioning cost study completed in the third quarter 2014 along with reassessmentcarrying values of the assumptions regarding the timing of decommissioning cash flowsEntergy Wholesale Commodities’ Palisades, Indian Point 2, and severanceIndian Point 3 plants and employee retention costs.related assets to their fair values. See Note 114 to the financial statements for further discussion of the impairment and related charges. Results of operations for 20142016 also include the $56.2a reduction of income tax expense, net of unrecognized tax benefits, of $238 million ($36.7 million after-tax) write-off in 2014 of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs as a result of a joint stipulation entered intochange in the tax classification of a legal entity that owned one of the Entergy Wholesale Commodities nuclear power plants; income tax benefits as a result of the settlement of the 2010-2011 IRS audit, including a $75 million tax benefit recognized by Entergy Louisiana related to the treatment of the Vidalia purchased power agreement and a $54 million net benefit recognized by Entergy Louisiana related to the treatment of proceeds received in 2010 for the financing of Hurricane Gustav and Hurricane Ike storm costs pursuant to Louisiana Act 55; and a reduction in expenses of $100 million ($64 million net-of-tax) due to the effects of recording in 2016 the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. See Note 3 to the financial statements for additional discussion of the income tax items. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Results of operations for 2015 include $2,036 million ($1,317 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of the impairment and related charges. As a result of the Entergy Louisiana and Entergy Gulf States Louisiana business combination, results of operations for 2015 also include two items that occurred in October 2015: 1) a deferred tax asset and resulting net increase in tax basis of approximately $334 million and 2) a regulatory liability of $107 million
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
($66 million net-of-tax) as a result of customer credits to be realized by electric customers of Entergy Louisiana, consistent with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, in which Entergy Mississippi agreed not to pursue recoveryterms of the costs deferred by an MPSC orderstipulated settlement in the new nuclear generation docket.business combination proceeding. See Note 2 to the financial statements for further discussion of the new nuclear generation development costsbusiness combination and customer credits. Results of operations for 2015 also include the sale in December 2015 of the 583 MW Rhode Island State Energy Center for a realized gain of $154 million ($100 million net-of-tax) on the sale and the joint stipulation.
As discussed in more detail in$77 million ($47 million net-of-tax) write-off and regulatory charges to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project is no longer probable of recovery. See Note 114 to the financial statements results of operations for 2013 include $322 million ($202 million after-tax) of impairment and other related charges to write down the carrying value of Vermont Yankee and related assets to their fair values. Also, earnings were negatively affected in 2013 by expenses, including other operation and maintenance expenses and taxes other than income taxes, of approximately $110 million ($70 million after-tax), including approximately $85 million ($55 million after-tax) for Utility and $25 million ($15 million after-tax) for Entergy Wholesale Commodities, recorded in connection with a strategic imperative intended to optimize the organization through a process known as human capital management. In December 2013, Entergy deferred for future collection approximately $45 million ($30 million after-tax) of these costs in the Arkansas and Louisiana
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
jurisdictions at the Utility, as approved by the APSC and the LPSC, respectively. See “Human Capital Management Strategic Imperative” below for further discussion.discussion of the Rhode Island State Energy Center sale. See Note 2 to the financial statements for further discussion of the Waterford 3 replacement steam generator prudence review proceeding.
Net Revenue
Utility
Following is an analysis of the change in net revenue comparing 20142016 to 2013.2015.
|
| | | |
| | Amount |
| | (In Millions) |
| | |
20132015 net revenue |
| $5,5245,829 |
|
| Retail electric price | 135289 |
|
Asset retirement obligationLouisiana business combination customer credits | 56107 |
|
| Volume/weather | 3614 |
|
MISO deferral | 16 |
|
Net wholesale revenueLouisiana Act 55 financing savings obligation | (2917 | ) |
| Other | (343 | ) |
20142016 net revenue |
| $5,7356,179 |
|
The retail electric price variance is primarily due to:
increasesan increase in the energy efficiency riderbase rates at Entergy Arkansas, as approved by the APSC,APSC. The new rates were effective July 2013February 24, 2016 and July 2014. Energy efficiency revenues are offset by costsbegan billing with the first billing cycle of April 2016. The increase included in other operation and maintenance expenses and have minimal effect on net income;
an interim base rate adjustment surcharge, effective with the effectfirst billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. A significant portion of the APSC’s orderincrease was related to the purchase of Power Block 2 of the Union Power Station;
an increase in the purchased power and capacity acquisition cost recovery rider for Entergy Arkansas’s 2013 rate case, including New Orleans, as approved by the City Council, effective with the first billing cycle of March 2016, primarily related to the purchase of Power Block 1 of the Union Power Station;
an annual base rate increase effective January 2014 offset by a MISO rider to provide customers credits in rates for transmission revenue received through MISO;
a formula rate plan revenues for Entergy Louisiana, implemented with the first billing cycle of March 2016, to collect the estimated first-year revenue requirement related to the purchase of Power Blocks 3 and 4 of the Union Power Station; and
an increase in revenues at Entergy Mississippi, as approved by the MSPC,MPSC, effective September 2013;
with the first billing cycle of July 2016, and an increase in Entergy Mississippi’s storm damage rider, as approved by the MPSC, effective October 2013. The increase inrevenues collected through the storm damage rider is offset by other operation and maintenance expenses and has no effect on net income;
an annual base rate increase at Entergy Texas, effective April 2014, as a result of the PUCT’s order in the September 2013 rate case; and
a formula rate plan increase at Entergy Louisiana, as approved by the LPSC, effective December 2014.rider.
See Note 2 to the financial statements for a discussion of rate proceedings.
The asset retirement obligation affects net revenue because Entergy records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The variance is primarily caused by increases in regulatory credits because of decreases in decommissioning trust earnings and increases in depreciation and accretion expenses and increases in regulatory credits to realign the asset retirement obligation regulatory assets with regulatory treatment.
The volume/weather variance is primarily due to an increase of 3,129 GWh, or 3%, in billed electricity usage primarily due to an increase in sales to industrial customers and the effect of more favorable weather on residential sales. The increase in industrial sales was primarily due to expansions, recovery of a major refining customer from an unplanned outage in 2013, and continued moderate growth in the manufacturing sector.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
The MISO deferral variance is primarily due to the deferral in 2014 of the non-fuel MISO-related charges, as approved by the LPSC and the MPSC, partially offset by the deferral in April 2013, as approved by the APSC, of costs incurred from March 2010 through December 2012 related to the transition and implementation of joining the MISO RTO. The deferral of non-fuel MISO-related charges is partially offset in other operation and maintenance expenses. See Note 2 to the financial statements for further discussion of the recoveryrate proceedings. See Note 14 to the financial statements for discussion of non-fuel MISO-related charges.the Union Power Station purchase.
The net wholesaleLouisiana business combination customer credits variance is due to a regulatory liability of $107 million recorded by Entergy in October 2015 as a result of the Entergy Gulf States Louisiana and Entergy Louisiana business combination. Consistent with the terms of the stipulated settlement in the business combination proceeding, electric customers of Entergy Louisiana will realize customer credits associated with the business combination; accordingly, in October 2015, Entergy recorded a regulatory liability of $107 million ($66 million net-of-tax). These costs are being
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
amortized over a nine-year period beginning December 2015. See Note 2 to the financial statements for further discussion of the business combination and customer credits.
The volume/weather variance is primarily due to a wholesale customer contract terminationthe effect of more favorable weather during the unbilled period and an increase in December 2013 and lower marginsindustrial usage, partially offset by the effect of less favorable weather on co-owner contractsresidential sales. The increase in industrial usage is primarily due to contract changes.expansion projects, primarily in the chemicals industry, and increased demand from new customers, primarily in the industrial gases industry.
The Louisiana Act 55 financing savings obligation variance results from a regulatory charge for tax savings to be shared with customers per an agreement approved by the LPSC. The tax savings resulted from the 2010-2011 IRS audit settlement on the treatment of the Louisiana Act 55 financing of storm costs for Hurricane Gustav and Hurricane Ike. See Note 3 to the financial statements for additional discussion of the settlement and benefit sharing.
Included in Other is a provision of $23 million recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding, offset by a provision of $32 million recorded in 2015 related to the uncertainty at that time associated with the resolution of the Waterford 3 replacement steam generator prudence review proceeding. See Note 2 to the financial statements for a discussion of the Waterford 3 replacement steam generator prudence review proceeding.
Entergy Wholesale Commodities
Following is an analysis of the change in net revenue comparing 20142016 to 2013.2015.
|
| | | |
| | Amount |
| | (In Millions) |
| | |
20132015 net revenue |
| $1,8021,666 |
|
| Nuclear realized price changes | 264(149 |
) |
Mark-to-marketRhode Island State Energy Center | 129(44 | ) |
| Nuclear volume | (36 | ) |
| FitzPatrick reimbursement agreement | 41 |
|
Nuclear volumefuel expenses | 3768 |
|
| Other | (84 | ) |
20142016 net revenue |
| $2,2241,542 |
|
As shown in the table above, net revenue for Entergy Wholesale Commodities increaseddecreased by approximately $422$124 million in 20142016 primarily due to:
higherlower realized wholesale energy prices primarily due to increases in Northeast market powerand lower capacity prices, the amortization of the Palisades below-market PPA, and higher capacity prices. Entergy Wholesale Commodities’ hedging strategies routinely include financial instruments that manage operational and liquidity risk. These positions, in addition to a larger-than-normal unhedged position in 2014 due to Vermont Yankee being in its final yearcapacity revenue. The effect of operation, allowed Entergy Wholesale Commoditiesthe amortization of the Palisades below-market PPA and Vermont Yankee capacity revenue on the net revenue variance from 2015 to benefit from increases in Northeast market power prices;2016 is minimal;
the effect of lower forward power prices on electricity derivative instruments that are not designated as hedges, including additional financial power sales conducted in the fourth quarter 2014 to lock in margins on some in-the-money purchased call options. These additional sales did not qualify for hedge accounting treatment, and decreases in forward prices after those sales were made accounted for the majoritysale of the positive mark-to-market variance. In fourth quarter 2013, Entergy Wholesale Commodities also entered into similar transactions, but the price movements after the forward sales wereRhode Island State Energy Center in the opposite direction and resulted in negative mark-to-market activity in 2013. When these positions settled in the first quarter 2014, the turnaround of the negative 2013 mark also contributed to the positive 2014 mark-to-market variance.December 2015. See Note 1614 to the financial statements for further discussion of derivative instruments;the Rhode Island State Energy Center sale; and
higherlower volume in itsthe Entergy Wholesale Commodities nuclear fleet resulting from approximately 90 fewer unplannedmore refueling outage days in 20142016 as compared to 2013, partially offset by a2015 and larger exercise of resupply options in 20132016 as compared to 2014 provided2015. See “Nuclear Matters - Indian Point” below for in purchase power agreements where Entergy Wholesale Commodities may elect to supply power from another source whendiscussion of the plant is not running. Amounts related to the exercise of resupply options are includedextended Indian Point 2 outage in the GWh billed in the table below.second quarter 2016.
Entergy Corporation and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
The decrease was partially offset by:
an increase resulting from the reimbursement agreement with Exelon pursuant to which Exelon reimbursed Entergy for specified out-of-pocket costs associated with preparing for the refueling and operation of FitzPatrick that otherwise would have been avoided had Entergy shut down FitzPatrick in January 2017. Revenues received from Exelon under the reimbursement agreement are offset in nuclear fuel expenses and other operation and maintenance expenses and have no material effect on net income. See “Entergy Wholesale Commodities Exit from the Merchant Power Business - Sale of FitzPatrick” below for further discussion of the reimbursement agreement; and
a decrease in nuclear fuel expenses primarily related to the impairments of the FitzPatrick, Pilgrim, and Palisades plants and related assets. See Note 14 to the financial statements for discussion of the impairments.
Following are key performance measures for Entergy Wholesale Commodities for 20142016 and 2013.2015.
| | | | 2014 | | 2013 | 2016 | | 2015 |
Owned capacity (MW) | 6,068 | | 6,068 | 4,800 | | 4,880 |
| GWh billed | 44,424 | | 45,127 | 35,881 | | 39,745 |
| Average realized price per MWh | $60.84 | | $50.86 | |
| |
| | |
| Entergy Wholesale Commodities Nuclear Fleet |
| | |
| Capacity factor | 91% | | 89% | 87% | | 91% |
| GWh billed | 40,253 | | 40,167 | 33,551 | | 35,859 |
| Average realized revenue per MWh | $60.35 | | $50.15 | |
| Average energy and capacity revenue per MWh | | $47.31 | | $50.29 |
| Refueling Outage Days: | | | | | | |
| FitzPatrick | 44 | | — | |
| Indian Point 2 | 24 | | — | 102 | | — |
| Indian Point 3 | — | | 28 | — | | 23 |
| Palisades | 56 | | — | — | | 32 |
| Pilgrim | — | | 45 | — | | 34 |
| Vermont Yankee | — | | 27 | |
| |
| (a) | The reduction in owned capacity is due to Entergy’s sale of its 50% membership interest in Top Deer Wind Ventures, LLC in November 2016. See Note 14 to the financial statements for discussion of the sale. |
Other Income Statement Items
Realized Revenue per MWhUtility
Other operation and maintenance expenses decreased from $2,443 million for 2015 to $2,360 million for 2016 primarily due to:
a decrease of $78 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;
the effects of recording in 2016 final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $19 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;
the deferral in 2016 of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC in February 2016 as part of the Entergy Arkansas 2015 rate case settlement. These costs are being
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement; and
a decrease of $13 million in energy efficiency costs, including the effects of true-ups to energy efficiency filings for fixed costs to be collected from customers and incentives recognized as a result of participation in energy efficiency programs.
The decrease was partially offset by an increase of $61 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor, and an overall higher scope of work done during plant outages in 2016 as compared to prior year.
The asset write-offs, impairments, and related charges variance is due to the following activity:
the $45 million ($28 million net-of-tax) write-off in 2015 to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery; and
the $23.5 million ($15.3 million net-of-tax) write-off in 2015 of the regulatory asset associated with the Spindletop gas storage facility as a result of the approval of the System Agreement termination settlement agreement.
See Note 2 to the financial statements for further discussion of the asset write-offs.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Union Power Station purchased in March 2016, partially offset by the effects of recording the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $11 million in 2016 of spent nuclear fuel storage costs previously recorded as depreciation. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Other expenses increased primarily due to an increase in nuclear refueling outage expenses as a result of amortization of higher costs associated with refueling outages and increases in decommissioning expenses in 2016 primarily due to revised decommissioning cost studies in 2015 for Grand Gulf and Waterford 3.
Entergy Wholesale Commodities
Other operation and maintenance expenses increased from $899 million for 2015 to $915 million for 2016 primarily due to:
an increase of $60 million in severance and retention costs related to the planned shutdown or sale of the Pilgrim and FitzPatrick plants. See “Entergy Wholesale Commodities Nuclear PlantsExit From the Merchant Power Business” below for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet;
$41 million associated with preparing to refuel FitzPatrick in January 2017. Exelon reimbursed Entergy for these costs in accordance with the reimbursement agreement discussed in “Entergy Wholesale Commodities Exit From the Merchant Power Business - Sale of FitzPatrick” below; and
an increase of $26 million in costs related to Pilgrim’s response to a planned NRC enhanced inspection as a result of the NRC placing Pilgrim in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix in September 2015. See Note 8 to the financial statements for further discussion of the NRC’s decision and Pilgrim’s response.
The increase was partially offset by:
the effects of sustained low natural gas pricesrecording the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $60 million in 2016 compared to the reimbursement of approximately $2 million in 2015 of spent nuclear fuel storage costs
Entergy Corporation and power market structure challenges have resultedSubsidiaries
Management’s Financial Discussion and Analysis
previously recorded as other operation and maintenance expenses. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;
a decrease of $32 million as a result of the sale of the Rhode Island State Energy Center in lower market pricesDecember 2015. See Note 14 to the financial statements for electricityfurther discussion of the Rhode Island State Energy Center sale; and
a decrease of $21 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the New Yorkdiscount rate used to value the benefit liabilities and New England power regions, whicha refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.
The asset write-offs, impairments, and related charges variance is where fourdue to $2,836 million ($1,829 million net-of-tax) in 2016 of impairment and related charges primarily to write down the carrying values of the five operatingEntergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values, partially offset by $2,036 million ($1,317 million net-of-tax) in 2015 of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of these charges.
Depreciation and amortization expenses decreased primarily due to:
decreases in depreciable asset balances as a result of the impairments of the FitzPatrick, Pilgrim, and Palisades plants. See Note 14 to the financial statements for further discussion of the impairments;
the effects of recording the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $15 million in 2016 compared to the reimbursement of approximately $4 million in 2015 of spent nuclear fuel storage costs previously recorded as depreciation. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
a decrease in depreciable asset balances as a result of the sale of the Rhode Island State Energy Center in December 2015. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale.
The gain on sale of asset resulted from the sale in December 2015 of the 583 MW Rhode Island State Energy Center in Johnston, Rhode Island, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment. Entergy sold the Rhode Island State Energy Center for approximately $490 million and realized a pre-tax gain of $154 million on the sale. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale.
Other expenses decreased primarily due to the reduction in deferred refueling outage amortization costs related to the impairments of the FitzPatrick, Pilgrim, and Palisades plants and related assets, partially offset by increases in decommissioning expenses primarily as a result of a trust transfer agreement Entergy entered into with NYPA in August 2016 to transfer the decommissioning trusts and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy and a revision to the estimated decommissioning cost liability for the Entergy Wholesale Commodities’ Pilgrim plant as a result of a revised decommissioning cost study in 2015. See Note 14 to the financial statements for further discussion of the impairments and related charges and Note 9 to the financial statements for further discussion of nuclear decommissioning costs.
Income Taxes
See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates, and for additional discussion regarding income taxes.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
The effective income tax rate for 2016 was 59.1%. The difference in the effective income tax rate versus the statutory rate of 35% for 2016 was primarily due to a change in the tax classification of a legal entity that owned one of the Entergy Wholesale Commodities nuclear power plants are located. A sixthand the reversal of a portion of the provision for uncertain tax positions as a result of the settlement of the 2010-2011 IRS audit, partially offset by state income taxes and certain book and tax differences related to utility plant Vermont Yankee, ceased operationsitems. See Note 3 to the financial statements for additional discussion of the change in the tax classification and the tax settlement.
The effective income tax rate for 2015 was 80.4%. The difference in the effective income tax rate versus the statutory rate of 35% for 2015 was primarily due to the tax effects of the Louisiana business combination. See Note 3 to the financial statements for further discussion of the tax effects of the Louisiana business combination.
Income Tax Legislation
On December 22, 2017, President Trump signed into law H.R. 1, also known as the Tax Cuts and Jobs Act (the Act). As a result of the Act, Entergy and the Registrant Subsidiaries re-measured their deferred tax assets and liabilities in December 2014. 2017 to reflect the reduction in the federal corporate income tax rate from 35% to 21% that is effective January 1, 2018. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses proceedings commenced or other responses by Entergy’s regulators to the Act.
On a going forward basis, after going through the appropriate regulatory processes Entergy expects the Act to reduce its operating cash flows because the lower federal corporate income tax rate will result in lower income tax expense collected in revenues and as excess deferred income taxes are returned to customers. In general, rate base is expected to increase over time as a consequence of the Act as the excess deferred income taxes are returned to customers. Entergy expects to finance its incremental cash requirements as a consequence of these changes through a combination of Registrant Subsidiary debt and Entergy Corporation debt and equity. Entergy Corporation expects the equity portion of this financing to be approximately $1 billion, and currently expects to issue all of this equity before the end of 2019. It is expected that certain credit metrics that incorporate operating cash flows or debt outstanding will be adversely affected by the effects of the Act.
The amount and timing of the earnings and cash effects of the Act and the financing of the incremental cash requirements will depend upon regulatory treatment of the effects of the Act. The Registrant Subsidiaries will work directly with their respective regulators to determine the appropriate path forward in each jurisdiction. Potential regulatory options that may be considered include:
determining the period over which certain income tax benefits are provided to customers;
accelerating depreciation or amortization for certain assets or asset classes; and
increasing or modifying capital investments.
Entergy Wholesale Commodities nuclear business experienced an annual realized price per MWhExit from the Merchant Power Business
Entergy management has undertaken a strategy to manage and reduce the risk of $60.35 in 2014, $50.15 in 2013, and $50.29 in 2012. The increase in realized price in 2014 is primarily attributable to a significant increase in first quarter 2014 prices due to cold winter weather and northeastern U.S. gas pipeline infrastructure limitations. Prior to 2009 the annual realized price per MWh for Entergy Wholesale Commodities generally increased each year, reaching a peak of $61.07 in 2009. As shown in the contracted sale of energy table in “Market and Credit Risk Sensitive Instruments,” Entergy Wholesale Commodities has sold forward 86% of its planned nuclear energy output for 2015 for an expected average contracted energy price of $48 per MWh based on market prices at December 31, 2014. In addition, Entergy Wholesale Commodities has sold forward 74% of its planned nuclear energy output for 2016 for an expected average contracted energy price of $49 per MWh based on market prices at December 31, 2014. The market price trend presents a challenging economic situation for the Entergy Wholesale Commodities plants. The challenge is greaterbusiness, which includes taking actions to reduce the size of the merchant fleet. Management evaluated the challenges for someeach of thesethe plants based on a variety of factors such as their market for both energy and capacity, their size, their contracted positions, and the amount of investment required to continue to operate and maintain the safety and integrity of the plants, including the estimated asset retirement costs. If,Management continues to look for ways to mitigate the operational and decommissioning risks associated with the merchant power business. Assumptions regarding the operating life of the plants and the decommissioning timeline and process continue to be evaluated. Changes to current assumptions could result in revisions to the asset retirement obligations and affect compliance with certain NRC minimum financial assurance requirements for meeting obligations to decommission the plants. Increases in the future, economic conditionsasset retirement obligations could result in an increase in operating expense in the period of a revision.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Assumptions regarding the possibility that a plant may have an operating life shorter than previously assumed will likely result in the need for additional contributions to decommissioning trust funds, or regulatory activity no longer support the continued operationposting of parent guarantees, letters of credit, or recoveryother surety mechanisms.
Entergy Wholesale Commodities includes the ownership of the costs of a plant it could adversely affect Entergy’s results of operations through loss of revenue, impairment charges, increased depreciation rates, transitional costs, or accelerated decommissioning costs.following nuclear reactors:
|
| | | | | | | | |
| | Location | | Market | | Capacity | | Planned Transaction |
| Vermont Yankee | | Vernon, VT | | ISO-NE | | 605 MW | | Plant in decommissioning phase, planned sale in 2018 |
| Pilgrim | | Plymouth, MA | | ISO-NE | | 688 MW | | Planned shutdown in 2019 |
| Indian Point 2 | | Buchanan, NY | | NYISO | | 1,028 MW | | Planned shutdown in 2020 |
| Indian Point 3 | | Buchanan, NY | | NYISO | | 1,041 MW | | Planned shutdown in 2021 |
| Palisades | | Covert, MI | | MISO | | 811 MW | | Planned shutdown in 2022 |
As discussed below, Entergy announced its plansold the FitzPatrick nuclear power plant to closeExelon in March 2017. Entergy Wholesale Commodities also includes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and decommission Vermont Yankee. This decision was approved byIndian Point 1 in New York that were acquired when Entergy purchased the BoardPalisades and Indian Point 2 nuclear plants, respectively. These facilities are in August 2013. The decision to shut down the plant was primarily due to sustained low natural gas and wholesale energy prices, the high cost structurevarious stages of the plant,decommissioning process. In addition, Entergy Wholesale Commodities provides operations and lack of a market structure that adequately compensates merchantmanagement services, including decommissioning services, to nuclear power plants for their environmental and fuel diversity benefitsowned by other utilities in the regionUnited States. A relatively minor portion of the Entergy Wholesale Commodities business is the ownership of interests in whichnon-nuclear power plants that sell the plant operated. electric power produced by those plants to wholesale customers.
Shutdown and Planned Sale of Vermont Yankee
On December 29, 2014, the Vermont Yankee plant ceased power production. See Note 1production and entered its decommissioning phase.In November 2016, Entergy entered into an agreement to sell 100% of the membership interests in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant and is in the Entergy Wholesale Commodities segment. The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of the nuclear decommissioning trust fund and the asset retirement obligation for the spent fuel management and decommissioning of the plant.
Entergy Nuclear Vermont Yankee has an outstanding credit facility with borrowing capacity of $145 million to pay for dry fuel storage costs. This credit facility is guaranteed by Entergy Corporation. At or before closing, a subsidiary of Entergy will assume the obligations under the existing credit facility or enter into a new credit facility, and Entergy will guarantee the credit facility. At the closing of the sale transaction, NorthStar will pay $1,000 for the membership interests in Entergy Nuclear Vermont Yankee, and NorthStar will cause Entergy Nuclear Vermont Yankee to issue a promissory note to an Entergy affiliate. The amount of the promissory note issued will be equal to the financial statements for discussionamount drawn under the credit facility or the amount drawn under the new credit facility, plus borrowing fees and costs incurred by Entergy in connection with such facility. The principal amount drawn under the outstanding credit facility was $104 million as of impairmentDecember 31, 2017, and the net book value of long-lived assets.Entergy Nuclear Vermont Yankee, including unrealized gains on the decommissioning trust fund, as of December 31, 2017, was approximately $123 million.
ImpairmentEntergy plans to transfer all spent nuclear fuel to dry cask storage by the end of long-lived assets2018 in advance of the planned transaction close. Under the sale agreement and related agreements to be entered into at the closing, NorthStar will commit to initiate decommissioning and site restoration by 2021 and complete those activities by 2030. The original planned completion date, as outlined in Entergy’s Post Shutdown Decommissioning Activities Report filed with the NRC, was 2075. Entergy Nuclear Vermont Yankee, under NorthStar ownership, will be required to repay the promissory note issued to Entergy with certain of the proceeds from the recovery of damages under its claims against the DOE related to spent nuclear decommissioning costs, and the factors that influence these items, are both discussed below in “Critical Accounting Estimates.” See also the discussion below in “Entergy Wholesalefuel disposal, with any balance remaining due at partial site release, subject to extension not to exceed two years from partial site release.
Entergy Corporation and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
Commodities AuthorizationsThe transaction is subject to Operate Itscertain closing conditions, including approval by the NRC; approval by the State of Vermont Public Utility Commission, including approval of site restoration standards that have been proposed as part of the transaction; the transfer of all spent nuclear fuel to dry fuel storage on the independent spent fuel storage installation; and that the market value of the fund assets held in the decommissioning trust fund for the Vermont Yankee Nuclear Power Plants” regardingStation, less the hypothetical income tax on the aggregate unrealized net gain of such fund assets at closing, is equal to or exceeds $451.95 million, subject to adjustments. Entergy has the option to contribute to the decommissioning trust fund if the value is less than $451.95 million, subject to adjustments. The transaction is planned to close by the end of 2018.
Sale of Rhode Island State Energy Center
In December 2015, Entergy sold the Rhode Island State Energy Center, a 583 MW natural gas-fired combined-cycle generating plant owned by Entergy in the Entergy Wholesale Commodities nuclear plant operating licensesegment. Entergy sold the Rhode Island State Energy Center for approximately $490 million and related activity.realized a pre-tax gain of $154 million on the sale.
Other Income Statement ItemsSale of Top Deer Investment
UtilityIn November 2016, Entergy sold its 50% membership interest in Top Deer Wind Ventures, LLC, a wind-powered electric generation joint venture owned by Entergy in the Entergy Wholesale Commodities segment and accounted for as an equity method investment. Entergy sold its 50% membership interest in Top Deer for approximately $0.5 million and realized a pre-tax loss of $0.2 million on the sale.
Other operation and maintenance expenses increased from $2,264 million for 2013 to $2,276 million for 2014 primarily due to:Sale of FitzPatrick
an increaseIn October 2015, Entergy determined that it would close the FitzPatrick plant. The original expectation was to shut down the FitzPatrick plant at the end of $53 millionits fuel cycle in nuclear generation expenses primarily due to higher material costs, higher contract labor costs, and higher NRC fees;
an increase of $38 million in administration fees related to participation in the MISO RTO beginning December 2013. The net income effect is partially offset due to deferrals of these fees in certain jurisdictions.January 2017. See Note 214 to the financial statements for further information on the deferrals;
an increase of $29 million in energy efficiency costs. These costs are recovered through energy efficiency riders and have a minimal effect on net income;
an increase of $24 million in storm damage accruals primarily at Entergy Arkansas effective January 2014, as approved by the APSC, and at Entergy Mississippi effective October 2013, as approved by the MPSC;
an increase of $20 million in regulatory, consulting, and legal fees;
an increase of $19 million in contract labor primarily due to higher infrastructure and application services and call center outsourcing;
an increase of $11 million primarily due to higher vegetation maintenance;
an increase of $7 million due to higher write-offs of uncollectible customer accounts in 2014 as compared to 2013;
an increase of $7 million due to the amortization in 2014 of costs deferred in 2013 related to the transition and implementation of joining the MISO RTO; and
several individually insignificant items.
The increase was partially offset by:
a decrease of $146 million in compensation and benefits costs primarily due to fewer employees, an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
a decrease of $36 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business;
a decrease of $9 million resulting from costs incurred in 2013 related to the generator stator incident at ANO, including an offset for insurance proceeds. See “ANO Damage, Outage, and NRC Reviews” below for further discussion of the incident;
a net decrease of $8 million related to the human capital management strategic imperative in 2014 as compared to the same period in 2013 including a decrease of $60 million in implementation costs, severance costs, and curtailment and special termination benefits, the deferral in 2013 of $44 million of costs incurred, as approved by the APSC and LPSC, and partial amortization in 2014 of $8 million of costs that were deferred in 2013. See “Human Capital Management Strategic Imperative” below for further discussion; and
a net decrease of $4 million related to Baxter Wilson (Unit 1) repairs. The increase in repair costs incurred in 2014 compared to the prior year were offset by expected insurance proceeds and the deferral of repair costs, as approved by the MPSC. See “Baxter Wilson Plant Event” in Note 8 to the financial statements for further discussion.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
The asset write-off, impairment and related charges variance is due to the $56.2 million ($36.7 million after-tax) write-off in 2014 of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs and a $16 million ($10.5 million after-tax) write-off recorded in 2014 because of the uncertainty associated with the resolutiondecision to cease operations earlier than expected.
In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy. When Entergy purchased Indian Point 3 and FitzPatrick in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specified their decommissioning obligations. NYPA had the right to require the Entergy subsidiaries to assume each of the Waterford 3 replacement steam generator project prudence review. See Note 2decommissioning liabilities provided that it assigned the corresponding decommissioning trust, up to a specified level, to the financial statements for further discussionEntergy subsidiaries. Under the original agreements, if the decommissioning liabilities were retained by NYPA, the Entergy subsidiaries would perform the decommissioning of new nuclear generation development costs and the prudence review.
Interest expense increased primarily dueplants at a price equal to the lease renewallesser of a pre-specified level or the amount in December 2013the decommissioning trust funds. At the time of the Grand Gulf sale leaseback and net debt issuancesacquisition of first mortgage bondsthe plants Entergy recorded a contract asset that represented an estimate of the present value of the difference between the stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies. The asset was increased by monthly accretion based on the first quarter 2014 and the second quarter 2013 by certain Utility operating companies. See Note 5applicable discount rate necessary to the financial statementsultimately provide for more details of long-term debt. The increase was partially offset by an increase in the allowance for borrowed funds used during construction due to a higher construction work in progress balance in 2014, including the Ninemile Unit 6 self-build project.
Other expenses increased primarily due to increases in decommissioning expenses resulting from revisions to the estimated future value of the decommissioning cost liabilitiescontract. The monthly accretion was recorded as interest income. As a result of revised decommissioning cost studiesthe agreement with NYPA, in the fourththird quarter 20132016, Entergy removed the contract asset from its balance sheet, and recorded receivables for the first quarter 2014, partially offsetbeneficial interests in the decommissioning trust funds and asset retirement obligations for the decommissioning liabilities. The asset retirement obligations are accreted monthly through a charge to decommissioning expense. The decommissioning trust funds for the Indian Point 3 and FitzPatrick plants were transferred to Entergy by a decreaseNYPA in nuclear refueling outage costs that are being amortized over the estimated period to the next outage.January 2017. See Note 9 to the financial statements for further discussion of theIndian Point 3 and FitzPatrick’s decommissioning cost revisions.
Entergy Wholesale Commodities
Other operationliabilities and maintenance expenses decreased from $1,048 million for 2013 to $1,023 million for 2014 primarily due to:
a decrease of $63 million in compensation and benefits costs primarily due to fewer employees, an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below andsee Note 1116 to the financial statements for further discussion of benefits costs;the receivables for the beneficial interests in Indian Point 3 and FitzPatrick’s decommissioning trust funds as of December 31, 2016.
In August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon. NRC approval of the sale was received in March 2017. The transaction closed in March 2017 for a purchase price of $110 million, which
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
included a decrease of $15$10 million duenon-refundable signing fee paid in August 2016, in addition to the absenceassumption by Exelon of expenses from Entergy Solutions District Energy, which was sold in November 2013; and
a decrease of $13 million in implementation costs, severance costs, and curtailment and special termination benefitscertain liabilities related to the human capital management strategic imperativeFitzPatrick plant, resulting in 2014 as compareda pre-tax gain on the sale of $16 million. At the transaction close, Exelon paid an additional $8 million for the proration of certain expenses prepaid by Entergy. See Note 14 to the same period in 2013. See “Human Capital Management Strategic Imperative” belowfinancial statements for further discussion.discussion of the sale of FitzPatrick. As discussed in Note 3 to the financial statements, as a result of the sale of FitzPatrick, Entergy re-determined the plant’s tax basis, resulting in a $44 million income tax benefit in the first quarter 2017
.
The decrease was partially offset by:Planned Shutdown of Pilgrim
an increaseIn October 2015, Entergy determined that it would close the Pilgrim plant. The decision came after management’s extensive analysis of $22 million incurredthe economics and operating life of the plant following the NRC’s decision in 2014 as comparedSeptember 2015 to 2013 relatedplace the plant in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix. The Pilgrim plant is expected to cease operations on May 31, 2019, at the shutdownend of Vermont Yankee including severance and retention costs.its current fuel cycle. See “Impairment of Long-Lived Assets” in Note 114 to the financial statements for discussion regarding the shutdown of the Vermont Yankee plantimpairment charges associated with the decision to cease operations earlier than expected and see Note 8 for further discussion on the placement of Pilgrim in December 2014;
an increase of $18 million primarily due to higher contract costs and higher NRC fees; and
$18 million in transmission imbalance sales in 2013.Column 4.
Planned Shutdown of Indian Point 2 and Indian Point 3
Indian Point 2 and Indian Point 3 have been involved, and have faced opposition, in extensive licensing proceedings. In January 2017, Entergy announced that it reached a settlement with New York State to shut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021. See further discussion of the licensing proceedings and the settlement reached with New York State in “Entergy Wholesale Commodities Authorizations to Operate Indian Point”below.
As discussed above, in August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust fund and decommissioning liability for the Indian Point 3 plant to Entergy. The asset write-off, impairments,decommissioning trust fund for the Indian Point 3 plant was transferred to Entergy by NYPA in January 2017.
See Note 14 to the financial statements for further discussion of the impairment charges associated with management’s evaluation of alternatives to the continued operation of the Indian Point plants.
Planned Shutdown of Palisades
Most of the Palisades output is sold under a power purchase agreement (PPA) with Consumers Energy, entered into when the plant was acquired in 2007, that is scheduled to expire in 2022. The PPA prices currently exceed market prices and escalate each year, up to $61.50/MWh in 2022. In December 2016, Entergy reached an agreement with Consumers Energy to amend the existing PPA to terminate early, on May 31, 2018. Pursuant to the agreement to amend the PPA, Consumers Energy would pay Entergy $172 million for the early termination of the PPA. The PPA amendment agreement was subject to regulatory approvals, including approval by the Michigan Public Service Commission. Separately, Entergy intended to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle.
In September 2017 the Michigan Public Service Commission issued an order conditionally approving the PPA amendment transaction, but only granting Consumers Energy recovery of $136.6 million of the $172 million requested early termination payment. As a result, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy will continue to operate Palisades under the current PPA with Consumers Energy, instead of shutting down in the fall of 2018 as previously planned. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022. As a result of the change in expected operating life of the plant, the expected probability-weighted undiscounted net cash flows as of September 30, 2017 exceeded the carrying value of the plant and related assets. Accordingly, nuclear fuel spending, nuclear refueling outage spending, and expenditures for capital assets incurred at Palisades after September 30, 2017 are no longer charged to expense as incurred, but recorded as
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
assets and depreciated or amortized, subject to the typical periodic impairment reviews prescribed in the accounting rules. See Note 9 to the financial statements for discussion of the associated asset retirement obligation revision. See Note 14 to the financial statements for discussion of the updated calculation of the liability amortization associated with the PPA and discussion of the impairment charges variance isassociated with the decision to cease operations earlier than expected.
Costs Associated with Entergy Wholesale Commodities Strategic Transactions
Entergy incurred approximately $113 million in costs in 2017 and $95 million in costs in 2016 associated with management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet, primarily employee retention and severance expenses and other benefits-related costs, and contracted economic development contributions. Entergy expects to incur employee retention and severance expenses of approximately $165 million in 2018, and approximately $205 million from 2019 through mid-2022 associated with these strategic transactions. See Note 13 to the financial statements for further discussion of these costs.
In 2017, Entergy Wholesale Commodities incurred impairment charges related to nuclear fuel spending, nuclear refueling outage spending, and expenditures for capital assets of $0.5 billion. These costs were charged to expense as incurred as a result of the impaired value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to $321.5 million ($202.2 million after-tax) in 2013the significantly reduced remaining estimated operating lives associated with management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet. Entergy expects to continue to incur costs associated with nuclear fuel-related spending and expenditures for capital assets and, except for Palisades, expects to continue to charge these costs to expense as incurred because Entergy expects the value of the plants to continue to be impaired.In 2016, Entergy Wholesale Commodities incurred impairment and other related charges of $2.8 billion primarily to write down the carrying valuevalues of Vermont Yankeethe Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values and $107.5 million ($69.8 million after-tax) in 2014 of impairment charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completed in the third quarter 2014.values. See Note 114 to the financial statements for further discussion of these impairment charges.
Depreciation and amortization expenses increased primarily due to a change effective in 2014 in the estimated average useful lives of plant in service as a result of a new depreciation study and an increase to depreciable plant balances.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
The gain on sale of business resulted from the sale in November 2013 of Entergy Solutions District Energy, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment that owned and operated district energy assets servicing the business districts in Houston and New Orleans. Entergy sold Entergy Solutions District Energy for $140 million and realized a pre-tax gain of $44 million on the sale.
Other income decreased primarily due to lower realized gains on nuclear decommissioning trust fund investments.
Other expenses increased primarily due to an increase in nuclear refueling outage costs that are being amortized over the estimated period to the next outage and an increase in decommissioning expenses primarily due to revisions to the estimated decommissioning cost liability for Vermont Yankee recorded in the third and fourth quarters of 2013. See “Critical Accounting Estimates - Nuclear Decommissioning Costs” below for further discussion of nuclear decommissioning costs.
Parent & Other
Other income decreased primarily due to the elimination of intersegment activity.
Income Taxes
See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates, and for additional discussion regarding income taxes.
The effective income tax rate for 2014 was 38%. The difference in the effective income tax rate versus the statutory rate of 35% for 2014 was primarily due to state income taxes, certain book and tax differences related to utility plant items, and the provision for uncertain tax positions, partially offset by a deferred state income tax reduction related to a New York tax law change and book and tax differences related to the allowance for equity funds used during construction.
The effective income tax rate for 2013 was 23.6%. The difference in the effective income tax rate versus the statutory rate of 35% for 2013 was primarily related to (1) IRS settlements as discussed further in Note 3 to the financial statements; and (2) a tax benefit associated with the now-terminated plan to spin off and merge the Utility’s transmission business, because certain associated costs became deductible with the termination of the transaction.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
2013 Compared to 2012
Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2013 to 2012 showing how much the line item increased or (decreased) in comparison to the prior period.
|
| | | | | | | | | | | | | | | |
| | Utility | | Entergy Wholesale Commodities | | Parent & Other | | Entergy |
| | (In Thousands) |
| 2012 Consolidated Net Income (Loss) |
| $960,322 |
| |
| $40,427 |
| |
| ($132,386 | ) | |
| $868,363 |
|
| | | | | | | | |
Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits) | 555,233 |
| | (51,509 | ) | | 7,136 |
| | 510,860 |
|
| Other operation and maintenance | 184,374 |
| | 90,222 |
| | 11,946 |
| | 286,542 |
|
| Asset write-off, impairments, and related charges | 9,411 |
| | (26,188 | ) | | 2,790 |
| | (13,987 | ) |
| Taxes other than income taxes | 37,547 |
| | 5,380 |
| | 125 |
| | 43,052 |
|
| Depreciation and amortization | 76,850 |
| | 39,824 |
| | (215 | ) | | 116,459 |
|
| Gain on sale of business | — |
| | 43,569 |
| | — |
| | 43,569 |
|
| Other income | 6,378 |
| | 29,624 |
| | 2,268 |
| | 38,270 |
|
| Interest expense | 32,688 |
| | (1,577 | ) | | 3,642 |
| | 34,753 |
|
| Other expenses | 18,271 |
| | 50,274 |
| | — |
| | 68,545 |
|
| Income taxes | 316,577 |
| | (138,800 | ) | | 17,349 |
| | 195,126 |
|
| 2013 Consolidated Net Income (Loss) |
| $846,215 |
| |
| $42,976 |
| |
| ($158,619 | ) | |
| $730,572 |
|
Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES” which accompanies Entergy Corporation’s financial statements in this report for further information with respect to operating statistics.
As discussed in more detail in Note 1 to the financial statements, results of operations include $322 million ($202 million after-tax) in 2013 and $356 million ($224 million after-tax) in 2012 of impairment and other related charges to write down the carrying value of Vermont Yankee and related assets to their fair values. Also, net income for Utility in 2012 was significantly affected by a settlement with the IRS related to the income tax treatment of the Louisiana Act 55 financing of the Hurricane Katrina and Hurricane Rita storm costs, which resulted in a reduction in income tax expense. The net income effect was partially offset by a regulatory charge, which reduced net revenue in 2012, associated with the storm costs settlement to reflect the obligation to customers with respect to the settlement. See Note 3 to the financial statements for additional discussion of the tax settlement.
Also, earnings were negatively affected in 2013 by expenses, including other operation and maintenance expenses and taxes other than income taxes, of approximately $110 million ($70 million after-tax), including approximately $85 million ($55 million after-tax) for Utility and $25 million ($15 million after-tax) for Entergy Wholesale Commodities, recorded in connection with a strategic imperative intended to optimize the organization through a process known as human capital management. In December 2013, Entergy deferred for future collection approximately $45 million ($30 million after-tax) of these costs in the Arkansas and Louisiana jurisdictions at the Utility, as approved by the APSC and the LPSC, respectively. See “Human Capital Management Strategic Imperative” below for further discussion.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Net Revenue
Utility
Following is an analysis of the change in net revenue comparing 2013 to 2012.
|
| | | |
| Amount |
| (In Millions) |
| |
2012 net revenue |
| $4,969 |
|
Retail electric price | 236 |
|
Louisiana Act 55 financing savings obligation | 165 |
|
Grand Gulf recovery | 75 |
|
Volume/weather | 40 |
|
Fuel recovery | 35 |
|
MISO deferral | 12 |
|
Asset retirement obligation | (23 | ) |
Other | 15 |
|
2013 net revenue |
| $5,524 |
|
The retail electric price variance is primarily due to:
a formula rate plan increase at Entergy Louisiana, effective January 2013, which includes an increase relating to the Waterford 3 steam generator replacement project, which was placed in service in December 2012. The net income effect of the formula rate plan increase is limited to a portion representing an allowed return on equity with the remainder offset by costs included in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes;
the recovery of Hinds plant costs through the power management rider at Entergy Mississippi, as approved by the MPSC, effective with the first billing cycle of 2013. The net income effect of the Hinds plant cost recovery is limited to a portion representing an allowed return on equity on the net plant investment with the remainder offset by the Hinds plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes;
an increase in the capacity acquisition rider at Entergy Arkansas, as approved by the APSC, effective with the first billing cycle of December 2012, relating to the Hot Spring plant acquisition. The net income effect of the Hot Spring plant cost recovery is limited to a portion representing an allowed return on equity on the net plant investment with the remainder offset by the Hot Spring plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes;
increases in the energy efficiency rider, as approved by the APSC, effective July 2013 and July 2012. Energy efficiency revenues are offset by costs included in other operation and maintenance expenses and have minimal effect on net income;
an annual base rate increase at Entergy Texas, effective July 2012, as a result of the PUCT’s order that was issued in September 2012 in the November 2011 rate case; and
a formula rate plan increase at Entergy Mississippi, effective September 2013.
See Note 2 to the financial statements for a discussion of rate proceedings.
The Louisiana Act 55 financing savings obligation variance results from a regulatory charge recorded in the second quarter 2012 because Entergy Gulf States Louisiana and Entergy Louisiana were required to share with customers the savings from the tax treatment related to the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing. See Note 3 to the financial statements for additional discussion of the tax treatment.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
The Grand Gulf recovery variance is primarily due to increased recovery of higher costs resulting from the Grand Gulf uprate.
The volume/weather variance is primarily due to the effects of more favorable weather on residential sales and an increase in industrial sales primarily due to growth in the refining segment.
The fuel recovery variance is primarily due to:
the deferral of increased capacity costs that will be recovered through fuel adjustment clauses;
the expiration of the Evangeline gas contract on January 1, 2013; and
an adjustment to deferred fuel costs recorded in the third quarter 2012 in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of this PUCT order issued in Entergy Texas’s 2011 rate case.
The MISO deferral variance is primarily due to the deferral in April 2013, as approved by the APSC, of costs incurred from March 2010 through December 2012 related to the transition and implementation of joining the MISO RTO.
The asset retirement obligation affects net revenue because Entergy records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The variance is primarily caused by a decrease in regulatory credits resulting from higher realized income on decommissioning trust fund investments.
Entergy Wholesale Commodities
Following is an analysis of the change in net revenue comparing 2013 to 2012.
|
| | | |
| Amount |
| (In Millions) |
| |
2012 net revenue |
| $1,854 |
|
Mark-to-market | (58 | ) |
Nuclear volume | (24 | ) |
Nuclear fuel expenses | (20 | ) |
Nuclear realized price changes | 58 |
|
Other | (8 | ) |
2013 net revenue |
| $1,802 |
|
As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by approximately $52 million in 2013 primarily due to:
the effect of rising forward power prices on electricity derivative instruments that are not designated as hedges, including additional financial power sales conducted in the fourth quarter 2013 to offset the planned exercise of in-the-money protective call options and to lock in margins. These additional sales did not qualify for hedge accounting treatment, and increases in forward prices after those sales were made accounted for the majority of the negative mark-to-market variance. The underlying transactions resulted in earnings in first quarter 2014 as these positions settled. See Note 16 to the financial statements for discussion of derivative instruments;
the decrease in net revenue compared to prior year resulting from the exercise of resupply options provided for in purchase power agreements where Entergy Wholesale Commodities may elect to supply power from another source when the plant is not running. Amounts related to the exercise of resupply options are included in the GWh billed in the table below; and
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
higher nuclear fuel expenses primarily resulting from the effect of the write-down in March 2012 of the carrying value of Vermont Yankee’s nuclear fuel, which resulted in a lower level of nuclear fuel amortization in 2012, and the subsequent purchase of additional nuclear fuel in early-2013.
These decreases were partially offset by higher capacity prices.
Following are key performance measures for Entergy Wholesale Commodities for 2013 and 2012.
|
| | | |
| | 2013 | | 2012 |
| Owned capacity (MW) (a) | 6,068 | | 6,612 |
| GWh billed | 45,127 | | 46,178 |
| Average realized price per MWh | $50.86 | | $50.02 |
| | | | |
| Entergy Wholesale Commodities Nuclear Fleet | | | |
| Capacity factor | 89% | | 89% |
| GWh billed | 40,167 | | 41,042 |
| Average realized revenue per MWh | $50.15 | | $50.29 |
| Refueling Outage Days: | | | |
| FitzPatrick | — | | 34 |
| Indian Point 2 | — | | 28 |
| Indian Point 3 | 28 | | — |
| Palisades | — | | 34 |
| Pilgrim | 45 | | — |
| Vermont Yankee | 27 | | — |
| |
(a) | The reduction in owned capacity is due to the retirement of the 544 MW Ritchie Unit 2 in November 2013. |
Other Income Statement Items
Utility
Other operation and maintenance expenses increased from $2,080 million for 2012 to $2,264 million for 2013 primarily due to:
an increase of $83 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
an increase of $46 million in fossil-fueled generation expenses primarily due to the acquisitions of the Hot Spring plant by Entergy Arkansas and the Hinds plant by Entergy Mississippi in November 2012. Costs related to the Hot Spring and Hinds plants are recovered through the capacity acquisition rider and power management rider, respectively, as previously discussed. Also contributing to the increases is an overall higher scope of work done during plant outages as compared to the prior year;
an increase of $72 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative, partially offset by the deferral of approximately $44 million of these costs. See the “Human Capital Management Strategic Imperative” below for further discussion;
an increase of $16 million in energy efficiency costs at Entergy Arkansas. These costs are recovered through an energy efficiency rider and have minimal effect on net income;
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
an increase of $13 million in nuclear expenses, primarily due to higher labor costs, including higher contract labor;
the deferral in 2012, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced 2012 expenses by $10 million; and
an increase of $9 million resulting from costs related to the generator stator incident at ANO, including an offset for expected insurance proceeds. See “ANO Damage, Outage, and NRC Reviews” below for further discussion of the incident.
Also, other operation and maintenance expenses include $36 million in 2013 and $38 million in 2012 of costs incurred related to the now-terminated plan to spin off and merge the Utility’s transmission business.
Taxes other than income taxes increased primarily due to an increase in ad valorem taxes, primarily due to the Hot Spring and Hinds plant acquisitions in 2012, as well as an increase in local franchise taxes resulting from higher residential and commercial revenues as compared with prior year.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Hot Spring and Hinds plant acquisitions in 2012 and the completion of the Waterford 3 steam generator replacement project and the Grand Gulf uprate project in 2012. Also contributing to the increase is an increase in depreciation rates as a result of the 2011 rate case order issued by the PUCT in September 2012.
Interest expense increased primarily due to net debt issuances in 2013 of $520 million by the Utility operating companies and System Energy and lower allowance for borrowed funds used during construction due to the completion of several major projects in 2012.
Entergy Wholesale Commodities
Other operation and maintenance expenses increased from $958 million for 2012 to $1,048 million for 2013 primarily due to:
an increase of $43 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
an increase of $23 million primarily due to the effect of the final court decisions in the Vermont Yankee and Indian Point 2 lawsuits against the U.S. Department of Energy related to spent nuclear fuel disposal recorded in 2012. The damages awarded included the reimbursement of approximately $25 million of spent nuclear fuel storage costs previously recorded as operation and maintenance expenses;
an increase of $16 million resulting from implementation and severance costs in 2013 related to the human capital management strategic imperative. See “Human Capital Management Strategic Imperative” below for further discussion; and
approximately $15 million in commitments recorded in connection with the settlement agreement with parties in Vermont regarding the operation and decommissioning of Vermont Yankee. See “Impairment of Long-Lived Assets” in Note 1 to the financial statements for further discussion of the settlement agreement.
The asset impairment variance is primarily due to $321.5 million ($202.2 million after-tax) in 2013 and $355.5 million ($223.5 million after-tax) in 2012 of impairment and other related charges primarily to write down the carrying value of Vermont Yankee and related assets to their fair values. See Note 1 to the financial statements for further discussion of these charges.
Depreciation and amortization expenses increased primarily due to an adjustment in 2012 resulting from final court decisions in the Indian Point 2 and Vermont Yankee lawsuits against the U.S. Department of Energy related to
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
spent nuclear fuel disposal. The effects of recording the proceeds from the judgment reduced the plant in service balances and included a $25 million reduction to previously-recorded depreciation expense.
The gain on sale of business resulted from the sale in November 2013 of Entergy Solutions District Energy, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment that owned and operated district energy assets serving the business districts in Houston and New Orleans. Entergy sold Entergy Solutions District Energy for $140 million and realized a pre-tax gain of $44 million on the sale.
Other income increased primarily due to realized decommissioning trust gains that resulted from portfolio reallocations for the Indian Point 2 and Palisades decommissioning trust funds.
Other expenses increased primarily due to a credit to decommissioning expense of $49 million in the second quarter 2012 resulting from a reduction in the decommissioning cost liability for a plant as a result of a revised decommissioning cost study. See “Critical Accounting Estimates - Nuclear Decommissioning Costs” for further discussion of nuclear decommissioning costs.
Parent & Other
Other operation and maintenance expenses increased primarily due to the elimination of intersegment activity.
Income Taxes
See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates, and for additional discussion regarding income taxes.
The effective income tax rate for 2013 was 23.6%. The difference in the effective income tax rate versus the statutory rate of 35% for 2013 was primarily related to (1) IRS settlements as discussed further in Note 3 to the financial statements; and (2) a tax benefit associated with the now-terminated plan to spin off and merge the Utility’s transmission business, because certain associated costs became deductible with the termination of the transaction.
The effective income tax rate for 2012 was 3.4%. The difference in the effective income tax rate versus the statutory rate of 35% for 2012 was primarily related to (1) IRS settlements as discussed further in Note 3 to the financial statements; and (2) a unanimous court decision from the U.S. Court of Appeals for the Fifth Circuit affirming an earlier decision of the U.S. Tax Court holding that Entergy was entitled to claim a credit against its U.S. tax liability for the U.K. windfall tax that it paid. The decision necessitated that Entergy reverse the provision for the uncertain tax position related to that item.
Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power PlantsIndian Point
The NRC operating license for Palisades expires in 2031, for Pilgrim expires in 2032, and for FitzPatrick expires in 2034. For additional discussion regarding the shutdown of the Vermont Yankee plant in December 2014, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.
In April 2007, Entergy submitted to the NRC a joint application to renew the operating licenses for Indian Point 2 and Indian Point 3 for an additional 20 years. The original expiration datedates of the NRC operating licenselicenses for Indian Point 2 wasand Indian Point 3 were in September 2013 and the original expiration date ofDecember 2015, respectively. While the NRC operatingstaff reviews the license for Indian Point 3 is in December 2015. Authorization to operaterenewal applications, Indian Point 2 rests, and for Indian Point 3 will rest, on Entergy’s having timely filed a license renewal application that remains pending before the NRC. Indian Point 2 has now entered its “period of extended operation” after expiration of the plant’s3’s initial license termterms have expired and the plants are operating under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed with the licensing agency. Indian Point 3 is expected to reach the same milestone,
In January 2017, Entergy reached a settlement with New York State, several State agencies, and to become subject to the same statutorily prescribed extension of its license expiration date, in December 2015. The license
Entergy Corporation and Subsidiaries
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renewal application forRiverkeeper, Inc., under which Indian Point 2 and Indian Point 3 qualifieswill cease commercial operation by April 30, 2020 and April 30, 2021, respectively, subject to certain conditions, including New York State’s withdrawal of opposition to Indian Point’s license renewals and issuance of contested permits and similar authorizations. See Note 14 to the financial statements for timely renewal protection because it met NRC regulatory standards for timely filing.a discussion of the impairment and related charges associated with the settlement with New York State.
The scope of NRCIndian Point settlement required New York State agencies to issue environmental certifications needed for license renewal applications is focused primarily on whether the licensee has in place aging management programs (detailed diagnostic analyses performed when and as prescribed) to ensure that passive systems, structures, and components (such as pipes and concrete and metal structures) can continue to perform their intended safety functions. Other aspects of nuclear plant operations (maintenance of active components like pumps and control systems, security, and emergency preparedness) are regulated by the NRC on an ongoing basis and, as such, are outside the scope of license renewal proceedings. The NRC also determines whether there are any environmental impacts that would affect license renewal.
Every application for renewal of a reactor operating license undergoes comprehensive NRC staff review to ensure the adequacy of the application and the aging management programs detailed in it. NRC staff’s conclusions following such review are set forth in a Final Safety Evaluation Report (FSER). Issuance of a renewed operating license is a “major federal action” underwater discharge permit based on current plant configuration. It also required the National Environmental Policy Act, so NRC staff also are requiredNew York State Attorney General and Riverkeeper to prepare an Environmental Impact Statement (EIS) regardingwithdraw their contentions pending before the proposed licensing action. The NRC has electedAtomic Safety and Licensing Board (ASLB). In exchange, Entergy commits to address certain EIS issues on a generic basis via the rulemaking process. As a result, the EIS for a particular license renewal proceeding has two components: the Generic Environmental Impact Statement and a Final Supplemental Environmental Impact Statement (FSEIS) addressing site-specific EIS issues. Both the FSER and the FSEIS are subject to updating by NRC staff in an individual license renewal proceeding.
Where, as in the casecease commercial operation of Indian Point one or more intervenors proposes for admission contentions alleging errors and omissions in the applicant’s license renewal application or the NRC staff’s review of related safety and environmental issues, the NRC appoints an ASLB to determine whether the contentions satisfy threshold standards and, if so, to adjudicate such “admitted” contentions. Safety-related contentions address issues that will be or have been described in the FSER; environmental-related contentions address issues that will be or have been described in the FSEIS. Contentions may be proposed at any time before license issuance based on new and material information, subject to timeliness and admissibility standards. Final ASLB orders on admissibility or resolving contentions, whether after hearing or on summary disposition, are appealable to the NRC.
Various governmental and private intervenors have sought and obtained party status to express opposition to renewal of the Indian Point 2 by April 30, 2020 and Indian Point 3 licenses. The ASLB has admitted 16 consolidated contentions based on 21 contentions originally proposed by the State ofApril 30, 2021. These actions have been completed, all New York or other parties.
Four of the 16 admitted contentions have been resolved by the ASLB without hearing, two by means of ASLB-approved settlements, a third by summary disposition as described below, and a fourth by motion to dismiss as moot as described in the second paragraph below. In July 2011 the ASLB granted the State of New York’s motion for summary disposition of an admitted contention challenging the adequacy of a section of Indian Point’s environmental analysis as incorporated in the Final Supplemental Environmental Impact Statement (FSEIS) (discussed below). That section provided cost estimates for Severe Accident Mitigation Alternatives (SAMAs), which are hardware and procedural changes that could be implemented to mitigate estimated impacts of off-site radiological releases in case of a hypothesized severe accident. In addition to finding that the SAMA cost analysis was insufficient, the ASLB directed the NRC staff to explain why cost-beneficial SAMAs should not beapprovals required to be implemented. Entergy appealed the ASLB’s decision to the NRC and the NRC staff supported Entergy’s appeal, while the State of New York opposed it. In December 2011 the NRC denied Entergy’s appeal as premature. Entergy renewed its appeal in February 2014 in conjunction with the filing of Track 1 appeals, as discussed further below. In May 2013, Entergy filed an updated SAMA cost analysis with the NRC, and in July 2013 the ASLB granted Entergy’s motion for clarification that a future NRC staff filing would be the trigger for potential new or amended contentions on the SAMA update.
Nine of the remaining admitted contentions were designated by the ASLB as “Track 1” and were subject to hearings over 12 days in October, November, and December 2012. In November 2013 the ASLB issued a decision on the nine Track 1 contentions. The ASLB resolved eight Track 1 contentions favorably to Entergy. No appeal was
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
taken from the ASLB's decision on six of those eight contentions, so they have been conclusively resolved in Entergy's favor. The ASLB resolved one Track 1 contention favorably to New York State. That contention was based on a dispute over the characterization of certain electrical equipment as “active” or “passive.” The ASLB found in favor of the State of New York despite precedent supporting the characterization advocated by Entergy and NRC staff.
Following the ASLB's November 2013 decision on Track 1 contentions, the State of New York and Clearwater each appealed the decision on a single contention (SAMA decontamination cost estimates for the State of New York and environmental justice for Clearwater), while Riverkeeper filed no appeals. Entergy and NRC staff both appealed the same three issues: (1) the ASLB’s decision on electrical transformers; (2) certain intermediate determinations in the ASLB’s overall favorable decision on environmental justice; and (3) the ASLB’s earlier decisions on SAMA cost estimates, thus renewing their appeals of that issue previously denied by the NRC as premature. Appeal (3) addressed a contention that was one of the four decided without hearing. The remaining appeals addressed contentions that were tried in Track 1 hearings.
In February 2015, the NRC granted petitions for review of two appeals for the purpose of obtaining additional information prior to making final disposition. The appeals for which the NRC requested answers to specified questions were New York State’s appeal on SAMA decontamination cost estimates and the appeal of Entergy and NRC staff on SAMA cost estimates. The NRC stated that the remaining appeals filed after the ASLB’s Track 1 decision would be resolved in the future. There is no deadline for the NRC action on either group of appeals from the ASLB.
The remaining four admitted consolidated contentions were designated byto issue renewed licenses have been granted, and the ASLB as “Track 2.” In April 2014has terminated proceedings before it following the ASLB granted Entergy’s motion to dismiss as moot a contention by Riverkeeper alleging that the FSEIS failed to adequately address endangered species issues. At the same time, the ASLB denied a motion filed by Riverkeeper in August 2013 to amend its endangered species contention. These ASLB decisions were not appealed and are now final, making a totalwithdrawal of nine of the original 16 admitted consolidated contentions that have been resolved favorably (or in the case of settlement, acceptably) to Entergy. Seven of the original 16 admitted consolidated contentions are on appeal (four total) or pending hearing on Track 2 (three total).
While Track 2 hearings have not been scheduled, the procedural steps leading to such hearings have begun. Pursuant to ASLB procedural orders, New York State filed in February 2015 proposed revisions to two of the three admitted contentions designated as Track 2. Entergy and NRC staff will have an opportunity to oppose or to seek limitations on those contention revisions, after which the ASLB will decide whether to accept New York State’s proposed revisions to previously-admitted contentions. In addition, before Track 2 hearings are convened, the parties will have the opportunity to update and complete their testimony.
Independent of the ASLB process, the NRC staff has performed its technical and environmental reviews of the Indian Point 2 and Indian Point 3 license renewal application. The NRC is not expected to issue renewed licenses earlier than third quarter 2018, as its staff issued an FSER in August 2009,must complete updates to the record on environmental and safety matters (a supplement to the final supplemental environmental impact statement and a supplement to the FSER in August 2011, an FSEIS in December 2010, a supplement to the FSEIS in June 2013, and, as noted above, a further supplement to the FSER in November 2014. In November 2014 the NRC staff advised of its proposed schedule for issuance of a further FSEIS supplement to address new information received by NRC staff since preparation and publication of the previous FSEIS supplement in June 2013. The proposed schedule identifies several milestones leading to the issuance of a new final FSEIS supplement in March 2016. The matters to be addressed in the new supplement include Entergy’s May 2013 submittal of updated cost information for SAMAs; Entergy’s February 2014 submittal of new aquatic impact information; the June 2013 revision by the NRC of its Generic Environmental Impact Statement relied upon in license renewal proceedings; and the NRC’s Continued Storage Of Spent Nuclear Fuel rule, which was published in the Federal Register in September 2014.
The hearing process is an integral component of the NRC’s regulatory framework, and evidentiary hearings on license renewal applications are not uncommon. Entergy is participating fully in the hearing and appeals processes as authorized by the NRC regulations. As noted in Entergy filings at the ASLB and the appellate levels, Entergy believes the contentions proposed by the intervenors are unsupported and without merit. Entergy will continue to work with the NRC staff as it completes its technical and environmental reviews of the Indian Point 2 and 3 license renewal
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
applications. See “Nuclear Matters” below for discussion of spent nuclear fuel storage issues and their potential effect on the timing of license renewals.safety evaluation report).
The New York State Department of Environmental Conservation (NYSDEC) has taken the position that Indian Point must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process. Entergy submitted its application for a water quality certification to NYSDEC in April 2009, with a reservation of rights regarding the applicability of Section 401 in this case. After Entergy submitted certain additional information in response to NYSDEC requests for additional information, in February 2010 the NYSDEC staff determined that Entergy’s water quality certification application was complete. In April 2010 the NYSDEC staff issued a proposed notice of denial of Entergy’s water quality certification application (the Notice). NYSDEC staff’s Notice triggered an administrative adjudicatory hearing before NYSDEC ALJs on the proposed Notice. The NYSDEC staff decision does not restrict Indian Point operations, but the issuance of a certification is potentially required prior to NRC issuance of renewed unit licenses. In June 2011, Entergy filed notice with the NRC that NYSDEC, the agency that would issue or deny a water quality certification for the Indian Point license renewal process, had taken longer than one year to take final action on Entergy’s application for a water quality certification and, therefore, had waived its opportunity to require a certification under the provisions of Section 401 of the Clean Water Act. The NYSDEC has notified the NRC that it disagrees with Entergy’s position and does not believe that it has waived the right to require a certification. The NYSDEC ALJs overseeing the agency’s certification adjudicatory process stated in a ruling issued in July 2011 that while the waiver issue is pending before the NRC, the NYSDEC hearing process will continue on selected issues. The ALJs held a Legislative Hearing (agency public comment session) and an Issues Conference (pre-trial conference) in July 2010 and set certain issues for trial in October 2011. In 2014, hearings were held on NYSDEC’s proposed best technology available, closed cycle cooling. The NYSDEC staff also has proposed annual fish protection outages of 42, 62, or 92 days at both units or at one unit with closed cycle cooling at the other. The ALJs held a further legislative hearing and issues conference on this NYSDEC staff proposal in July 2014. In January 2015, Entergy wrote NYSDEC leadership requesting an explanation of the delay in release of the ruling following an ALJ’s on-record statement that the ALJ’s draft ruling was under “executive review.” In February 2015, the ALJs issued a ruling scheduling hearings on the outage proposals and other pending issues in September and October 2015, with post-hearing briefing to follow in December 2015.
The ALJs have issued no partial decisions on the several issues that have been the subject of hearing during the past three years and have not announced a schedule for doing so. After the completion of hearings on the merits, the ALJs will issue a recommended decision to the NYSDEC Commissioner’s designated delegate who will then issue the final agency decision. A party to the proceeding can appeal the final agency decision to state court.
In addition, before the NRC may issue renewed operating licenses it must resolve its obligation to address the requirements of the Coastal Zone Management Act (CZMA). Most commonly, those requirements are met by the applicant’s demonstration that the activity authorized by the federal permit being sought is consistent with the host state’s federally-approved coastal management policies. Entergy has undertaken three independent initiatives to resolve CZMA issues: “grandfathering;” “previous review;” and a “consistency certification.”
First, Entergy filed with the New York State Department of State (NYSDOS) in November 2012 a petition for declaratory order that Indian Point is grandfathered under either of two criteria prescribed by the New York Coastal Management Program (NYCMP), which sets forth the state coastal policies applied in a CZMA consistency review. NYSDOS denied the motion by order dated January 2013. Entergy filed a petition for judicial review of NYSDOS’s decision with the New York State Supreme Court for Albany County in March 2013. The court denied Entergy’s appeal in December 2013. Entergy initiated an appeal to the Appellate Division of the New York State Supreme Court in January 2014. In December 2014 a five-judge panel of that court unanimously held that Indian Point is exempt from CZMA consistency review by NYSDOS because it meets one of the two criteria for grandfathering established in the NYCMP. The court did not address the second criterion.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Appeal to New York State’s highest court, the State Court of Appeals, is discretionary in this case. In January 2015, NYSDOS filed with the same court a motion for reargument or, alternatively, leave to appeal to the State Court of Appeals. Entergy timely filed opposing papers. If the Appellate Division denies NYSDOS’s motion, NYSDOS may then file a separate motion for leave to appeal directly with the State Court of Appeals.
Second, in July 2012, Entergy filed a supplement to the Indian Point license renewal applications currently pending before the NRC. The supplement states that, based on applicable federal law and in light of prior reviews by the State of New York, the NRC may issue the requested renewed operating licenses for Indian Point without the need for an additional consistency review by the State of New York under the CZMA. In July 2012, Entergy filed a motion for declaratory order with the ASLB seeking confirmation of its position that no further CZMA consistency determination is required before the NRC may issue renewed licenses. In April 2013 the State of New York and Riverkeeper filed answers opposing Entergy’s motion. The State of New York also filed a cross-motion for declaratory order seeking confirmation that Indian Point had not been previously reviewed, and that only NYSDOS could conduct a CZMA review for NRC license renewal purposes. In April 2013 the NRC Staff filed answers recommending the ASLB deny both Entergy’s and the State of New York’s motions for declaratory order. In June 2013 the ASLB denied Entergy’s and the State of New York’s motions, without prejudice, on the ground that consultation on the matter of previous review among the NRC, Entergy (as applicant), and the State of New York had not taken place, as the ASLB determined to be required. In December 2013, NRC staff initiated consultation under federal CZMA regulations by serving on NYSDOS written questions related to whether Indian Point had been previously reviewed. In May 2014 the NYSDOS responded to questions the NRC staff submitted in December 2013. In July 2014, Entergy submitted comments on NYSDOS’s responses and NYSDOS filed a reply to those comments. Further submissions to the NRC staff with respect to the previous review issue were made by Entergy in November 2014 and by NYSDOS in December 2014. The NRC staff advised the ASLB in February 2015 that it is reviewing the information it has received regarding previous review and will provide further information when available.
Third, in December 2012, Entergy filed with NYSDOS a consistency determination explaining why Indian Point satisfies all applicable NYCMP policies while noting that Entergy did not concede NYSDOS’s right to conduct a new CZMA review for Indian Point. In January 2013, NYSDOS notified Entergy that it deemed the consistency determination incomplete because it did not include the final version of a further supplement to the FSEIS that was targeted for subsequent issuance by NRC staff. In June 2013, NYSDOS notified Entergy that NYSDOS had received a copy of the final version of the FSEIS on June 20, 2013, and that NYSDOS’s review of the Indian Point consistency determination had begun that date. By a series of agreements, Entergy and NYSDOS agreed to extend NYSDOS’s deadline for concurring with or objecting to the Indian Point consistency certification to December 31, 2014. In November 2014, Entergy filed with the NRC and with NYSDOS a notice withdrawing the consistency certification. Entergy cited the NRC staff’s announcement two days earlier of its intent to issue in March 2016 a new FSEIS supplement addressing, among other things, new information concerning aquatic impacts. Entergy stated that unless the previous review or grandfathering issues were first and finally resolved in Entergy’s favor, Entergy intended to file a new consistency certification after the NRC issues the FSEIS supplement. That new consistency certification would initiate NYSDOS’s review process, would allow the FSEIS supplement to also be part of the record before NYSDOS, and, were NYSDOS to object to the new certification, would also be part of the record before the U.S. Secretary of Commerce on appeal.
NYSDOS disputed the effectiveness of Entergy’s November 2014 notice withdrawing the consistency certification. In December 2014, Entergy and NYSDOS executed an agreement intended to preserve the parties’ respective positions on withdrawal. The agreement provides, among other things, that if NYSDOS is correct about withdrawal not being effective, the parties will be deemed to have agreed to a stay of NYSDOS’s deadline for decision on the 2012 consistency certification to June 30, 2015.
Entergy Corporation and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
ANO Damage, Outage,Operations may be extended up to four additional years for each unit by mutual agreement of Entergy and NRC ReviewsNew York State based on an exigent reliability need for Indian Point generation. In accordance with the FERC-approved tariff of the New York Independent System Operator (NYISO), Entergy submitted to the NYISO a notice of generator deactivation based on the dates in the settlement (no later than April 30, 2020 for Indian Point Unit 2 and April 30, 2021 for Indian Point Unit 3). In December 2017, NYISO issued a report stating there will not be a system reliability need following the deactivation of Indian Point. The NYISO also has advised that it will perform an analysis of the potential competitive impacts of the proposed retirement under provisions of its tariff. The deadline for the NYISO to make a withholding determination is in dispute and is pending before the FERC.
On March 31, 2013, during a scheduled refueling outage at ANO 1, a contractor-owned and operated heavy-lifting apparatus collapsed while moving the generator stator out of the turbine building. The collapse resulted in the death of an ironworker and injuries to several other contract workers, caused ANO 2 to shut down, and damaged the ANO turbine building. The turbine building serves both ANO 1 and 2 and is a non-radiological area of the plant. ANO 2 reconnected to the grid on April 28, 2013 and ANO 1 reconnected to the grid on August 7, 2013. The total cost of assessment, restoration of off-site power, site restoration, debris removal, and replacement of damaged property and equipment was approximately $95 million. In addition to contractually agreeing to cease commercial operations early, in February 2017 Entergy Arkansas incurred replacement power costs for ANO 2 power during its outage and incurred incremental replacement power costs for ANO 1 power because the outage extended beyond the originally-planned duration of the refueling outage. In February 2014 the APSC approved Entergy Arkansas’s request to exclude from the calculation of its revised energy cost rate $65.9 million of deferred fuel and purchased energy costs incurred in 2013 as a result of the ANO stator incident. The APSC authorized Entergy Arkansas to retain the $65.9 million in its deferred fuel balance with recovery to be reviewed in a later period after more information regarding various claims associated with the ANO stator incident is available.
Entergy Arkansas is pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. Entergy is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants, including ANO. NEIL has notified Entergy that it believes that a $50 million course of construction sublimit applies to any loss associated with the lifting apparatus failure and stator drop at ANO. Entergy has responded that it disagrees with NEIL’s position and is evaluating its options for enforcing its rights under the policy. During 2014, Entergy Arkansas collected $50 million from NEIL and is pursuing additional recoveries due under the policy. On July 12, 2013, Entergy Arkansas filed a complaint in the Circuit Court in Pope County, Arkansas against the owner of the heavy-lifting apparatus that collapsed, an engineering firm, a contractor, and certain individuals asserting claims of breach of contract, negligence, and gross negligence in connection with their responsibility for the stator drop.
Shortly after the stator incident, the NRC deployed an augmented inspection team to review the plant’s response. In July 2013 a second team of NRC inspectors visited ANO to evaluate certain items that were identified as requiring follow-up inspection to determine whether performance deficiencies existed. In March 2014 the NRC issued an inspection report on the follow-up inspection that discussed two preliminary findings, one that was preliminarily determined to be “red with high safety significance” for Unit 1 and one that was preliminarily determined to be “yellow with substantial safety significance” for Unit 2, with the NRC indicating further that these preliminary findings may warrant additional regulatory oversight. This report also noted that one additional item relatedan amendment to flood barrier effectiveness was still under review.
In May 2014its license renewal application changing the NRC met with Entergy during a regulatory conference to discuss the preliminary red and yellow findings and Entergy’s response to the findings. During the regulatory conference, Entergy presented information on the facts and assumptions the NRC used to assess the potential findings. The NRC used the information provided by Entergy at the regulatory conference to finalize its decision regarding the inspection team’s findings. In a letter dated June 23, 2014, the NRC classified both findings as “yellow with substantial safety significance.” In an assessment follow-up letter for ANO dated July 29, 2014, the NRC stated that given the two yellow findings, it determined that the performance at ANO is in the “degraded cornerstone column,” or column 3,term of the NRC’s reactor oversight process action matrix beginning the first quarter 2014. Corrective actions in responserequested licenses to the NRC’s findings have been taken and remain ongoing at ANO. The NRC plans to conduct supplemental inspection activity to review the actions taken to address the yellow findings. Entergy will continue to interactcoincide with the NRC to address the NRC’s findings.
In September 2014 the NRC issued an inspection reportlatest possible extension by mutual agreement based on the flood barrier effectiveness issue that was still under review at the time of the March 2014 inspection report. Whileexigent reliability needs: April 30, 2024 for Indian Point 2 and April 30, 2025 for Indian Point 3. If Entergy believes that the flood barrier issues that led to the finding have been addressed at ANO, NRC processes still requiredreasonably determines that the NRC assesswill treat the safety significanceamendment other than as a routine amendment, Entergy may withdraw the amendment.
Other provisions of the deficiencies. In its September 2014 inspection report,settlement include termination of all then-existing investigations of Indian Point by the NRC discussed a preliminary findingagencies signing the agreement, which include the New York State Department of “yellow with
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
substantial safety significance” forState, the Unit 1 and Unit 2 auxiliary and emergency diesel fuel storage buildings. The NRC indicated that these preliminary findings may warrant additional regulatory oversight. Entergy requested a public regulatory conference regardingNew York State Department of Public Service, the inspection,New York State Department of Health, and the conference was held in October 2014. DuringNew York State Attorney General. The settlement recognizes the regulatory conference, Entergy presented information relatedright of New York State agencies to the factspursue new investigations and assumptions used by the NRC in arriving at its preliminary finding of “yellowenforcement actions with substantial safety significance.” In January 2015 the NRC issued its final risk significance determination for the flood barrier violation originally cited in the September 2014 report. The NRC’s final risk significance determination was classified as “yellow with substantial safety significance.”
The NRC’s January 2015 letter did not advise ANO of the additional level of oversightrespect to new circumstances or existing conditions that will result from the yellow finding related to the flood barrier issue, and it stated that the NRC would inform ANO of this decision by separate correspondence. The yellow finding may result in ANO being placed into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. Placement into this column would require significant additional NRC inspection activities at the ANO site, including a review of the site’s root cause evaluation associated with the flood barrier and stator issues, an assessment of the effectiveness of the site’s corrective action program, an additional design basis inspection, a safety culture assessment, and possibly other inspection activities consistent with the NRC’s Inspection Procedure. The additional NRC inspection activities at the site are expected to increase ANO’s operating costs.
Human Capital Management Strategic Imperativebecome materially exacerbated.
Another provision of the settlement obligates Entergy engagedto establish a $15 million fund for environmental projects and community support. Apportionment and allocation of funds to beneficiaries are to be determined by mutual agreement of New York State and Entergy. The settlement recognizes New York State’s right to perform an annual inspection of Indian Point, with scope and timing to be determined by mutual agreement.
In May 2017 a plaintiff filed two parallel state court appeals challenging New York State’s actions in a strategic imperative intendedsigning and implementing the Indian Point settlement with Entergy on the basis that the State failed to optimize the organization through a process known as human capital management. In July 2013 management completed a comprehensive reviewperform sufficient environmental analysis of Entergy’s organization design and processes. This effort resulted in a new internal organization structure, which resulted in the elimination of approximately 800 employee positions. Entergy incurred approximately $110 million and approximately $20 million in costs in 2013 and 2014, respectively, associated with this phase of human capital management, primarily implementation costs, severance expenses, pension curtailment losses, special termination benefits expense, and corporate property, plant, and equipment impairments. In December 2013, Entergy deferred for future recovery approximately $45 million of these costs, as approved by the APSC and the LPSC. See Note 2its actions. All signatories to the financial statementssettlement agreement, including the Entergy affiliates that hold NRC licenses for details of the deferrals and Note 13 to the financial statements for details of the restructuring charges.Indian Point, were named. The appeals were voluntarily dismissed in November 2017.
Liquidity and Capital Resources
This section discusses Entergy’s capital structure, capital spending plans and other uses of capital, sources of capital, and the cash flow activity presented in the cash flow statement.
Capital Structure
Entergy’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital ratio for Entergy as of December 31, 2017 is primarily due to an increase in commercial paper outstanding in 2017 as compared to 2016.
| | | | 2014 | | 2013 | 2017 | | 2016 |
| Debt to capital | 57.6 | % | | 57.9 | % | 67.1% | | 64.8% |
| Effect of excluding securitization bonds | (1.4 | %) | | (1.6 | %) | (0.8%) | | (1.0%) |
| Debt to capital, excluding securitization bonds (a) | 56.2 | % |
| 56.3 | % | 66.3% |
| 63.8% |
| Effect of subtracting cash | (2.8 | %) | | (1.5 | %) | (1.1%) | | (2.0%) |
| Net debt to net capital, excluding securitization bonds (a) | 53.4 | % |
| 54.8 | % | 65.2% |
| 61.8% |
| |
| (a) | Calculation excludes the Arkansas, Louisiana, New Orleans, and Texas securitization bonds, which are non-recourse to Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas, respectively. |
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and commercial paper, capital lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, common shareholders’ equity, and subsidiaries’ preferred stock without sinking fund. Net capital consists of capital less cash
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
and cash equivalents. Entergy uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy’s financial condition because the securitization bonds are non-recourse to Entergy, as more fully described in Note 5 to the financial statements. Entergy also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy’s financial condition because net debt indicates Entergy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Long-term debt, including the currently maturing portion, makes up most of Entergy’s total debt outstanding. Following are Entergy’s long-term debt principal maturities and estimated interest payments as of December 31, 2014.2017. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2014.2017. The amounts below include payments on the Entergy Louisiana and System EnergyEnergy’s Grand Gulf sale-leaseback transactions,transaction, which are included in long-term debt on the balance sheet.
| | Long-term debt maturities and estimated interest payments | | 2015 | | 2016 | | 2017 | | 2018-2019 | | after 2019 | | 2018 | | 2019 | | 2020 | | 2021-2022 | | after 2022 |
| | | (In Millions) | | (In Millions) |
| Utility | |
| $882 |
| |
| $746 |
| |
| $886 |
| |
| $2,070 |
| |
| $13,997 |
| |
| $1,427 |
| |
| $1,430 |
| |
| $927 |
| |
| $2,234 |
| |
| $15,102 |
|
| Entergy Wholesale Commodities | | 19 |
| | 2 |
| | 2 |
| | 4 |
| | 53 |
| | 3 |
| | 3 |
| | 106 |
| | — |
| | — |
|
| Parent and Other | | 624 |
| | 60 |
| | 537 |
| | 757 |
| | 466 |
| | 76 |
| | 76 |
| | 520 |
| | 953 |
| | 832 |
|
| Total | |
| $1,525 |
| |
| $808 |
| |
| $1,425 |
| |
| $2,831 |
| |
| $14,516 |
| |
| $1,506 |
| |
| $1,509 |
| |
| $1,553 |
| |
| $3,187 |
| |
| $15,934 |
|
Note 5 to the financial statements provides more detail concerning long-term debt outstanding.
Entergy Corporation has in place a credit facility that has a borrowing capacity of $3.5 billion and expires in March 2019. Entergy Corporation hasAugust 2022. The facility permits the ability to issueissuance of letters of credit against 50%$20 million of the total borrowing capacity of the credit facility. The commitment fee is currently 0.275%0.225% of the undrawn commitment amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior unsecured debt ratings of Entergy Corporation. The weighted average interest rate for the year ended December 31, 20142017 was 1.93%2.55% on the drawn portion of the facility.
As of December 31, 2014,2017, amounts outstanding and capacity available under the $3.5 billion credit facility are:
| | Capacity (a) | | Borrowings | | Letters of Credit | | Capacity Available | | Borrowings | | Letters of Credit | | Capacity Available |
(In Millions) | | $3,500 | | $695 | | $9 | | $2,796 | | $210 | | $6 | | $3,284 |
A covenant in Entergy Corporation’s credit facility requires Entergy to maintain a consolidated debt ratio, as defined, of 65% or less of its total capitalization. The calculation of this debt ratio under Entergy Corporation’s credit facility is different than the calculation of the debt to capital ratio above. One such difference is that it excludes the effects, among other things, of certain impairments related to the Entergy Wholesale Commodities nuclear generation assets. Entergy is currently in compliance with the covenant and expects to remain in compliance with this covenant. If Entergy fails to meet this ratio, or if Entergy or one of the Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the Entergy Corporation credit facility’s maturity date may occur.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Corporation has a commercial paper program with a Board-approved program limit of up to $1.52 billion. AtAs of December 31, 2014,2017, Entergy Corporation had $484 million$1.467 billion of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 20142017 was 0.88%1.49%.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Capital lease obligations are a minimal part of Entergy’s overall capital structure. Following are Entergy’s payment obligations under those leases.
|
| | | | | | | | | |
| | 2015 | | 2016 | | 2017 | | 2018-2019 | | after 2019 |
| | (In Millions) |
| Capital lease payments | $5 | | $4 | | $4 | | $7 | | $28 |
|
| | | | | | | | | |
| | 2018 | | 2019 | | 2020 | | 2021-2022 | | after 2022 |
| | (In Millions) |
| Capital lease payments | $3 | | $3 | | $3 | | $6 | | $19 |
The capital leases are discussed in Note 10 to the financial statements.
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 20142017 as follows:
|
| | | | | | | | | | |
Company | | Expiration Date | | Amount of Facility | | Interest Rate (a) | | Amount Drawn as of December 31, 20142017 | | Letters of Credit Outstanding as of December 31, 2017 |
| Entergy Arkansas | | April 20152018 | | $20 million (b) | | 1.67%2.82% | | — | | — |
| Entergy Arkansas | | March 2019August 2022 | | $150 million (c) | | 1.67%2.82% | | — |
Entergy Gulf States Louisiana | | March 2019 | | $150 million (d) | | 1.42% | | — |
| Entergy Louisiana | | March 2019August 2022 | | $200350 million (e)(c) | | 1.42%2.82% | | — | | $9.1 million |
| Entergy Mississippi | | May 2018 | | $10 million (d) | | 3.07% | | — | | — |
| Entergy Mississippi | | May 20152018 | | $1020 million (f)(d) | | 1.67%3.07% | | — | | — |
| Entergy Mississippi | | May 20152018 | | $2035 million (f)(d) | | 1.67%3.07% | | — | | — |
| Entergy Mississippi | | May 2015 | | $35 million (f) | | 1.67% | | — |
Entergy Mississippi | | May 20152018 | | $37.5 million (f)(d) | | 1.67%3.07% | | — | | — |
| Entergy New Orleans | | November 20152018 | | $25 million (c) | | 1.92%3.04% | | — | | $0.8 million |
| Entergy Texas | | March 2019August 2022 | | $150 million (g)(c) | | 1.67%3.07% | | — | | $25.6 million |
| |
(a) | The interest rate is the estimated interest rate as of December 31, 20142017 that would behave been applied to outstanding borrowings under the facility. |
| |
(b) | Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable at Entergy Arkansas’s option. |
| |
(c) | The credit facility allows Entergy Arkansas to issuepermits the issuance of letters of credit against 50%a portion of the borrowing capacity of the facility. As of December 31, 2014, no letters of credit were outstanding.facility as follows: $5 million for Entergy Arkansas; $15 million for Entergy Louisiana; $10 million for Entergy New Orleans; and $30 million for Entergy Texas. |
| |
(d) | The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, no letters of credit were outstanding. |
| |
(e)
| The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, no letters of credit were outstanding. |
| |
(f)
| Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option. |
| |
(g) | The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, $1.3 million in letters of credit were outstanding. |
Each of the credit facilities requires the Registrant Subsidiary borrower to maintain a debt ratio, as defined, of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In addition, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each entered into one or more uncommitted standby letter of credit facilities as a means to post collateral to support its obligations related to MISO. Following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2014:2017:
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
|
| | | | | | | | | |
| | | | Amount of | | | | Letters of Credit Issued as of |
| Company | | | Uncommitted Facility | | Letter of Credit Fee | | December 31, 2014 |
| Entergy Arkansas | | | $25 million | | 0.70% | |
| $2.0 | million |
| Entergy Gulf States Louisiana | | | $75 million | | 0.70% | |
| $27.9 | million |
| Entergy Louisiana | | | $50 million | | 0.70% | |
| $4.7 | million |
| Entergy Mississippi | | | $40 million | | 0.70% | |
| $14.4 | million |
| Entergy Mississippi | | | $40 million | | 1.50% | |
| $— |
|
| Entergy New Orleans | | | $15 million | | 0.75% | |
| $8.1 | million |
| Entergy Texas | | | $50 million | | 0.70% | |
| $24.5 | million |
|
| | | | | | | |
| Company | | | Amount of Uncommitted Facility | | Letter of Credit Fee | | Letters of Credit Issued as of December 31, 2017 (a) |
| Entergy Arkansas | | | $25 million | | 0.70% | | $1.0 million |
| Entergy Louisiana | | | $125 million | | 0.70% | | $29.7 million |
| Entergy Mississippi | | | $40 million | | 0.70% | | $15.3 million |
| Entergy New Orleans | | | $15 million | | 1.00% | | $1.4 million |
| Entergy Texas | | | $50 million | | 0.70% | | $22.8 million |
| |
| (a) | As of December 31, 2017, letters of credit posted with MISO covered financial transmission right exposure of $0.2 million for Entergy Arkansas, $0.1 million for Entergy Mississippi, and $0.05 million for Entergy Texas. See Note 15 to the financial statements for discussion of financial transmission rights. |
In January 2015, Entergy Nuclear Vermont Yankee entered intohas a credit facility guaranteed by Entergy Corporation with a borrowing capacity of $60$145 million whichthat expires in January 2018. AlsoNovember 2020. As of December 31, 2017, $104 million in January 2015,cash borrowings were outstanding under the credit facility. The weighted average interest rate for the year ended December 31, 2017 was 2.64% on the drawn portion of the facility. Entergy Nuclear Vermont Yankee entered intoalso had an uncommitted credit facility guaranteed by Entergy Corporation with a borrowing capacity of $85 million which expiresthat expired in January 2018. As of December 31, 2017, there were no cash borrowings outstanding under the credit facility. See Note 4 to the financial statements for additional discussion of the Vermont Yankee credit facilities.
Operating Lease Obligations and Guarantees of Unconsolidated Obligations
Entergy has a minimal amount of operating lease obligations and guarantees in support of unconsolidated obligations. Entergy’s guarantees in support of unconsolidated obligations are not likely to have a material effect on Entergy’s financial condition, results of operations, or cash flows. Following are Entergy’s payment obligations as of December 31, 20142017 on non-cancelable operating leases with a term over one year:
|
| | | | | | | | | |
| | 2015 | | 2016 | | 2017 | | 2018-2019 | | after 2019 |
| | (In Millions) |
| Operating lease payments | $90 | | $77 | | $62 | | $97 | | $96 |
|
| | | | | | | | | |
| | 2018 | | 2019 | | 2020 | | 2021-2022 | | after 2022 |
| | (In Millions) |
| Operating lease payments | $80 | | $83 | | $67 | | $102 | | $97 |
The operatingOperating leases are discussed in Note 10 to the financial statements.
Summary of Contractual Obligations of Consolidated Entities
| | | Contractual Obligations | | 2015 | | 2016-2017 | | 2018-2019 | | after 2019 | | Total | | 2018 | | 2019-2020 | | 2021-2022 | | after 2022 | | Total |
| | | (In Millions) | | (In Millions) |
| Long-term debt (a) | |
| $1,525 |
| |
| $2,233 |
| |
| $2,831 |
| |
| $14,516 |
| |
| $21,105 |
| |
| $1,506 |
| |
| $3,062 |
| |
| $3,187 |
| |
| $15,934 |
| |
| $23,689 |
|
| Capital lease payments (b) | |
| $5 |
| |
| $8 |
| |
| $7 |
| |
| $28 |
| |
| $48 |
| |
| $3 |
| |
| $6 |
| |
| $6 |
| |
| $19 |
| |
| $34 |
|
| Operating leases (b) (c) | |
| $90 |
| |
| $139 |
| |
| $97 |
| |
| $96 |
| |
| $422 |
| |
| $80 |
| |
| $150 |
| |
| $102 |
| |
| $97 |
| |
| $429 |
|
| Purchase obligations (d) | |
| $1,898 |
| |
| $2,738 |
| |
| $2,405 |
| |
| $5,821 |
| |
| $12,862 |
| |
| $1,394 |
| |
| $2,485 |
| |
| $1,992 |
| |
| $4,728 |
| |
| $10,599 |
|
| |
| (a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
| (b) | Lease obligations are discussed in Note 10 to the financial statements. |
| |
| (c) | Does not include power purchase agreements that are accounted for as leases that are included in purchase obligations. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| |
| (d) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. Almost all of the total are fuel and purchased power obligations. |
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
In addition to the contractual obligations givenstated above, Entergy currently expects to contribute approximately $396.2$352.1 million to its pension plans and approximately $66.9$52.3 million to other postretirement plans in 2015,2018, although the 2018 required pension contributions will not be known with more certainty untilwhen the January 1, 20152018 valuations are completed, which is expected by April 1, 2015.2018. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy has $441$916 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
Capital Funds Agreement
Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:
maintain System Energy’s equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);
permit the continued commercial operation of Grand Gulf;
pay in full all System Energy indebtedness for borrowed money when due; and
enable System Energy to make payments on specific System Energy debt, under supplements to the agreement assigning System Energy’s rights in the agreement as security for the specific debt.
Capital Expenditure Plans and Other Uses of Capital
Following are the amounts of Entergy’s planned construction and other capital investments by operating segment for 20152018 through 2017.2020.
| | | Planned construction and capital investments | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 |
| | | (In Millions) | | (In Millions) |
| Utility: | | | | | | | | | | | | |
| Generation | |
| $1,585 |
| |
| $635 |
| |
| $1,040 |
| |
| $1,590 |
| |
| $1,410 |
| |
| $1,245 |
|
| Transmission | | 805 |
| | 670 |
| | 665 |
| | 990 |
| | 865 |
| | 735 |
|
| Distribution | | 715 |
| | 700 |
| | 650 |
| | 860 |
| | 1,030 |
| | 945 |
|
| Other | | 230 |
| | 190 |
| | 155 |
| |
| Utility Support | | | 480 |
| | 335 |
| | 375 |
|
| Total | | 3,335 |
| | 2,195 |
| | 2,510 |
| | 3,920 |
| | 3,640 |
| | 3,300 |
|
| Entergy Wholesale Commodities | | 425 |
| | 265 |
| | 275 |
| | 245 |
| | 75 |
| | 35 |
|
| Total | |
| $3,760 |
| |
| $2,460 |
| |
| $2,785 |
| |
| $4,165 |
| |
| $3,715 |
| |
| $3,335 |
|
Planned construction and capital investments refer to amounts Entergy plans to spend on routine capital projects that are necessary to support reliability of its service, equipment, or systems and to support normal customer growth, and includes spending for the nuclear and non-nuclear plants at Entergy Wholesale Commodities. In addition to routine capital projects, they also refer to amounts Entergy plans to spend on non-routine capital investments for which Entergy is either contractually obligated, has Board approval, or otherwise expects to make to satisfy regulatory or legal requirements. Amounts include the following:following types of construction and capital investments:
Potential resource planning investments,Investments, including the UnionSt. Charles Power Station, acquisitionLake Charles Power Station, New Orleans Power Station, and Montgomery County Power Station, each discussed below, and potential construction of additional generation.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Entergy Wholesale Commodities investments associated with specific investments such as component replacements, software and security, NYPA value sharing in January 2015,and dry cask storage,storage.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Investments in Entergy’s nuclear license renewal.
Environmental compliance spending, including potential scrubbers at White Bluff to meet pending Arkansas state requirements under the Clean Air Visibility Rule. Entergy continues to review potential environmental spending needs and financing alternatives for any such spending, and future spending estimates could change based on the results of this continuing analysis and the implementation of new environmental laws and regulations.
NRC post-Fukushima requirements for the Utility and Entergy Wholesale Commodities nuclear fleets.fleet.
Transmission spending to enhance reliability, reduce congestion, and enable economic growth.
Distribution spending to enhance reliability and improve service to customers, including investment to support advanced metering.
For the next several years, the Utility’s owned generating capacity is projected to be adequate to meet MISO reserve requirements; however, in the longer-term additional supply resources will be needed, and its supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. Estimated capital expenditures are also subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints and requirements, environmental regulations, business opportunities, market volatility, economic trends, changes in project plans, and the ability to access capital.
UnionSt. Charles Power Station Purchase Agreement
In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire the Union Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas-fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Pursuant to the agreement, Entergy Gulf States Louisiana will acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas will each acquire one power block and a 25% undivided ownership interest in such related assets. If Entergy Arkansas or Entergy Texas do not obtain approval for the purchase of their power blocks, Entergy Gulf States Louisiana will seek to purchase the power blocks not approved. The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments. In addition, Entergy Gulf States Louisiana anticipates selling 20% of the capacity and energy associated with its two power blocks to Entergy New Orleans through a cost-based, life-of-unit power purchase agreement. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. These include regulatory approvals from the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino anti-trust law. In December 2014, Entergy Texas filed its application with the PUCT for approval of the acquisition. The PUCT has indicated that it will convene the hearing on the merits of this case in June 2015. Entergy Texas intends to file a rate application to seek cost recovery later in 2015. In JanuaryAugust 2015, Entergy Gulf States Louisiana filed its application with the LPSC and Entergy Arkansas filed its application with the APSC, each for approval of the acquisition and cost recovery. Closing is targeted to occur in late-2015.
Ninemile Point Unit 6 Self-Build Project
In June 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’sthe construction of the St. Charles Power Station, a nominal 980 megawatt combined-cycle gas turbine generating facility (Ninemile 6) at itsunit, on land adjacent to the existing Ninemile Point electricLittle Gypsy plant in St. Charles Parish, Louisiana. It is currently estimated to cost $869 million to construct, including transmission interconnection and other related costs. The LPSC issued an order approving certification of St. Charles Power Station in December 2016. Construction is in progress and commercial operation is estimated to occur by mid-2019.
Lake Charles Power Station
In November 2016, Entergy Louisiana filed an application with the LPSC seeking certification that the public convenience and necessity would be served by the construction of the Lake Charles Power Station, a nominal 994 megawatt combined-cycle generating station. Ninemile 6unit in Westlake, Louisiana, on land adjacent to the existing Nelson plant in Calcasieu Parish. The current estimated cost of the Lake Charles Power Station is a nominally-sized 560 MW unit$872 million, including estimated costs of transmission interconnection and other related costs. In May 2017 the parties to the proceeding agreed to an uncontested stipulation finding that construction of the Lake Charles Power Station is in the public interest and authorizing an in-service rate recovery plan. In July 2017 the LPSC issued an order unanimously approving the stipulation and approved certification of the unit. Construction is in progress and commercial operation is expected to cost approximately $655 millionoccur by mid-2020.
New Orleans Power Station
In June 2016, Entergy New Orleans filed an application with the City Council seeking a public interest determination and authorization to construct when spendingthe New Orleans Power Station, a 226 MW advanced combustion turbine in New Orleans, Louisiana, at the site of the existing Michoud generating facility, which was retired effective May 31, 2016. In January 2017 several intervenors filed testimony opposing the construction of the New Orleans Power Station on various grounds. In July 2017, Entergy New Orleans submitted a supplemental and amending application to the City Council seeking approval to construct either the originally proposed 226 MW advanced combustion turbine, or alternatively, a 128 MW unit composed of natural gas-fired reciprocating engines and a related cost recovery plan. The application included an updated cost estimate of $232 million for the 226 MW advanced combustion turbine. The cost estimate for the alternative 128 MW unit is complete, excluding interconnection and transmission upgrades. Entergy Gulf States Louisiana joined in$210 million. In addition, the application seeking certification of its purchase under a life-of-unit power purchase agreement ofrenewed the commitment to pursue up to 25%100 MW of the capacity and energy generated by Ninemile 6. The Ninemile 6 capacity and energy is allocated 55%renewable resources to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20%serve New Orleans. In testimony filed subsequent to Entergy New Orleans. In February 2012Orleans’s supplemental and amending application, several intervenors oppose City Council approval of either alternative, while the City Council passedadvisors and one intervenor support the smaller alternative. A contested hearing was held in December 2017 and post-hearing briefs were filed in January 2018. In February 2018 the City Council Utility Committee adopted a resolution approving construction of the 128 MW unit. The full City Council is expected
Entergy Corporation and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
to vote on the resolution in March 2018. The commercial operation date is dependent on the alternative selected by the City Council and the receipt of other permits and approvals.
authorizingMontgomery County Power Station
In October 2016, Entergy New Orleans to purchase 20%Texas filed an application with the PUCT seeking certification that the public convenience and necessity would be served by the construction of the Ninemile 6 energy and capacity. In March 2012 the LPSC unanimously voted to grant the certifications requested by Entergy Gulf States Louisiana and Entergy Louisiana. Following approval by the LPSC, Entergy Louisiana issued full notice to proceedMontgomery County Power Station, a nominal 993 MW combined-cycle generating unit in Montgomery County, Texas on land adjacent to the project’s engineering, procurement,existing Lewis Creek plant. The current estimated cost of the Montgomery County Power Station is $937 million, including approximately $111 million of transmission interconnection and construction contractor.
Under terms approved bynetwork upgrades and other related costs. The independent monitor, who oversaw the LPSC, non-fuel costs may be recoveredrequest for proposal process, filed testimony and a report affirming that the Montgomery County Power Station was selected through Entergy Louisiana’san objective and Entergy Gulf States Louisiana’s formula rate plans beginning infair request for proposal process that showed no undue preference to any proposal. In June 2017 parties to the month after the unit is placed in service. In July 2014, Entergy Louisiana and Entergy Gulf States Louisianaproceeding filed an unopposed stipulation and settlement agreement. The stipulation contemplates that Entergy Texas’s level of cost-recovery for generation construction costs for Montgomery County Power Station is capped at $831 million, subject to certain exclusions such as force majeure events. Transmission interconnection and network upgrades and other related costs are not subject to the $831 million cap. In July 2017 the PUCT approved the stipulation. Subject to the timely receipt of other permits and approvals, commercial operation is estimated to occur by mid-2021.
Washington Parish Energy Center
In April 2017, Entergy Louisiana signed a purchase and sale agreement with a subsidiary of Calpine Corporation for the acquisition of a peaking plant. Calpine will construct the plant, which will consist of two natural gas-fired combustion turbine units with a total nominal capacity of approximately 361 MW. The plant, named the Washington Parish Energy Center, will be located in Bogalusa, Louisiana and, subject to permits and approvals, is expected to be completed in 2021. Subject to regulatory approvals, Entergy Louisiana will purchase the plant once it is complete for an estimated total investment of approximately $261 million, including transmission and other related costs. In May 2017, Entergy Louisiana filed an application with the LPSC that estimates a first year revenue requirement associatedseeking certification of the plant. A procedural schedule has been established, with Ninemile 6the deadlines recently extended and provides a mechanismthe hearing continued from March 2018 until June 2018 in order to updateallow the revenue requirement asparties an opportunity to reach settlement.
Advanced Metering Infrastructure (AMI)
See Note 2 to the in-service date approaches, which was subsequently approvedfinancial statements for discussion of filings made by the LPSC. In late December 2014, roughly contemporaneous withUtility operating companies regarding the unit’s placement in service, a final updated estimated revenue requirementdeployment of $51.1AMI. The filings included estimates of implementation costs for AMI of $208 million for Entergy Arkansas, $330 million for Entergy Louisiana, and $26.8$132 million for Entergy Gulf States Louisiana was filed. The December 2014 estimate forms the basis of rates implemented effective with the first billing cycle of January 2015. Under terms approved by the City Council,Mississippi, $75 million for Entergy New Orleans’s non-fuel costs associated with Ninemile 6 may be recovered through a special riderOrleans, and $132 million for that purpose. The unit was placed in service in December 2014. Entergy Louisiana will submit project and cost information to the LPSC in mid-2015 to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project.Texas.
Dividends and Stock Repurchases
Declarations of dividends on Entergy’s common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy’s common stock dividends based upon Entergy’s earnings per share from the Utility operating segment and the Parent and Other portion of the business, financial strength, and future investment opportunities. At its January 20152018 meeting, the Board declared a dividend of $0.83$0.89 per share, which is the same quarterly dividend per share that Entergy has paid since the second quarter 2010.share. Entergy paid $596$629 million in 2014, $5932017, $612 million in 2013,2016, and $589$599 million in 20122015 in cash dividends on its common stock.
In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options, restricted stock, performance units, and restricted stock unit awards to key employees, which may be exercised to obtain shares of Entergy’s common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
In addition to the authority to fund grant exercises, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. As of December 31, 2014,2017, $350 million of authority remains under the $500 million share repurchase program. The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities, or if limitations in the credit markets continue for a prolonged period.
Sources of Capital
Entergy’s sources to meet its capital requirements and to fund potential investments include:
internally generated funds;
cash on hand ($1,422781 million as of December 31, 2014)2017);
securities issuances;
bank financing under new or existing facilities or commercial paper; and
sales of assets.
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Provisions within the Articlesarticles of Incorporation or pertinent indentures and various other agreementsincorporation relating to the long-term debt and preferred stock of certain of Entergy Corporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred stock. As of December 31, 2014, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively. All debt and common and preferred equity issuances by the Registrant Subsidiaries require prior regulatory approval and their preferred equity and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy believes that the Registrant Subsidiaries have sufficient capacity under these tests to meet foreseeable capital needs.
The FERC has jurisdiction over securities issuances by the Utility operating companies and System Energy, (exceptexcept securities with maturities longer than one year issued by Entergy Arkansas, and Entergy New Orleans, which areis subject to the jurisdiction of the APSC and theAPSC. The City Council respectively).has concurrent jurisdiction over Entergy New Orleans’s securities issuances with maturities longer than one year. No regulatory approvals are necessary for Entergy Corporation to issue securities. The current FERC-authorized short-term borrowing limits are effective through October 31, 2015. Entergy Gulf States Louisiana,2019. Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through October 2015.2019. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2015.2018. Entergy New Orleans also has obtained long-term financing authorization from the City Council that extends through July 2016.June 2018. Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through October 20152019 for issuances by its respective nuclear fuel company variable interest entity. In addition to borrowings from commercial banks, the FERC short-term borrowing orders authorize the Registrant Subsidiaries to continue as participants inmay also borrow from the Entergy System money pool.pool and from other internal short-term borrowing arrangements. The money pool is an intercompanyand the other internal borrowing arrangementarrangements are inter-company borrowing arrangements designed to reduce Entergy’s subsidiaries’ dependence on external short-term borrowings. Borrowings from the money poolinternal and external short-term borrowings combined may not exceed the FERC-authorized short-term borrowing limits. See Notes 4 and 5 to the financial statements for further discussion of Entergy’s borrowing limits, authorizations, and amounts outstanding.
Hurricane Isaac
In August 2012, Hurricane Isaac caused extensive damage to portions of Entergy’s service area in Louisiana, and to a lesser extent in Mississippi and Arkansas. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. In January 2013, Entergy Gulf States Louisiana and Entergy Louisiana drew $65 million and $187 million, respectively, from their funded storm reserve escrow accounts. In April 2013, Entergy Gulf States Louisiana and Entergy Louisiana filed a joint application with the LPSC relating to Hurricane Isaac system restoration costs. Specifically, Entergy Gulf States Louisiana and Entergy Louisiana requested that the LPSC determine the amount of such costs that were prudently incurred and are, thus, eligible for recovery from customers. Including carrying costs and additional storm escrow funds for prior storms, Entergy Gulf States Louisiana requested an LPSC determination that $73.8 million in system restoration costs were prudently incurred and Entergy Louisiana requested an LPSC determination that $247.7 million in system restoration costs were prudently incurred. In May 2013, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana's and Entergy Louisiana's storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane Isaac system restoration costs incurred by Entergy Gulf States Louisiana and Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of each company’s costs. Following an evidentiary hearing and recommendations by the ALJ, the LPSC voted in June 2014 to approve a series of orders which (i) quantify the amount of Hurricane Isaac system restoration costs prudently incurred ($66.5 million for Entergy Gulf States Louisiana and $224.3 million for Entergy Louisiana); (ii) determine the level of storm reserves to be re-established ($90 million for Entergy Gulf States Louisiana and $200 million for Entergy Louisiana); (iii) authorize Entergy Gulf States Louisiana and Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) grant other requested relief associated with storm reserves and Act 55 financing of Hurricane
Entergy Corporation and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
Isaac system restoration costs. Entergy Gulf States Louisiana committed to pass on to customers a minimum of $6.9 million of customer benefits through annual customer credits of approximately $1.4 million for five years. Entergy Louisiana committed to pass on to customers a minimum of $23.9 million of customer benefits through annual customer credits of approximately $4.8 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.
In July 2014, Entergy Gulf States Louisiana issued $110 million of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes. In July 2014, Entergy Louisiana issued $190 million of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.
In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $71 million in bonds under Act 55 of the Louisiana Legislature. From the $69 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $3 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $66 million directly to Entergy Gulf States Louisiana. Entergy Gulf States Louisiana used the $66 million received from the LURC to acquire 662,426.80 Class C preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 7.5% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2014, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1.75 billion.
In August 2014 the LCDA issued another $243.85 million in bonds under Act 55 of the Louisiana Legislature. From the $240 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $13 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $227 million directly to Entergy Louisiana. Entergy Louisiana used the $227 million received from the LURC to acquire 2,272,725.89 Class C preferred, non-voting, membership interest units of Entergy Holdings Company LLC that carry a 7.5% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2014, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1.75 billion.
Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy, Entergy Gulf States Louisiana, or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remit the collections to the bond indenture trustee. Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the collections as revenue because they are merely acting as the billing and collection agents for the state.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Cash Flow Activity
As shown in Entergy’s Consolidated Statements of Cash Flows, cash flows for the years ended December 31, 2014, 2013,2017, 2016, and 20122015 were as follows:
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
| Cash and cash equivalents at beginning of period |
| $739 |
| |
| $533 |
| |
| $694 |
|
| $1,188 |
| |
| $1,351 |
| |
| $1,422 |
|
| |
|
| | | | |
|
| | | | |
| Net cash provided by (used in): | |
| | |
| | |
| |
| | |
| | |
|
| Operating activities | 3,890 |
| | 3,189 |
| | 2,940 |
| 2,624 |
| | 2,999 |
| | 3,291 |
|
| Investing activities | (2,955 | ) | | (2,602 | ) | | (3,639 | ) | (3,841 | ) | | (3,850 | ) | | (2,609 | ) |
| Financing activities | (252 | ) | | (381 | ) | | 538 |
| 810 |
| | 688 |
| | (753 | ) |
| Net increase (decrease) in cash and cash equivalents | 683 |
| | 206 |
| | (161 | ) | |
| Net decrease in cash and cash equivalents | | (407 | ) | | (163 | ) | | (71 | ) |
| | | | | | | | | | | |
| Cash and cash equivalents at end of period |
| $1,422 |
| |
| $739 |
| |
| $533 |
|
| $781 |
| |
| $1,188 |
| |
| $1,351 |
|
Operating Activities
20142017 Compared to 20132016
Net cash flow provided by operating activities increaseddecreased by $701$375 million in 20142017 primarily due to:
higherlower Entergy Wholesale Commodities and Utility net revenue, excluding the effect of revenues resulting from the FitzPatrick reimbursement agreement with Exelon, in 20142017 as compared to prior year, as discussed above. See Note 14 to the financial statements for discussion of the reimbursement agreement;
an increase of $141 million in spending on nuclear refueling outages in 2017 as compared to the same periodprior year;
an increase of $94 million in 2013,severance and retention payments in 2017 as discussed previously;
proceeds of $310 million receivedcompared to the prior year. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the LURCMerchant Power Business” above for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet;
a refund to customers in August 2014January 2017 of approximately $71 million as a result of the Louisiana Act 55 storm cost financings.settlement approved by the LPSC related to the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for a discussion of the Act 55 storm cost financings;settlement and refund;
an increaseproceeds of $60$23 million received in 2014 as2017 compared to 2013 as a resultproceeds of $58$102 million margin deposits made by Entergy Wholesale Commoditiesreceived in 2013;
a decrease in income tax payments of $50 million in 2014 compared2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to 2013 primarily due to state income tax effectsthe financial statements for discussion of the settlement of the 2004-2005 IRS audit paid in 2013;spent nuclear fuel litigation; and
approximately $25 million in spending in 2013 related to the generator stator incident at ANO, as discussed previously.
The increase was partially offset by:
an increase of $236$20 million in pension contributions in 2014, partially offset by a decrease of $38 million in lump sum retirement payments out of the non-qualified pension plan in 2014 as compared to 2013.2017. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;funding.
proceeds
The decrease was partially offset by:
income tax refunds of $72$13 million in 2017 compared to income tax payments of $95 million in 2016. Entergy received income tax refunds in 20132017 resulting from the U.S. Departmentcarryback of Energy resulting from litigation regardingnet operating losses. Entergy made income tax payments in 2016 related to the storageeffect of spent nuclear fuel;the 2006-2007 IRS audit and for jurisdictions that do not have net operating loss carryovers or jurisdictions in which the utilization of net operating loss carryovers are limited. See Note 3 to the financial statements for a discussion of the income tax audit;
an increasea decrease of $44$68 million in spending on nuclear refueling outagesinterest paid in 20142017 as compared to 2013; and
the prior year primarily due to an increaseinterest payment of $25$60 million made in storm restoration spendingMarch 2016 related to the purchase of a beneficial interest in 2014.the Waterford
2013 Compared to 2012
Net cash provided by operating activities increased by $249 million in 2013 primarily due to:
increased recovery of deferred fuel costs;
higher Utility net revenues in 2013 resulting from additional generation investments made in 2012;
Entergy Corporation and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
proceeds3 leased assets. See Note 10 to the financial statements for a discussion of $72 million associated withEntergy Louisiana’s purchase of a beneficial interest in the payments received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel;Waterford 3 leased assets; and
a decrease of approximately $84 million in storm restoration spending in 2013 due to Hurricane Isaac in August 2012, partially offset by an increase of approximately $23 million in storm restoration spending in 2013 due to the Arkansas December 2012 winter storm;
a refundtiming of $30.6 million, including interest, paidrecovery of fuel and purchased power costs in 2017 as compared to AmerenUE in June 2012. The FERC ordered Entergy Arkansas to refund to AmerenUE the rough production cost equalization payments previously collected.prior year. See Note 2 to the financial statements for furthera discussion of fuel and purchased power cost recovery.
2016 Compared to 2015
Net cash flow provided by operating activities decreased by $292 million in 2016 primarily due to:
a decrease due to the timing of recovery of fuel and purchased power costs in 2016 as compared to 2015. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;
lower Entergy Wholesale Commodities net revenue in 2016 as compared to 2015, as discussed previously; and
an increase of $83 million in interest paid in 2016 as compared to 2015 primarily due to an interest payment of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets and an increase in interest expense primarily due to 2016 net debt issuances by various Utility operating companies, partially offset by a decrease in interest paid in 2016 on the Grand Gulf sale-leaseback obligation. See Note 10 to the financial statements for a discussion of Entergy Louisiana’s purchase of a beneficial interest in the Waterford 3 leased assets and for details of the Grand Gulf lease obligation. See Note 5 to the financial statements for a discussion of long-term debt.
The decrease was partially offset by:
higher Utility net revenues in 2016 as compared to 2015, as discussed above;
proceeds of $102 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for discussion of the FERC order; andspent nuclear fuel litigation;
a decrease of $14$46 million in spending on nuclear refueling outages in 20132016 as compared to 2015; and
a decrease of $19 million in spending related to the same periodshutdown of Vermont Yankee, which ceased power production in prior year.December 2014.
Investing Activities
2017 Compared to 2016
Net cash flow used in investing activities decreased by $9 million in 2017 primarily due to the purchase of the Union Power Station for approximately $949 million in March 2016 and proceeds of $100 million from the sale in March 2017 of the FitzPatrick plant to Exelon. See Note 14 to the financial statements for discussion of the Union Power Station purchase and the sale of FitzPatrick. The increasedecrease was partially offset by:
an increase of $79$827 million in income tax paymentsconstruction expenditures, primarily in the Utility business. The increase in construction expenditures in the Utility business is primarily due to the 2013 state income tax effects of the settlement of the 2004-2005 IRS audit in the fourth quarter 2012;
an increase of $52$452 million in lump sum retirement payments outfossil-fueled generation construction expenditures primarily due to higher spending in 2017 on the St. Charles Power Station project and the Lake Charles Power Station project and a higher scope of the non-qualified pension plan, partially offset by work performed on various other fossil projects in 2017 as compared to 2016; an increase of $133 million in distribution construction expenditures primarily due to a higher scope of non-storm related work performed in 2017 as compared to 2016 and higher storm restoration spending in 2017; an increase of $102 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2017 as compared to 2016; an increase of $101 million in transmission construction expenditures primarily due to a higher scope of work performed on transmission projects in 2017 as compared to 2016; and an increase of $51 million due to increased spending on advanced metering infrastructure in 2017;
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
a decrease of $7$144 million in pension contributions.proceeds received from the DOE in 2017 as compared to the prior year resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 118 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;
the decrease in Entergy Wholesale Commodities net revenue that was discussed previously; and
approximately $25 million in spending related to the generator stator incident at ANO, as discussed previously.
Investing Activities
2014 Compared to 2013
Net cash used in investing activities increased by $353 million in 2014 primarily due to:
the deposit of a total of $276 million into storm reserve escrow accounts in 2014, primarily by Entergy Gulf States Louisiana and Entergy Louisiana. See “Hurricane Isaac” above for a discussion of storm reserve escrow account replenishments in 2014;
the withdrawal of a total of $260 million from storm reserve escrow accounts in 2013, primarily by Entergy Gulf States Louisiana and Entergy Louisiana, after Hurricane Isaac. See “Hurricane Isaac” above for discussion of storm reserve escrow account withdrawals;
proceeds of $140 million from the sale in November 2013 of Entergy Solutions District Energy. See Note 15 to the financial statements for further discussion of the sale;
proceeds of $21 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel;fuel litigation; and
an increasea decrease of $63 million in nuclear fuel purchases due to variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle.
2016 Compared to 2015
Net cash flow used in investing activities increased by $1,241 million in 2016 primarily due to:
the purchase of the Union Power Station for approximately $949 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;
proceeds of approximately $490 million from the sale in December 2015 of Rhode Island State Energy Center. See Note 14 to the financial statements for further discussion of the sale; and
an increase of $279 million in construction expenditures, primarily in the Utility business. The increase in construction expenditures in the Utility business is primarily due to an increase of $114 million in transmission construction expenditures primarily due to an overall higher scope of work performed on transmission projects in 2016 as compared to 2015, an increase of $106 million in nuclear construction expenditures primarily due to a higher scope of work on various nuclear projects in 2016 as compared to 2015, an increase of $95 million in fossil-fueled generation construction expenditures primarily due to spending on the St. Charles Power Station project in 2016, an increase of $79 million in distribution construction expenditures primarily due to a higher scope of non-storm related work performed in 2016 as compared to the same period in 2015 and higher storm restoration spending in 2016, and an increase of $65 million in information technology construction expenditures due to various information technology projects and upgrades in 2016. The increase was partially offset by a decrease of $148 million in spending related to compliance with NRC post-Fukushima requirements in the Utility and Entergy Wholesale Commodities businesses.
The increase was partially offset by:
a decrease of $179 million in construction expenditures, primarilynuclear fuel purchases due to variations from year to year in the Utility business, including a decrease in spending ontiming and pricing of fuel reload requirements, material and services deliveries, and the Ninemile 6 self-build project and spending in 2013 ontiming of cash payments during the generator stator incident at ANO, partially offset by nuclear fuel cycle;
an increase in storm restoration spending. Entergy’s construction spending plans for 2015 through 2017 are discussed further in “Capital Expenditure Plans and Other Uses of Capital” above;
a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statement of Cash Flows, as Entergy received net deposits of $47$151 million in 2014proceeds received from the DOE in 2016 as compared to the prior year resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;
a $71 million NYPA value sharing payment in 2015. See Note 14 to the financial statements for further discussion of Entergy’s NYPA value sharing agreements; and returned net deposits
the deposit of $88$64 million into Entergy New Orleans’s storm reserve escrow accounts in 2015.
Financing Activities
2017 Compared to 2016
Net cash flow provided by financing activities increased by $122 million in 2013.2017 primarily due to:
Entergy’s net issuances of $1,123 million of commercial paper in 2017 compared to net repayments of $78 million of commercial paper in 2016;
an increase of $95 million resulting from lower redemptions of preferred stock. In 2017, Entergy Wholesale Commodities’ forward sales contracts are discussed in the “MarketNew Orleans redeemed its $7.8 million of 4.75% Series preferred stock, its $6 million of 5.56% Series preferred stock, and Credit Risk Sensitive Instruments” section below; andits $6 million of 4.36% Series preferred stock. In 2016, Entergy Arkansas redeemed its $75 million of 6.45%
Entergy Corporation and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
$37 million in insurance proceeds received in 2014 for property damages related to the generator stator incident at ANO, as discussed above.
2013 Compared to 2012
Net cash used in investing activities decreased by $1,038Series preferred stock and its $10 million in 2013 primarily due to:
the acquisitions of the Hot Spring plant by Entergy Arkansas6.08% Series preferred stock and the Hinds plant by Entergy Mississippi in November 2012. See Note 15 to the financial statements for further discussion of these plant acquisitions;
the withdrawal of a total of $260 million from storm reserve escrow accounts in 2013, primarily by Entergy Gulf States Louisiana and Entergy Louisiana, after Hurricane Isaac. See Note 2 to the financial statements for a discussion of Hurricane Isaac;
a decrease in construction expenditures, primarily in the Utility business, resulting from spending in 2012 on the uprate project at Grand Gulf and storm restoration spending in 2012 resulting from the Arkansas December 2012 winter storm and Hurricane Isaac, substantially offset by spending in 2013 on the Ninemile 6 self-build project and spending in 2013 related to the generator stator incident at ANO, as discussed previously; and
proceeds of $140 million from the sale in November 2013 of Entergy Solutions District Energy. See Note 15 to the financial statements for further discussion of the sale.
The decrease was partially offset by:
a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statement of Cash Flows, as Entergy returned $50 million more net deposits in 2013 than 2012. Entergy Wholesale Commodities’ forward sales contracts are discussed in the “Market and Credit Risk Sensitive Instruments” section below; and
proceeds of $21 million in 2013 compared to proceeds of $109 million in 2012 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel.
Financing Activities
2014 Compared to 2013
Net cash flow used in financing activities decreased by $129 million in 2014 primarily due to:
long-term debt activity providing approximately $777redeemed its $30 million of cash in 2014 compared to using $69 million of cash in 2013. The most significant long-term debt activity in 2014 included the net issuance of approximately $385 million of long-term debt at the Utility operating companies and System Energy and Entergy Corporation increasing borrowings outstanding on its long-term credit facility by $440 million in 2014;
Entergy Corporation repaid $561 million of commercial paper in 2014 and issued $380 million in 2013;6.25% Series preferred stock;
an increase of $112 million in 2014 compared to a decrease of $129 million in 2013 in short-term borrowings by the nuclear fuel company variable interest entities;
the repurchase of $183 million of Entergy common stock in 2014; and
an increase of $170$48 million in treasury stock issuances in 20142017 primarily due to a larger amount of previously repurchased Entergy Corporation common stock issued in 20142017 to satisfy stock option exercises.exercises; and
net borrowings of $41 million by the nuclear fuel company variable interest entities in 2017 compared to net repayments of $1 million in 2016.
2013 Compared to 2012
Financing activities used $381The increase was partially offset by long-term debt activity providing approximately $224 million in netof cash in 20132017 compared to providing $538approximately $1,489 million of cash in 2016. Included in the long-term debt activity is $490 million in net2017 and $135 million in 2016 for the repayment of borrowings on the Entergy Corporation long-term credit facility.
2016 Compared to 2015
Entergy’s financing activities provided $688 million of cash in 2012for 2016 compared to using $753 million of cash for 2015 primarily due to:to the following activity:
long-term debt activity usingproviding approximately $69$1,489 million of cash in 20132016 compared to providing $348$41 million of cash in 2012. The most significant2015. Included in the long-term debt activity in 2013 included theis net issuancerepayments of approximately
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
$520 million of long-term debt at the Utility operating companies and System Energy and Entergy Corporation decreasing borrowings outstanding on its long-term credit facility by $540 million;
Entergy Corporation issued $380 million of commercial paper in 2013 and $665$135 million in 2012,2016 compared to net borrowings of $140 million in part, to repay borrowings2015 on itsthe Entergy Corporation long-term credit facility;
the issuance of $110 million of preferred stock in 2015. See Note 6 to the financial statements for further discussion;
$100 million of common stock repurchased in 2015, as discussed above;
a net decreaseincrease of $136$41 million in 2016 in short-term borrowings by the nuclear fuel company variable interest entities; and
$51a decrease of $21 million in proceedsresulting from the sale to a third party in 2012higher repurchase/redemptions of a portionpreferred stock. In September 2015, Entergy Louisiana redeemed its $100 million 6.95% Series preferred membership interests, of which $16 million was owned by Entergy Louisiana Holdings, an Entergy subsidiary, and Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s ClassLouisiana repurchased its $10 million Series A 8.25% preferred membership interests.interests as part of a multi-step process to effectuate the Entergy Louisiana and Entergy Gulf States Louisiana business combination. See Note 2 to the financial statements for a discussion of the combination. In 2016, Entergy Arkansas redeemed its $75 million of 6.45% Series preferred stock and its $10 million of 6.08% Series preferred stock and Entergy Mississippi redeemed its $30 million of 6.25% Series preferred stock.
For the details of Entergy’s commercial paper program and the nuclear fuel company variable interest entities’ short-term borrowings, see Note 4 to the financial statements. See Note 5 to the financial statements for details of long-term debt.
Rate, Cost-recovery, and Other Regulation
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that the Utility operating companies and System Energy charge for their services significantly influence Entergy’s financial position, results of operations, and liquidity. These companies are regulated and the rates charged to their customers are determined in regulatory proceedings. Governmental agencies, including the APSC, the City Council, the LPSC, the MPSC, the City Council, the PUCT, and the FERC, are primarily responsible for approval of the rates charged to customers. Following is a summary of the Utility operating companies’ authorized returns on common equity:
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
|
| | |
| Company | | Authorized Return on Common Equity |
| | | |
| Entergy Arkansas | | 9.5% |
Entergy Gulf States Louisiana | | 9.15%-10.75% Electric; 9.45%-10.45% Gas9.25% - 10.25% |
| Entergy Louisiana | | 9.15% - 10.75% Electric; 9.45% - 10.45% Gas |
| Entergy Mississippi | | 10.07%9.47% - 11.49% |
| Entergy New Orleans | | 10.7% - 11.5% Electric; 10.25% - 11.25% Gas |
| Entergy Texas | | 9.8% |
The Utility operating companies’ base rate, fuel and purchased power cost recovery, and storm cost recovery proceedings are discussed in Note 2 to the financial statements.
Federal Regulation
Entergy’s Integration Into the MISO Regional Transmission Organization
In April 2011, Entergy announced that each of the Utility operating companies proposed to join the MISO RTO, an RTO operating in several U.S. states and also in Canada. On December 19, 2013, the Utility operating companies completed their planned integration into the MISO RTO. Becoming a member of MISO does not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities. With the Utility operating companies fully integrated as members, however, MISO assumed control of transmission planning and congestion management and, through its Day 2 market, MISO provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the market.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
The Utility operating companies obtained from each of their retail regulators the public interest findings sought by the Utility operating companies in order to move forward with their plan to join MISO. Each of the retail regulators’ orders includes conditions, some of which entail compliance prospectively. See also “System Agreement - Utility Operating Company Notices of Termination of System Agreement Participation” below.
Beginning in 2011 the Utility operating companies and the MISO RTO began submitting various filings with the FERC that contained many of the rates, terms and conditions that would govern the Utility operating companies’ integration into the MISO RTO. The Utility operating companies and the MISO RTO received the FERC orders necessary for those companies to integrate into the MISO RTO consistent with the approvals obtained from the Utility operating companies’ retail regulators, although some proceedings remain pending at the FERC.
In January 2013, Occidental Chemical Corporation filed with the FERC a petition for declaratory judgment and complaint against MISO alleging that MISO’s proposed treatment of Qualifying Facilities (QFs) in the Entergy region is unduly discriminatory in violation of sections 205 and 206 of the Federal Power Act and violates the Public Utility Regulatory Policies Act (PURPA) and the FERC’s implementing regulations. In February 2014, Occidental also filed a petition for enforcement with the FERC against the LPSC. Occidental’s petition for enforcement alleges that the LPSC’s January 2014 order, which approved Entergy Gulf States Louisiana’s and Entergy Louisiana’s application for modification of Entergy’s methodology for calculating avoided cost rates paid to QFs, is inconsistent with the requirements of PURPA and the FERC’s regulations implementing PURPA. In April 2014 the FERC issued a “Notice Of Intent Not To Act At This Time” with respect to Occidental’s petition for enforcement against the LPSC. The FERC concluded that Occidental’s petition for enforcement largely raises the same issues as those raised in the January 2013 complaint and petition for declaratory order that Occidental filed against MISO, and that the two proceedings should be addressed at the same time. The FERC reserved its ability to issue a further order or to take further action at a future date should it find that doing so is appropriate.
In April 2014, Occidental filed a complaint in federal district court for the Middle District of Louisiana against the LPSC and Entergy Louisiana that challenges the January 2014 order issued by the LPSC on grounds similar to those raised in the 2013 complaint and 2014 petition for enforcement that Occidental previously filed at the FERC. The district court complaint also seeks damages from Entergy Louisiana and a declaration from the district court that in pursuing the January 2014 order Entergy Louisiana breached an existing agreement with Occidental and an implied covenant of good faith and fair dealing. In January 2015 the district court granted Entergy Louisiana’s motion to stay the district court proceeding, pending a decision from the FERC relating to the MISO tariff and market rules that are underlying Occidental’s district court complaint. In January 2015, Occidental filed a motion for reconsideration in the district court and also filed a notice of appeal to the U.S. Fifth Circuit Court of Appeals. In February 2015 the district court denied the motion for reconsideration as moot, finding it lacked jurisdiction to consider the motion because Occidental had sought an appeal to the U.S. Fifth Circuit Court of Appeals.
In February 2013, Entergy Services, on behalf of the Utility operating companies, made a filing with the FERC requesting to adopt the standard Attachment O formula rate template used by transmission owners to establish transmission rates within MISO. The filing proposed four transmission pricing zones for the Utility operating companies, one for Entergy Arkansas, one for Entergy Mississippi, one for Entergy Texas, and one for Entergy Louisiana, Entergy Gulf States Louisiana, and Entergy New Orleans. In June 2013 the FERC issued an order accepting the use of four transmission pricing zones and set for hearing and settlement judge procedures those issues of material fact that FERC decided could not be resolved based on the existing record. Several parties, including the City Council, filed requests for rehearing of the June 2013 order. In February 2014 the FERC issued an order addressing the rehearing requests. Among other things, the FERC denied rehearing and affirmed its prior decision allowing the four transmission pricing zones for the Utility operating companies in MISO. The FERC granted rehearing and set for hearing and settlement judge proceedings certain challenges of MISO’s regional through and out rates. In March 2014 certain parties filed a request for rehearing of the FERC’s February 2014 order on issues related to MISO’s regional through and out rates. In February 2014 and April 2014 various parties appealed the FERC’s June 2013 and February 2014 orders to the U.S. Court of Appeals for the D.C. Circuit where the appeals have been consolidated for further proceedings.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
System Agreement
The FERC regulates wholesale sales of electricity rates (including Entergy Utility intrasystem energy allocations pursuant to the System Agreement) and interstate transmission of electricity, as well asincluding rates for System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. The current return on equity under the Unit Power Sales Agreement is 10.94%. Prior to each operating company’s termination of participation in the System Agreement (Entergy Arkansas in December 2013, Entergy Mississippi in November 2015, and Entergy Louisiana, Entergy New Orleans, and Entergy Texas each in August 2016), the Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which iswas a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System AgreementFERC and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement.federal courts. See Note 2 to the financial statements for discussionsdiscussion of this litigation.
Utility Operating Company Notices of Termination ofthe System Agreement Participation
Consistent with their written notices of termination delivered in December 2005 and November 2007, respectively, Entergy Arkansas and Entergy Mississippiproceedings, a complaint filed with the FERC in February 2009 their notices of cancellationchallenging System Energy’s return on equity, and System Energy’s proposed amendments to terminate their participation in the System Agreement, effective December 18, 2013 and November 7, 2015, respectively. In November 2009 the FERC accepted the notices of cancellation and determined that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96-month notice period without payment of a fee or the requirement to otherwise compensate the remaining Utility operating companies as a result of withdrawal. In December 2009 the LPSC and the City Council filed with the FERC a request for rehearing of the FERC's November 2009 order. In February 2011 the FERC denied the LPSC’s and the City Council’s rehearing requests. In September and October 2012 the U.S. Court of Appeals for the D.C. Circuit denied the LPSC’s and the City Council’s appeals of the FERC decisions. In January 2013 the LPSC and the City Council filed a petition for a writ of certiorari with the U.S. Supreme Court. In May 2013 the U.S. Supreme Court denied the petition for a writ of certiorari. Effective December 18, 2013, Entergy Arkansas ceased participating in the SystemUnit Power Sales Agreement.
In October 2012 the PUCT issued an order approving the transfer of operational control of Entergy Texas’s transmission facilities to MISO as in the public interest, subject to the terms and conditions in a non-unanimous settlement filed with the PUCT in August 2012, with several additional terms and conditions requested by the PUCT and agreed to by the settling parties. In particular, the settlement and the PUCT order required Entergy Texas, unless otherwise directed by the PUCT, to provide by October 31, 2013 its notice to exit the System Agreement, subject to certain conditions. In addition, the PUCT order requires Entergy Texas, as well as Entergy Corporation and Entergy Services, Inc., to exercise reasonable best efforts to engage the Utility operating companies and their retail regulators in searching for a consensual means, subject to FERC approval, of allowing Entergy Texas to exit the System Agreement prior to the end of the mandatory 96-month notice period.
In December 2012 the PUCT Staff filed a memo in the proceeding established by the PUCT to track compliance with its October 2012 order. In the memo, the PUCT Staff expressed concerns about the effect of Entergy Texas’s exit from the System Agreement on PPAs for gas and oil-fired generation units owned by Entergy Texas and Entergy Gulf States Louisiana that were entered into upon the December 2007 jurisdictional separation of Entergy Gulf States, Inc. and, further, expressed concerns about the implications of these issues as they relate to the continuing validity of the PUCT’s October 2012 order regarding MISO. Entergy Texas subsequently filed a position statement relating that Entergy Texas’s exit from the System Agreement would trigger the termination of the PPAs of concern to the PUCT Staff. Entergy Texas expressed its continuing commitment to work collaboratively with the PUCT Staff and other parties to address ongoing issues and challenges in implementing the PUCT order including any potential effect from termination of the PPAs. In January 2013, Entergy Texas filed an updated analysis assessing the effect on the benefits of MISO membership of terminating the particular PPAs addressed in Entergy Texas’s Statement of Position upon Entergy Texas’s exit from the System Agreement, and determined that termination of these PPAs did not adversely affect the benefits of the move to MISO once Entergy Texas exits the System Agreement. An independent consultant
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
was retained to assist the PUCT Staff in its assessment of the analysis. In April 2013 the PUCT staff filed a study performed by its independent consultant assessing Entergy Texas’s January 2013 updated analysis of the effect of termination of certain PPAs on Entergy Texas’s costs upon Entergy Texas’s exit from the System Agreement. While the independent consultant study concluded that the adjustments made in Entergy Texas’s updated analysis were analytically correct, the consultant also recommended further study regarding the effect of the termination of the PPAs on the benefits associated with Entergy Texas joining MISO. Entergy Texas filed a response to the consultant study, noting a number of errors in the analysis and recommending against any further study of this matter. Entergy Texas subsequently agreed to fund further analysis, to be performed by a different independent consultant for the PUCT, regarding the effects of termination of these PPAs. In August 2013 the report of the PUCT’s second independent consultant regarding the effects of termination of these PPAs was filed with the PUCT as part of a larger report addressing the results of the consultant’s comprehensive analysis of Entergy Texas’s transition to operations post-exit from the System Agreement. The report concluded, consistent with Entergy Texas’s updated analysis, that under both the “Foundation Case” capacity price forecast and the high capacity price sensitivity that were performed, Entergy Texas and its customers would be better off on a present-value basis if these PPAs terminate. Under the low capacity price sensitivity, there was a net cost to Entergy Texas customers if these PPAs terminate. Consistent with the requirements of the PUCT conditional order approving the change in control to MISO, on October 18, 2013, Entergy Texas gave notice of cancellation to terminate its participation in the System Agreement.
In November 2012 the Utility operating companies filed amendments to the System Agreement with the FERC pursuant to section 205 of the Federal Power Act. The amendments consist primarily of the technical revisions needed to the System Agreement to (i) allocate certain charges and credits from the MISO settlement statements to the participating Utility operating companies; and (ii) address Entergy Arkansas’s withdrawal from the System Agreement. As noted in the filing, the Utility operating companies’ integration into MISO and the revisions to the System Agreement are the main feature of the Utility operating companies’ future operating arrangements, including the successor arrangements with respect to the departure of Entergy Arkansas from the System Agreement. The LPSC, MPSC, PUCT, and City Council filed protests at the FERC regarding the amendments filed in November 2012 and other aspects of the Utility operating companies’ future operating arrangements, including requests that the continued viability of the System Agreement in MISO (among other issues) be set for hearing by the FERC. On March 12, 2013, the Utility operating companies filed an answer to the protests. The answer proposed, among other things, that: (1) the FERC allow the System Agreement revisions to go into effect as of December 19, 2013, without a hearing and for an initial two-year transition period; (2) no later than October 18, 2013, Entergy Services submit a filing pursuant to section 205 of the Federal Power Act that provides Entergy Texas’s notice of cancellation to terminate participation in the System Agreement and responds to the PUCT’s position that Entergy Texas be allowed to terminate its participation prior to the end of the mandatory 96-month notice period; and (3) at least six months prior to the end of the two-year transition period, Entergy Services submits an additional filing under section 205 of the Federal Power Act that addresses the allocation of MISO charges and credits among the Utility operating companies that remain in the System Agreement. On December 18, 2013, the FERC issued an order accepting the revisions filed in November 2012, subject to a further compliance filing and other conditions. The FERC set one issue for hearing involving a settlement with Union Pacific regarding certain coal delivery issues. Consistent with the decisions described above, Entergy Arkansas’s participation in the System Agreement terminated effective December 18, 2013. In December 2014 a FERC ALJ issued an initial decision finding that Entergy Arkansas would realize benefits after December 18, 2013 from the 2008 settlement agreement between Entergy Services, Entergy Arkansas, and Union Pacific, related to certain coal delivery issues. The ALJ further found that all of the Utility operating companies should share in those benefits pursuant to the methodology proposed by the MPSC. The Utility operating companies and other parties to the proceeding have filed briefs on exceptions and/or briefs opposing exceptions with the FERC challenging various aspects of the December 2014 initial decision and the matter is pending before the FERC.
In keeping with the commitments made in their March 2013 answer to the protests and after a careful evaluation of the basis for and continued reasonableness of the 96-month System Agreement termination notice period, the Utility operating companies filed with the FERC on October 11, 2013 to amend the System Agreement changing the notice period for an operating company to terminate its participation in the System Agreement from 96 months to 60 months. The proposed amendment also clarifies that the revised notice period will apply to any written notice of termination
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
provided by an operating company on or after October 12, 2013. On October 18, 2013, Entergy Texas provided notice to terminate its participation in the System Agreement effective after expiration of the proposed 60-month notice period or such other period as approved by FERC. The proposed amendment and Entergy Texas’s termination notice are without prejudice to continuing efforts among affected operating companies and their retail regulators to search for a consensual means of allowing Entergy Texas an early exit from the System Agreement, which could be different from that proposed in the October 11, 2013 FERC filing. Comments on both filings were filed in November 2013.
The LPSC, the City Council, and the PUCT protested the proposed amendment to shorten the notice period for an operating company to terminate its participation in the System Agreement from 96 months to 60 months. The City Council argued that Entergy has not adequately supported its proposal to shorten the notice period from 96 months to 60 months and asked the FERC to either reject the amendment or set it for hearing. The PUCT supported shortening of the notice period, but argued that 60 months is not short enough and that the FERC should instead order Entergy to shorten the notice period to correspond to the time required for a Utility operating company to become operationally ready to participate in the MISO markets (but no longer than 36 months). The LPSC argued that the 60-month proposal was not justified and failed to make provision for the consequences that would flow from a company’s withdrawal from the System Agreement. The LPSC and the City Council both separately protested Entergy Texas’s termination notice.
In January 2014 the LPSC issued a directive that no later than February 15, 2014, Entergy Louisiana and Entergy Gulf States Louisiana each shall provide notice of their intention to terminate their participation in the System Agreement and shall make the necessary filings at the FERC of such notice. The LPSC further directed that Entergy Louisiana and Entergy Gulf States Louisiana and LPSC Staff continue utilizing their reasonable best efforts to achieve a consensual resolution permitting early termination of the System Agreement. On February 14, 2014, Entergy Louisiana and Entergy Gulf States Louisiana provided notice of their respective decisions to terminate their participation in the System Agreement and made a filing with the FERC seeking acceptance of the notice. In the FERC filing, Entergy Louisiana and Entergy Gulf States Louisiana requested an effective date of February 14, 2019 or such other effective date approved by the FERC for the termination. In March 2014 the City Council submitted comments to the FERC regarding the notices of termination. The City Council requested the FERC either to condition its acceptance of the notices on compliance with the prior 96-month notice termination period, or in the alternative, to consolidate the notice filings with the proceeding related to the Utility operating companies’ proposal to shorten the System Agreement’s termination notice period from 96 months to 60 months, and to set all of the proceedings for hearing. Also in March 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed a response to the City Council’s comments requesting that the FERC accept the notices without hearing and with an effective date subject to and consistent with the notice period established by the FERC in the proceeding related to the Utility operating companies’ proposal to shorten the System Agreement’s termination notice period.
In December 2014 the FERC issued an order setting the proposed amendment changing the notice period from 96 months to 60 months for settlement judge and hearing procedures. The FERC’s order also conditionally accepted the notices of termination filed by Entergy Texas, Entergy Louisiana, and Entergy Gulf States Louisiana, to be effective as of the dates requested in those filings, subject to the outcome of the settlement judge procedures and hearing on the proposed amendment. Entergy Louisiana, Entergy Gulf States Louisiana, Entergy New Orleans, and Entergy Texas continue to explore with the LPSC staff, City Council advisors, and the PUCT staff the early termination of the System Agreement on a consensual basis.
U.S. Department of Justice Investigation
In September 2010, Entergy was notified that the U.S. Department of Justice had commenced a civil investigation of competitive issues concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies. In November 2012 the U.S. Department of Justice issued a press release in which the U.S. Department of Justice stated, among other things, that the civil investigation concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies would remain open. The release noted, however, the intention of each of the Utility operating companies
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
to join MISO and Entergy’s agreement with ITC to undertake the spin-off and merger of Entergy’s transmission business. The release stated that if Entergy follows through on these matters, the U.S. Department of Justice’s concerns will be resolved. The release further stated that the U.S. Department of Justice will monitor developments, and in the event that Entergy does not make meaningful progress, the U.S. Department of Justice can and will take appropriate enforcement action, if warranted. On December 13, 2013, Entergy and ITC mutually agreed to terminate the transaction following denial by the MPSC of the joint application related to the transaction. On December 19, 2013, the Utility operating companies successfully completed their planned integration into the MISO RTO.
Market and Credit Risk Sensitive Instruments
Market risk is the risk of changes in the value of commodity and financial instruments, or in future net income or cash flows, in response to changing market conditions. Entergy holds commodity and financial instruments that are exposed to the following significant market risks.
The commodity price risk associated with the sale of electricity by the Entergy Wholesale Commodities business.
The interest rate and equity price risk associated with Entergy’s investments in pension and other postretirement benefit trust funds. See Note 11 to the financial statements for details regarding Entergy’s pension and other postretirement benefit trust funds.
The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds, particularly in the Entergy Wholesale Commodities business. See Note 1716 to the financial statements for details regarding Entergy’s decommissioning trust funds.
The interest rate risk associated with changes in interest rates as a result of Entergy’s outstanding indebtedness. Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization. See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding.
The Utility has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail regulators, the Utility operating companies use commodity and financial instruments to hedge the exposure to price volatility inherent in their purchased power, fuel, and gas purchased for resale costs that are recovered from customers.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy’s commodity and financial instruments are also exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Entergy is also exposed to a potential demand on liquidity due to credit support requirements within its supply or sales agreements.
Commodity Price Risk
Power Generation
As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy in the day ahead or spot markets. In addition to selling the energy produced by its plants, Entergy Wholesale Commodities also sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both. In addition to its forward physical power contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, and options, to manage forward commodity price risk. Certain hedge volumes have price downside and upside relative to market price movement. The contracted minimum, expected value, and sensitivities are provided in the table below to show potential variations. The sensitivities may not reflect the total
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
maximum upside potential from higher market prices. The information contained in the following table represents projections at a point in time and will vary over time based on numerous factors, such as future market prices, contracting activities, and generation. Following is a summary of Entergy Wholesale Commodities’ current forward capacity and generation contracts as well as total revenue projections based on market prices as of December 31, 2014.2017.
Entergy Wholesale Commodities Nuclear Portfolio
|
| | | | | | | | | | |
| | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
| Unit-contingent (b) | | 47% | | 23% | | 14% | | 14% | | 16% |
| Unit-contingent with availability guarantees (c) | | 18% | | 17% | | 18% | | 3% | | 3% |
| Firm LD (d) | | 40% | | 34% | | 7% | | —% | | —% |
| Offsetting positions (e) | | (19%) | | —% | | —% | | —% | | —% |
| Total | | 86% | | 74% | | 39% | | 17% | | 19% |
| Planned generation (TWh) (f) (g) | | 35 | | 36 | | 35 | | 35 | | 36 |
| Average revenue per MWh on contracted volumes: | | | | | | | | | | |
| Minimum | | $47 | | $47 | | $48 | | $56 | | $57 |
| Expected based on market prices as of December 31, 2014 | | $48 | | $49 | | $50 | | $56 | | $57 |
| Sensitivity: -/+ $10 per MWh market price change | | $47-$50 | | $47-$53 | | $49-$53 | | $56 | | $57 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
| Bundled capacity and energy contracts (i) | | 18% | | 18% | | 18% | | 18% | | 18% |
| Capacity contracts (j) | | 30% | | 15% | | 16% | | 7% | | —% |
| Total | | 48% | | 33% | | 34% | | 25% | | 18% |
| Planned net MW in operation (g) | | 4,406 | | 4,406 | | 4,406 | | 4,406 | | 4,406 |
| Average revenue under contract per kW per month(applies to capacity contracts only) | | $3.9 | | $3.4 | | $5.6 | | $7.0 | | $— |
| | | | | | | | | | | |
| Total Nuclear Energy and Capacity Revenues | | | | | | | | | | |
| Expected sold and market total revenue per MWh | | $53 | | $50 | | $50 | | $51 | | $53 |
| Sensitivity: -/+ $10 per MWh market price change | | $51-$56 | | $46-$56 | | $44-$57 | | $43-$60 | | $45-$61 |
Entergy Corporation and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
Entergy Wholesale Commodities Non-NuclearNuclear Portfolio
|
| | | | | | | | | | |
| | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
| Cost-based contracts (k) | | 38% | | 36% | | 34% | | 34% | | 34% |
| Firm LD (d) | | 7% | | 7% | | 7% | | 7% | | 7% |
| Total | | 45% | | 43% | | 41% | | 41% | | 41% |
| Planned generation (TWh) (f) (l) | | 5 | | 6 | | 6 | | 6 | | 6 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
| Cost-based contracts (k) | | 24% | | 24% | | 26% | | 26% | | 26% |
| Bundled capacity and energy contracts (i) | | 8% | | 8% | | 8% | | 8% | | 8% |
| Capacity contracts (j) | | 54% | | 53% | | 57% | | 24% | | —% |
| Total | | 86% | | 85% | | 91% | | 58% | | 34% |
| Planned net MW in operation (l) | | 1,052 | | 1,052 | | 977 | | 977 | | 977 |
|
| | | | | | | | | | |
| | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
| Unit-contingent (b) | | 98% | | 91% | | 51% | | 74% | | 67% |
| Firm LD (c) | | 9% | | —% | | —% | | —% | | —% |
| Offsetting positions (d) | | (9%) | | —% | | —% | | —% | | —% |
| Total | | 98% | | 91% | | 51% | | 74% | | 67% |
| Planned generation (TWh) (e) (f) | | 27.9 | | 25.5 | | 17.9 | | 9.7 | | 2.8 |
| Average revenue per MWh on contracted volumes: | | | | | | | | | | |
| Expected based on market prices as of December 31, 2017 | | $39.1 | | $40.6 | | $50.5 | | $59.2 | | $58.8 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (g): | | | | | | | | | | |
| Bundled capacity and energy contracts (h) | | 22% | | 25% | | 36% | | 69% | | 99% |
| Capacity contracts (i) | | 36% | | 13% | | —% | | —% | | —% |
| Total | | 58% | | 38% | | 36% | | 69% | | 99% |
| Planned net MW in operation (average) (f) | | 3,568 | | 3,167 | | 2,195 | | 1,158 | | 338 |
| Average revenue under contract per kW per month (applies to capacity contracts only) | | $7.1 | | $9.1 | | $— | | $— | | $— |
| | | | | | | | | | | |
| Total Energy and Capacity Revenues (j) | | | | | | | | | | |
| Expected sold and market total revenue per MWh | | $47.0 | | $46.9 | | $48.9 | | $56.1 | | $47.8 |
| Sensitivity: -/+ $10 per MWh market price change | | $46.9 - $47.2 | | $46.0 - $47.8 | | $44.3 - $53.5 | | $53.5 - $58.7 | | $44.5 - $51.1 |
| |
| (a) | Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty that may require regulatory approval or approval of transmission rights. Positions that are not classified as hedges are netted in the planned generation under contract. |
| |
| (b) | Transaction under which power is supplied from a specific generation asset; if the asset is not operating, the seller is generally not liable to buyer for any damages. |
| |
(c) | A sale of power on a Certain unit-contingent basis coupled withsales include a guarantee of availability providesavailability. Availability guarantees provide for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees. |
| |
(d)(c) | Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract, a portion of which may be capped through the use of risk management products. This also includes option transactions that may expire without being exercised. |
| |
(e)(d) | Transactions for the purchase of energy, generally to offset a Firm LD transaction. |
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(f)(e) | Amount of output expected to be generated by Entergy Wholesale Commodities resources considering plant operating characteristics, outage schedules, and expected market conditions that affect dispatch. |
| |
(g)(f) | Assumes NRC license renewals for plants whose current licenses expired or expire within five years, and uninterrupted normal operation at all operating plants. NRC license renewal applications are in process for two units, as follows (with current license expirations in parentheses):the planned shutdown of Pilgrim on May 31, 2019, planned shutdown of Indian Point 2 (September 2013 and now operating under its periodon April 30, 2020, planned shutdown of extended operations while its application is pending) and Indian Point 3 (December 2015). For a discussion regarding the license renewal applicationon April 30, 2021, and planned shutdown of Palisades on May 31, |
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Management’s Financial Discussion and Analysis
2022. Assumes NRC license renewals for two units, as follows (with current license expirations in parentheses): Indian Point 2 (September 2013 and now operating under its period of extended operations while its application is pending) and Indian Point 3 (December 2015 and now operating under its period of extended operations while its application is pending). For a discussion regarding the planned shutdown of the Pilgrim, Indian Point 2, Indian Point 3, and Palisades plants, see “Entergy Wholesale Commodities Exit from the Merchant Power Business” above. For a discussion regarding the license renewals for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” above.
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(h)(g) | Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions. |
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(i)(h) | A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold. |
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(j)(i) | A contract for the sale of an installed capacity product in a regional market. |
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(k)(j) | Contracts priced in accordanceIncludes assumptions on converting a portion of the portfolio to contracted with cost-based rates, a ratemaking concept used forfixed price cost or discount and excludes non-cash revenue from the designamortization of the Palisades below-market purchased power agreement, mark-to-market activity, and development of rate schedules to ensure that the filed rate schedules recover only the cost of providing the service; these contracts are on owned non-utility resources located within Entergy’s Utility service area and were executed |
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Management's Financial Discussion and Analysis
prior to receiving market-based rate authority under MISO. The percentage sold assumes completion of the necessary transmission upgrades required for the approved transmission rights.
| |
(l) | Non-nuclear planned generation and net MW in operation include purchases from affiliated and non-affiliated counterparties under long-term contracts and exclude energy and capacity from Entergy Wholesale Commodities’ wind investment. The decrease in planned net MW in operation beginning in 2017 is due to the expiration of a non-affiliated 75 MW contact.revenues. |
Entergy estimates that a positive $10 per MWh change in the annual average energy price in the markets in which the Entergy Wholesale Commodities nuclear business sells power, based on the respective year-end market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax income of $107$3 million in 20152018 and would have had a corresponding effect on pre-tax income of $240$37 million in 2014.2017. A negative $10 per MWh change in the annual average energy price in the markets based on the respective year-end market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax income of ($73)3) million in 20152018 and would have had a corresponding effect on pre-tax income of ($91)31) million in 2014.2017.
Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, NYPAEntergy subsidiaries and the subsidiaries that own the FitzPatrick and Indian Point 3 plantsNYPA amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements, the Entergy subsidiaries agreed to makemade annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014. Entergy subsidiaries paid NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24 million. The annual payment for each year’s output iswas due by January 15 of the following year.year, and the final payment to NYPA was made in January 2015. Entergy recordsrecorded the liability for payments to NYPA as power iswas generated and sold by Indian Point 3 and FitzPatrick. In 2014, 2013, and 2012, Entergy Wholesale Commodities recorded a liability of approximately $72 million for generation during each of those years. An amount equal to the liability was recorded each year to the plant asset account as contingent purchase price consideration for the plants. This amount will be depreciated over the expected remaining useful life of the plants.
Some of the agreements to sell the power produced by Entergy Wholesale Commodities’ power plants contain provisions that require an Entergy subsidiary to provide collateralcredit support to secure its obligations under the agreements. The Entergy subsidiary is required to provide collateralcredit support based upon the difference between the current market prices and contracted power prices in the regions where Entergy Wholesale Commodities sells power. The primary form of collateralcredit support to satisfy these requirements is an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral.credit support. At December 31, 2014,2017, based on power prices at that time, Entergy had liquidity exposure of $159$167 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $5$8 million of posted cash collateral. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2014,2017, Entergy would have been required to provide approximately $51$98 million of additional cash or letters of credit under some of the agreements. As of December 31, 2014,2017, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $52$372 million for a $1 per MMBtu increase in gas prices in both the short-andshort- and long-term markets.
As of December 31, 2014,2017, substantially all of the counterparties or their guarantors forcredit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 20182022 is with counterparties or their guarantors that have public investment grade credit ratings.
Nuclear Matters
After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently
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refinedNuclear Matters
Entergy’s Utility and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based uponEntergy Wholesale Commodities businesses include the task force’s recommendations,ownership and operation of nuclear generating plants and are, therefore, subject to the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operatorsrisks related to undertake plant modificationssuch ownership and perform additional analyses that will, among other things, result in increased operatingoperation. These include risks related to: the use, storage, and capital costs associated with operating nuclear plants. The NRC, with input fromhandling and disposal of high-level and low-level radioactive materials; the industry, is continuing to determine the specific actions required by the orders. Entergy’s estimated capital expendituressubstantial financial requirements, both for 2015 through 2017 for complying with the NRC orders are included in the planned construction and other capital investments estimates given in “Liquidity and Capital Resources - Capital Expenditure Plans and Other Uses of Capital” above.
In June 2012operational needs, to position Entergy’s nuclear fleet to meet its operational goals, including the U.S. Court of Appeals for the D.C. Circuit vacated the NRC’s 2010 update to its Waste Confidence Decision, which had found generically that a permanent geologic repository to store spent nuclear fuel would be available when necessary and that spent nuclear fuel could be stored at nuclear reactor sites in the interim without significant environmental effects, and remanded the case for further proceedings. The court concluded that the NRC had not satisfied thefinancial requirements of the National Environmental Policy Act (NEPA) when it considered environmental effects in reaching these conclusions. The Waste Confidence Decision has been relied upon by NRC license renewal applicants to address some of theemerging issues that the NEPA requires the NRC to address before it issues a renewed license. Certain nuclear opponents filed requests with the NRC asking it to address the issues raised by the court’s decision in the license renewal proceedings for a number of nuclear plants including Grand Gulf and Indian Point 2 and 3. In August 2012 the NRC issued an order stating that it will not issue final licenses dependent upon the Waste Confidence Decision until the D.C. Circuit’s remand is addressed, but also stating that licensing reviews and proceedings should continue to move forward. In September 2014 the NRC published a new final Waste Confidence rule, named Continued Storage of Spent Nuclear Fuel, that for licensing purposes adopts non-site specific findings concerning the environmental impacts of the continued storage of spent nuclear fuel at reactor sites - for 60 years, 100 years and indefinitely - after the reactor’s licensed period of operations. The NRC also issued an order lifting its suspension of licensing proceedings after the final rule’s effective date in October 2014. After the final rule became effective, New York, Connecticut, and Vermont filed a challenge to the rule in the U.S. Court of Appeals. The final rule remains in effect while that challenge is pending unless the court orders otherwise.
The nuclear industry continues to address susceptibility tolike stress corrosion cracking of certain materials within the reactor coolant system. The issue is applicableplant systems and the Fukushima event; the implementation of plans to cease merchant generation at all Entergy Wholesale Commodities nuclear unitsplants by 2022 and the post-shutdown decommissioning of these plants; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license renewal and amendments, and decommissioning; the performance and capacity factors of these nuclear plants; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to varying degreescomplete decommissioning of each site when required; and is managedlimitations on the amounts and types of insurance commercially available for losses in accordanceconnection with industry standard practicesnuclear plant operations and guidelinescatastrophic events such as a nuclear accident.
ANO
See Note 8 to the financial statements for discussion of the NRC’s decision in March 2015 to move ANO into the “multiple/repetitive degraded cornerstone column,” or Column 4, of the NRC’s Reactor Oversight Process Action Matrix, and the resulting significant additional NRC inspection activities at the ANO site.
Pilgrim
See Note 8 to the financial statements for discussion of the NRC’s decision in September 2015 to place Pilgrim in Column 4 of its Reactor Oversight Process Action Matrix due to its finding of continuing weaknesses in Pilgrim’s corrective action program that include in-service examinations, replacements,contributed to repeated unscheduled shutdowns and mitigation strategies. Developmentsequipment failures.
Indian Point
During the scheduled refueling and maintenance outage at Indian Point 2 in the industry or identificationfirst quarter 2016, comprehensive inspections were done as part of the aging management program that calls for an in-depth inspection of the reactor vessel. Inspections of more than 2,000 bolts in the reactor’s removable insert liner identified issues with roughly 11% of the bolts that required further analysis. Entergy replaced bolts as appropriate, and the unit returned to service in June 2016. In 2016, Entergy evaluated the scope and duration of Indian Point 3’s scheduled refueling outage planned for 2017, which began in March 2017. Based on the results of the 2016 evaluation and analysis, Entergy extended Indian Point 3’s planned 2017 outage duration. Entergy performed the same in-depth inspection of the reactor vessel at Indian Point 3 during Indian Point 3’s spring 2017 refueling and maintenance outage that it performed for Indian Point 2. Based on inspection data, Entergy replaced approximately the nuclear units could require unanticipated remediation effortssame number of bolts at Indian Point 3 that cannot be quantifiedit replaced at Indian Point 2 before returning the plant to service in advance.May 2017.
Grand Gulf
Grand Gulf began a maintenance outage on September 8, 2016 to replace a residual heat removal pump. Although the pump had been replaced, on September 27, 2016 management decided to keep the plant in an outage for additional training and other steps to support management’s operational goals. Grand Gulf returned to service on January 31, 2017.
Based on the plant’s performance indicators, in November 2016 the NRC placed Grand Gulf in the “regulatory response column,” or Column 2, of its Reactor Oversight Process Action Matrix. Entergy is implementing a plan to restore Grand Gulf to Column 1, including addressing the issues related to the three very low safety significance non-
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cited violations identified in the NRC’s report on the results of its October 2016 special inspection. Depending on the success of implementing that plan and the plant’s performance indicators, there is risk that the NRC could move Grand Gulf into the “degraded cornerstone column,” or Column 3, of the NRC’s Reactor Oversight Process Action Matrix.
Critical Accounting Estimates
The preparation of Entergy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy’s financial position, results of operations, or cash flows.
Nuclear Decommissioning Costs
Entergy subsidiaries own nuclear generation facilities in both the Utility and Entergy Wholesale Commodities operating segments. Regulations require Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and cash is deposited in trust funds during the facilities’ operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates.
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Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated. A highestimated for those plants that do not have an announced shutdown date. The estimate may include assumptions regarding the possibility that the plant may have an operating life shorter than the operating license expiration, as well as assumptions regarding the probability that the plant’s license will be renewed and the plant will operate for some time beyond the originalthose plants that have not yet received operating license term has been assumed for purposes of calculating the decommissioning liability for a number of Entergy’s nuclear units.renewal. Second, an assumption must be made whether all decommissioning activity will proceed immediately upon plant retirement, or whether the plant will be placed in SAFSTOR status. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. A change of assumption regarding either the probability of license renewal, the period of continued operation, or the use of a SAFSTOR period can change the present value of the asset retirement obligations.obligation.
Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2% to 3.25%.3% annually. A 50 basis50-basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 9%3% to 15%18%. The timing assumption influences the significance of the effect of a change in the estimated inflation or cost escalation rate because the effect increases with the length of time assumed before decommissioning activity ends.
Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. The current Presidential administration, however, has defunded the Yucca Mountain project. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy’s nuclear plant owners are continuing to pursue damage claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy’s decommissioning studies include cost estimates for spent fuel storage, when applicable.storage. These estimates could change in the future, however, based on the expected timing of when the DOE begins to fulfill its obligation to receive and store spent nuclear fuel. See Note 8 to the financial statements for further discussion of Entergy’s spent nuclear fuel litigation.
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Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of nuclear facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates. Given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could occur, however, and affect current cost estimates. In addition, if regulations regarding nuclear decommissioning were to change, this could significantly affect cost estimates.
Interest Rates - The estimated decommissioning costs that are the basis for the recorded decommissioning liability are discounted to present value using a credit-adjusted risk-free rate. When the decommissioning liability is revised, increases in cash flows are discounted using the current credit-adjusted risk-free rate. Decreases in estimated cash flows are discounted using the credit-adjusted risk-free rate used previously in estimating the decommissioning liability that is being revised. Therefore, to the extent that a revised cost study results in an increase in estimated cash flows, a change in interest rates from the time of the previous cost estimate will affect the calculation of the present value of the revised decommissioning liability.
Future revisionsRevisions of estimated decommissioning costs that decrease the liability also result in a decrease in the asset retirement cost asset. For the non-rate-regulated portions of Entergy’s business for which the plant’s value is impaired, these reductions will immediately reduce operating expenses in the period of the revision if the reduction of the liability exceeds the amount of the undepreciated asset retirement costplant asset at the date of the revision. Future revisionsRevisions of estimated decommissioning costs that increase the liability result in an increase in the asset retirement cost asset, which is then depreciated over the asset’s remaining economic life. For a plant in the non-rate-regulated portions of Entergy’s business for which the plant’s value is impaired, however, including a plant that is shutdown, or is nearing its shutdown date, however, for the non-rate-regulated portions of Entergy’s business the increase in the liability willis likely to immediately increase operating expense in the period of the revision and not increase the asset retirement cost asset.
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In 2014, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study. The revised estimates resulted in a $47.6 million increase in the decommissioning cost liabilities, along with a corresponding increase in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.
See Note 114 to the financial statements for further discussion of the shutdownimpairment of Vermont Yankeelong-lived assets and the December 2013 settlement agreement involving Entergy and Vermont parties. In accordance with the settlement agreement, Entergy Vermont Yankee provided to the Vermont parties, in 2014, a site assessment study of the costs and tasks of radiological decommissioning, spent nuclear fuel management, and site restoration for Vermont Yankee. Entergy Vermont Yankee also filed its Post-Shutdown Decommissioning Activities Report (PSDAR) for Vermont Yankee with the NRC in December 2014. As part of the development of the site assessment study and PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2014. The revised estimate, along with reassessment of the assumptions regarding the timing of decommissioning cash flows, resulted in a $101.6 million increase in the decommissioning cost liability and a corresponding impairment charge.
In the fourth quarter 2014, Entergy Gulf States Louisiana recorded a revision to its estimated decommissioning cost liability for River Bend as a result of a revised decommissioning cost study. The revised estimate resulted in a $20 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining useful life of the unit.
In the fourth quarter 2014, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $99.9 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.
In the first quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for a nuclear site as a result of a revised decommissioning cost study. The revised estimate resulted in a $46.6 million reduction in the decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset.
In the third quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee as a result of a revised decommissioning cost study. The revised estimate resulted in a $58 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the plant. The asset retirement cost asset was included in the carrying value used to write down Vermont Yankee and related assets to their fair values in third quarter 2013. See Note 19 to the financial statements for further discussion of the resulting impairment charge recorded in third quarter 2013.asset retirement obligations.
In the fourth quarter 2013,Utility Regulatory Accounting
Entergy’s Utility operating companies and System Energy recordedare subject to retail regulation by their respective state and local regulators and to wholesale regulation by the FERC. Because these regulatory agencies set the rates the Utility operating companies and System Energy are allowed to charge customers based on allowable costs, including a revisionreasonable return on equity, the Utility operating companies and System Energy apply accounting standards that require the financial statements to its estimated decommissioning cost liability for Grand Gulf as a resultreflect the effects of a revised decommissioning cost study. The revised estimate resulted in a $102.3 million increase in its decommissioning liability, along with a corresponding increase inrate regulation, including the related asset retirement cost assetrecording of regulatory assets and liabilities. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs that have been deferred because it is probable such amounts will be depreciated over the remaining life of the unit.
In the fourth quarter 2013, Entergy Louisiana recorded a revisionreturned to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $39.4 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.
In the fourth quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee. As a result of a settlement agreement regarding the remaining operation and decommissioning of Vermont Yankee, Entergy reassessed its assumptions regarding the timing of
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decommissioning cash flows. The reassessment resulted in a $27.2 million increase in the decommissioning cost liability and a corresponding impairment charge.customers through future regulated rates. See Note 12 to the financial statements for furthera discussion of rate and regulatory matters, including details of Entergy’s and the Vermont Yankee plant.Registrant Subsidiaries’ regulatory assets and regulatory liabilities.
InFor each regulatory jurisdiction in which they conduct business, the second quarter 2012,Utility operating companies and System Energy assess whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. If the assessments made by the Utility operating companies and System Energy are ultimately different than actual regulatory outcomes, it could materially affect the results of operations, financial position, and cash flows of Entergy Wholesale Commodities recorded a reduction of $60.6 million inor the estimated decommissioning cost liability for a plant as a result of a revised decommissioning cost study. The revised estimate resulted in a credit to decommissioning expense of $49 million, reflecting the excess of the reduction in the liability over the amount of the undepreciated asset retirement costs asset.Registrant Subsidiaries.
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized
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during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Impairment of Long-lived Assets and Trust Fund Investments
Entergy has significant investments in long-lived assets in both of its operating segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment when there are indications that an impairment may exist. This evaluation involves a significant degree of estimation and uncertainty. In the Entergy Wholesale Commodities business, Entergy’s investments in merchant generation assets are subject to impairment if adverse market or regulatory conditions arise, particularly if it leads to a decision foror an expectation that Entergy towill operate a plant for a shorter period than previously expected; if there is a significant adverse change in the physical condition of a plant; if investment in a plant significantly exceeds expected levels;previously-expected amounts; or, for certain nuclear plantsIndian Point 2 and Indian Point 3, if their operating licenses are not renewed.
If an asset is considered held for use, and Entergy concludes that events and circumstances are present indicating that an impairment analysis has been triggeredshould be performed under the accounting standards, the sum of the expected undiscounted future cash flows from the asset are compared to the asset’s carrying value. The carrying value of the asset includes any capitalized asset retirement cost associated with the decommissioning liability,liability; therefore, changes in assumptions that affect the decommissioning liability can increase or decrease the carrying value of the asset subject to impairment. If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded. If the expected undiscounted future cash flows are less than the carrying value and the carrying value exceeds the fair value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is considered held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.
These estimatesThe expected future cash flows are based on a number of key assumptions, including:
Future power and fuel prices - Electricity and gas prices can be very volatile. This volatility increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows.
Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, these transactions are relatively infrequent, the market for such assets is volatile, and the value of individual assets is affected by factors unique to those assets.
Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant effect on operations could cause a significant change in these assumptions.
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Timing and the life of the asset - Entergy currently assumes for somean expected life of its nuclear units, that the plant’s license will be renewed.asset. A change in thatthe timing assumption, whether due to management decisions regarding operation of the plant, the regulatory process, or operational or other factors, could have a significant effect on the expected future cash flows and result in a significant effect on operations.
For additional discussion regarding the shutdown of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” inSee Note 114 to the financial statements.statements for a discussion of the impairments of the Palisades, Indian Point, FitzPatrick, and Pilgrim plants.
Entergy evaluates investment securities in the Entergy Wholesale Commodities’ nuclear decommissioning trust funds with unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. If Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary-impairment is considered to have occurred and it is measured by the
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present value of cash flows expected to be collected less the amortized cost basis (credit loss). Entergy did not have any material other than temporary impairments relating to credit losses on debt securities in 2014, 2013, or 2012. The assessment of whether an investment in an equity security has suffered an other than temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. As discussed in Note 1 to the financial statements, unrealized losses on equity securities that are considered other-than-temporarily impaired are recorded in earnings for Entergy Wholesale Commodities. Entergy Wholesale Commodities did not record material charges to other incomeEffective January 1, 2018 with the adoption of ASU 2016-01, unrealized losses and gains on investments in 2014, 2013, or 2012 resulting from the recognition of other-than-temporary impairment of equity securities held in itsby the Entergy Wholesale Commodities’ nuclear decommissioning trust funds will be recorded in earnings as they occur. See Note 16 to the financial statements for details on the decommissioning trust funds.
Taxation and Uncertain Tax Positions
Management exercises significant judgment in evaluating the potential tax effects of Entergy’s operations, transactions, and other events. Entergy accounts for uncertain income tax positions using a recognition model under a two-step approach with a more likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement. Management evaluates each tax position based on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether available information supports the assertion that the recognition threshold has been met. Additionally, measurement of unrecognized tax benefits to be recorded in the consolidated financial statements is based on the probability of different potential outcomes. Income tax expense and tax positions recorded could be significantly affected by events such as additional transactions contemplated or consummated by Entergy as well as audits by taxing authorities of the tax positions taken in transactions. Management believes that the financial statement tax balances are accounted for and adjusted appropriately each quarter as necessary in accordance with applicable authoritative guidance; however, the ultimate outcome of tax matters could result in favorable or unfavorable effects on the consolidated financial statements. Entergy’s income taxes, including unrecognized tax benefits, open audits, and other significant tax matters are discussed in Note 3 to the financial statements.
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Income Tax Legislation” above and Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified, defined benefit pension plans that cover substantially all employees.employees, including cash balance plans and final average pay plans. Additionally, Entergy currently provides other postretirement health care and life insurance benefits for substantially all full-time employees whose most recent date of hire or rehire is before July 1, 2014 and who reach retirement age and meet certain eligibility requirements while still working for Entergy.
In December 2013, Entergy announced that employees hired or rehired after June 30, 2014, will participate in a new cash balance defined benefit pension plan and will be eligible to receive an enhanced employer matching contribution under one of the Entergy defined contribution plans, rather than the current final average pay defined benefit pension plan and employer matching contribution. These changes are prospective and have no effect on the December 31, 2013 pension obligation. Additionally, at the same time, Entergy announced changes to its other postretirement benefits which include, among other things, elimination of other postretirement benefits for all non-bargaining employees hired or rehired after June 30, 2014 and for certain bargaining employees hired or rehired after June 30, 2014, or such later date provided for in their applicable collective bargaining agreement, and setting a dollar limit cap on Entergy’s contribution to retiree medical costs, effective 2019 for those non-bargaining employees who commence their Entergy retirement benefits on or after January 1, 2015 and for certain bargaining employees who commence their Entergy retirement benefits on or after January 1, 2015 or such later date as provided for in their applicable collective bargaining agreement. In accordance with accounting standards, certain of the other postretirement benefit changes have been reflected in the December 31, 2013 other postretirement obligation. The changes affecting active bargaining unit employees are being negotiated with their unions prior to implementation, where necessary, and to the extent required by law.
Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate for the Utility and Entergy Wholesale Commodities segments.
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Assumptions
Key actuarial assumptions utilized in determining these costs include:
Discount rates used in determining future benefit obligations;
Projectedqualified pension and other postretirement health care and life insurance costs include discount rates, projected healthcare cost trend rates;
Expectedrates, expected long-term rate of return on plan assets;
Rateassets, rate of increase in future compensation levels;
Retirement rates;levels, retirement rates and
Mortality mortality rates.
Annually, Entergy reviews and, when necessary, adjusts the first four assumptions listed above on an annual basisfor the pension and adjusts them as necessary.other postretirement plans. Every three-to-five years, a formal actuarial assumption experience study that compares assumptions to the actual experience of the pension and other postretirement health care and life insurance plans is conducted. The falling interest rate environment over the past few years and volatility in the financial equity markets have affected Entergy’s funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $504.4 million in the qualified pension benefit obligation and $94.4 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $77.4 million and other postretirement cost by approximately $12.3 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.Discount rates
In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yieldsuses a yield curve based on high-quality corporate debt and matches these rates with Entergy’s projected stream of benefit payments. Based on recent market trends,debt. Before 2016 the discount rates used to calculate its 2014 qualified pensionestimate the service cost and interest cost components of benefit obligation and 2015 qualified pension cost ranged from 4.03% to 4.40% for its specific pension plans (4.27% combined rate for all pension plans). The discount rates used to calculate its 2013 qualified pension benefit obligation and 2014 qualified pension cost ranged from 5.04% to 5.26% for its specific pension plans (5.14% combined rate for all pension plans). The discount rates used to calculate its 2012 qualified pension benefit obligation and 2013 qualified pension cost ranged from 4.31% to 4.50% for its specific pension plans (4.36% combined rate for all pension plans). Thecosts were the same as the weighted-average discount rate used to calculatemeasure the benefit obligation at the beginning of the year. In 2016, Entergy refined its 2014approach to estimating the service cost and interest cost components. Under the refined approach, instead of using the weighted-average benefit obligation discount rate at the beginning of the year, the 2016 service and interest costs’ expected cash flows were discounted by the applicable spot rates. The refinement had the effect of lowering 2016 qualified pension costs by $61 million and 2016 other postretirement health care and life insurance benefit obligation and 2015 other postretirement benefit cost was 4.23%. The discount rate used to calculate its 2013 other postretirement benefit obligation and 2014 other postretirement benefit cost was 5.05%. The discount rate used to calculate its 2012 other postretirement benefit obligation and 2013 other postretirement benefit cost was 4.36%. costs by $15 million.
Projected health care cost trend rates
Entergy’s health care cost trend is affected by both medical cost inflation, and with respect to capped costs under the plan, the effects of general inflation. Entergy reviews actual recent cost trends and projected future trends in establishing its health care cost trend rates. Based on this review, Entergy’s health care cost trend rate assumption used in measuring the December 31, 2014 accumulated postretirement benefit obligation and 2015 postretirement cost was 7.10% for pre-65 retirees and 7.70% for post-65 retirees for 2014, gradually decreasing each successive year until it reaches 4.75% in 2023 and beyond for both pre-65 and post-65 retirees. Entergy’s assumed health care cost trend rate assumption used in measuring the December 31, 2013 accumulated postretirement benefit obligation and 2014 postretirement cost was 7.25% for pre-65 retirees and 7.00% for post-65 retirees for 2013, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees. Entergy’s assumed health care cost trend rate assumption used in measuring 2013 postretirement cost was 7.50% for pre-65 retirees and 7.25% for post-65 retirees, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees. Entergy’s assumed
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
health care cost trend rate assumption used in measuring 2012 postretirement cost was 7.75% for pre-65 retirees and 7.50% for post-65 retirees, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees.
The assumedExpected long-term rate of increase in future compensation levels used to calculate 2014 and 2013 benefit obligations was 4.23%.return on plan assets
In determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and some of its investment managers.
Entergy conducts periodic asset/liability studies in order to set its target asset allocations.
Since 2003, Entergy has targeted an asset allocation for its qualified pension plan assets of roughly 65% equity securities and 35% fixed-income securities. In 2017, Entergy completed and adopted an optimization study inconfirmed the 2011 liability-driven investment strategy for theits pension assets, thatwhich recommended that the target asset allocation adjust dynamically over time, based on the funded status of the plan, from its current allocation to an ultimate allocation. In 2017, Entergy adopted a new ultimate allocation for pension assets of 45%35% equity securities and 55%65% fixed income securities. The ultimate asset allocation is expected to be attained when the plan is 105% funded.
The currentIn 2016, the target allocations for both Entergy’s non-taxable other postretirement benefit assets and its taxable other postretirement benefit assets arewere 65% equity securities and 35% fixed-income securities. This takes into accountDuring the first quarter of 2017, Entergy implemented a new asset allocation adjustments that were made during 2012.strategy, based on the funded status of each sub-account within each trust, which resulted in an overall shift to more fixed income in the non-taxable trusts and no material changes in asset allocation to the taxable trust. The new strategy no longer focuses on targeting an overall asset allocation for each trust, but rather a target asset allocation for each sub-account within each trust. See Note 11 to the financial statements for discussion of the current asset allocations for Entergy’s other postretirement assets.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Retirement and mortality rates
In October 2017 the Internal Revenue Service issued updated mortality regulations for single employer plans for determining cash contribution requirements. The regulations, based on the Society of Actuaries’ 2014 mortality table, are effective for plan years beginning on or after January 1, 2018.
Costs and Sensitivities
The estimated 2018 and actual 2017 qualified pension and other postretirement costs and related underlying assumptions and sensitivities are shown below:
|
| | | | |
| Costs | | Estimated 2018 | | 2017 |
| | | (In Millions) |
| Qualified pension cost | | $254.8 | | $214.2 |
| Other postretirement cost | | $13.1 | | $25.6 |
| | | | | |
| Assumptions | | 2018 | | 2017 |
| Discount rates | | | | |
| Qualified pension | | | | |
| Service cost | | 3.89% | | 4.75% |
| Interest cost | | 3.44% | | 3.73% |
| Other postretirement | | | | |
| Service cost | | 3.88% | | 4.60% |
| Interest cost | | 3.33% | | 3.61% |
| | | | | |
| Expected long-term rates of return | | | | |
| Qualified pension assets | | 7.50% | | 7.50% |
| Other postretirement - non-taxable assets | | 6.50% - 7.50% | | 6.50% - 6.90% |
| Other postretirement - taxable assets - after tax rate | | 5.50% | | 5.75% |
| | | | | |
| Weighted-average rate of future compensation | | 3.98% | | 3.98% |
| | | | | |
| Assumed health care cost trend rates | | | | |
| Pre-65 retirees | | 6.95% | | 6.55% |
| Post-65 retirees | | 7.25% | | 7.25% |
| Ultimate rate | | 4.75% | | 4.75% |
| Year ultimate rate is reached and beyond | | 2027 | | 2026 |
Actual asset returns have an effect on Entergy’s expected long term rate ofqualified pension and other postretirement costs. In 2017, Entergy’s actual average annual return on qualified pension assets used to calculate 2014, 2013,was approximately 16% and 2012 qualified pension costs was 8.5% and will be 8.25% for 2015. Entergy’s expected long term rate of return on tax deferred other postretirement assets used to calculate other postretirement costs was 8.3% for 2014 and 8.5% for 2013 and 2012. It will be 8.05% for 2015. For Entergy’s taxable postretirement assets,approximately 14%, as compared with the 2017 expected long term ratelong-term rates of return was 6.5% for 2014, 2013, and 2012, and will be 6.25% in 2015.discussed above.
Accounting standards allow for the deferral
Entergy Corporation and deferral of gainsSubsidiaries
Management’s Financial Discussion and losses arising from the difference between actuarial estimates and actual experience. Prior service costs/credits and deferred gains and losses are then amortized into expense over future periods. Certain decisions, including workforce reductions and plan amendments, may significantly reduce the expense amortization period and result in immediate recognition of certain previously-deferred costs and gains/losses in the form of curtailment losses or gains. Similarly, payments made to settle benefit obligations can also result in recognition in the form of settlement losses or gains.Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified pension projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).millions):
| | | Actuarial Assumption | | Change in Assumption | | Impact on 2014 Qualified Pension Cost | | Impact on 2014 Qualified Projected Benefit Obligation | | Change in Assumption | | Impact on 2018 Qualified Pension Cost | | Impact on 2017 Qualified Projected Benefit Obligation |
| | | Increase/(Decrease) | | Increase/(Decrease) |
| Discount rate | | (0.25%) | | $18,707 | | $271,656 | | (0.25%) | | $23 | | $250 |
| Rate of return on plan assets | | (0.25%) | | $10,631 | | $— | | (0.25%) | | $15 | | $— |
| Rate of increase in compensation | | 0.25% | | $7,561 | | $44,183 | | 0.25% | | $7 | | $34 |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).millions):
| | | Actuarial Assumption | | Change in Assumption | | Impact on 2014 Postretirement Benefit Cost | | Impact on 2014 Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2018 Postretirement Benefit Cost | | Impact on 2017 Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) | | Increase/(Decrease) |
| Discount rate | | (0.25%) | | $4,716 | | $63,342 | | (0.25%) | | $3 | | $50 |
| Health care cost trend | | 0.25% | | $7,953 | | $55,954 | | 0.25% | | $5 | | $39 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Accounting Mechanisms
Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. See Note 11 to the financial statements for a further discussion of Entergy’s funded status.
In accordance with pension accounting standards, Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. Additionally, accounting standards allow for the deferral of prior service costs/credits arising from plan amendments that attribute an increase or decrease in benefits to employee service in prior periods. Prior service costs/credits are then amortized into expense over the average future working life of active employees. Certain decisions, including workforce reductions, plan amendments, and plant shutdowns may significantly reduce the expense amortization period and result in immediate recognition of certain previously-deferred costs and gains/losses in the form of curtailment gains or losses. Similarly, payments made to settle benefit obligations can also result in recognition in the form of settlement losses or gains.
Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For other postretirement benefit plan assets Entergy uses fair value when determining MRV.
Costs and Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. See Note 11 to the financial statements for a further discussion of Entergy’s funded status.
Funding
In 2014, Entergy’s total qualified pension cost was $216.5 million, including a $0.7 million special termination charge related to workforce downsizing. Entergy anticipates 2015 qualified pension cost to be $320.7 million. Entergy’s pension funding in 2017 was approximately $399 million for 2014. Entergy’s$410 million. Entergy estimates pension contributions to the pension trust are currently estimated towill be approximately $396.2$352.1 million in 2015,2018; although the 2018 required pension contributions will not be known with more certainty untilwhen the January 1, 20152018 valuations are completed, which is expected by April 1, 2015.2018.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Minimum required funding calculations as determined under Pension Protection Act guidance are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date. Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall that, under the Pension Protection Act, must be funded over a seven-year rolling period. The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on calculated fair market values of assets divided by funding liabilities, does not meet certain thresholds. For funding purposes, asset gains and losses are smoothed in to the calculated fair market value of assets and the funding liability is based upon a weighted average 24-month corporate bond rate published by the U.S. Treasury; therefore, periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.
Moving Ahead for Progress in the 21st Century Act (MAP-21) became federal law in July 2012. Under the law, the segment rates used to calculate funding liabilities must be within a corridor of the 25-year average of prior segment rates. The interest rate corridor applies to the determination of minimum funding requirements and benefit restrictions. TheThese pension funding stabilization provisions will provide for a near-term reduction in minimum funding
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
requirements for single employer defined benefit plans in response to the historically low interest rates that existed when the law was enacted. The law did not reduce contribution requirements over the long term.
The interest rate stabilization periods of MAP-21 were extended by the Highway and Transportation Funding Act (HATFA) became federal law in August 2014. HATFA’s pension provisions provided a five-year extension of2014 and the MAP-21 pension funding stabilization.Bipartisan Budget Act in 2015.
Total postretirement health care and life insurance benefit costs for Entergy in 2014 were $50.1 million. Entergy expects 2015 postretirement health care and life insurance benefit costs to be $66.2 million. Entergy contributed $76.5$44.3 million to its postretirement plans in 2014. Entergy’s current estimate of contributions2017 and plans to its other postretirement plans is approximately $66.9contribute $52.3 million in 2015.2018.
Federal Healthcare Legislation
TheIn 2010 the Patient Protection and Affordable Care Act (PPACA) became federal law on March 23, 2010, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 became federal law and, as amended, certain provisions of the PPACA. Entergy has implemented the major provisions of the law.
Aimposed a 40% excise tax on per capita medical benefit costs that exceed certain thresholdsthresholds. In January 2018 the effective date of the excise tax was delayed and is duecurrently expected to take effect beginning in 2018. There are still many technical issues, however, that have not been finalized.2022. Entergy will continue to monitor these developments to determine the possible effect on Entergy.
Other Contingencies
As a company with multi-state utility operations, Entergy is subject to a number of federal and state laws and regulations and other factors and conditions in the areas in which it operates, which potentially subject it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a reserve for those matters which are considered probable and estimable in accordance with generally accepted accounting principles.
Environmental
Entergy must comply with environmental laws and regulations applicable to air emissions, water discharges, solid and hazardous waste, toxic substances, protected species, and other environmental matters. Under these various laws and regulations, Entergy could incur substantial costs to comply or address any impacts to the environment. Entergy conducts studies to determine the extent of any required remediation and has recorded liabilities based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites or issues could be identified which require environmental remediation or corrective action for which Entergy could be liable. The amounts of environmental liabilities recorded can be significantly affected by the following external events or conditions.
Changes to existing federal, state, or federallocal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party.
The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority.
Litigation
Entergy is regularly named as a defendant in a number of lawsuits involving employment, customers, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably possible, or remote and records
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
liabilities for cases that have a probable likelihood of loss and the loss can be estimated. Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, the ultimate outcome of the litigation to which Entergy is exposed has the potential to materially affect the results of operations, financial position, and cash flows of Entergy or the Registrant Subsidiaries.
Entergy’s operations, including acquisitions and divestitures, require Entergy to evaluate risks such as the potential tax effects of a transaction, or warranties made in connection with such a transaction. Entergy believes that it has adequately assessed and provided for these types of risks, where applicable. Any provisions recorded for these types of issues, however, could be significantly affected by events such as claims made by third parties under warranties, additional transactions contemplated by Entergy, or completion of reviews of the tax treatment of certain transactions or issues by taxing authorities.
New Accounting Pronouncements
TheSee Note 1 to the financial statements for discussion of new accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.
In April 2014 the FASB issued ASU No. 2014-08, “Presentation of Financial Statements (Topic 205) and Property Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” which changes the requirements for reporting discontinued operations. The ASU states that a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results when the component of an entity or group of components of an entity meets the criteria to be classified as held for sale, is disposed of by sale, or is disposed of other than by sale. The amendments in this ASU also require additional disclosures about discontinued operations. ASU 2014-08 is effective for Entergy for the first quarter 2015. Entergy does not currently expect ASU 2014-08 to affect materially its results of operations, financial position, or cash flows.
In May 2014 the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The ASU’s core principle is that “an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.” The ASU details a five-step model that should be followed to achieve the core principle. ASU 2014-09 is effective for Entergy for the first quarter 2017. Entergy does not expect ASU 2014-09 to affect materially its results of operations, financial position, or cash flows.
In November 2014 the FASB issued ASU No. 2014-16, “Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity.” The ASU states that for hybrid financial instruments issued in the form of a share, an entity should determine the nature of the host contract by considering all stated and implied substantive terms and features of the hybrid financial instrument, weighing each term and feature on the basis of relevant facts and circumstances. ASU 2014-16 is effective for Entergy for the first quarter 2016. Entergy does not expect ASU 2014-16 to affect materially its results of operations, financial position, or cash flows.pronouncements.
ENTERGY CORPORATION AND SUBSIDIARIES
REPORT OF MANAGEMENT
Management of Entergy Corporation and its subsidiaries has prepared and is responsible for the financial statements and related financial information included in this document. To meet this responsibility, management establishes and maintains a system of internal controls over financial reporting designed to provide reasonable assurance regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles. This system includes communication through written policies and procedures, an employee Code of Entegrity, and an organizational structure that provides for appropriate division of responsibility and training of personnel. This system is also tested by a comprehensive internal audit program.
Entergy management assesses the design and effectiveness of Entergy’s internal control over financial reporting on an annual basis. In making this assessment, management uses the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. The 2013 COSO Framework was utilized for management’s assessment. Management acknowledges, however, that all internal control systems, no matter how well designed, have inherent limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation.
Entergy Corporation’s independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of Entergy Corporation’s internal control over financial reporting as of December 31, 2014.2017.
In addition, the Audit Committee of the Board of Directors, composed solely of independent Directors, meets with the independent auditors, internal auditors, management, and internal accountants periodically to discuss internal controls, and auditing and financial reporting matters. The Audit Committee appoints the independent auditors annually, seeks shareholder ratification of the appointment, and reviews with the independent auditors the scope and results of the audit effort. The Audit Committee also meets periodically with the independent auditors and the chief internal auditor without management present, providing free access to the Audit Committee.
Based on management’s assessment of internal controls using the 2013 COSO criteria, management believes that Entergy and each of the Registrant Subsidiaries maintained effective internal control over financial reporting as of December 31, 2014.2017. Management further believes that this assessment, combined with the policies and procedures noted above, provides reasonable assurance that Entergy’s and each of the Registrant Subsidiaries’ financial statements are fairly and accurately presented in accordance with generally accepted accounting principles.
|
| |
LEO P. DENAULT Chairman of the Board and Chief Executive Officer of Entergy Corporation | ANDREW S. MARSH Executive Vice President and Chief Financial Officer of Entergy Corporation, Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc.,LLC, Entergy Texas, Inc., and System Energy Resources, Inc. |
HUGH T. MCDONALDRICHARD C. RILEY
Chairman of the Board, President, and Chief Executive Officer of Entergy Arkansas, Inc. | PHILLIP R. MAY, JR. Chairman of the Board, President, and Chief Executive Officer of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC |
HALEY R. FISACKERLY Chairman of the Board, President, and Chief Executive Officer of Entergy Mississippi, Inc. | CHARLES L. RICE, JR. Chairman of the Board, President, and Chief Executive Officer of Entergy New Orleans, Inc.LLC |
SALLIE T. RAINER Chair of the Board, President, and Chief Executive Officer of Entergy Texas, Inc. | THEODORE H. BUNTING, JR.RODERICK K. WEST
Chairman of the Board, President, and Chief Executive Officer of System Energy Resources, Inc. |
| | ENTERGY CORPORATION AND SUBSIDIARIES | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | 2014 |
| 2013 |
| 2012 |
| 2011 |
| 2010 | 2017 |
| 2016 |
| 2015 |
| 2014 |
| 2013 |
| | (In Thousands, Except Percentages and Per Share Amounts) | (In Thousands, Except Percentages and Per Share Amounts) |
| | | | | | | | | | | | | | | | | | | |
| Operating revenues |
| $12,494,921 |
|
|
| $11,390,947 |
|
|
| $10,302,079 |
|
|
| $11,229,073 |
|
|
| $11,487,577 |
|
| $11,074,481 |
|
|
| $10,845,645 |
| |
| $11,513,251 |
| |
| $12,494,921 |
|
|
| $11,390,947 |
|
| Income from continuing operations |
| $960,257 |
|
|
| $730,572 |
|
|
| $868,363 |
|
|
| $1,367,372 |
|
|
| $1,270,305 |
| |
| Earnings per share from continuing operations: | |
| |
| |
|
| |
|
| |
| |
| Net income (loss) | |
| $425,353 |
|
|
| ($564,503 | ) | |
| ($156,734 | ) | |
| $960,257 |
|
|
| $730,572 |
|
| Earnings (loss) per share: | | |
| | | | | |
|
| |
|
| Basic |
| $5.24 |
|
|
| $3.99 |
|
|
| $4.77 |
|
|
| $7.59 |
|
|
| $6.72 |
|
| $2.29 |
|
|
| ($3.26 | ) | |
| ($0.99 | ) | |
| $5.24 |
|
|
| $3.99 |
|
| Diluted |
| $5.22 |
|
|
| $3.99 |
|
|
| $4.76 |
|
|
| $7.55 |
|
|
| $6.66 |
|
| $2.28 |
|
|
| ($3.26 | ) | |
| ($0.99 | ) | |
| $5.22 |
|
|
| $3.99 |
|
| Dividends declared per share |
| $3.32 |
|
|
| $3.32 |
|
|
| $3.32 |
|
|
| $3.32 |
|
|
| $3.24 |
|
| $3.50 |
|
|
| $3.42 |
| |
| $3.34 |
| |
| $3.32 |
|
|
| $3.32 |
|
| Return on common equity | 9.58 | % |
| 7.56 | % |
| 9.33 | % |
| 15.43 | % |
| 14.61 | % | 5.12 | % |
| (6.73 | %) | | (1.83 | )% | | 9.58 | % |
| 7.56 | % |
| Book value per share, year-end |
| $55.83 |
|
|
| $54.00 |
|
|
| $51.72 |
|
|
| $50.81 |
|
|
| $47.53 |
|
| $44.28 |
|
|
| $45.12 |
| |
| $51.89 |
| |
| $55.83 |
|
|
| $54.00 |
|
| Total assets |
| $46,527,854 |
|
|
| $43,406,446 |
|
|
| $43,202,502 |
|
|
| $40,701,699 |
|
|
| $38,685,276 |
|
| $46,707,149 |
|
|
| $45,904,434 |
| |
| $44,647,681 |
| |
| $46,414,455 |
|
|
| $43,290,290 |
|
| Long-term obligations (a) |
| $12,740,579 |
|
|
| $12,382,127 |
|
|
| $12,141,370 |
|
|
| $10,268,645 |
|
|
| $11,575,973 |
|
| $14,535,077 |
|
|
| $14,695,422 |
| |
| $13,456,742 |
| |
| $12,627,180 |
|
|
| $12,265,971 |
|
| | (a) Includes long-term debt (excluding currently maturing debt), noncurrent capital lease obligations, and subsidiary preferred stock without sinking fund that is not presented as equity on the balance sheet. | |
| (a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and subsidiary preferred stock without sinking fund that is not presented as equity on the balance sheet. | | (a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and subsidiary preferred stock without sinking fund that is not presented as equity on the balance sheet. |
| | | 2014 |
| 2013 |
| 2012 |
| 2011 |
| 2010 | 2017 |
| 2016 |
| 2015 |
| 2014 |
| 2013 |
| | (Dollars In Millions) | (Dollars In Millions) |
| | | | | | | | | | | | | | | | | | | |
| Utility Electric Operating Revenues: | |
|
| |
|
| |
|
| |
|
| |
| |
| Utility electric operating revenues: | | |
|
| |
|
| |
|
| |
|
| |
|
| Residential |
| $3,555 |
|
|
| $3,396 |
|
|
| $3,022 |
|
|
| $3,369 |
|
|
| $3,375 |
|
| $3,355 |
|
|
| $3,288 |
|
|
| $3,518 |
|
|
| $3,555 |
|
|
| $3,396 |
|
| Commercial | 2,553 |
|
| 2,415 |
|
| 2,174 |
|
| 2,333 |
|
| 2,317 |
| 2,480 |
|
| 2,362 |
|
| 2,516 |
|
| 2,553 |
|
| 2,415 |
|
| Industrial | 2,623 |
|
| 2,405 |
|
| 2,034 |
|
| 2,307 |
|
| 2,207 |
| 2,584 |
|
| 2,327 |
|
| 2,462 |
|
| 2,623 |
|
| 2,405 |
|
| Governmental | 227 |
|
| 218 |
|
| 198 |
|
| 205 |
|
| 212 |
| 231 |
|
| 217 |
|
| 223 |
|
| 227 |
|
| 218 |
|
| Total retail | 8,958 |
|
| 8,434 |
|
| 7,428 |
|
| 8,214 |
|
| 8,111 |
| 8,650 |
|
| 8,194 |
|
| 8,719 |
|
| 8,958 |
|
| 8,434 |
|
| Sales for resale | 330 |
|
| 210 |
|
| 179 |
|
| 216 |
|
| 389 |
| 253 |
|
| 236 |
|
| 249 |
|
| 330 |
|
| 210 |
|
| Other | 304 |
|
| 298 |
|
| 264 |
|
| 244 |
|
| 241 |
| 376 |
|
| 437 |
|
| 341 |
|
| 304 |
|
| 298 |
|
| Total |
| $9,592 |
|
|
| $8,942 |
|
|
| $7,871 |
|
|
| $8,674 |
|
|
| $8,741 |
|
| $9,279 |
|
|
| $8,867 |
|
|
| $9,309 |
|
|
| $9,592 |
|
|
| $8,942 |
|
| | | | | | | | | | | | | | | | | | | |
| Utility Billed Electric Energy Sales (GWh): |
|
|
|
|
| |
|
| |
|
| |
| |
| Utility billed electric energy sales (GWh): | |
|
|
|
|
| |
|
| |
|
| |
|
| Residential | 35,932 |
|
| 35,169 |
|
| 34,664 |
|
| 36,684 |
|
| 37,465 |
| 33,834 |
|
| 35,112 |
|
| 36,068 |
|
| 35,932 |
|
| 35,169 |
|
| Commercial | 28,827 |
|
| 28,547 |
|
| 28,724 |
|
| 28,720 |
|
| 28,831 |
| 28,745 |
|
| 29,197 |
|
| 29,348 |
|
| 28,827 |
|
| 28,547 |
|
| Industrial | 43,723 |
|
| 41,653 |
|
| 41,181 |
|
| 40,810 |
|
| 38,751 |
| 47,769 |
|
| 45,739 |
|
| 44,382 |
|
| 43,723 |
|
| 41,653 |
|
| Governmental | 2,428 |
|
| 2,412 |
|
| 2,435 |
|
| 2,474 |
|
| 2,463 |
| 2,511 |
|
| 2,547 |
|
| 2,514 |
|
| 2,428 |
|
| 2,412 |
|
| Total retail | 110,910 |
|
| 107,781 |
|
| 107,004 |
|
| 108,688 |
|
| 107,510 |
| 112,859 |
|
| 112,595 |
|
| 112,312 |
|
| 110,910 |
|
| 107,781 |
|
| Sales for resale | 9,462 |
|
| 3,020 |
|
| 3,200 |
|
| 4,111 |
|
| 4,372 |
| 11,550 |
|
| 11,054 |
|
| 9,274 |
|
| 9,462 |
|
| 3,020 |
|
| Total | 120,372 |
|
| 110,801 |
|
| 110,204 |
|
| 112,799 |
|
| 111,882 |
| 124,409 |
|
| 123,649 |
|
| 121,586 |
|
| 120,372 |
|
| 110,801 |
|
| | | | | | | | | | | | | | | | | | | |
| Entergy Wholesale Commodities: | |
|
| |
|
| |
|
| |
|
| |
| |
|
| |
|
| |
|
| |
|
| |
|
| Operating Revenues |
| $2,719 |
| |
| $2,313 |
| |
| $2,326 |
| |
| $2,414 |
| |
| $2,566 |
| |
| Billed Electric Energy Sales (GWh) | 44,424 |
| | 45,127 |
| | 46,178 |
| | 43,497 |
| | 42,934 |
| |
| Operating revenues | |
| $1,657 |
| |
| $1,850 |
| |
| $2,062 |
| |
| $2,719 |
| |
| $2,313 |
|
| Billed electric energy sales (GWh) | | 30,501 |
| | 35,881 |
| | 39,745 |
| | 44,424 |
| | 45,127 |
|
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors and Shareholders of
Entergy Corporation and Subsidiaries
New Orleans, Louisiana
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 20142017 and 2013, and2016, the related consolidated income statements, and consolidated statements of operations, comprehensive income (loss), cash flows, and changes in equity, for each of the three years in the period ended December 31, 2014. These financial statements are2017, and the responsibility ofrelated notes (collectively referred to as the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States)“financial statements”). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidatedthe financial statements present fairly, in all material respects, the financial position of Entergythe Corporation and Subsidiaries as of December 31, 20142017 and 2013,2016, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 2014,2017, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Corporation’s internal control over financial reporting as of December 31, 2014,2017, based on the criteria established in Internal Control - Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 20152018, expressed an unqualified opinion on the Corporation’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on the Corporation’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 20152018
53We have served as the Corporation’s auditor since 2001.
| | ENTERGY CORPORATION AND SUBSIDIARIES | | CONSOLIDATED INCOME STATEMENTS | |
| CONSOLIDATED STATEMENTS OF OPERATIONS | | CONSOLIDATED STATEMENTS OF OPERATIONS |
| | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 | | 2017 | | 2016 | | 2015 |
| | | (In Thousands, Except Share Data) | | (In Thousands, Except Share Data) |
| OPERATING REVENUES | | | | | | | | | | | | |
| Electric | |
| $9,591,902 |
| |
| $8,942,360 |
| |
| $7,870,649 |
| |
| $9,278,895 |
| |
| $8,866,659 |
| |
| $9,308,678 |
|
| Natural gas | | 181,794 |
| | 154,353 |
| | 130,836 |
| | 138,856 |
| | 129,348 |
| | 142,746 |
|
| Competitive businesses | | 2,721,225 |
| | 2,294,234 |
| | 2,300,594 |
| | 1,656,730 |
| | 1,849,638 |
| | 2,061,827 |
|
| TOTAL | | 12,494,921 |
| | 11,390,947 |
| | 10,302,079 |
| | 11,074,481 |
| | 10,845,645 |
| | 11,513,251 |
|
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
| | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 2,632,558 |
| | 2,445,818 |
| | 2,036,835 |
| | 1,991,589 |
| | 1,809,200 |
| | 2,452,171 |
|
| Purchased power | | 1,915,414 |
| | 1,554,332 |
| | 1,255,800 |
| | 1,427,950 |
| | 1,220,527 |
| | 1,390,805 |
|
| Nuclear refueling outage expenses | | 267,679 |
| | 256,801 |
| | 245,600 |
| | 168,151 |
| | 208,678 |
| | 251,316 |
|
| Other operation and maintenance | | 3,310,536 |
| | 3,331,934 |
| | 3,045,392 |
| | 3,423,689 |
| | 3,296,711 |
| | 3,354,981 |
|
| Asset write-offs, impairments, and related charges | | 179,752 |
| | 341,537 |
| | 355,524 |
| | 538,372 |
| | 2,835,637 |
| | 2,104,906 |
|
| Decommissioning | | 272,621 |
| | 242,104 |
| | 184,760 |
| | 405,685 |
| | 327,425 |
| | 280,272 |
|
| Taxes other than income taxes | | 604,606 |
| | 600,350 |
| | 557,298 |
| | 617,556 |
| | 592,502 |
| | 619,422 |
|
| Depreciation and amortization | | 1,318,638 |
| | 1,261,044 |
| | 1,144,585 |
| | 1,389,978 |
| | 1,347,187 |
| | 1,337,276 |
|
| Other regulatory charges (credits) - net | | (13,772 | ) | | 45,597 |
| | 175,104 |
| | (131,901 | ) | | 94,243 |
| | 175,304 |
|
| TOTAL | | 10,488,032 |
| | 10,079,517 |
| | 9,000,898 |
| | 9,831,069 |
| | 11,732,110 |
| | 11,966,453 |
|
| | | | | | | | | | | | | |
| Gain on sale of business | | — |
| | 43,569 |
| | — |
| |
| Gain on sale of asset | | | 16,270 |
| | — |
| | 154,037 |
|
| | | | | | | | | | | | | |
| OPERATING INCOME | | 2,006,889 |
| | 1,354,999 |
| | 1,301,181 |
| |
| OPERATING INCOME (LOSS) | | | 1,259,682 |
| | (886,465 | ) | | (299,165 | ) |
| | | | | | | | | | | | | |
| OTHER INCOME | | |
| | |
| | |
| | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 64,802 |
| | 66,053 |
| | 92,759 |
| | 95,088 |
| | 67,563 |
| | 51,908 |
|
| Interest and investment income | | 147,686 |
| | 199,300 |
| | 127,776 |
| | 288,197 |
| | 145,127 |
| | 187,062 |
|
| Miscellaneous - net | | (42,016 | ) | | (59,762 | ) | | (53,214 | ) | | (12,701 | ) | | (41,617 | ) | | (95,997 | ) |
| TOTAL | | 170,472 |
| | 205,591 |
| | 167,321 |
| | 370,584 |
| | 171,073 |
| | 142,973 |
|
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest expense | | 661,083 |
| | 629,537 |
| | 606,596 |
| | 707,212 |
| | 700,545 |
| | 670,096 |
|
| Allowance for borrowed funds used during construction | | (33,576 | ) | | (25,500 | ) | | (37,312 | ) | | (44,869 | ) | | (34,175 | ) | | (26,627 | ) |
| TOTAL | | 627,507 |
| | 604,037 |
| | 569,284 |
| | 662,343 |
| | 666,370 |
| | 643,469 |
|
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 1,549,854 |
| | 956,553 |
| | 899,218 |
| |
| INCOME (LOSS) BEFORE INCOME TAXES | | | 967,923 |
| | (1,381,762 | ) | | (799,661 | ) |
| | | | | | | | | | | | | |
| Income taxes | | 589,597 |
| | 225,981 |
| | 30,855 |
| | 542,570 |
| | (817,259 | ) | | (642,927 | ) |
| | | | | | | | | | | | | |
| CONSOLIDATED NET INCOME | | 960,257 |
| | 730,572 |
| | 868,363 |
| |
| CONSOLIDATED NET INCOME (LOSS) | | | 425,353 |
| | (564,503 | ) | | (156,734 | ) |
| | | | | | | | | | | | | |
| Preferred dividend requirements of subsidiaries | | 19,536 |
| | 18,670 |
| | 21,690 |
| | 13,741 |
| | 19,115 |
| | 19,828 |
|
| | | | | | | | | | | | | |
| NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION | |
| $940,721 |
| |
| $711,902 |
| |
| $846,673 |
| |
| NET INCOME (LOSS) ATTRIBUTABLE TO ENTERGY CORPORATION | | |
| $411,612 |
| |
| ($583,618 | ) | |
| ($176,562 | ) |
| | | | | | | | | | | | | |
| Earnings per average common share: | | |
| | |
| | |
| |
| Earnings (loss) per average common share: | | | |
| | |
| | |
|
| Basic | |
| $5.24 |
| |
| $3.99 |
| |
| $4.77 |
| |
| $2.29 |
| |
| ($3.26 | ) | |
| ($0.99 | ) |
| Diluted | |
| $5.22 |
| |
| $3.99 |
| |
| $4.76 |
| |
| $2.28 |
| |
| ($3.26 | ) | |
| ($0.99 | ) |
| | | | | | | | | | | | | |
| Basic average number of common shares outstanding | | 179,506,151 |
| | 178,211,192 |
| | 177,324,813 |
| | 179,671,797 |
| | 178,885,660 |
| | 179,176,356 |
|
| Diluted average number of common shares outstanding | | 180,296,885 |
| | 178,570,400 |
| | 177,737,565 |
| | 180,535,893 |
| | 178,885,660 |
| | 179,176,356 |
|
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
|
| | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | |
| | For the Years Ended December 31, |
| | 2014 | | 2013 | | 2012 |
| | (In Thousands) |
| | | | | | |
| Net Income |
| $960,257 |
| |
| $730,572 |
| |
| $868,363 |
|
| | | | | | |
| Other comprehensive income (loss) | |
| | |
| | |
|
| Cash flow hedges net unrealized gain (loss) | |
| | |
| | |
|
| (net of tax expense (benefit) of $96,141, ($87,940), and ($55,750)) | 179,895 |
| | (161,682 | ) | | (97,591 | ) |
| Pension and other postretirement liabilities | |
| | |
| | |
|
| (net of tax expense (benefit) of ($152,763), $220,899, and ($61,223)) | (281,566 | ) | | 302,489 |
| | (91,157 | ) |
| Net unrealized investment gains | |
| | |
| | |
|
| (net of tax expense of $66,594, $118,878, and $61,104) | 89,439 |
| | 122,709 |
| | 63,609 |
|
| Foreign currency translation | |
| | |
| | |
|
| (net of tax expense (benefit) of ($404), $131, and $275) | (751 | ) | | 243 |
| | 508 |
|
| Other comprehensive income (loss) | (12,983 | ) | | 263,759 |
| | (124,631 | ) |
| | | | | | |
| Comprehensive Income | 947,274 |
| | 994,331 |
| | 743,732 |
|
| Preferred dividend requirements of subsidiaries | 19,536 |
| | 18,670 |
| | 21,690 |
|
| Comprehensive Income Attributable to Entergy Corporation |
| $927,738 |
| |
| $975,661 |
| |
| $722,042 |
|
| | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
|
|
| | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) |
| | |
| | For the Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| | | | | | |
| Net Income (Loss) |
| $425,353 |
| |
| ($564,503 | ) | |
| ($156,734 | ) |
| | | | | | |
| Other comprehensive income (loss) | |
| | |
| | |
|
| Cash flow hedges net unrealized gain (loss) | |
| | |
| | |
|
| (net of tax expense (benefit) of ($22,570), ($55,298), and $3,752) | (41,470 | ) | | (101,977 | ) | | 7,852 |
|
| Pension and other postretirement liabilities | |
| | |
| | |
|
| (net of tax expense (benefit) of ($4,057), ($3,952), and $61,576) | (61,653 | ) | | (2,842 | ) | | 103,185 |
|
| Net unrealized investment gains (losses) | |
| | |
| | |
|
| (net of tax expense (benefit) of $80,069, $57,277, and ($45,904)) | 115,311 |
| | 62,177 |
| | (59,138 | ) |
| Foreign currency translation | |
| | |
| | |
|
| (net of tax benefit of $403, $689, and $345) | (748 | ) | | (1,280 | ) | | (641 | ) |
| Other comprehensive income (loss) | 11,440 |
| | (43,922 | ) | | 51,258 |
|
| | | | | | |
| Comprehensive Income (Loss) | 436,793 |
| | (608,425 | ) | | (105,476 | ) |
| Preferred dividend requirements of subsidiaries | 13,741 |
| | 19,115 |
| | 19,828 |
|
| Comprehensive Income (Loss) Attributable to Entergy Corporation |
| $423,052 |
| |
| ($627,540 | ) | |
| ($125,304 | ) |
| | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
|
| | ENTERGY CORPORATION AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | | | | |
| Consolidated net income | |
| $960,257 |
| |
| $730,572 |
| |
| $868,363 |
| |
| Adjustments to reconcile consolidated net income to net cash flow provided by operating activities: | | | | | | | |
| Consolidated net income (loss) | | |
| $425,353 |
| |
| ($564,503 | ) | |
| ($156,734 | ) |
| Adjustments to reconcile consolidated net income (loss) to net cash flow provided by operating activities: | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 2,127,892 |
| | 2,012,076 |
| | 1,771,649 |
| | 2,078,578 |
| | 2,123,291 |
| | 2,117,236 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 596,935 |
| | 311,789 |
| | (26,479 | ) | | 529,053 |
| | (836,257 | ) | | (820,350 | ) |
| Asset write-offs, impairments and related charges | | 123,527 |
| | 341,537 |
| | 355,524 |
| |
| Gain on sale of business | | — |
| | (43,569 | ) | | — |
| |
| Asset write-offs, impairments, and related charges | | | 357,251 |
| | 2,835,637 |
| | 2,104,906 |
|
| Gain on sale of asset | | | (16,270 | ) | | — |
| | (154,037 | ) |
| Changes in working capital: | | |
| | |
| | |
| | |
| | |
| | |
|
| Receivables | | 98,493 |
| | (180,648 | ) | | (14,202 | ) | | (97,637 | ) | | (96,975 | ) | | 38,152 |
|
| Fuel inventory | | 3,524 |
| | 4,873 |
| | (11,604 | ) | | (3,043 | ) | | 38,210 |
| | (12,376 | ) |
| Accounts payable | | (12,996 | ) | | 94,436 |
| | (6,779 | ) | | 101,802 |
| | 174,421 |
| | (135,211 | ) |
| Prepaid taxes and taxes accrued | | (62,985 | ) | | (142,626 | ) | | 55,484 |
| | 33,853 |
| | (28,963 | ) | | 81,969 |
|
| Interest accrued | | 25,013 |
| | (3,667 | ) | | 1,152 |
| | 742 |
| | (7,335 | ) | | (11,445 | ) |
| Deferred fuel costs | | (70,691 | ) | | (4,824 | ) | | (99,987 | ) | | 56,290 |
| | (241,896 | ) | | 298,725 |
|
| Other working capital accounts | | 112,390 |
| | (66,330 | ) | | (151,989 | ) | | (4,331 | ) | | 31,197 |
| | (113,701 | ) |
| Changes in provisions for estimated losses | | 301,871 |
| | (248,205 | ) | | (24,808 | ) | | (3,279 | ) | | 20,905 |
| | 42,566 |
|
| Changes in other regulatory assets | | (1,061,537 | ) | | 1,105,622 |
| | (398,428 | ) | | 595,504 |
| | (48,469 | ) | | 262,317 |
|
| Changes in other regulatory liabilities | | 87,654 |
| | 397,341 |
| | 170,421 |
| | 2,915,795 |
| | 158,031 |
| | 61,241 |
|
| Deferred tax rate change recognized as regulatory liability / asset | | | (3,665,498 | ) | | — |
| | — |
|
| Changes in pensions and other postretirement liabilities | | 1,308,166 |
| | (1,433,663 | ) | | 644,099 |
| | (130,686 | ) | | (136,919 | ) | | (446,418 | ) |
| Other | | (647,952 | ) | | 314,505 |
| | (192,131 | ) | | (549,977 | ) | | (421,676 | ) | | 134,344 |
|
| Net cash flow provided by operating activities | | 3,889,561 |
| | 3,189,219 |
| | 2,940,285 |
| | 2,623,500 |
| | 2,998,699 |
| | 3,291,184 |
|
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Construction/capital expenditures | | (2,119,191 | ) | | (2,287,593 | ) | | (2,674,650 | ) | | (3,607,532 | ) | | (2,780,222 | ) | | (2,500,860 | ) |
| Allowance for equity funds used during construction | | 68,375 |
| | 69,689 |
| | 96,131 |
| | 96,000 |
| | 68,345 |
| | 53,635 |
|
| Nuclear fuel purchases | | (537,548 | ) | | (517,825 | ) | | (557,960 | ) | | (377,324 | ) | | (314,706 | ) | | (493,604 | ) |
| Payment for purchase of plant | | — |
| | (17,300 | ) | | (456,356 | ) | |
| Proceeds from sale of assets and businesses | | 10,100 |
| | 147,922 |
| | — |
| |
| Payment for purchase of plant or assets | | | (16,762 | ) | | (949,329 | ) | | — |
|
| Proceeds from sale of assets | | | 100,000 |
| | — |
| | 487,406 |
|
| Insurance proceeds received for property damages | | 40,670 |
| | — |
| | — |
| | 26,157 |
| | 20,968 |
| | 24,399 |
|
| Changes in securitization account | | 1,511 |
| | 155 |
| | 4,265 |
| | 1,323 |
| | 4,007 |
| | (5,806 | ) |
| NYPA value sharing payment | | (72,000 | ) | | (71,736 | ) | | (72,000 | ) | | — |
| | — |
| | (70,790 | ) |
| Payments to storm reserve escrow account | | (276,057 | ) | | (7,716 | ) | | (8,957 | ) | | (2,878 | ) | | (1,544 | ) | | (69,163 | ) |
| Receipts from storm reserve escrow account | | — |
| | 260,279 |
| | 27,884 |
| | 11,323 |
| | — |
| | 5,916 |
|
| Decrease (increase) in other investments | | 46,983 |
| | (82,955 | ) | | 15,175 |
| |
| Decrease in other investments | | | 1,078 |
| | 9,055 |
| | 571 |
|
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | — |
| | 21,034 |
| | 109,105 |
| | 25,493 |
| | 169,085 |
| | 18,296 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 1,872,115 |
| | 2,031,552 |
| | 2,074,055 |
| | 3,162,747 |
| | 2,408,920 |
| | 2,492,176 |
|
| Investment in nuclear decommissioning trust funds | | (1,989,446 | ) | | (2,147,099 | ) | | (2,196,489 | ) | | (3,260,674 | ) | | (2,484,627 | ) | | (2,550,958 | ) |
| Net cash flow used in investing activities | | (2,954,488 | ) | | (2,601,593 | ) | | (3,639,797 | ) | | (3,841,049 | ) | | (3,850,048 | ) | | (2,608,782 | ) |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | ENTERGY CORPORATION AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of: | | | | | | | | | | | | |
| Long-term debt | | 3,100,069 |
| | 3,746,016 |
| | 3,478,361 |
| | 1,809,390 |
| | 6,800,558 |
| | 3,502,189 |
|
| Preferred stock of subsidiary | | — |
| | 24,249 |
| | — |
| | 14,399 |
| | — |
| | 107,426 |
|
| Mandatorily redeemable preferred membership units of subsidiary | | — |
| | — |
| | 51,000 |
| |
| Treasury stock | | 194,866 |
| | 24,527 |
| | 62,886 |
| | 80,729 |
| | 33,114 |
| | 24,366 |
|
| Retirement of long-term debt | | (2,323,313 | ) | | (3,814,666 | ) | | (3,130,233 | ) | | (1,585,681 | ) | | (5,311,324 | ) | | (3,461,518 | ) |
| Repurchase of common stock | | (183,271 | ) | | — |
| | — |
| | — |
| | — |
| | (99,807 | ) |
| Repurchase / redemptions of preferred stock | | | (20,599 | ) | | (115,283 | ) | | (94,285 | ) |
| Changes in credit borrowings and commercial paper - net | | (448,475 | ) | | 250,889 |
| | 687,675 |
| | 1,163,296 |
| | (79,337 | ) | | (104,047 | ) |
| Other | | 23,579 |
| | — |
| | — |
| | (7,731 | ) | | (6,872 | ) | | (9,136 | ) |
| Dividends paid: | | |
| | |
| | |
| | |
| | |
| | |
|
| Common stock | | (596,117 | ) | | (593,037 | ) | | (589,209 | ) | | (628,885 | ) | | (611,835 | ) | | (598,897 | ) |
| Preferred stock | | (19,511 | ) | | (18,802 | ) | | (22,329 | ) | | (13,940 | ) | | (20,789 | ) | | (19,758 | ) |
| Net cash flow provided by (used in) financing activities | | (252,173 | ) | | (380,824 | ) | | 538,151 |
| | 810,978 |
| | 688,232 |
| | (753,467 | ) |
| | | | | | | | | | | | | |
| Effect of exchange rates on cash and cash equivalents | | — |
| | (245 | ) | | (508 | ) | |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | 682,900 |
| | 206,557 |
| | (161,869 | ) | |
| Net decrease in cash and cash equivalents | | | (406,571 | ) | | (163,117 | ) | | (71,065 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | 739,126 |
| | 532,569 |
| | 694,438 |
| | 1,187,844 |
| | 1,350,961 |
| | 1,422,026 |
|
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | |
| $1,422,026 |
| |
| $739,126 |
| |
| $532,569 |
| |
| $781,273 |
| |
| $1,187,844 |
| |
| $1,350,961 |
|
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
| | |
| | |
| | |
|
| Cash paid during the period for: | | |
| | |
| | |
| |
| Cash paid (received) during the period for: | | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $611,376 |
| |
| $570,212 |
| |
| $546,125 |
| |
| $678,371 |
| |
| $746,779 |
| |
| $663,630 |
|
| Income taxes | |
| $77,799 |
| |
| $127,735 |
| |
| $49,214 |
| |
| ($13,375 | ) | |
| $95,317 |
| |
| $103,589 |
|
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | ENTERGY CORPORATION AND SUBSIDIARIES | CONSOLIDATED BALANCE SHEETS | ASSETS | | | | | | |
| | | December 31, | | December 31, |
| | | 2014 | | 2013 | | 2017 | | 2016 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT ASSETS | | | | | | | | |
| Cash and cash equivalents: | | | | | | | | |
| Cash | |
| $131,327 |
| |
| $129,979 |
| |
| $56,629 |
| |
| $129,579 |
|
| Temporary cash investments | | 1,290,699 |
| | 609,147 |
| | 724,644 |
| | 1,058,265 |
|
| Total cash and cash equivalents | | 1,422,026 |
| | 739,126 |
| | 781,273 |
| | 1,187,844 |
|
| Accounts receivable: | | |
| | |
| | |
| | |
|
| Customer | | 596,917 |
| | 670,641 |
| | 673,347 |
| | 654,995 |
|
| Allowance for doubtful accounts | | (35,663 | ) | | (34,311 | ) | | (13,587 | ) | | (11,924 | ) |
| Other | | 220,342 |
| | 195,028 |
| | 169,377 |
| | 158,419 |
|
| Accrued unbilled revenues | | 321,659 |
| | 340,828 |
| | 383,813 |
| | 368,677 |
|
| Total accounts receivable | | 1,103,255 |
| | 1,172,186 |
| | 1,212,950 |
| | 1,170,167 |
|
| Deferred fuel costs | | 155,140 |
| | 116,379 |
| | 95,746 |
| | 108,465 |
|
| Accumulated deferred income taxes | | 27,783 |
| | 175,073 |
| |
| Fuel inventory - at average cost | | 205,434 |
| | 208,958 |
| | 182,643 |
| | 179,600 |
|
| Materials and supplies - at average cost | | 918,584 |
| | 915,006 |
| | 723,222 |
| | 698,523 |
|
| Deferred nuclear refueling outage costs | | 214,188 |
| | 192,474 |
| | 133,164 |
| | 146,221 |
|
| Prepayments and other | | 343,223 |
| | 410,489 |
| | 156,333 |
| | 193,448 |
|
| TOTAL | | 4,389,633 |
| | 3,929,691 |
| | 3,285,331 |
| | 3,684,268 |
|
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
| | |
| | |
|
| Investment in affiliates - at equity | | 36,234 |
| | 40,350 |
| | 198 |
| | 198 |
|
| Decommissioning trust funds | | 5,370,932 |
| | 4,903,144 |
| | 7,211,993 |
| | 5,723,897 |
|
| Non-utility property - at cost (less accumulated depreciation) | | 213,791 |
| | 199,375 |
| | 260,980 |
| | 233,641 |
|
| Other | | 405,169 |
| | 210,616 |
| | 441,862 |
| | 469,664 |
|
| TOTAL | | 6,026,126 |
| | 5,353,485 |
| | 7,915,033 |
| | 6,427,400 |
|
| | | | | | | | | |
| PROPERTY, PLANT, AND EQUIPMENT | | |
| | |
| | |
| | |
|
| Electric | | 44,881,419 |
| | 42,935,712 |
| | 47,287,370 |
| | 45,191,216 |
|
| Property under capital lease | | 945,784 |
| | 941,299 |
| | 620,544 |
| | 619,527 |
|
| Natural gas | | 377,565 |
| | 366,365 |
| | 453,162 |
| | 413,224 |
|
| Construction work in progress | | 1,425,981 |
| | 1,514,857 |
| | 1,980,508 |
| | 1,378,180 |
|
| Nuclear fuel | | 1,542,055 |
| | 1,566,904 |
| | 923,200 |
| | 1,037,899 |
|
| TOTAL PROPERTY, PLANT AND EQUIPMENT | | 49,172,804 |
| | 47,325,137 |
| | 51,264,784 |
| | 48,640,046 |
|
| Less - accumulated depreciation and amortization | | 20,449,858 |
| | 19,443,493 |
| | 21,600,424 |
| | 20,718,639 |
|
| PROPERTY, PLANT AND EQUIPMENT - NET | | 28,722,946 |
| | 27,881,644 |
| | 29,664,360 |
| | 27,921,407 |
|
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
| | |
| | |
|
| Regulatory assets: | | |
| | |
| | |
| | |
|
| Regulatory asset for income taxes - net | | 836,064 |
| | 849,718 |
| | — |
| | 761,280 |
|
| Other regulatory assets (includes securitization property of $724,839 as of December 31, 2014 and $822,218 as of December 31, 2013) | | 4,968,553 |
| | 3,893,363 |
| |
| Other regulatory assets (includes securitization property of $485,031 as of December 31, 2017 and $600,996 as of December 31, 2016) | | | 4,935,689 |
| | 4,769,913 |
|
| Deferred fuel costs | | 238,102 |
| | 172,202 |
| | 239,298 |
| | 239,100 |
|
| Goodwill | | 377,172 |
| | 377,172 |
| | 377,172 |
| | 377,172 |
|
| Accumulated deferred income taxes | | 48,351 |
| | 62,011 |
| | 178,204 |
| | 117,885 |
|
| Other | | 920,907 |
| | 887,160 |
| | 112,062 |
| | 1,606,009 |
|
| TOTAL | | 7,389,149 |
| | 6,241,626 |
| | 5,842,425 |
| | 7,871,359 |
|
| | | | | | | | | |
| TOTAL ASSETS | |
| $46,527,854 |
| |
| $43,406,446 |
| |
| $46,707,149 |
| |
| $45,904,434 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | ENTERGY CORPORATION AND SUBSIDIARIES | CONSOLIDATED BALANCE SHEETS | LIABILITIES AND EQUITY | | | | | | |
| | | December 31, | | December 31, |
| | | 2014 | | 2013 | | 2017 | | 2016 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing long-term debt | |
| $899,375 |
| |
| $457,095 |
| |
| $760,007 |
| |
| $364,900 |
|
| Notes payable and commercial paper | | 598,407 |
| | 1,046,887 |
| | 1,578,308 |
| | 415,011 |
|
| Accounts payable | | 1,166,431 |
| | 1,173,313 |
| | 1,452,216 |
| | 1,285,577 |
|
| Customer deposits | | 412,166 |
| | 370,997 |
| | 401,330 |
| | 403,311 |
|
| Taxes accrued | | 128,108 |
| | 191,093 |
| | 214,967 |
| | 181,114 |
|
| Accumulated deferred income taxes | | 38,039 |
| | 28,307 |
| |
| Interest accrued | | 206,010 |
| | 180,997 |
| | 187,972 |
| | 187,229 |
|
| Deferred fuel costs | | 91,602 |
| | 57,631 |
| | 146,522 |
| | 102,753 |
|
| Obligations under capital leases | | 2,508 |
| | 2,323 |
| | 1,502 |
| | 2,423 |
|
| Pension and other postretirement liabilities | | 57,994 |
| | 67,419 |
| | 71,612 |
| | 76,942 |
|
| Other | | 248,251 |
| | 484,510 |
| | 221,771 |
| | 180,836 |
|
| TOTAL | | 3,848,891 |
| | 4,060,572 |
| | 5,036,207 |
| | 3,200,096 |
|
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
| | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 9,133,161 |
| | 8,724,635 |
| | 4,466,503 |
| | 7,495,290 |
|
| Accumulated deferred investment tax credits | | 247,521 |
| | 263,765 |
| | 219,634 |
| | 227,147 |
|
| Obligations under capital leases | | 29,710 |
| | 32,218 |
| | 22,015 |
| | 24,582 |
|
| Regulatory liability for income taxes-net | | | 2,900,204 |
| | — |
|
| Other regulatory liabilities | | 1,383,609 |
| | 1,295,955 |
| | 1,588,520 |
| | 1,572,929 |
|
| Decommissioning and asset retirement cost liabilities | | 4,458,296 |
| | 3,933,416 |
| | 6,185,814 |
| | 5,992,476 |
|
| Accumulated provisions | | 418,128 |
| | 115,139 |
| | 478,273 |
| | 481,636 |
|
| Pension and other postretirement liabilities | | 3,638,295 |
| | 2,320,704 |
| | 2,910,654 |
| | 3,036,010 |
|
| Long-term debt (includes securitization bonds of $784,862 as of December 31, 2014 and $883,013 as of December 31, 2013) | | 12,500,109 |
| | 12,139,149 |
| |
| Long-term debt (includes securitization bonds of $544,921 as of December 31, 2017 and $661,175 as of December 31, 2016) | | | 14,315,259 |
| | 14,467,655 |
|
| Other | | 557,649 |
| | 583,667 |
| | 393,748 |
| | 1,121,619 |
|
| TOTAL | | 32,366,478 |
| | 29,408,648 |
| | 33,480,624 |
| | 34,419,344 |
|
| | | | | | | | | |
| Commitments and Contingencies | |
|
| |
|
| |
|
| |
|
|
| | | | | | | | | |
| Subsidiaries’ preferred stock without sinking fund | | 210,760 |
| | 210,760 |
| | 197,803 |
| | 203,185 |
|
| | | | | | | | | |
| EQUITY | | |
| | |
| |
| Common Shareholders’ Equity: | | |
| | |
| |
| Common stock, $.01 par value, authorized 500,000,000 shares; issued 254,752,788 shares in 2014 and in 2013 | | 2,548 |
| | 2,548 |
| |
| COMMON EQUITY | | | |
| | |
|
| Common stock, $.01 par value, authorized 500,000,000 shares; issued 254,752,788 shares in 2017 and in 2016 | | | 2,548 |
| | 2,548 |
|
| Paid-in capital | | 5,375,353 |
| | 5,368,131 |
| | 5,433,433 |
| | 5,417,245 |
|
| Retained earnings | | 10,169,657 |
| | 9,825,053 |
| | 7,977,702 |
| | 8,195,571 |
|
| Accumulated other comprehensive loss | | (42,307 | ) | | (29,324 | ) | | (23,531 | ) | | (34,971 | ) |
| Less - treasury stock, at cost (75,512,079 shares in 2014 and 76,381,936 shares in 2013) | | 5,497,526 |
| | 5,533,942 |
| |
| Total common shareholders’ equity | | 10,007,725 |
| | 9,632,466 |
| |
| Subsidiaries’ preferred stock without sinking fund | | 94,000 |
| | 94,000 |
| |
| Less - treasury stock, at cost (74,235,135 shares in 2017 and 75,623,363 shares in 2016) | | | 5,397,637 |
| | 5,498,584 |
|
| TOTAL | | 10,101,725 |
| | 9,726,466 |
| | 7,992,515 |
| | 8,081,809 |
|
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $46,527,854 |
| |
| $43,406,446 |
| |
| $46,707,149 |
| |
| $45,904,434 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | ENTERGY CORPORATION AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | | For the Years Ended December 31, 2014, 2013, and 2012 | |
| For the Years Ended December 31, 2017, 2016, and 2015 | | For the Years Ended December 31, 2017, 2016, and 2015 |
| | | | | | | | | | | |
| | |
| Common Shareholders’ Equity |
| | |
| Common Shareholders’ Equity |
| |
| | Subsidiaries’
Preferred
Stock | | Common Stock | | Treasury Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | Subsidiaries’ Preferred Stock | | Common Stock | | Treasury Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
| | (In Thousands) | (In Thousands) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2011 |
| $94,000 |
| |
| $2,548 |
| |
| ($5,680,468 | ) | |
| $5,360,682 |
| |
| $9,446,960 |
| |
| ($168,452 | ) | |
| $9,055,270 |
| |
| Balance at December 31, 2014 | |
| $94,000 |
| |
| $2,548 |
| |
| ($5,497,526 | ) | |
| $5,375,353 |
| |
| $10,169,657 |
| |
| ($42,307 | ) | |
| $10,101,725 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (a) | 21,690 |
| | — |
| | — |
| | — |
| | 846,673 |
| | — |
| | 868,363 |
| |
| Other comprehensive loss | — |
| | — |
| | — |
| | — |
| | — |
| | (124,631 | ) | | (124,631 | ) | |
| Consolidated net income (loss) (a) | | 19,828 |
| | — |
| | — |
| | — |
| | (176,562 | ) | | — |
| | (156,734 | ) |
| Other comprehensive income | | — |
| | — |
| | — |
| | — |
| | — |
| | 51,258 |
| | 51,258 |
|
| Common stock repurchases | | — |
| | — |
| | (99,807 | ) | | — |
| | — |
| | — |
| | (99,807 | ) |
| Preferred stock repurchases / redemptions | | (94,000 | ) | | — |
| | — |
| | — |
| | (285 | ) | | — |
| | (94,285 | ) |
| Common stock issuances related to stock plans | — |
| | — |
| | 105,649 |
| | (2,830 | ) | | — |
| | — |
| | 102,819 |
| — |
| | — |
| | 44,954 |
| | 28,405 |
| | — |
| | — |
| | 73,359 |
|
| Common stock dividends declared | — |
| | — |
| | — |
| | — |
| | (589,042 | ) | | — |
| | (589,042 | ) | — |
| | — |
| | — |
| | — |
| | (598,897 | ) | | — |
| | (598,897 | ) |
| Preferred dividend requirements of subsidiaries (a) | (21,690 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (21,690 | ) | (19,828 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (19,828 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2012 |
| $94,000 |
| |
| $2,548 |
| |
| ($5,574,819 | ) | |
| $5,357,852 |
| |
| $9,704,591 |
| |
| ($293,083 | ) | |
| $9,291,089 |
| |
| Balance at December 31, 2015 | |
| $— |
| |
| $2,548 |
| |
| ($5,552,379 | ) | |
| $5,403,758 |
| |
| $9,393,913 |
| |
| $8,951 |
| |
| $9,256,791 |
|
| | | | | | | | | | | | | | | |
| Consolidated net income (loss) (a) | | 19,115 |
| | — |
| | — |
| | — |
| | (583,618 | ) | | — |
| | (564,503 | ) |
| Other comprehensive loss | | — |
| | — |
| | — |
| | — |
| | — |
| | (43,922 | ) | | (43,922 | ) |
| Common stock issuances related to stock plans | | — |
| | — |
| | 53,795 |
| | 13,487 |
| | — |
| | — |
| | 67,282 |
|
| Common stock dividends declared | | — |
| | — |
| | — |
| | — |
| | (611,835 | ) | | — |
| | (611,835 | ) |
| Subsidiaries' capital stock redemptions | | — |
| | — |
| | — |
| | — |
| | (2,889 | ) | | — |
| | (2,889 | ) |
| Preferred dividend requirements of subsidiaries (a) | | (19,115 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (19,115 | ) |
| | | | | | | | | | | | | | | |
| Balance at December 31, 2016 | |
| $— |
| |
| $2,548 |
| |
| ($5,498,584 | ) | |
| $5,417,245 |
| |
| $8,195,571 |
| |
| ($34,971 | ) | |
| $8,081,809 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (a) | 18,670 |
| | — |
| | — |
| | — |
| | 711,902 |
| | — |
| | 730,572 |
| 13,741 |
| | — |
| | — |
| | — |
| | 411,612 |
| | — |
| | 425,353 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | 263,759 |
| | 263,759 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 11,440 |
| | 11,440 |
|
| Common stock issuances related to stock plans | — |
| | — |
| | 40,877 |
| | 10,279 |
| | — |
| | — |
| | 51,156 |
| — |
| | — |
| | 100,947 |
| | 16,188 |
| | — |
| | — |
| | 117,135 |
|
| Common stock dividends declared | — |
| | — |
| | — |
| | — |
| | (591,440 | ) | | — |
| | (591,440 | ) | — |
| | — |
| | — |
| | — |
| | (628,885 | ) | | — |
| | (628,885 | ) |
| Subsidiaries' capital stock redemptions | | — |
| | — |
| | — |
| | — |
| | (596 | ) | | — |
| | (596 | ) |
| Preferred dividend requirements of subsidiaries (a) | (18,670 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (18,670 | ) | (13,741 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (13,741 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2013 |
| $94,000 |
| |
| $2,548 |
| |
| ($5,533,942 | ) | |
| $5,368,131 |
| |
| $9,825,053 |
| |
| ($29,324 | ) | |
| $9,726,466 |
| |
| | | | | | | | | | | | | | | |
| Consolidated net income (a) | 19,536 |
| | — |
| | — |
| | — |
| | 940,721 |
| | — |
| | 960,257 |
| |
| Other comprehensive loss | — |
| | — |
| | — |
| | — |
| | — |
| | (12,983 | ) | | (12,983 | ) | |
| Common stock repurchases | — |
| | — |
| | (183,271 | ) | | — |
| | — |
| | — |
| | (183,271 | ) | |
| Common stock issuances related to stock plans | — |
| | — |
| | 219,687 |
| | 7,222 |
| | — |
| | — |
| | 226,909 |
| |
| Common stock dividends declared | — |
| | — |
| | — |
| | — |
| | (596,117 | ) | | — |
| | (596,117 | ) | |
| Preferred dividend requirements of subsidiaries (a) | (19,536 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (19,536 | ) | |
| | | | | | | | | | | | | | | |
| Balance at December 31, 2014 |
| $94,000 |
| |
| $2,548 |
| |
| ($5,497,526 | ) | |
| $5,375,353 |
| |
| $10,169,657 |
| |
| ($42,307 | ) | |
| $10,101,725 |
| |
| Balance at December 31, 2017 | |
| $— |
| |
| $2,548 |
| |
| ($5,397,637 | ) | |
| $5,433,433 |
| |
| $7,977,702 |
| |
| ($23,531 | ) | |
| $7,992,515 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | | | | | | |
| (a) Consolidated net income and preferred dividend requirements of subsidiaries for 2014, 2013, and 2012 include $12.9 million, $12 million, and $15 million, respectively, of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity. | |
| (a) Consolidated net income and preferred dividend requirements of subsidiaries include $13.7 million for 2017, $19.1 million for 2016, and $14.9 million for 2015 of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity. | | (a) Consolidated net income and preferred dividend requirements of subsidiaries include $13.7 million for 2017, $19.1 million for 2016, and $14.9 million for 2015 of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity. |
ENTERGY CORPORATION AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The accompanying consolidated financial statements include the accounts of Entergy Corporation and its subsidiaries. As required by generally accepted accounting principles in the United States of America, all intercompany transactions have been eliminated in the consolidated financial statements. Entergy’s Registrant Subsidiaries (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy) also include their separate financial statements in this Form 10-K. The Registrant Subsidiaries and many other Entergy subsidiaries also maintain accounts in accordance with FERC and other regulatory guidelines.
Use of Estimates in the Preparation of Financial Statements
In conformity with generally accepted accounting principles in the United States of America, the preparation of Entergy Corporation’s consolidated financial statements and the separate financial statements of the Registrant Subsidiaries requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses, and the disclosure of contingent assets and liabilities. Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used.
Revenues and Fuel Costs
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Louisiana, Mississippi, and Texas, respectively. Entergy Gulf States Louisiana also distributes natural gas to retail customers in and around Baton Rouge, Louisiana. Entergy New Orleans sells both electric power and natural gas to retail customers in the City of New Orleans, except for Algiers, whereincluding Algiers. Prior to October 1, 2015, Entergy Louisiana iswas the electric power supplier.supplier for Algiers. The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power generated by plants owned by subsidiaries in that segment.
Entergy recognizes revenue from electric power and natural gas sales when power or gas is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, Entergy’s Utility operating companies accrue an estimate of the revenues for energy delivered since the latest billings. The Utility operating companies calculate the estimate based upon several factors including billings through the last billing cycle in a month, actual generation in the month, historical line loss factors, and prices in effect in Entergy’s Utility operating companies’ various jurisdictions. Changes are made to the inputs in the estimate as needed to reflect changes in billing practices. Each month the estimated unbilled revenue amounts are recorded as revenue and unbilled accounts receivable, and the prior month’s estimate is reversed. Therefore, changes in price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the next, and may result in variability in reported revenues from one period to the next as prior estimates are reversed and new estimates recorded.
Entergy records revenue fromFor sales under rates implemented subject to refund, lessEntergy reduces revenue by accruing estimated amounts accrued for probable refunds when Entergy believes it is probable that revenues will be refunded to customers based upon the status of the rate proceeding as of the date the financial statements are prepared.proceeding.
Entergy’s Utility operating companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is billed based on a pre-determined fuel cost (fixed fuel factor),
Entergy Corporation and Subsidiaries
Notes to Financial Statements
the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing. System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are computed by allowing a return on System Energy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy’s effective interest cost for its debt allocable to its investment in Grand Gulf.
Accounting for MISO transactions
In December 2013, Entergy joinedis a member of MISO, a regional transmission organization that maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. In the MISO market, Entergy offers its generation and bids its load into the market on an hourly basis. MISO settles these hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market clearing price that takes into account physical limitations on the transmission system, generation, and demand throughout the MISO region. MISO evaluates the market participants’ energy offers and demand bids to economically and reliably dispatch the entire MISO system. Entergy nets purchases and sales within the MISO market on an hourly basis and reports in operating revenues when in a net selling position for an hour period and in operating expenses when in a net purchasing position.position for an hour period.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost.cost less regulatory disallowances and impairments. Depreciation is computed on the straight-line basis at rates based on the applicable estimated service lives of the various classes of property. For the Registrant Subsidiaries, the original cost of plant retired or removed, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the Registrant Subsidiaries’ plant is subject to mortgage liens.
Electric plant includes the portions of Grand Gulf and Waterford 3 that have beenwere sold and leased back.back in prior periods. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions. In March 2016, Entergy Louisiana completed the first step in a two-step transaction to purchase the undivided interests in Waterford 3 that were previously being leased by acquiring a beneficial interest in the Waterford 3 leased assets. In February 2017 the leases were terminated and the leased assets transferred to Entergy Louisiana. See Note 10 to the financial statements for further discussion of Entergy Louisiana’s purchase of the Waterford 3 leased assets.
Net property, plant, and equipment for Entergy (including property under capital lease and associated accumulated amortization) by business segment and functional category, as of December 31, 20142017 and 2013,2016, is shown below:
| | | 2014 | | Entergy | | Utility | | Entergy Wholesale Commodities | | Parent & Other | |
| 2017 | | | Entergy | | Utility | | Entergy Wholesale Commodities | | Parent & Other |
| | | (In Millions) | | (In Millions) |
| Production | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Nuclear | |
| $9,639 |
| |
| $6,586 |
| |
| $3,053 |
| |
| $— |
| |
| $6,946 |
| |
| $6,694 |
| |
| $252 |
| |
| $— |
|
| Other | | 3,425 |
| | 3,067 |
| | 358 |
| | — |
| | 4,215 |
| | 4,118 |
| | 97 |
| | — |
|
| Transmission | | 4,197 |
| | 4,164 |
| | 33 |
| | — |
| | 5,844 |
| | 5,842 |
| | 2 |
| | — |
|
| Distribution | | 6,973 |
| | 6,973 |
| | — |
| | — |
| | 8,000 |
| | 8,000 |
| | — |
| | — |
|
| Other | | 1,521 |
| | 1,373 |
| | 145 |
| | 3 |
| | 1,755 |
| | 1,748 |
| | 3 |
| | 4 |
|
| Construction work in progress | | 1,426 |
| | 969 |
| | 456 |
| | 1 |
| | 1,981 |
| | 1,951 |
| | 30 |
| | — |
|
| Nuclear fuel | | 1,542 |
| | 840 |
| | 702 |
| | — |
| | 923 |
| | 822 |
| | 101 |
| | — |
|
| Property, plant, and equipment - net | |
| $28,723 |
| |
| $23,972 |
| |
| $4,747 |
| |
| $4 |
| |
| $29,664 |
| |
| $29,175 |
| |
| $485 |
| |
| $4 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Entergy | | Utility | | Entergy Wholesale Commodities | | Parent & Other | |
| 2016 | | | Entergy | | Utility | | Entergy Wholesale Commodities | | Parent & Other |
| | | (In Millions) | | (In Millions) |
| Production | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Nuclear | |
| $9,667 |
| |
| $6,601 |
| |
| $3,066 |
| |
| $— |
| |
| $6,948 |
| |
| $6,524 |
| |
| $424 |
| |
| $— |
|
| Other | | 2,836 |
| | 2,465 |
| | 371 |
| | — |
| | 4,047 |
| | 4,000 |
| | 47 |
| | — |
|
| Transmission | | 3,929 |
| | 3,894 |
| | 35 |
| | — |
| | 5,226 |
| | 5,223 |
| | 3 |
| | — |
|
| Distribution | | 6,716 |
| | 6,716 |
| | — |
| | — |
| | 7,648 |
| | 7,648 |
| | — |
| | — |
|
| Other | | 1,652 |
| | 1,475 |
| | 174 |
| | 3 |
| | 1,636 |
| | 1,521 |
| | 111 |
| | 4 |
|
| Construction work in progress | | 1,515 |
| | 1,217 |
| | 298 |
| | — |
| | 1,378 |
| | 1,334 |
| | 44 |
| | — |
|
| Nuclear fuel | | 1,567 |
| | 855 |
| | 712 |
| | — |
| | 1,038 |
| | 817 |
| | 221 |
| | — |
|
| Property, plant, and equipment - net | |
| $27,882 |
| |
| $23,223 |
| |
| $4,656 |
| |
| $3 |
| |
| $27,921 |
| |
| $27,067 |
| |
| $850 |
| |
| $4 |
|
Depreciation rates on average depreciable property for Entergy approximated 3.0% in 2017, 2.8% in 2014, 2.6%2016, and 2.9% in 2013, and 2.5% in 2012.2015. Included in these rates are the depreciation rates on average depreciable Utility property of 2.5%2.6% in 2014, 2.5%2017, 2.6% in 2013,2016, and 2.4% 2012,2.7% 2015, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 5.5%22.3% in 2014, 4.1%2017, 5.2% in 2013,2016, and 3.5%5.4% in 2012.2015. The increasehigher depreciation rate in 20142017 for Entergy Wholesale Commodities resulted from implementationreflects the significantly reduced remaining estimated operating lives associated with management’s strategy to reduce the size of a new depreciation study.the Entergy Wholesale Commodities’ merchant fleet.
Entergy amortizes nuclear fuel using a units-of-production method. Nuclear fuel amortization is included in fuel expense in the income statements. Because the value of their long-lived assets are impaired, and their remaining estimated operating lives significantly reduced, the Entergy Wholesale Commodities nuclear plants, except for Palisades, charge nuclear fuel costs directly to expense when incurred because their undiscounted cash flows are insufficient to recover the carrying amount of these capital additions.
“Non-utility property - at cost (less accumulated depreciation)” for Entergy is reported net of accumulated depreciation of $185.5$167 million and $203$169 million as of December 31, 20142017 and 2013,2016, respectively.
Construction expenditures included in accounts payable is $209$368 million and $166$253 million at December 31, 20142017 and 2013,2016, respectively.
Net property, plant, and equipment for the Registrant Subsidiaries (including property under capital lease and associated accumulated amortization) by company and functional category, as of December 31, 20142017 and 2013,2016, is shown below:
| | | 2014 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2017 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) | | (In Millions) |
| Production | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear | |
| $1,097 |
| |
| $1,403 |
| |
| $2,151 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $1,935 |
| |
| $1,368 |
| |
| $3,664 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $1,660 |
|
| Other | | 593 |
| | 282 |
| | 1,279 |
| | 526 |
| | (11 | ) | | 399 |
| | — |
| | 806 |
| | 2,016 |
| | 560 |
| | 207 |
| | 531 |
| | — |
|
| Transmission | | 1,166 |
| | 711 |
| | 859 |
| | 642 |
| | 44 |
| | 695 |
| | 48 |
| | 1,650 |
| | 2,148 |
| | 900 |
| | 81 |
| | 1,021 |
| | 42 |
|
| Distribution | | 1,928 |
| | 1,004 |
| | 1,443 |
| | 1,125 |
| | 357 |
| | 1,116 |
| | — |
| | 2,226 |
| | 2,748 |
| | 1,316 |
| | 440 |
| | 1,270 |
| | — |
|
| Other | | 164 |
| | 173 |
| | 287 |
| | 194 |
| | 181 |
| | 98 |
| | 17 |
| | 247 |
| | 592 |
| | 203 |
| | 204 |
| | 168 |
| | 39 |
|
| Construction work in progress | | 284 |
| | 127 |
| | 242 |
| | 68 |
| | 19 |
| | 125 |
| | 50 |
| | 281 |
| | 1,281 |
| | 149 |
| | 47 |
| | 102 |
| | 70 |
|
| Nuclear fuel | | 294 |
| | 132 |
| | 163 |
| | — |
| | — |
| | — |
| | 251 |
| | 277 |
| | 337 |
| | — |
| | — |
| | — |
| | 208 |
|
| Property, plant, and equipment - net | |
| $5,526 |
| |
| $3,832 |
| |
| $6,424 |
| |
| $2,555 |
| |
| $590 |
| |
| $2,433 |
| |
| $2,301 |
| |
| $6,855 |
| |
| $12,786 |
| |
| $3,128 |
| |
| $979 |
| |
| $3,092 |
| |
| $2,019 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2016 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) | | (In Millions) |
| Production | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear | |
| $1,047 |
| |
| $1,422 |
| |
| $2,202 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $1,930 |
| |
| $1,201 |
| |
| $3,540 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $1,783 |
|
| Other | | 609 |
| | 271 |
| | 684 |
| | 537 |
| | (7 | ) | | 371 |
| | — |
| | 801 |
| | 1,966 |
| | 537 |
| | 213 |
| | 483 |
| | — |
|
| Transmission | | 1,086 |
| | 646 |
| | 770 |
| | 638 |
| | 31 |
| | 673 |
| | 49 |
| | 1,491 |
| | 1,925 |
| | 740 |
| | 79 |
| | 943 |
| | 45 |
|
| Distribution | | 1,831 |
| | 950 |
| | 1,420 |
| | 1,096 |
| | 340 |
| | 1,079 |
| | — |
| | 2,144 |
| | 2,632 |
| | 1,242 |
| | 414 |
| | 1,216 |
| | — |
|
| Other | | 192 |
| | 184 |
| | 292 |
| | 197 |
| | 181 |
| | 106 |
| | 17 |
| | 216 |
| | 517 |
| | 201 |
| | 188 |
| | 106 |
| | 25 |
|
| Construction work in progress | | 209 |
| | 105 |
| | 673 |
| | 37 |
| | 29 |
| | 95 |
| | 29 |
| | 304 |
| | 670 |
| | 118 |
| | 25 |
| | 111 |
| | 44 |
|
| Nuclear fuel | | 322 |
| | 197 |
| | 147 |
| | — |
| | — |
| | — |
| | 189 |
| | 307 |
| | 250 |
| | — |
| | — |
| | — |
| | 260 |
|
| Property, plant, and equipment - net | |
| $5,296 |
| |
| $3,775 |
| |
| $6,188 |
| |
| $2,505 |
| |
| $574 |
| |
| $2,324 |
| |
| $2,214 |
| |
| $6,464 |
| |
| $11,500 |
| |
| $2,838 |
| |
| $919 |
| |
| $2,859 |
| |
| $2,157 |
|
Depreciation rates on average depreciable property for the Registrant Subsidiaries are shown below:
|
| | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| 2014 | 2.4% | | 1.8% | | 2.5% | | 2.6% | | 3.1% | | 2.5% | | 3.0% |
| 2013 | 2.5% | | 1.8% | | 2.5% | | 2.6% | | 3.0% | | 2.5% | | 2.8% |
| 2012 | 2.5% | | 1.8% | | 2.4% | | 2.6% | | 3.0% | | 2.4% | | 2.8% |
|
| | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| 2017 | 2.5% | | 2.3% | | 3.1% | | 3.5% | | 2.6% | | 2.8% |
| 2016 | 2.5% | | 2.3% | | 3.1% | | 3.4% | | 2.5% | | 2.8% |
| 2015 | 2.6% | | 2.3% | | 3.2% | | 3.0% | | 2.6% | | 2.8% |
Non-utility property - at cost (less accumulated depreciation) for Entergy Gulf States Louisiana is reported net of accumulated depreciation of $151 million and $146 million as of December 31, 2014 and 2013, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $3.2$152.3 million and $3$154.4 million as of December 31, 20142017 and 2013,2016, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Mississippi is reported net of accumulated depreciation of $2.2$0.5 million and $2.1$0.5 million as of December 31, 20142017 and 2013,2016, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $10.4$4.9 million and $10.4$4.9 million as of December 31, 20142017 and 2013,2016, respectively.
As of December 31, 2014,2017, construction expenditures included in accounts payable are $37.3$58.8 million for Entergy Arkansas, $23.4 million for Entergy Gulf States Louisiana, $48$160.4 million for Entergy Louisiana, $7.8$17.1 million for Entergy Mississippi, $0.9$2.5 million for Entergy New Orleans, $24.1$32.8 million for Entergy Texas, and $7.7$33.9 million for System Energy. As of December 31, 2013,2016, construction expenditures included in accounts payable are $61.9$40.9 million for Entergy Arkansas, $13.1 million for Entergy Gulf States Louisiana, $31.1$114.8 million for Entergy Louisiana, $2.8$11.5 million for Entergy Mississippi, $1.7$2.3 million for Entergy New Orleans, $10.9$9.3 million for Entergy Texas, and $6.7$6.2 million for System Energy.
Jointly-Owned Generating Stations
Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. All parties are required to provide their own financing. The investments, fuel expenses, and other operation and maintenance expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2014,2017, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | Generating Stations | Generating Stations | | Fuel-Type | | Total Megawatt Capability (a) | | Ownership | | Investment | | Accumulated Depreciation | Generating Stations | | Fuel Type | | Total Megawatt Capability (a) | | Ownership | | Investment | | Accumulated Depreciation |
| | | | | | | | | | | (In Millions) | | | | | | | | | (In Millions) |
| Utility business: | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas - | | | | | | | | | | | | | | | | | | | | | | | |
| Independence | | Unit 1 | | Coal | | 839 |
| | 31.50 | % | |
| $129 |
| |
| $98 |
| Unit 1 | | Coal | | 836 |
| | 31.50 | % | |
| $140 |
| |
| $103 |
|
| | | Common Facilities | | Coal | | | | 15.75 | % | |
| $34 |
| |
| $26 |
| |
| Independence | | Common Facilities | | Coal | | | | 15.75 | % | |
| $34 |
| |
| $27 |
|
| White Bluff | | Units 1 and 2 | | Coal | | 1,637 |
| | 57.00 | % | |
| $503 |
| |
| $355 |
| Units 1 and 2 | | Coal | | 1,636 |
| | 57.00 | % | |
| $531 |
| |
| $364 |
|
| Ouachita (b) | | Common
Facilities | | Gas | | | | 66.67 | % | |
| $169 |
| |
| $145 |
| Common Facilities | | Gas | |
|
| | 66.67 | % | |
| $172 |
| |
| $150 |
|
Entergy Gulf States Louisiana - | | | | | | | | |
| | | | | |
| Union (c) | | Units 1 and 2 Common Facilities | | Gas | |
|
| | 50.00 | % | |
| $1 |
| |
| $— |
|
| Union (c) | | Common Facilities | | Gas | | | | 25.00 | % | |
| $28 |
| |
| $3 |
|
| Entergy Louisiana - | | | | | | | | |
| | | | |
| Roy S. Nelson | | Unit 6 | | Coal | | 537 |
| | 40.25 | % | |
| $261 |
| |
| $181 |
| Unit 6 | | Coal | | 550 |
| | 40.25 | % | |
| $280 |
| |
| $194 |
|
| Roy S. Nelson | | Unit 6 Common
Facilities | | Coal | | | | 17.70 | % | |
| $10 |
| |
| $4 |
| Unit 6 Common Facilities | | Coal | | | | 25.79 | % | |
| $15 |
| |
| $6 |
|
| Big Cajun 2 | | Unit 3 | | Coal | | 594 |
| | 24.15 | % | |
| $149 |
| |
| $105 |
| Unit 3 | | Coal | | 574 |
| | 24.15 | % | |
| $150 |
| |
| $117 |
|
| Big Cajun 2 | | Unit 3 Common Facilities | | Coal | | | | 8.05 | % | |
| $5 |
| |
| $2 |
|
| Ouachita (b) | | Common
Facilities | | Gas | | | | 33.33 | % | |
| $87 |
| |
| $74 |
| Common Facilities | | Gas | |
|
| | 33.33 | % | |
| $90 |
| |
| $75 |
|
| Entergy Louisiana - | | | | | | | | | |
| Acadia | | Common
Facilities | | Gas | | | | 50.00 | % | |
| $19 |
| |
| $— |
| Common Facilities | | Gas | |
|
| | 50.00 | % | |
| $20 |
| |
| $— |
|
| Union (c) | | Common Facilities | | Gas | | | | 50.00 | % | |
| $55 |
| |
| $3 |
|
| Entergy Mississippi - | | | | | | | | |
| | | | | | | | | | | |
| | | | |
| Independence | | Units 1 and 2
and Common
Facilities | | Coal | | 1,681 |
| | 25.00 | % | |
| $251 |
| |
| $149 |
| Units 1 and 2 and Common Facilities | | Coal | | 1,678 |
| | 25.00 | % | |
| $266 |
| |
| $156 |
|
| Entergy New Orleans - | | | | | | | | | |
| Union (c) | | Units 1 and 2 Common Facilities | | Gas | |
|
| | 50.00 | % | |
| $1 |
| |
| $— |
|
| Union (c) | | Common Facilities | | Gas | | | | 25.00 | % | |
| $28 |
| |
| $3 |
|
| Entergy Texas - | | | | | | | | |
| | | | | | | | | | | |
| | | | |
| Roy S. Nelson | | Unit 6 | | Coal | | 537 |
| | 29.75 | % | |
| $188 |
| |
| $115 |
| Unit 6 | | Coal | | 550 |
| | 29.75 | % | |
| $200 |
| |
| $114 |
|
| Roy S. Nelson | | Unit 6 Common
Facilities | | Coal | | | | 13.07 | % | |
| $6 |
| |
| $2 |
| Unit 6 Common Facilities | | Coal | | | | 14.16 | % | |
| $6 |
| |
| $3 |
|
| Big Cajun 2 | | Unit 3 | | Coal | | 594 |
| | 17.85 | % | |
| $112 |
| |
| $72 |
| Unit 3 | | Coal | | 574 |
| | 17.85 | % | |
| $113 |
| |
| $76 |
|
| Big Cajun 2 | | Unit 3 Common Facilities | | Coal | | | | 5.95 | % | |
| $3 |
| |
| $1 |
|
| System Energy - | | | | | | | | |
| | | | | | | | | | | |
| | | | |
| Grand Gulf | | Unit 1 | | Nuclear | | 1,409 |
| | 90.00 | % | (c) | |
| $4,819 |
| |
| $2,820 |
| |
| Grand Gulf (d) | | Unit 1 | | Nuclear | | 1,414 |
| | 90.00 | % | |
| $4,916 |
| |
| $3,175 |
|
Entergy Wholesale Commodities: | | | | | | | | |
| | | | | | | | | | | |
| | | | |
| Independence | | Unit 2 | | Coal | | 842 |
| | 14.37 | % | |
| $69 |
| |
| $46 |
| Unit 2 | | Coal | | 842 |
| | 14.37 | % | |
| $73 |
| |
| $50 |
|
| Independence | | Common
Facilities | | Coal | | | | 7.18 | % | |
| $16 |
| |
| $11 |
| Common Facilities | | Coal | | | | 7.18 | % | |
| $17 |
| |
| $12 |
|
| Roy S. Nelson | | Unit 6 | | Coal | | 537 |
| | 10.9 | % | |
| $107 |
| |
| $57 |
| Unit 6 | | Coal | | 550 |
| | 10.90 | % | |
| $113 |
| |
| $62 |
|
| Roy S. Nelson | | Unit 6 Common Facilities | | Coal | | | | 4.79 | % | |
| $2 |
| |
| $1 |
| Unit 6 Common Facilities | | Coal | | | | 5.19 | % | |
| $2 |
| |
| $1 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
| (a) | “Total Megawatt Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. |
| |
| (b) | Ouachita Units 1 and 2 are owned 100% by Entergy Arkansas and Ouachita Unit 3 is owned 100% by Entergy Gulf States Louisiana. The investment and accumulated depreciation numbers above are only for the common facilities and not for the generating units. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
| (c) | Union Unit 1 is owned 100% by Entergy New Orleans, Union Unit 2 is owned 100% by Entergy Arkansas, Union Units 3 and 4 are owned 100% by Entergy Louisiana. The investment and accumulated depreciation numbers above are only for the specified common facilities and not for the generating units. |
| |
| (d) | Includes a leasehold interest held by System Energy. System Energy’s Grand Gulf lease obligations are discussed in Note 10 to the financial statements. |
Nuclear Refueling Outage Costs
Nuclear refueling outage costs are deferred during the outage and amortized over the estimated period to the next outage because these refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line. Because the value of their long-lived assets are impaired, and their remaining estimated operating lives significantly reduced, the Entergy Wholesale Commodities nuclear plants, except for Palisades, charge nuclear refueling outage costs directly to expense when incurred because their undiscounted cash flows are insufficient to recover the carrying amount of these costs.
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction by the Registrant Subsidiaries. AFUDC increases both the plant balance and earnings and is realized in cash through depreciation provisions included in the rates charged to customers.
Income Taxes
Entergy Corporation and the majority of its subsidiaries file a United States consolidated federal income tax return. Entergy Louisiana, LLC and Entergy New Orleans, LLC are not members of the Entergy Corporation consolidated federal income tax filing group but, rather, are included in the Entergy Utility Holding Company, LLC consolidated federal income tax filing group. Each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the tax filing entities in accordance with Entergy’s intercompany income tax allocation agreement.agreements. Deferred income taxes are recorded for temporary differences between the book and tax basis of assets and liabilities, and for certain losses and credits available for carryforward.
Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the tax or rate was enacted. See the “Other Tax Matters - Tax Cuts and Jobs Act” section in Note 3 to the financial statements for discussion of the effects of the enactment of the Tax Cuts and Jobs Act, in December 2017.
The benefits of investment tax credits are deferred and amortized over the average useful life of the related property, as a reduction of income tax expense, for such credits associated with regulatedrate-regulated operations in accordance with ratemaking treatment.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Earnings (Loss) per Share
The following table presents Entergy’s basic and diluted earnings per share calculation included on the consolidated statements of income:operations:
| | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| | (In Millions, Except Per Share Data) | (In Millions, Except Per Share Data) |
| | | | $/share | | | | $/share | | | | $/share | | | $/share | | | | $/share | | | | $/share |
| Net income attributable to Entergy Corporation |
| $940.7 |
| | |
| |
| $711.9 |
| | |
| |
| $846.7 |
| | |
| |
| Basic earnings per average common share | 179.5 |
| |
| $5.24 |
| | 178.2 |
| |
| $3.99 |
| | 177.3 |
| |
| $4.77 |
| |
| Net income (loss) attributable to Entergy Corporation | |
| $411.6 |
| | |
| |
| ($583.6 | ) | | |
| |
| ($176.6 | ) | | |
|
| Basic earnings (loss) per average common share | | 179.7 |
| |
| $2.29 |
| | 178.9 |
| |
| ($3.26 | ) | | 179.2 |
| |
| ($0.99 | ) |
| Average dilutive effect of: | |
| | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
| | |
|
| Stock options | 0.3 |
| | (0.01 | ) | | 0.1 |
| | — |
| | 0.3 |
| | (0.01 | ) | 0.2 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other equity plans | 0.5 |
| | (0.01 | ) | | 0.3 |
| | — |
| | 0.1 |
| | — |
| 0.6 |
| | (0.01 | ) | | — |
| | — |
| | — |
| | — |
|
| Diluted earnings per average common shares | 180.3 |
| |
| $5.22 |
| | 178.6 |
| |
| $3.99 |
| | 177.7 |
| |
| $4.76 |
| |
| Diluted earnings (loss) per average common shares | | 180.5 |
| |
| $2.28 |
| | 178.9 |
| |
| ($3.26 | ) | | 179.2 |
| |
| ($0.99 | ) |
The calculation of diluted earnings (loss) per share excluded 5,743,0132,927,512 options outstanding at December 31, 2014, 8,866,5422017, 7,137,210 options outstanding at December 31, 2013,2016, and 7,164,3197,399,820 options outstanding at December 31, 2012 that
Entergy Corporation and Subsidiaries
Notes to Financial Statements2015 because they were antidilutive.
could potentially dilute basic earnings per share in the future. Those options were not included in the calculation of diluted earnings per share because the exercise price of those options exceeded the average market price for the year.
Stock-based Compensation Plans
Entergy grants stock options, restricted stock, performance units, and restricted liabilitystock unit awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans, which are shareholder-approved stock-based compensation plans. These plans are described more fully in Note 12 to the financial statements. The cost of the stock-based compensation is charged to income over the vesting period. Awards under Entergy’s plans generally vest over 3three years.
Effective January 1, 2017, Entergy adopted ASU 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.” The ASU permits the election of an accounting policy change to the method of recognizing forfeitures of stock-based compensation. Previously, Entergy recorded an estimate of the number of forfeitures expected to occur each period. Entergy elected to change this policy to account for forfeitures when they occur. This accounting change was applied retrospectively, but did not result in an adjustment to retained earnings as of January 1, 2017. As a result of adoption of the ASU, Entergy now prospectively recognizes all income tax effects related to share-based payments through the income statement. In the first quarter 2017, stock option expirations, along with other stock compensation activity, resulted in the write-off of $11.5 million of deferred tax assets.
Accounting for the Effects of Regulation
Entergy’s Utility operating companies and System Energy are rate-regulated enterprises whose rates meet three criteria specified in accounting standards. The Utility operating companies and System Energy have rates that (i) are approved by a body (its regulator) empowered to set rates that bind customers; (ii) are cost-based; and (iii) can be charged to and collected from customers. These criteria may also be applied to separable portions of a utility’s business, such as the generation or transmission functions, or to specific classes of customers. Because the Utility operating companies and System Energy meet these criteria, each of them capitalizes costs, thatwhich would otherwise be charged to expense, if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Such capitalized costs are reflected as regulatory assets in the accompanying financial statements. When an enterprise
Entergy Corporation and Subsidiaries
Notes to Financial Statements
concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity’s balance sheet.
An enterprise that ceases to meet the three criteria for all or part of its operations should report that event in its financial statements. In general, the enterprise no longer meeting the criteria should eliminate from its balance sheet all regulatory assets and liabilities related to the applicable operations. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs, it is possible that an impairment may exist that could require further write-offs of plant assets.
Entergy Gulf States Louisiana does not apply regulatory accounting standards to the Louisiana retail deregulated portion of River Bend, the 30% interest in River Bend formerly owned by Cajun, and its steam business, unless specific cost recovery is provided for in tariff rates. The Louisiana retail deregulated portion of River Bend is operated under a deregulated asset plan representing a portion (approximately 15%) of River Bend plant costs, generation, revenues, and expenses established under a 1992 LPSC order. The plan allows Entergy Gulf States Louisiana to sell the electricity from the deregulated assets to Louisiana retail customers at 4.6 cents per kWh or off-system at higher prices, with certain provisions for sharing incremental revenue above 4.6 cents per kWh between customers and shareholders.
Regulatory Asset or Liability for Income Taxes
Accounting standards for income taxes provide that a regulatory asset or liability be recorded if it is probable that the currently determinable future increase or decrease in regulatory income tax expense will be recovered from or reimbursedreturned to customers through future rates. The primary sourceThere are two main sources of Entergy’s regulatory asset or liability for income taxestaxes. There is a regulatory asset related to the ratemaking treatment of the tax effects of book depreciation for the equity component of AFUDC that has been capitalized to property, plant, and equipment but for which there is no corresponding tax basis. Equity-AFUDC is a component of property, plant, and equipment that is included in rate base when the plant is placed in service. There is a regulatory liability related to the adjustment of Entergy’s net deferred income taxes that was required by the enactment in December 2017 of a change in the federal corporate income tax rate, which is discussed in Note 3 to the financial statements.
Cash and Cash Equivalents
Entergy considers all unrestricted highly liquid debt instruments with an original maturity of three months or less at date of purchase to be cash equivalents.
Entergy Corporation and Subsidiaries
Notes to Financial StatementsSecuritization Recovery Trust Accounts
The funds that Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas hold in their securitization recovery trust accounts are not classified as cash and cash equivalents or restricted cash and cash equivalents because of their nature, uses, and restrictions. These funds are classified as part of other current assets and other investments, depending on the timeframe within which the Registrant Subsidiary expects to use the funds.
Allowance for Doubtful Accounts
The allowance for doubtful accounts reflects Entergy’s best estimate of losses on the accounts receivable balances. The allowance is based on accounts receivable agings, historical experience, and other currently available evidence. Utility operating company customer accounts receivable are written off consistent with approved regulatory requirements.
Investments
Entergy records decommissioning trust funds on the balance sheet at their fair value. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment
Entergy Corporation and Subsidiaries
Notes to Financial Statements
for decommissioning trust funds, for unrealized gains/(losses) on investment securities the Registrant Subsidiaries record an offsetting amount in other regulatory liabilities/assets for the unrealized gains/(losses) on investment securities.assets. For the 30% interest in River Bend formerly owned by Cajun, Entergy Gulf States Louisiana has recordedrecords an offsetting amount in other deferred credits for the unrealized gains/(losses).excess trust earnings not currently expected to be needed to decommission the plant. Decommissioning trust funds for Pilgrim, Indian Point 1, Indian Point 2, Indian Point 3, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of shareholders’ equity because these assets are classified as available for sale. Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of shareholders’ equity unless the unrealized loss is other than temporary and therefore recorded in earnings. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Effective January 1, 2018 with the adoption of ASU 2016-01, unrealized gains and losses on investments in equity securities held by the nuclear decommissioning trust funds will be recorded in earnings as they occur rather than in other comprehensive income. In accordance with the regulatory treatment of the decommissioning trust funds of the Registrant Subsidiaries, an offsetting amount of unrealized gains/losses will continue to be recorded in other regulatory liabilities/assets. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. See Note 1716 to the financial statements for details on the decommissioning trust funds.
Equity Method Investments
Entergy owns investments that are accounted for under the equity method of accounting because Entergy’s ownership level results in significant influence, but not control, over the investee and its operations. Entergy records its share of the investee'sinvestee’s comprehensive earnings and losses in income and as an increase or decrease to the investment account. Any cash distributions are charged against the investment account. Entergy discontinues the recognition of losses on equity investments when its share of losses equals or exceeds its carrying amount for an investee plus any advances made or commitments to provide additional financial support. See Note 14 to the financial statements for additional information regarding Entergy’s equity method investments.
Derivative Financial Instruments and Commodity Derivatives
The accounting standards for derivative instruments and hedging activities require that all derivatives be recognized at fair value on the balance sheet, either as assets or liabilities, unless they meet various exceptions including the normal purchase, purchase/normal salessale criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction. Due to regulatory treatment, an offsetting regulatory asset or liability is recorded for changes in fair value of recognized derivatives for the Registrant Subsidiaries.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Contracts for commodities that will be physically delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, meet the normal purchase, normal sales criteria and are not recognized on the balance sheet. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.
For other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. To qualify for hedge accounting, the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods when the underlying transactions actually occur. The ineffective portions of all hedges are recognized in current-period earnings. Changes in the fair value of derivative instruments that are not designated as cash flow hedges are recorded in current-period earnings on a mark-to-market basis.
Entergy has determined that contracts to purchase uranium do not meet the definition of a derivative under the accounting standards for derivative instruments because they do not provide for net settlement and the uranium markets are not sufficiently liquid to conclude that forward contracts are readily convertible to cash. If the uranium markets do become sufficiently liquid in the future and Entergy begins to account for uranium purchase contracts as derivative instruments, the fair value of these contracts would be accounted for consistent with Entergy’s other derivative instruments. See Note 15 to the financial statements for further details on Entergy’s derivative instruments and hedging activities.
Fair Values
The estimated fair values of Entergy’s financial instruments and derivatives are determined using historical prices, bid prices, market quotes, and financial modeling. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not accrue to the benefit or detriment of stockholders.affect net income. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. See Note 1615 to the financial statements for further discussion of fair value.
Impairment of Long-LivedLong-lived Assets
Entergy periodically reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets. Projected net cash flows depend on the expected operating life of the assets, the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy and capacity over the remaining life of the assets.
Two nuclear power plants in Because the values of their long-lived assets are impaired, and their remaining estimated operating lives significantly reduced, the Entergy Wholesale Commodities business segment (Indian Point 2 and Indian Point 3) have an application pendingnuclear plants, except for renewed NRC licenses. Various parties have expressed oppositionPalisades, are charging additional expenditures for capital assets directly to renewalexpense when incurred because their undiscounted cash flows are insufficient to recover the carrying amount of these capital additions. See Note 14 to the financial statements for further discussions of the licenses. Under federal law, nuclear power plants may continue to operate beyond their original license expiration dates while their timely filed renewal applications are pending NRC approval. On September 28, 2013, Indian Point 2 reached the expiration date of its original NRC operating license and entered into the period of extended operation under the timely renewal rule. In December 2015, Indian Point 3 will reach the expiration date of its original NRC operations license and, similarly, will enter the period of extended operation under the timely renewal rule if its license is not renewed before then. If the NRC does not renew the operating license for either of these plants, the plant’s operating life could be shortened, reducing its projected net cash flows and potentially impairing its value as an asset.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In March 2011 the NRC renewed Vermont Yankee’s operating license for an additional 20 years. The renewed operating license expires in March 2032. Vermont Yankee operated under a Certificate of Public Good from the State of Vermont that was scheduled to expire in March 2012, but had an amended petition pending before the Vermont Public Service Board (VPSB) for a renewed Certificate of Public Good to operate until March 2032.
In June 2013 the VPSB completed hearings on Entergy’s amended petition for a Certificate of Public Good to continuing operating Vermont Yankee. In August 2013, Entergy announced that it planned to close Vermont Yankee at the end of 2014 and that same day filed a second amended petition seeking authorization to operate the plant only until that date. In December 2013, Entergy and Vermont entered into a settlement agreement, with an accompanying memorandum of understanding that was filed with the VPSB, under which Vermont agreed to support Entergy’s request to operate Vermont Yankee until the end of 2014. The settlement agreement provided for Entergy to make $10 million in economic transition payments, $5 million in clean energy development support, and a transitional $5 million payment to Vermont. The settlement agreement also provided for Entergy to set aside a new $25 million fund to ensure the Vermont Yankee site is restored after decommissioning. These terms were contingent upon the VPSB issuing by March 31, 2014 a Certificate of Public Good authorizing Vermont Yankee’s operation through 2014, and otherwise conforming to the terms of the settlement agreement. The settlement agreement also provided for the dismissal or discontinuation of other litigation between Entergy and Vermont. On March 28, 2014, the VPSB approved the memorandum of understanding and issued a Certificate of Public Good authorizing Vermont Yankee to operate until December 31, 2014. In May 2014 the VPSB denied a motion that had been filed by one of the intervenors to amend its approval order. Pursuant to its commitment in the settlement agreement, Entergy Vermont Yankee provided to the Vermont parties in October 2014, a site assessment study of the costs and tasks of radiological decommissioning, spent nuclear fuel management, and site restoration of Vermont Yankee. Entergy Vermont Yankee also filed its Post-Shutdown Decommissioning Activities Report (PSDAR) for Vermont Yankee with the NRC in December 2014.
Because of the uncertainty regarding the continued operation of Vermont Yankee, Entergy tested the recoverability of the plant and related assets in each quarter since the first quarter 2010 after a bill to approve the continued operation of Vermont Yankee was defeated in the Vermont legislature. Vermont law at that time required legislative approval of Vermont Yankee’s continued operation although that law was later invalidated by the U.S. federal courts as preempted by the Atomic Energy Act. The determination of recoverability is based on the probability-weighted undiscounted net cash flows expected to be generated by the plant and related assets. Projected net cash flows primarily depend on the status of the pending legal and state regulatory matters, as well as projections of future revenues and expenses over the remaining life of the plant. Prior to the first quarter 2012, the probability-weighted undiscounted net cash flows exceeded the carrying value of the Vermont Yankee plant and related assets. The decline, however, in the overall energy market and the projected forward prices of power as of March 31, 2012, which are significant inputs in the determination of net cash flows, resulted in the probability-weighted undiscounted future cash flows being less than the asset group’s carrying value. Entergy performed a fair value analysis based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimated fair value of the plant and related assets at March 31, 2012 was $162 million, while the carrying value was $517.5 million. Therefore, the assets were written down to their fair value and an impairment charge of $355.5 million ($223.5 million after-tax) was recognized. The impairment charge was recorded as a separate line item in Entergy’s consolidated statement of income for 2012, and is included within the resultsimpairments of the Entergy Wholesale Commodities segment.nuclear plants.
The estimate of fair value was based on the price that Entergy would expect to receive in a hypothetical sale of the Vermont Yankee plant and related assets to a market participant on March 31, 2012. In order to determine this price, Entergy used significant observable inputs, including quoted forward power and gas prices, where available. Significant unobservable inputs, such as projected long-term pre-tax operating margins (cash basis), and estimated weighted average costs of capital were also used in the estimation of fair value. In addition, Entergy made certain assumptions regarding future tax deductions associated with the plant and related assets. Based on the use of significant unobservable inputs, the fair value measurement for the entirety of the asset group, and for each type of asset within the asset group, is classified as Level 3 in the fair value hierarchy discussed in Note 16 to the financial statements.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The following table sets forth a description of significant unobservable inputs used in the valuation of the Vermont Yankee plant and related assets as of March 31, 2012:
|
| | | | |
Significant Unobservable Inputs | | Range | | Weighted Average |
| | | | |
Weighted average cost of capital | | 7.5%-8.0% | | 7.8% |
Long-term pre-tax operating margin (cash basis) | | 6.1%-7.8% | | 7.2% |
On August 27, 2013, Entergy announced its plan to close and decommission Vermont Yankee at the end of its fuel cycle at the end of 2014. This decision was approved by the Board in August 2013, although the exact date of shutdown was not determined. The decision to shut down the plant was primarily due to sustained low natural gas and wholesale energy prices, the high cost structure of the plant, and lack of a market structure that adequately compensates merchant nuclear plants for their environmental and fuel diversity benefits in the region in which the plant operates.
As a result of the decision to shut down the plant, Entergy recognized non-cash impairment and other related charges of $291.5 million ($183.7 million after-tax) during the third quarter 2013 to write down the carrying value of Vermont Yankee and related assets to their fair values. Entergy performed a fair value analysis based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimated fair value of the plant and related assets was $62 million, while the carrying value was $349 million. The carrying value of $349 million reflected the effect of a $58 million increase in Vermont Yankee’s estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations. Impairment and other related charges were recorded as a separate line item in Entergy’s consolidated statements of income for 2013 and this impairment charge is included within the results of the Entergy Wholesale Commodities segment.
The estimate of fair value was based on the price that Entergy would expect to receive in a hypothetical sale of the Vermont Yankee plant and related assets to a market participant. In order to determine this price, Entergy used significant observable inputs, including quoted forward power and gas prices, where available. Significant unobservable inputs, such as projected long-term pre-tax operating margins (cash basis), and estimated weighted average costs of capital were also used in the estimation of fair value. In addition, Entergy made certain assumptions regarding future tax deductions associated with the plant and related assets. Based on the use of significant unobservable inputs, the fair value measurement for the entirety of the asset group, and for each type of asset within the asset group, is classified as Level 3 in the fair value hierarchy discussed in Note 16 to the financial statements.
The following table sets forth a description of significant unobservable inputs used in the valuation of the Vermont Yankee plant and related assets as of July 31, 2013:
|
| | |
Significant Unobservable Inputs | | Amount |
| | |
Weighted average cost of capital | | 7.5% |
Long-term pre-tax operating margin (cash basis) | | 7.0% |
Entergy’s Accounting Policy group, which reports to the Chief Accounting Officer, was primarily responsible for determining the valuation of the Vermont Yankee plant and related assets, in consultation with external advisors. Accounting Policy obtained and reviewed information from other Entergy departments with expertise on the various inputs and assumptions that were necessary to calculate the fair value of the asset group.
As a result of the settlement agreement entered into by Entergy and Vermont regarding the remaining operation and decommissioning of Vermont Yankee discussed above, Entergy reassessed its assumptions regarding the timing of decommissioning cash flows for Vermont Yankee. The reassessment resulted in a $27.2 million increase in the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
decommissioning cost liability and a corresponding impairment charge, recorded in December 2013. As part of the development of the site assessment study and PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2014. The revised estimate, along with reassessment of the assumptions regarding the timing of decommissioning cash flows, resulted in a $101.6 million increase in the decommissioning cost liability and a corresponding impairment charge, recorded in September 2014. Impairment charges are recorded as a separate line item in Entergy’s consolidated statements of income for 2014 and 2013, and this impairment charge is included within the results of the Entergy Wholesale Commodities segment.
In addition to the $101.6 million impairment charge in September 2014 and depreciation recorded on the remaining plant balance in 2014, Entergy also recorded charges of $45.8 million related to severance and employee retention costs in 2014 relating to the shutdown of Vermont Yankee.
Vermont Yankee ceased operation in December 2014. In January 2015, Vermont Yankee completed the defueling of the reactor and submitted the certification of permanent cessation of operations and permanent removal of fuel from the reactor vessel to the NRC.
River Bend AFUDC
The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Entergy Gulf States Louisiana on a net-of-tax basis during the construction of River Bend and what the AFUDC would have been on a pre-tax basis. The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized through August 2025.
Reacquired Debt
The premiums and costs associated with reacquired debt of Entergy’s Utility operating companies and System Energy (except that portion allocable to the deregulated operations of Entergy Gulf States Louisiana) are included in regulatory assets and are being amortized over the life of the related new issuances, or over the life of the original debt issuance if the debt is not refinanced, in accordance with ratemaking treatment.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Taxes Imposed on Revenue-Producing Transactions
Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues, unless required to report them differently by a regulatory authority.
Presentation of Preferred Stock without Sinking Fund
Accounting standards regarding non-controlling interests and the classification and measurement of redeemable securities require the classification of preferred securities between liabilities and shareholders’ equity on the balance sheet if the holders of those securities have protective rights that allow them to gain control of the board of directors in certain circumstances. These rights would have the effect of giving the holders the ability to potentially redeem their securities, even if the likelihood of occurrence of these circumstances is considered remote. The Entergy Arkansas, Entergy Mississippi, and, prior to December 1, 2017, Entergy New Orleans articles of incorporation provide, generally, that the holders of each company’s preferred securities may elect a majority of the respective company’s board of directors if dividends are not paid for a year, until such time as the dividends in arrears are paid. Therefore, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans present their preferred securities outstanding between liabilities and shareholders’ equity on the balance sheet. In November 2017, Entergy Gulf States Louisiana and Entergy Louisiana, both organized as limited liability companies, haveNew Orleans redeemed its outstanding preferred securities with similar protective rights with respectas part of a multi-step process to unpaid dividends, but provideundertake an internal restructuring. See Note 2 to the financial statements for
Entergy Corporation and Subsidiaries
Notes to Financial Statements
the election of board members that would not constitute a majority of the board; and their preferred securities are therefore classified for all periods presented as a component of members’ equity.New Orleans’s internal restructuring.
The outstanding preferred securities of Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans, and Entergy Utility Holding Company (a Utility subsidiary) and Entergy Finance Holding (an Entergy Wholesale Commodities subsidiary), whose preferred holders also have protective rights, are similarly presented between liabilities and equity on Entergy’s consolidated balance sheets and the outstanding preferred securities of Entergy Gulf States Louisiana and Entergy Louisiana are presented within total equity in Entergy’s consolidated balance sheets. The preferred dividends or distributions paid by all subsidiaries are reflected for all periods presented outside of consolidated net income.
New Accounting Pronouncements
The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.
In April 2014 the FASB issued ASU No. 2014-08, “Presentation of Financial Statements (Topic 205) and Property Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” which changes the requirements for reporting discontinued operations. The ASU states that a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results when the component of an entity or group of components of an entity meets the criteria to be classified as held for sale, is disposed of by sale, or is disposed of other than by sale. The amendments in this ASU also require additional disclosures about discontinued operations. ASU 2014-08 is effective for Entergy for the first quarter 2015. Entergy does not currently expect ASU 2014-08 to affect materially its results of operations, financial position, or cash flows.
In May 2014 the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The ASU’s core principle is that “an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.” The ASU details a five-step model that should be followed to achieve the core principle. With FASB issuance of ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” ASU 2014-09 is effective for Entergy for the first quarter 2017.2018. Entergy does not expecthas selected the modified retrospective transition method. Entergy’s evaluation of ASU 2014-09 tohas not identified any effects that it expects will affect materially its results of operations, financial position, or cash flows.flows, other than changes in required financial statement disclosures. The adoption of the ASU did not result in an adjustment to retained earnings as of January 1, 2018.
In November 2014January 2016 the FASB issued ASU No. 2014-16, “Derivatives2016-01 “Financial Instruments (Subtopic 825-10): Recognition and Hedging (Topic 815): Determining Whether the Host Contract in a HybridMeasurement of Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity.Assets and Financial Liabilities.” The ASU states thatrequires investments in equity securities, excluding those accounted for hybrid financial instruments issuedunder the equity method or resulting in the form of a share, an entity should determine the natureconsolidation of the host contract by considering all stated and implied substantive terms and featuresinvestee, to be measured at fair value with changes recognized in net income. The ASU requires a qualitative assessment to identify impairments of the hybrid financial instrument, weighing each term and feature on the basis of relevant facts and circumstances.investments in equity securities that do not have a readily determinable fair value. ASU 2014-162016-01 is effective for Entergy for the first quarter 2016.2018. Entergy does not expectexpects that ASU 2014-16 to2016-01 will affect materially its results of operations financial position, or cash flows.by requiring unrealized gains and losses on investments in equity securities held by the nuclear decommissioning trust funds to be recorded in earnings rather than in other comprehensive income. In accordance with the regulatory treatment of the decommissioning trust funds of Entergy Arkansas, Entergy Louisiana, and System Energy, an offsetting amount of unrealized gains/losses will continue to be recorded in other regulatory liabilities/assets. Entergy recorded an adjustment to retained earnings of $633 million as of January 1, 2018 for the cumulative effect of the unrealized gains and losses
Entergy Corporation and Subsidiaries
Notes to Financial Statements
on investments in equity securities held by the decommissioning trust funds that do not meet the criteria for regulatory accounting treatment.
In February 2016 the FASB issued ASU No. 2016-02, “Leases (Topic 842).” The ASU’s core principle is that “a lessee should recognize the assets and liabilities that arise from leases.” The ASU considers that “all leases create an asset and a liability,” and accordingly requires recording the assets and liabilities related to all leases with a term greater than 12 months. In January 2018 the FASB issued ASU No. 2018-01, “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842,” providing entities the option to elect not to evaluate existing land easements that are not currently accounted for under the previous lease standard. ASU 2016-02 is effective for Entergy for the first quarter 2019, and Entergy does not expect to early adopt the standard. Entergy expects that ASU 2016-02 will affect its financial position by increasing the assets and liabilities recorded relating to its operating leases. Entergy is evaluating ASU 2016-02 for other effects on its results of operations, financial position, cash flows, and financial statement disclosures, as well as the potential to elect various practical expedients permitted by the standards.
In June 2016 the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The ASU requires entities to record a valuation allowance on financial instruments recorded at amortized cost or classified as available-for-sale debt securities for the total credit losses expected over the life of the instrument. Increases and decreases in the valuation allowance will be recognized immediately in earnings. ASU 2016-13 is effective for Entergy for the first quarter 2020. Entergy is evaluating ASU 2016-13 for the expected effects on its results of operations, financial position, and cash flows.
In October 2016 the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory.” The ASU requires entities to recognize the income tax consequences of intra-entity asset transfers, other than inventory, at the time the transfer occurs. ASU 2016-16 is effective for Entergy for the first quarter 2018 and will affect its statement of financial position by requiring recognition of deferred tax assets or liabilities arising from intra-entity asset transfers. Entergy recorded an adjustment to retained earnings of $56 million as of January 1, 2018 for the cumulative-effect of the recognition of the deferred tax assets arising from intra-entity asset transfers.
In March 2017 the FASB issued ASU No. 2017-07, “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” The ASU requires entities to report the service cost component of defined benefit pension cost and postretirement benefit cost (net benefit cost) in the same line item as other compensation costs arising from services rendered during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. In addition, the ASU allows only the service cost component of net benefit cost to be eligible for capitalization. ASU 2017-07 is effective for Entergy for the first quarter 2018. Entergy does not expect ASU 2017-07 to affect materially its results of operations, financial position, or cash flows.
In August 2017 the FASB issued ASU No. 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The ASU makes a number of amendments to hedge accounting, most significantly changing the recognition and presentation of highly effective hedges. Upon adoption of the standard there will no longer be separate recognition or presentation of the ineffective portion of highly effective hedges. In addition, the ASU allows entities to designate a contractually-specified component as the hedged risk, simplifies the process for assessing the effectiveness of hedges, and adds additional disclosure requirements for hedges. ASU 2017-12 is effective for Entergy for the first quarter 2019. Entergy does not expect to early adopt the standard. Entergy expects that ASU 2017-12 will affect its net income by eliminating volatility in earnings related to the ineffective portion of designated hedges on nuclear power sales. Entergy is evaluating ASU 2017-12 for other effects on its results of operations, financial position, or cash flows.
In February 2018 the FASB issued ASU No. 2018-02, “Income Statement- Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” The ASU
Entergy Corporation and Subsidiaries
Notes to Financial Statements
allows reclassification from accumulated other comprehensive income to retained earnings for certain tax effects resulting from the Tax Cuts and Jobs Act that would otherwise be stranded in accumulated other comprehensive income . ASU 2018-02 is effective for Entergy for the first quarter 2019, but may be early adopted. Entergy plans to adopt the ASU in the first quarter 2018. Entergy expects that upon the adoption of ASU 2018-02 it will record to the statement of financial position a net reclassification reducing retained earnings and increasing accumulated other comprehensive income by approximately $15 million. Entergy does not expect that ASU 2018-02 will have any other material effect on its results of operations, financial position, or cash flows.
NOTE 2. RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Regulatory Assets and Regulatory Liabilities
Regulatory assets represent probable future revenues associated with costs that Entergy expects to recover from customers through the regulatory ratemaking process under which the Utility business operates. Regulatory liabilities represent probable future reductions in revenues associated with amounts that Entergy expects to benefit customers through the regulatory ratemaking process under which the Utility business operates. In addition to the regulatory assets and liabilities that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” and “Other regulatory liabilities” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 20142017 and 2013:2016:
Other Regulatory Assets
Entergy
| | | | 2014 | | 2013 | 2017 | | 2016 |
| | (In Millions) | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)(a) |
| $2,798.8 |
| |
| $1,723.1 |
|
| $2,642.3 |
| |
| $2,635.5 |
|
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) | 736.2 |
| | 786.8 |
| |
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (b) | 513.8 |
| | 447.6 |
| |
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a) | | 746.0 |
| | 677.2 |
|
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) (Note 5) | | 558.9 |
| | 637.0 |
|
Removal costs - recovered through depreciation rates (Note 9) (b)(a) | 245.1 |
| | 188.9 |
| 436.5 |
| | 353.9 |
|
Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) | | 109.8 |
| | — |
|
Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators | | 86.4 |
| | 22.1 |
|
Unamortized loss on reacquired debt - recovered over term of debt | | 82.9 |
| | 91.4 |
|
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | 139.2 |
| | 160.6 |
| 73.7 |
| | 100.0 |
|
Under-recovered retail rate revenues - recovered through rate riders when rates are redetermined periodically | 79.6 |
| | 77.7 |
| |
Unamortized loss on reacquired debt - recovered over term of debt | 76.2 |
| | 83.0 |
| |
MISO implementation costs - recovery through retail rate riders (Note 2 - Retail Rate Proceedings) | 69.6 |
| | 74.7 |
| |
Transition to competition costs - recovered over a 15-year period through February 2021 | 66.2 |
| | 74.4 |
| 37.7 |
| | 47.9 |
|
New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (c)(b) | 58.4 |
| | 115.2 |
| 36.4 |
| | 43.7 |
|
Human capital management costs - recovery through retail rate mechanisms (Note 2 - Retail Rate Proceedings) | 42.3 |
| | 45.0 |
| |
| Other | 143.2 |
| | 116.4 |
| 125.1 |
| | 161.2 |
|
| Entergy Total |
| $4,968.6 |
| |
| $3,893.4 |
|
| $4,935.7 |
| |
| $4,769.9 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas
| | | | 2014 | | 2013 | 2017 | | 2016 |
| | (In Millions) | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)(a) |
| $838.2 |
| |
| $517.1 |
|
| $757.0 |
| |
| $786.6 |
|
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (b)(a) | 254.8 |
| | 225.9 |
| 345.2 |
| | 322.9 |
|
Storm damage costs - recovered either through securitization or retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | 125.6 |
| | 115.2 |
| |
Removal costs - recovered through depreciation rates (Note 9) (b) | 59.0 |
| | 18.6 |
| |
Removal costs - recovered through depreciation rates (Note 9) (a) | | 176.9 |
| | 128.5 |
|
Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) | | 109.8 |
| | — |
|
Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds) | | 76.2 |
| | 88.9 |
|
Retail rate deferrals - recovered through rate riders as rates are redetermined annually | | 28.2 |
| | 10.1 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 26.2 |
| | 28.8 |
| 24.3 |
| | 27.6 |
|
MISO implementation costs - recovery through retail rates through 2018 (Note 2 - Retail Rate Proceedings) (c) | 25.1 |
| | 30.9 |
| |
Under-recovered retail rate revenues - recovered through rate riders when rates are redetermined periodically | 23.3 |
| | 36.1 |
| |
Human capital management costs - recovery through retail rates through June 2017 (Note 2 - Retail Rate Proceedings) (c) | 17.3 |
| | 22.0 |
| |
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b) | | 14.4 |
| | 16.1 |
|
Lake Catherine 4 reliability and sustainability cost deferral - recovery through retail rates (b) | | 8.9 |
| | 9.8 |
|
Incremental ice storm costs - recovered through 2032 | 9.0 |
| | 9.5 |
| 7.4 |
| | 7.9 |
|
MISO costs - recovery through retail rates through 2018 (Note 2 - Retail Rate Proceedings) (b) | | 5.5 |
| | 11.1 |
|
Human capital management costs - recovery through retail rates through August 2019 (Note 2 - Retail Rate Proceedings) (b) | | 4.4 |
| | 7.0 |
|
| Other | 12.8 |
| | 10.3 |
| 9.2 |
| | 11.5 |
|
| Entergy Arkansas Total |
| $1,391.3 |
| |
| $1,014.4 |
|
| $1,567.4 |
| |
| $1,428.0 |
|
Entergy Gulf States Louisiana
|
| | | | | | | |
| | 2014 | | 2013 |
| | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b) |
| $286.8 |
| |
| $194.2 |
|
New nuclear generation development costs - recovery through formula rate plan beginning December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (c) | 29.2 |
| | 29.5 |
|
Spindletop gas storage facility - recovery period through December 2032 (a) | 26.2 |
| | 27.8 |
|
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | 18.6 |
| | 20.5 |
|
MISO implementation costs - recovery through the MISO cost recovery mechanism beginning December 2014 through November 2017 (Note 2 - Retail Rate Proceedings) | 15.7 |
| | 15.3 |
|
Human capital management costs - recovery through formula rate plan beginning December 2014 through November 2017 (Note 2 - Retail Rate Proceedings) | 11.2 |
| | 10.0 |
|
Under-recovered retail rate revenues - recovered through rate riders when rates are redetermined periodically | 11.1 |
| | 3.0 |
|
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (b) | 10.8 |
| | 11.0 |
|
Gas hedging costs - recovered through fuel rates upon settlement (Note 16 - Derivatives) | 8.2 |
| | — |
|
Unamortized loss on reacquired debt - recovered over term of debt | 6.8 |
| | 8.3 |
|
| Other | 1.8 |
| | 1.9 |
|
| Entergy Gulf States Louisiana Total |
| $426.4 |
| |
| $321.5 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Louisiana
| | | | 2014 | | 2013 | 2017 | | 2016 |
| | (In Millions) | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b)(a) |
| $487.2 |
| |
| $318.4 |
|
| $724.6 |
| |
| $715.7 |
|
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (b)(a) | 156.7 |
| | 139.2 |
| 218.6 |
| | 199.4 |
|
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | 139.2 |
| | 160.6 |
| 71.4 |
| | 97.8 |
|
New nuclear generation development costs - recovery through formula rate plan beginning December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (c)(b) | 29.2 |
| | 29.5 |
| 35.8 |
| | 43.1 |
|
MISO implementation costs - recovery through the MISO cost recovery mechanism beginning December 2014 through November 2017 (Note 2 - Retail Rate Proceedings) | 21.4 |
| | 20.8 |
| |
Unamortized loss on reacquired debt - recovered over term of debt | 14.3 |
| | 15.2 |
| 24.7 |
| | 27.0 |
|
Human capital management costs - recovery through formula rate plan beginning December 2014 through November 2017 (Note 2 - Retail Rate Proceedings) | 13.8 |
| | 13.0 |
| |
Storm damage costs, including hurricane costs - recovered through retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | 13.7 |
| | 3.4 |
| |
Storm damage costs - recovered through retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | 14.3 |
| | — |
|
Business combination external costs deferral - recovery through formula rate plan beginning December 2015 through November 2025 (b) | | 14.1 |
| | 15.2 |
|
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | | 12.9 |
| | 14.8 |
|
| Other | 38.7 |
| | 15.4 |
| 29.4 |
| | 55.1 |
|
| Entergy Louisiana Total |
| $914.2 |
| |
| $715.5 |
|
| $1,145.8 |
| |
| $1,168.1 |
|
Entergy Mississippi
| | | | 2014 | | 2013 | 2017 | | 2016 |
| | (In Millions) | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)(a) |
| $224.3 |
| |
| $135.3 |
|
| $218.7 |
| |
| $217.2 |
|
Removal costs - recovered through depreciation rates (Note 9) (b)(a) | 76.3 |
| | 64.3 |
| 91.6 |
| | 82.0 |
|
Under-recovered retail rate revenues - recovered through rate riders when rates are redetermined periodically | 28.7 |
| | 39.2 |
| |
Retail rate deferrals - recovered through rate riders as rates are redetermined annually | | 49.4 |
| | 9.3 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 8.2 |
| | 8.9 |
| 17.6 |
| | 18.9 |
|
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (b)(a) | 6.3 |
| | 5.9 |
| 7.6 |
| | 7.2 |
|
Baxter Wilson outage costs - recovered through retail rates over two years beginning February 2015 (Note 8 - Baxter Wilson Plant Event) | 6.0 |
| | — |
| |
MISO implementation costs - recovery through retail rate riders (Note 2 – Retail Rate Proceedings) | 4.0 |
| | 4.2 |
| |
New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) | — |
| | 56.2 |
| |
| Other | 10.9 |
| | 4.5 |
| 13.0 |
| | 7.6 |
|
| Entergy Mississippi Total |
| $364.7 |
| |
| $318.5 |
|
| $397.9 |
| |
| $342.2 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy New Orleans
| | | | 2014 | | 2013 | 2017 | | 2016 |
| | (In Millions) | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)(a) |
| $115.8 |
| |
| $76.8 |
|
| $102.8 |
| |
| $108.8 |
|
Removal costs - recovered through depreciation rates (Note 9) (b) | 35.2 |
| | 34.9 |
| |
Michoud plant maintenance – recovered over a 7-year period through September 2018 | 7.2 |
| | 9.1 |
| |
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | 5.0 |
| | 4.6 |
| 82.3 |
| | 93.6 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | | 44.8 |
| | 40.1 |
|
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually | | 4.4 |
| | 4.3 |
|
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (b)(a) | 3.8 |
| | 3.7 |
| 4.3 |
| | 4.2 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 1.8 |
| | 2.0 |
| 3.0 |
| | 3.4 |
|
Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings) | | 2.6 |
| | 3.0 |
|
Michoud plant maintenance – recovered over a 7-year period through September 2018 | | 1.4 |
| | 3.3 |
|
| Other | 6.8 |
| | 6.1 |
| 5.8 |
| | 7.4 |
|
| Entergy New Orleans Total |
| $175.6 |
| |
| $137.2 |
|
| $251.4 |
| |
| $268.1 |
|
Entergy Texas
| | | | 2014 | | 2013 | 2017 | | 2016 |
| | (In Millions) | (In Millions) |
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) |
| $591.7 |
| |
| $663.6 |
| |
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds) | |
| $386.1 |
| |
| $442.4 |
|
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)(a) | 217.0 |
| | 143.0 |
| 169.2 |
| | 201.7 |
|
Transition to competition costs - recovered over a 15-year period through February 2021 | 66.2 |
| | 74.4 |
| 37.7 |
| | 47.9 |
|
Removal costs - recovered through depreciation rates (Note 9) (b)(a) | 18.9 |
| | 15.1 |
| 55.2 |
| | 33.5 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 10.5 |
| | 7.7 |
| 8.7 |
| | 9.0 |
|
Rate case costs - recovered through retail rates (c) | 8.4 |
| | 10.8 |
| |
| Other | 9.4 |
| | 4.6 |
| 4.5 |
| | 5.7 |
|
| Entergy Texas Total |
| $922.1 |
| |
| $919.2 |
|
| $661.4 |
| |
| $740.2 |
|
System Energy
| | | | 2014 | | 2013 | 2017 | | 2016 |
| | (In Millions) | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (b)(a) |
| $191.0 |
| |
| $132.9 |
|
| $202.7 |
| |
| $193.5 |
|
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (b)(a) | 80.4 |
| | 60.8 |
| 169.1 |
| | 142.5 |
|
Removal costs - recovered through depreciation rates (Note 9) (b)(a) | 55.7 |
| | 56.0 |
| 67.9 |
| | 69.7 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 8.5 |
| | 12.0 |
| 4.6 |
| | 5.5 |
|
| System Energy Total |
| $335.6 |
| |
| $261.7 |
|
| $444.3 |
| |
| $411.2 |
|
| |
| (a) | The jurisdictional split order assigned the regulatory asset to Entergy Texas. The regulatory asset, however, is being recovered and amortized at Entergy Gulf States Louisiana. As a result, a billing occurs monthly over the same term as the recovery and receipts will be submitted to Entergy Texas. Entergy Texas has recorded a receivable from Entergy Gulf States Louisiana and Entergy Gulf States Louisiana has recorded a corresponding payable. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
(b) | Does not earn a return on investment, but is offset by related liabilities. |
| |
(c)(b) | Does not earn a return on investment. |
Other Regulatory Liabilities
Entergy
|
| | | | | | | |
| | 2014 | | 2013 |
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a) |
| $656.7 |
| |
| $529.6 |
|
Vidalia purchased power agreement (Note 8) | 242.8 |
| | 263.1 |
|
Louisiana Act 55 financing savings obligation (Note 2) | 156.0 |
| | 156.0 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 82.7 |
| | 72.3 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | 79.5 |
| | 92.3 |
|
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the UPSA | 53.6 |
| | 60.7 |
|
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and FERC | 44.4 |
| | 44.4 |
|
Asset retirement obligation - will be returned to customers dependent upon timing of decommissioning (Note 9) (a) | 27.7 |
| | 31.5 |
|
| Other | 40.2 |
| | 46.1 |
|
| Entergy Total |
| $1,383.6 |
| |
| $1,296.0 |
|
Entergy Arkansas
|
| | | | | | | |
| | 2014 | | 2013 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a) |
| $254.0 |
| |
| $214.1 |
|
Deferred capacity acquisition cost recovery - returned to customers through rate riders when rates are redetermined periodically | — |
| | 4.7 |
|
| Other | — |
| | 0.6 |
|
| Entergy Arkansas Total |
| $254.0 |
| |
| $219.4 |
|
Entergy Gulf States Louisiana
|
| | | | | | | |
| | 2014 | | 2013 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a) |
| $85.9 |
| |
| $64.1 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 36.9 |
| | 35.3 |
|
Asset retirement obligation - will be returned to customers dependent upon timing of decommissioning (Note 9) (a) | 27.7 |
| | 31.5 |
|
Louisiana Act 55 financing savings obligation (Note 2) | 25.5 |
| | 25.5 |
|
Gas hedging costs - returned to customers through fuel rates (Note 16 - Derivatives) | — |
| | 2.2 |
|
| Other | 0.3 |
| | 0.8 |
|
| Entergy Gulf States Louisiana Total |
| $176.3 |
| |
| $159.4 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Other Regulatory Liabilities
Entergy Louisiana
|
| | | | | | | |
| | 2014 | | 2013 |
| | (In Millions) |
Vidalia purchased power agreement (Note 8) |
| $242.8 |
| |
| $263.1 |
|
Louisiana Act 55 financing savings obligation (Note 2) | 130.5 |
| | 130.5 |
|
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a) | 123.2 |
| | 98.9 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 45.7 |
| | 37.0 |
|
| Other | 3.9 |
| | 3.7 |
|
| Entergy Louisiana Total |
| $546.1 |
| |
| $533.2 |
|
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $989.3 |
| |
| $735.5 |
|
Vidalia purchased power agreement (Note 8) (b) | 151.6 |
| | 202.4 |
|
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b) | 124.8 |
| | 165.5 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | 67.9 |
| | 67.9 |
|
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination) | 65.8 |
| | 83.5 |
|
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC | 44.4 |
| | 44.4 |
|
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a) | 36.7 |
| | 32.7 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 32.4 |
| | 53.9 |
|
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement | 32.1 |
| | 39.3 |
|
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings) | — |
| | 68.0 |
|
| Other | 43.5 |
| | 79.8 |
|
| Entergy Total |
| $1,588.5 |
| |
| $1,572.9 |
|
Entergy TexasArkansas
|
| | | | | | | |
| | 2014 | | 2013 |
| | (In Millions) |
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically |
| $5.1 |
| |
| $4.2 |
|
Line loss adjustment - returned to customers through fuel rates | — |
| | 1.0 |
|
| Entergy Texas Total |
| $5.1 |
| |
| $5.2 |
|
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $354.0 |
| |
| $280.8 |
|
| Other | 9.6 |
| | 25.1 |
|
| Entergy Arkansas Total |
| $363.6 |
| |
| $305.9 |
|
System Energy
|
| | | | | | | |
| | 2014 | | 2013 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a) |
| $193.6 |
| |
| $152.4 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | 79.5 |
| | 92.3 |
|
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the UPSA | 53.6 |
| | 60.7 |
|
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and FERC | 44.4 |
| | 44.4 |
|
| System Energy Total |
| $371.1 |
| |
| $349.8 |
|
| |
(a) | Offset by related asset. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Louisiana
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $323.7 |
| |
| $235.4 |
|
Vidalia purchased power agreement (Note 8) (b) | 151.6 |
| | 202.4 |
|
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b) | 124.8 |
| | 165.5 |
|
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination) | 65.8 |
| | 83.5 |
|
Gas hedging costs - refunded through fuel rates (Note 15 - Derivatives) | — |
| | 10.9 |
|
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a) | 36.7 |
| | 32.7 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 32.4 |
| | 53.9 |
|
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings) | — |
| | 68.0 |
|
| Other | 26.1 |
| | 28.7 |
|
| Entergy Louisiana Total |
| $761.1 |
| |
| $881.0 |
|
Entergy Texas
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically |
| $4.8 |
| |
| $6.2 |
|
| Other | 2.1 |
| | 2.3 |
|
| Entergy Texas Total |
| $6.9 |
| |
| $8.5 |
|
System Energy
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a) |
| $311.6 |
| |
| $219.3 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | 67.9 |
| | 67.9 |
|
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC | 44.4 |
| | 44.4 |
|
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement | 32.1 |
| | 39.3 |
|
| System Energy Total |
| $456.0 |
| |
| $370.9 |
|
| |
| (a) | Offset by related asset. |
| |
| (b) | As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21% effective January 2018, the Vidalia purchased power agreement regulatory liability was reduced by $30.5 million and the Louisiana Act 55 financing savings obligation regulatory liabilities were reduced by $25.0 million, with corresponding increases to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Regulatory activity regarding the Tax Cuts and Jobs Act
See the “Other Tax Matters - Tax Cuts and Jobs Act” section in Note 3 to the financial statements for discussion of the effects of the enactment of the Tax Cuts and Jobs Act, in December 2017, including its effects on Entergy’s and the Registrant Subsidiaries’ regulatory asset/liability for income taxes.
After enactment of the Tax Cuts and Jobs Act the APSC issued an order that applies to investor-owned utilities in Arkansas, including Entergy Arkansas. The order requests information regarding certain effects of the Tax Cuts and Jobs Act and requires the utilities to begin, effective January 1, 2018, to record regulatory liabilities to record the effects of the Act, subject to review by the APSC, although the order acknowledges that the exact amount of tax savings and rate reductions cannot be determined at this time. Entergy Arkansas requested clarification or, in the alternative, rehearing regarding the requirement to record a regulatory liability, and also responded to the request for information. In its request for clarification Entergy Arkansas sought clarification that the amount of any regulatory liability would be determined only after the utilities are heard and present evidence on the issue, as this otherwise would be arbitrary and could implicate single-issue and retroactive ratemaking. The APSC has not responded to the request for clarification. In its response to the APSC’s request for information Entergy Arkansas states that its formula rate plan rider already provides the means for customers to realize the benefits of the Act, except for the return of unprotected excess accumulated deferred income taxes. Entergy Arkansas’s next formula rate plan filing is scheduled for July 2018. Entergy Arkansas intends to return unprotected excess accumulated deferred income taxes as expeditiously as possible, subject to a subsequent request to be made by Entergy Arkansas and approval by the APSC.
After enactment of the Tax Cuts and Jobs Act the LPSC passed an agenda item requiring utilities, including Entergy Louisiana, to file reports regarding certain effects of the Act. Entergy Louisiana responded to the directive and stated in its response that it is working with the LPSC staff and other interested parties to extend its formula rate plan such that its next base rate change will occur effective September 2018, or it would file a base rate case. Entergy Louisiana went on to state that if the formula rate plan is extended Entergy Louisiana’s next adjustment of rates will reflect the new 21% federal corporate income tax rate. Entergy Louisiana stated that it is working with the LPSC staff and interested parties to determine when the tax rate reduction will be reflected in rates, along with when and how the excess accumulated deferred income taxes will be reflected in rates, and how certain tax sharing agreement customer credits will be adjusted. On February 21, 2018, the LPSC issued a special order requiring that all LPSC-jurisdictional utilities, beginning as of January 1, 2018, record as a regulatory liability (deferred liability) the amount required to reflect the reduction in the federal corporate income tax rate from 35% to 21% and the associated savings in excess accumulated deferred income taxes until such time as its rates are changed by the LPSC to reflect these federal tax savings. In the same special order, the LPSC also initiated a new rulemaking docket to consider these issues and the appropriate manner in which to flow through the benefits to Louisiana customers and to provide an opportunity for discovery and comments of jurisdictional utilities and other interested stakeholders. The rulemaking further requires the LPSC staff to report back to the LPSC as soon as practicable and preferably by the March 21, 2018, LPSC Business and Executive Session with recommendations as to how the federal tax-related benefits will be flowed through to Louisiana customers.
After enactment of the Tax Cuts and Jobs Act the MPSC ordered utilities, including Entergy Mississippi, that operate under a formula rate plan to file a description by February 26, 2018, of how the Act will be reflected in the formula rate plan under which the utility operates. In addition to the description that is due February 26, 2018, Entergy Mississippi’s formula rate plan 2018 test year filing is scheduled to be filed by March 15, 2018.
After enactment of the Tax Cuts and Jobs Act the City Council passed a resolution ordering Entergy New Orleans to, effective January 1, 2018, record deferred regulatory liabilities to account for the Act’s effect on Entergy New Orleans’s revenue requirement and to make a filing by mid-March 2018 regarding the Act’s effects on Entergy New Orleans’s operating income and rate base and potential mechanisms for customers to receive benefits of the Act. The resolution also directed Entergy New Orleans to request that Entergy Services file with the FERC for revisions of the Unit Power Sales Agreement and MSS-4 replacement tariffs to address the return of excess accumulated deferred income taxes. Entergy plans to make such filings with the FERC by the end of March 2018.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
After enactment of the Tax Cuts and Jobs Act the PUCT issued an order requiring most utilities, including Entergy Texas, beginning January 25, 2018, to record a regulatory liability for the difference between revenues collected under existing rates and revenues that would have been collected had existing rates been set using the new federal income tax rates and also for the balance of excess accumulated deferred income taxes. The order also directs the PUCT staff to investigate each investor-owned utility on a case-by-case basis to determine the appropriate mechanism to adjust its rates to reflect the changes under the Act. In both a memorandum issued prior to the open meeting when the order was discussed and during the discussions at the open meeting discussing the order, the PUCT indicated that it would consider utility earnings in determining the treatment of the liability and the effects of the Act. Entergy Texas had previously provided information to the PUCT Staff in the docket and stated that it expects the PUCT to address the lower tax expense as part of Entergy Texas’s rate case expected to be filed in May 2018. Entergy Texas also stated that it would be inappropriate for the PUCT to require a refund of the reduction in income tax expense in 2018 resulting from the Act on a retroactive basis and without a comprehensive review of Entergy Texas’s cost of service and earned return on equity. In a subsequent order issued following the February 2018 open meeting, the PUCT clarified that carrying costs need not be recorded as part of the regulatory liability.
The Registrant Subsidiaries will continue to work with their respective regulators to determine the appropriate path forward in each jurisdiction regarding the effects of the Act.
Fuel and purchased power cost recovery
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements. The table below shows the amount of deferred fuel costs as of December 31, 20142017 and 20132016 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
| | | | 2014 | | 2013 | 2017 | | 2016 |
| | (In Millions) | (In Millions) |
| Entergy Arkansas (a) |
| $209.2 |
| |
| $68.7 |
|
| $130.4 |
| |
| $163.6 |
|
| Entergy Gulf States Louisiana (b) |
| $89.5 |
| |
| $109.7 |
| |
| Entergy Louisiana (b) |
| $17.6 |
| |
| $37.6 |
|
| $96.7 |
| |
| $119.9 |
|
| Entergy Mississippi |
| ($2.2 | ) | |
| $38.1 |
|
| $32.4 |
| |
| $7.0 |
|
| Entergy New Orleans (b) |
| ($24.3 | ) | |
| ($19.1 | ) |
| ($3.7 | ) | |
| $8.9 |
|
| Entergy Texas |
| $11.9 |
| |
| ($4.1 | ) |
| ($67.3 | ) | |
| ($54.5 | ) |
| |
| (a) | 2014 includes $65.9Includes $67.1 million for Entergy Arkansasin 2017 and $66.9 million in 2016 of fuel and purchased power and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months. |
| |
| (b) | 2014 and 2013 include $100.1Includes $168.1 million for Entergy Gulf States Louisiana, $68 millionin each year for Entergy Louisiana and $4.1 million in each year for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months. |
Entergy Arkansas
Production Cost Allocation Rider
The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below. These costs cause an increase in Entergy
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects themthe costs from customers over twelve months.
In May 2014, Entergy Arkansas filed its annual redetermination of the production cost allocation rider to recover the $3 million unrecovered retail balance as of December 31, 2013 and the $67.8 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. In June 2014 the APSC suspended the annual redetermination of the production cost allocation rider and scheduled a hearing in September 2014. Upon a joint motion of the parties, the APSC canceled the September 2014 hearing and in January 2015 the APSC issued an order approving Entergy Arkansas’s request for recovery of the $3 million under-recovered amount based on the true-up of the production cost allocation rider and the $67.8 million May 2014 System Agreement bandwidth remedy payment subject to refund with interest, with recovery of these payments concluding with the last billing cycle in December 2015. The APSC also found that Entergy Arkansas is entitled to carrying charges pursuant to the current terms of the production cost allocation rider. Entergy Arkansas made its compliance filing pursuant to the order in January 2015 and the APSC issued its approval order, also in January 2015. The redetermined rate went into effect with the first billing cycle of February 2015.
the production cost allocation rider, which included a $38 million payment made by Entergy CorporationArkansas as a result of the FERC’s February 2014 order related to the comprehensive bandwidth recalculation for calendar year 2006, 2007, and Subsidiaries
Notes2008 production costs. The redetermined rate for the 2015 production cost allocation rider update was added to Financial Statementsthe redetermined rate from the 2014 production cost allocation rider update and the combined rate was effective with the first billing cycle of July 2015. This combined rate was effective through December 2015. The collection of the remainder of the redetermined rate for the 2015 production cost allocation rider update continued through June 2016.
In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update became effective with the first billing cycle of July 2016, and the rates were effective through June 2017.
In May 2017, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected recovery of the production cost allocation rider true-up adjustment of the 2016 unrecovered retail balance in the amount of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.
Energy Cost Recovery RiderEntergy New Orleans
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) |
| $102.8 |
| |
| $108.8 |
|
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | 82.3 |
| | 93.6 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | 44.8 |
| | 40.1 |
|
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually | 4.4 |
| | 4.3 |
|
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a) | 4.3 |
| | 4.2 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 3.0 |
| | 3.4 |
|
Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings) | 2.6 |
| | 3.0 |
|
Michoud plant maintenance – recovered over a 7-year period through September 2018 | 1.4 |
| | 3.3 |
|
| Other | 5.8 |
| | 7.4 |
|
| Entergy New Orleans Total |
| $251.4 |
| |
| $268.1 |
|
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over- or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.Texas
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds) |
| $386.1 |
| |
| $442.4 |
|
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) | 169.2 |
| | 201.7 |
|
Transition to competition costs - recovered over a 15-year period through February 2021 | 37.7 |
| | 47.9 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | 55.2 |
| | 33.5 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 8.7 |
| | 9.0 |
|
| Other | 4.5 |
| | 5.7 |
|
| Entergy Texas Total |
| $661.4 |
| |
| $740.2 |
|
In October 2005 the APSC initiated an investigation into Entergy Arkansas’s interim energy cost recovery rate. The investigation focused on Entergy Arkansas’s 1) gas contracting, portfolio, and hedging practices; 2) wholesale purchases during the period; 3) management of the coal inventory at its coal generation plants; and 4) response to the contractual failure of the railroads to provide coal deliveries. In March 2006 the APSC extended its investigation to cover the costs included in Entergy Arkansas’s March 2006 annual energy cost rate filing, and a hearing was held in the APSC investigation in October 2006.System Energy
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a) |
| $202.7 |
| |
| $193.5 |
|
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a) | 169.1 |
| | 142.5 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | 67.9 |
| | 69.7 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 4.6 |
| | 5.5 |
|
| System Energy Total |
| $444.3 |
| |
| $411.2 |
|
In January 2007 the APSC issued an order in its review of the energy cost rate. The APSC found that Entergy Arkansas failed to maintain an adequate coal inventory level going into the summer of 2005 and that Entergy Arkansas should be responsible for any incremental energy costs that resulted from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas has since resolved litigation with the railroad regarding the delivery problems. The APSC staff was directed to perform an analysis with Entergy Arkansas’s assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within sixty days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas will be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider. Entergy Arkansas requested rehearing of the order.
| |
| (a) | Does not earn a return on investment, but is offset by related liabilities. |
| |
| (b) | Does not earn a return on investment. |
In February 2010 the APSC denied Entergy Arkansas’s request for rehearing, and held a hearing in September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas. A decision is pending. Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.
The APSC also established a separate docket to consider the resolved railroad litigation, and in February 2010 it established a procedural schedule that concluded with testimony through September 2010. The testimony has been filed, and the APSC will decide the case based on the record in the proceeding.
In January 2014, Entergy Arkansas filed a motion with the APSC relating to its redetermination of its energy cost rate to be filed in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude $65.9 million of deferred fuel and purchased energy costs incurred in 2013 from the redetermination of its 2014 energy cost rate. The $65.9 million is an estimate of the incremental fuel and replacement energy costs that Entergy Arkansas incurred as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information is available regarding various claims associated with the ANO stator incident. The APSC approved Entergy Arkansas’s request in February 2014. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.
Entergy Gulf States Louisiana and Entergy Louisiana
Entergy Gulf States Louisiana and Entergy Louisiana recover electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Gulf States Louisiana’s purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through the fuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009. The LPSC Staff issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1 million from Entergy Louisiana’s fuel adjustment clause to base rates. The recommended refund was made by Entergy Louisiana in May 2013 in the form of a credit to customers through its fuel adjustment clause filing. Two parties intervened in the proceeding. A procedural schedule was established for the identification of issues by the intervenors and for Entergy Louisiana to submit comments regarding the LPSC Staff report and any issues raised by intervenors. One intervenor is seeking further proceedings regarding certain issues it raised in its comments on the LPSC Staff report. Entergy Louisiana has filed responses to both the LPSC Staff report and the issues raised by the intervenor. As required by the procedural schedule, a joint status report was submitted in October 2013 by the parties. A status conference was held in December 2013. Discovery is in progress, but a procedural schedule has not been established.Other Regulatory Liabilities
In December 2011 the LPSC authorized its staff to initiate another proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009. Discovery is in progress, but a procedural schedule has not been established.
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Gulf States Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery has yet to commence.
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery has yet to commence. |
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $989.3 |
| |
| $735.5 |
|
Vidalia purchased power agreement (Note 8) (b) | 151.6 |
| | 202.4 |
|
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b) | 124.8 |
| | 165.5 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | 67.9 |
| | 67.9 |
|
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination) | 65.8 |
| | 83.5 |
|
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC | 44.4 |
| | 44.4 |
|
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a) | 36.7 |
| | 32.7 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 32.4 |
| | 53.9 |
|
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement | 32.1 |
| | 39.3 |
|
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings) | — |
| | 68.0 |
|
| Other | 43.5 |
| | 79.8 |
|
| Entergy Total |
| $1,588.5 |
| |
| $1,572.9 |
|
Entergy MississippiArkansas
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $354.0 |
| |
| $280.8 |
|
| Other | 9.6 |
| | 25.1 |
|
| Entergy Arkansas Total |
| $363.6 |
| |
| $305.9 |
|
Entergy Mississippi’s rate schedules include an energy cost recovery rider that is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
Entergy Mississippi had a deferred fuel balance of $60.4 million as of March 31, 2014. In May 2014, Entergy Mississippi filed for an interim adjustment under its energy cost recovery rider. The interim adjustment proposed a net energy cost factor designed to collect over a six-month period the under-recovered deferred fuel balance as of March 31, 2014 and also reflected a natural gas price of $4.50 per MMBtu. In May 2014, Entergy Mississippi and the Public Utilities Staff entered into a joint stipulation in which Entergy Mississippi agreed to a revised net energy cost factor that reflected the proposed interim adjustment with a reduction in costs recovered through the energy cost recovery rider associated with the suspension of the DOE nuclear waste storage fee. In June 2014 the MPSC approved the joint stipulation and allowed Entergy Mississippi’s interim adjustment. In November 2014, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. Due to lower gas prices and a lower deferred fuel balance, the redetermined annual factor was a decrease from the revised interim net energy cost factor. In January 2015 the MPSC approved the redetermined annual factor effective January 30, 2015.
Mississippi Attorney General Complaint
The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. In December 2008 the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
defendant Entergy companies removedLouisiana
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $323.7 |
| |
| $235.4 |
|
Vidalia purchased power agreement (Note 8) (b) | 151.6 |
| | 202.4 |
|
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b) | 124.8 |
| | 165.5 |
|
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination) | 65.8 |
| | 83.5 |
|
Gas hedging costs - refunded through fuel rates (Note 15 - Derivatives) | — |
| | 10.9 |
|
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a) | 36.7 |
| | 32.7 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 32.4 |
| | 53.9 |
|
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings) | — |
| | 68.0 |
|
| Other | 26.1 |
| | 28.7 |
|
| Entergy Louisiana Total |
| $761.1 |
| |
| $881.0 |
|
Entergy Texas
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically |
| $4.8 |
| |
| $6.2 |
|
| Other | 2.1 |
| | 2.3 |
|
| Entergy Texas Total |
| $6.9 |
| |
| $8.5 |
|
System Energy
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a) |
| $311.6 |
| |
| $219.3 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | 67.9 |
| | 67.9 |
|
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC | 44.4 |
| | 44.4 |
|
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement | 32.1 |
| | 39.3 |
|
| System Energy Total |
| $456.0 |
| |
| $370.9 |
|
| |
| (a) | Offset by related asset. |
| |
| (b) | As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21% effective January 2018, the Vidalia purchased power agreement regulatory liability was reduced by $30.5 million and the Louisiana Act 55 financing savings obligation regulatory liabilities were reduced by $25.0 million, with corresponding increases to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Regulatory activity regarding the attorney general’s lawsuitTax Cuts and Jobs Act
See the “Other Tax Matters - Tax Cuts and Jobs Act” section in Note 3 to U.S. District Courtthe financial statements for discussion of the effects of the enactment of the Tax Cuts and Jobs Act, in Jackson, Mississippi.December 2017, including its effects on Entergy’s and the Registrant Subsidiaries’ regulatory asset/liability for income taxes.
After enactment of the Tax Cuts and Jobs Act the APSC issued an order that applies to investor-owned utilities in Arkansas, including Entergy Arkansas. The Mississippi attorney general movedorder requests information regarding certain effects of the Tax Cuts and Jobs Act and requires the utilities to remandbegin, effective January 1, 2018, to record regulatory liabilities to record the mattereffects of the Act, subject to review by the APSC, although the order acknowledges that the exact amount of tax savings and rate reductions cannot be determined at this time. Entergy Arkansas requested clarification or, in the alternative, rehearing regarding the requirement to record a regulatory liability, and also responded to the request for information. In its request for clarification Entergy Arkansas sought clarification that the amount of any regulatory liability would be determined only after the utilities are heard and present evidence on the issue, as this otherwise would be arbitrary and could implicate single-issue and retroactive ratemaking. The APSC has not responded to the request for clarification. In its response to the APSC’s request for information Entergy Arkansas states that its formula rate plan rider already provides the means for customers to realize the benefits of the Act, except for the return of unprotected excess accumulated deferred income taxes. Entergy Arkansas’s next formula rate plan filing is scheduled for July 2018. Entergy Arkansas intends to return unprotected excess accumulated deferred income taxes as expeditiously as possible, subject to a subsequent request to be made by Entergy Arkansas and approval by the APSC.
After enactment of the Tax Cuts and Jobs Act the LPSC passed an agenda item requiring utilities, including Entergy Louisiana, to file reports regarding certain effects of the Act. Entergy Louisiana responded to the directive and stated in its response that it is working with the LPSC staff and other interested parties to extend its formula rate plan such that its next base rate change will occur effective September 2018, or it would file a base rate case. Entergy Louisiana went on to state court.that if the formula rate plan is extended Entergy Louisiana’s next adjustment of rates will reflect the new 21% federal corporate income tax rate. Entergy Louisiana stated that it is working with the LPSC staff and interested parties to determine when the tax rate reduction will be reflected in rates, along with when and how the excess accumulated deferred income taxes will be reflected in rates, and how certain tax sharing agreement customer credits will be adjusted. On February 21, 2018, the LPSC issued a special order requiring that all LPSC-jurisdictional utilities, beginning as of January 1, 2018, record as a regulatory liability (deferred liability) the amount required to reflect the reduction in the federal corporate income tax rate from 35% to 21% and the associated savings in excess accumulated deferred income taxes until such time as its rates are changed by the LPSC to reflect these federal tax savings. In August 2012 the District Courtsame special order, the LPSC also initiated a new rulemaking docket to consider these issues and the appropriate manner in which to flow through the benefits to Louisiana customers and to provide an opportunity for discovery and comments of jurisdictional utilities and other interested stakeholders. The rulemaking further requires the LPSC staff to report back to the LPSC as soon as practicable and preferably by the March 21, 2018, LPSC Business and Executive Session with recommendations as to how the federal tax-related benefits will be flowed through to Louisiana customers.
After enactment of the Tax Cuts and Jobs Act the MPSC ordered utilities, including Entergy Mississippi, that operate under a formula rate plan to file a description by February 26, 2018, of how the Act will be reflected in the formula rate plan under which the utility operates. In addition to the description that is due February 26, 2018, Entergy Mississippi’s formula rate plan 2018 test year filing is scheduled to be filed by March 15, 2018.
After enactment of the Tax Cuts and Jobs Act the City Council passed a resolution ordering Entergy New Orleans to, effective January 1, 2018, record deferred regulatory liabilities to account for the Act’s effect on Entergy New Orleans’s revenue requirement and to make a filing by mid-March 2018 regarding the Act’s effects on Entergy New Orleans’s operating income and rate base and potential mechanisms for customers to receive benefits of the Act. The resolution also directed Entergy New Orleans to request that Entergy Services file with the FERC for revisions of the Unit Power Sales Agreement and MSS-4 replacement tariffs to address the return of excess accumulated deferred income taxes. Entergy plans to make such filings with the FERC by the end of March 2018.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
After enactment of the Tax Cuts and Jobs Act the PUCT issued an opinion denyingorder requiring most utilities, including Entergy Texas, beginning January 25, 2018, to record a regulatory liability for the Attorney General’s motiondifference between revenues collected under existing rates and revenues that would have been collected had existing rates been set using the new federal income tax rates and also for remand, finding that the District Court has subject matter jurisdictionbalance of excess accumulated deferred income taxes. The order also directs the PUCT staff to investigate each investor-owned utility on a case-by-case basis to determine the appropriate mechanism to adjust its rates to reflect the changes under the Class Action FairnessAct. In both a memorandum issued prior to the open meeting when the order was discussed and during the discussions at the open meeting discussing the order, the PUCT indicated that it would consider utility earnings in determining the treatment of the liability and the effects of the Act. Entergy Texas had previously provided information to the PUCT Staff in the docket and stated that it expects the PUCT to address the lower tax expense as part of Entergy Texas’s rate case expected to be filed in May 2018. Entergy Texas also stated that it would be inappropriate for the PUCT to require a refund of the reduction in income tax expense in 2018 resulting from the Act on a retroactive basis and without a comprehensive review of Entergy Texas’s cost of service and earned return on equity. In a subsequent order issued following the February 2018 open meeting, the PUCT clarified that carrying costs need not be recorded as part of the regulatory liability.
The Registrant Subsidiaries will continue to work with their respective regulators to determine the appropriate path forward in each jurisdiction regarding the effects of the Act.
Fuel and purchased power cost recovery
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues. The defendant Entergy companies answered the complaint and filed a counterclaim for relief based upon the Mississippi Public Utilities Actdifference between revenues collected and the Federal Power Act. In May 2009 the defendant Entergy companies filed a motion for judgmentcurrent fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the pleadings asserting groundsUtility operating companies’ financial statements. The table below shows the amount of federal preemption, the exclusive jurisdictiondeferred fuel costs as of December 31, 2017 and 2016 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
| Entergy Arkansas (a) |
| $130.4 |
| |
| $163.6 |
|
| Entergy Louisiana (b) |
| $96.7 |
| |
| $119.9 |
|
| Entergy Mississippi |
| $32.4 |
| |
| $7.0 |
|
| Entergy New Orleans (b) |
| ($3.7 | ) | |
| $8.9 |
|
| Entergy Texas |
| ($67.3 | ) | |
| ($54.5 | ) |
| |
| (a) | Includes $67.1 million in 2017 and $66.9 million in 2016 of fuel and purchased power costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months. |
| |
| (b) | Includes $168.1 million in each year for Entergy Louisiana and $4.1 million in each year for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months. |
Entergy Arkansas
Production Cost Allocation Rider
The APSC approved a production cost allocation rider for recovery from customers of the MPSC, and factual errorsretail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the attorney general’s complaint. In September 2012“System Agreement Cost Equalization Proceedings” section below. These costs cause an increase in Entergy
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the District Court heard oral argument on Entergy’s motion for judgment oncosts over seven months but collects the pleadings. The District Court’s ruling on the motion for judgment on the pleadings is pending.costs from customers over twelve months.
In May 2014, Entergy Arkansas filed its annual redetermination of the production cost allocation rider to recover the $3 million unrecovered retail balance as of December 31, 2013 and the $67.8 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. In January 2015 the APSC issued an order approving Entergy Arkansas’s request for recovery of the $3 million under-recovered amount based on the true-up of the production cost allocation rider and the $67.8 million May 2014 the U.S. Supreme Court issued a decision in which it held that cases brought by attorneys general as the sole plaintiff to enforce state laws were notSystem Agreement bandwidth remedy payment subject to refund with interest, with recovery of these payments concluding with the federal lawlast billing cycle in December 2015. The APSC also found that allowed federal courtsEntergy Arkansas is entitled to hear those cases as “mass action” lawsuits. One day latercarrying charges pursuant to the Attorney General renewedcurrent terms of the production cost allocation rider. Entergy Arkansas made its motioncompliance filing pursuant to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies have responded to that motionorder in January 2015 and the District Court held oral argument onAPSC issued its approval order, also in January 2015. The redetermined rate went into effect with the motion to remand infirst billing cycle of February 2014.2015.
In May 2015, Entergy also has asserted federal question jurisdictionArkansas filed its annual redetermination of the production cost allocation rider, which included a $38 million payment made by Entergy Arkansas as a basisresult of the FERC’s February 2014 order related to the comprehensive bandwidth recalculation for calendar year 2006, 2007, and 2008 production costs. The redetermined rate for the district court having jurisdiction2015 production cost allocation rider update was added to the redetermined rate from the 2014 production cost allocation rider update and also has pending the motioncombined rate was effective with the first billing cycle of July 2015. This combined rate was effective through December 2015. The collection of the remainder of the redetermined rate for judgment on the pleadings.2015 production cost allocation rider update continued through June 2016.
In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update became effective with the first billing cycle of July 2016, and the rates were effective through June 2017.
In May 2017, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected recovery of the production cost allocation rider true-up adjustment of the 2016 unrecovered retail balance in the amount of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.
Entergy New Orleans
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) |
| $102.8 |
| |
| $108.8 |
|
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | 82.3 |
| | 93.6 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | 44.8 |
| | 40.1 |
|
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually | 4.4 |
| | 4.3 |
|
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a) | 4.3 |
| | 4.2 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 3.0 |
| | 3.4 |
|
Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings) | 2.6 |
| | 3.0 |
|
Michoud plant maintenance – recovered over a 7-year period through September 2018 | 1.4 |
| | 3.3 |
|
| Other | 5.8 |
| | 7.4 |
|
| Entergy New Orleans Total |
| $251.4 |
| |
| $268.1 |
|
Entergy Texas
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds) |
| $386.1 |
| |
| $442.4 |
|
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) | 169.2 |
| | 201.7 |
|
Transition to competition costs - recovered over a 15-year period through February 2021 | 37.7 |
| | 47.9 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | 55.2 |
| | 33.5 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 8.7 |
| | 9.0 |
|
| Other | 4.5 |
| | 5.7 |
|
| Entergy Texas Total |
| $661.4 |
| |
| $740.2 |
|
System Energy
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a) |
| $202.7 |
| |
| $193.5 |
|
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a) | 169.1 |
| | 142.5 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | 67.9 |
| | 69.7 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 4.6 |
| | 5.5 |
|
| System Energy Total |
| $444.3 |
| |
| $411.2 |
|
| |
| (a) | Does not earn a return on investment, but is offset by related liabilities. |
| |
| (b) | Does not earn a return on investment. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Other Regulatory Liabilities
Entergy
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $989.3 |
| |
| $735.5 |
|
Vidalia purchased power agreement (Note 8) (b) | 151.6 |
| | 202.4 |
|
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b) | 124.8 |
| | 165.5 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | 67.9 |
| | 67.9 |
|
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination) | 65.8 |
| | 83.5 |
|
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC | 44.4 |
| | 44.4 |
|
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a) | 36.7 |
| | 32.7 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 32.4 |
| | 53.9 |
|
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement | 32.1 |
| | 39.3 |
|
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings) | — |
| | 68.0 |
|
| Other | 43.5 |
| | 79.8 |
|
| Entergy Total |
| $1,588.5 |
| |
| $1,572.9 |
|
Entergy Arkansas
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $354.0 |
| |
| $280.8 |
|
| Other | 9.6 |
| | 25.1 |
|
| Entergy Arkansas Total |
| $363.6 |
| |
| $305.9 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Louisiana
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $323.7 |
| |
| $235.4 |
|
Vidalia purchased power agreement (Note 8) (b) | 151.6 |
| | 202.4 |
|
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b) | 124.8 |
| | 165.5 |
|
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination) | 65.8 |
| | 83.5 |
|
Gas hedging costs - refunded through fuel rates (Note 15 - Derivatives) | — |
| | 10.9 |
|
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a) | 36.7 |
| | 32.7 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 32.4 |
| | 53.9 |
|
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings) | — |
| | 68.0 |
|
| Other | 26.1 |
| | 28.7 |
|
| Entergy Louisiana Total |
| $761.1 |
| |
| $881.0 |
|
Entergy Texas
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically |
| $4.8 |
| |
| $6.2 |
|
| Other | 2.1 |
| | 2.3 |
|
| Entergy Texas Total |
| $6.9 |
| |
| $8.5 |
|
System Energy
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a) |
| $311.6 |
| |
| $219.3 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | 67.9 |
| | 67.9 |
|
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC | 44.4 |
| | 44.4 |
|
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement | 32.1 |
| | 39.3 |
|
| System Energy Total |
| $456.0 |
| |
| $370.9 |
|
| |
| (a) | Offset by related asset. |
| |
| (b) | As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21% effective January 2018, the Vidalia purchased power agreement regulatory liability was reduced by $30.5 million and the Louisiana Act 55 financing savings obligation regulatory liabilities were reduced by $25.0 million, with corresponding increases to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Regulatory activity regarding the Tax Cuts and Jobs Act
See the “Other Tax Matters - Tax Cuts and Jobs Act” section in Note 3 to the financial statements for discussion of the effects of the enactment of the Tax Cuts and Jobs Act, in December 2017, including its effects on Entergy’s and the Registrant Subsidiaries’ regulatory asset/liability for income taxes.
After enactment of the Tax Cuts and Jobs Act the APSC issued an order that applies to investor-owned utilities in Arkansas, including Entergy Arkansas. The order requests information regarding certain effects of the Tax Cuts and Jobs Act and requires the utilities to begin, effective January 1, 2018, to record regulatory liabilities to record the effects of the Act, subject to review by the APSC, although the order acknowledges that the exact amount of tax savings and rate reductions cannot be determined at this time. Entergy Arkansas requested clarification or, in the alternative, rehearing regarding the requirement to record a regulatory liability, and also responded to the request for information. In its request for clarification Entergy Arkansas sought clarification that the amount of any regulatory liability would be determined only after the utilities are heard and present evidence on the issue, as this otherwise would be arbitrary and could implicate single-issue and retroactive ratemaking. The APSC has not responded to the request for clarification. In its response to the APSC’s request for information Entergy Arkansas states that its formula rate plan rider already provides the means for customers to realize the benefits of the Act, except for the return of unprotected excess accumulated deferred income taxes. Entergy Arkansas’s next formula rate plan filing is scheduled for July 2018. Entergy Arkansas intends to return unprotected excess accumulated deferred income taxes as expeditiously as possible, subject to a subsequent request to be made by Entergy Arkansas and approval by the APSC.
After enactment of the Tax Cuts and Jobs Act the LPSC passed an agenda item requiring utilities, including Entergy Louisiana, to file reports regarding certain effects of the Act. Entergy Louisiana responded to the directive and stated in its response that it is working with the LPSC staff and other interested parties to extend its formula rate plan such that its next base rate change will occur effective September 2018, or it would file a base rate case. Entergy Louisiana went on to state that if the formula rate plan is extended Entergy Louisiana’s next adjustment of rates will reflect the new 21% federal corporate income tax rate. Entergy Louisiana stated that it is working with the LPSC staff and interested parties to determine when the tax rate reduction will be reflected in rates, along with when and how the excess accumulated deferred income taxes will be reflected in rates, and how certain tax sharing agreement customer credits will be adjusted. On February 21, 2018, the LPSC issued a special order requiring that all LPSC-jurisdictional utilities, beginning as of January 1, 2018, record as a regulatory liability (deferred liability) the amount required to reflect the reduction in the federal corporate income tax rate from 35% to 21% and the associated savings in excess accumulated deferred income taxes until such time as its rates are changed by the LPSC to reflect these federal tax savings. In the same special order, the LPSC also initiated a new rulemaking docket to consider these issues and the appropriate manner in which to flow through the benefits to Louisiana customers and to provide an opportunity for discovery and comments of jurisdictional utilities and other interested stakeholders. The rulemaking further requires the LPSC staff to report back to the LPSC as soon as practicable and preferably by the March 21, 2018, LPSC Business and Executive Session with recommendations as to how the federal tax-related benefits will be flowed through to Louisiana customers.
After enactment of the Tax Cuts and Jobs Act the MPSC ordered utilities, including Entergy Mississippi, that operate under a formula rate plan to file a description by February 26, 2018, of how the Act will be reflected in the formula rate plan under which the utility operates. In addition to the description that is due February 26, 2018, Entergy Mississippi’s formula rate plan 2018 test year filing is scheduled to be filed by March 15, 2018.
After enactment of the Tax Cuts and Jobs Act the City Council passed a resolution ordering Entergy New Orleans to, effective January 1, 2018, record deferred regulatory liabilities to account for the Act’s effect on Entergy New Orleans’s revenue requirement and to make a filing by mid-March 2018 regarding the Act’s effects on Entergy New Orleans’s operating income and rate base and potential mechanisms for customers to receive benefits of the Act. The resolution also directed Entergy New Orleans to request that Entergy Services file with the FERC for revisions of the Unit Power Sales Agreement and MSS-4 replacement tariffs to address the return of excess accumulated deferred income taxes. Entergy plans to make such filings with the FERC by the end of March 2018.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
After enactment of the Tax Cuts and Jobs Act the PUCT issued an order requiring most utilities, including Entergy Texas, beginning January 25, 2018, to record a regulatory liability for the difference between revenues collected under existing rates and revenues that would have been collected had existing rates been set using the new federal income tax rates and also for the balance of excess accumulated deferred income taxes. The order also directs the PUCT staff to investigate each investor-owned utility on a case-by-case basis to determine the appropriate mechanism to adjust its rates to reflect the changes under the Act. In both a memorandum issued prior to the open meeting when the order was discussed and during the discussions at the open meeting discussing the order, the PUCT indicated that it would consider utility earnings in determining the treatment of the liability and the effects of the Act. Entergy Texas had previously provided information to the PUCT Staff in the docket and stated that it expects the PUCT to address the lower tax expense as part of Entergy Texas’s rate case expected to be filed in May 2018. Entergy Texas also stated that it would be inappropriate for the PUCT to require a refund of the reduction in income tax expense in 2018 resulting from the Act on a retroactive basis and without a comprehensive review of Entergy Texas’s cost of service and earned return on equity. In a subsequent order issued following the February 2018 open meeting, the PUCT clarified that carrying costs need not be recorded as part of the regulatory liability.
The Registrant Subsidiaries will continue to work with their respective regulators to determine the appropriate path forward in each jurisdiction regarding the effects of the Act.
Fuel and purchased power cost recovery
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements. The table below shows the amount of deferred fuel costs as of December 31, 2017 and 2016 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
| Entergy Arkansas (a) |
| $130.4 |
| |
| $163.6 |
|
| Entergy Louisiana (b) |
| $96.7 |
| |
| $119.9 |
|
| Entergy Mississippi |
| $32.4 |
| |
| $7.0 |
|
| Entergy New Orleans (b) |
| ($3.7 | ) | |
| $8.9 |
|
| Entergy Texas |
| ($67.3 | ) | |
| ($54.5 | ) |
| |
| (a) | Includes $67.1 million in 2017 and $66.9 million in 2016 of fuel and purchased power costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months. |
| |
| (b) | Includes $168.1 million in each year for Entergy Louisiana and $4.1 million in each year for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months. |
Entergy Arkansas
Production Cost Allocation Rider
The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below. These costs cause an increase in Entergy
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects the costs from customers over twelve months.
In May 2014, Entergy Arkansas filed its annual redetermination of the production cost allocation rider to recover the $3 million unrecovered retail balance as of December 31, 2013 and the $67.8 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. In January 2015 the APSC issued an order approving Entergy Arkansas’s request for recovery of the $3 million under-recovered amount based on the true-up of the production cost allocation rider and the $67.8 million May 2014 System Agreement bandwidth remedy payment subject to refund with interest, with recovery of these payments concluding with the last billing cycle in December 2015. The APSC also found that Entergy Arkansas is entitled to carrying charges pursuant to the current terms of the production cost allocation rider. Entergy Arkansas made its compliance filing pursuant to the order in January 2015 and the APSC issued its approval order, also in January 2015. The redetermined rate went into effect with the first billing cycle of February 2015.
In May 2015, Entergy Arkansas filed its annual redetermination of the production cost allocation rider, which included a $38 million payment made by Entergy Arkansas as a result of the FERC’s February 2014 order related to the comprehensive bandwidth recalculation for calendar year 2006, 2007, and 2008 production costs. The redetermined rate for the 2015 production cost allocation rider update was added to the redetermined rate from the 2014 production cost allocation rider update and the combined rate was effective with the first billing cycle of July 2015. This combined rate was effective through December 2015. The collection of the remainder of the redetermined rate for the 2015 production cost allocation rider update continued through June 2016.
In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update became effective with the first billing cycle of July 2016, and the rates were effective through June 2017.
In May 2017, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected recovery of the production cost allocation rider true-up adjustment of the 2016 unrecovered retail balance in the amount of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over- or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
In January 2014, Entergy Arkansas filed a motion with the APSC relating to its redetermination of its energy cost rate that was subsequently filed in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude $65.9 million of deferred fuel and purchased energy costs incurred in 2013 from the redetermination of its 2014 energy cost rate. The $65.9 million is an estimate of the incremental fuel and replacement
Entergy Corporation and Subsidiaries
Notes to Financial Statements
energy costs that Entergy Arkansas incurred as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information is available regarding various claims associated with the ANO stator incident. The APSC approved Entergy Arkansas’s request in February 2014. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that docket, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a docket for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs previously noted, subject to certain timelines and conditions set forth in the settlement agreement. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.
In March 2017, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01164 per kWh to $0.01547 per kWh. The APSC staff filed testimony in March 2017 recommending that the redetermined rate be implemented with the first billing cycle of April 2017 under the normal operation of the tariff. Accordingly, the redetermined rate went into effect on March 31, 2017 pursuant to the tariff. In July 2017 the Arkansas Attorney General requested additional information to support certain of the costs included in Entergy Arkansas’s 2017 energy cost rate redetermination.
Entergy Louisiana
Entergy Louisiana recovers electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Louisiana’s purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
In April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit included a review of the reasonableness of charges flowed through the fuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009. The LPSC staff issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1 million from Entergy Louisiana’s fuel adjustment clause to base rates. The recommended refund was made by Entergy Louisiana in May 2013 in the form of a credit to customers through its fuel adjustment clause filing. In October 2016 the LPSC staff filed testimony affirming the recommendation in its audit report on the lone remaining issue that nuclear dry fuel storage costs should be realigned to base rates. The parties agreed to remove that remaining issue to a separate docket because the same issue was outstanding in the Entergy Gulf States Louisiana audit for the same time period. In November 2016 the LPSC approved the resolution of this audit and the creation of a new docket for the resolution of the proper method of recovery for nuclear dry fuel storage costs. In December 2016 the LPSC opened a new docket in order to resolve the issue regarding the proper methodology for the recovery of nuclear dry fuel storage costs. In October 2017 the LPSC approved the continued recovery of the nuclear dry fuel storage costs through the fuel adjustment clause, resolving the open issue in the audit.
In December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009. In March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that it was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained positions from its report. Subsequently, the parties entered into a settlement, which was approved by the LPSC in November 2016. The settlement recognized the dry cask storage recovery method issue, which was addressed in the separate proceeding approved by the LPSC in October 2017, provided for a refund of $5 million, which was made to legacy Entergy Gulf States Louisiana customers in December 2016, and resolved all other issues raised in the audit.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Gulf States Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015. No report of audit has been issued.
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015. No report of audit has been issued.
In June 2016 the LPSC staff provided notice of audits of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2014 through 2015 and charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2012 through 2015. Discovery commenced in March 2017. No report of audit has been issued.
Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs, Entergy Louisiana plans to cap the average fuel adjustment charge to be billed in March 2018 at $0.03060 per kWh and to defer billing of all fuel costs in excess of the capped amounts by including such costs in the over- or under-recovery account.
Entergy Mississippi
Entergy Mississippi’s rate schedules include an energy cost recovery rider that is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
Entergy Mississippi had a deferred fuel over-recovery balance of $58.3 million as of May 31, 2015, along with an under-recovery balance of $12.3 million under the power management rider. Pursuant to those tariffs, in July 2015, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider to flow through to customers the approximately $46 million net over-recovery over a six-month period. In August 2015, the MPSC approved the interim adjustments effective with September 2015 bills. In November 2015, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi should file a revised fuel factor with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor effective April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.
In November 2016, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an over-recovery of less than $2 million as of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also in January 2017 the MPSC certified to the Mississippi Legislature the audit reports of its independent auditors for the fuel year ending September 30, 2016. In its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016. The MPSC hired independent auditors to conduct an annual operations audit and a financial audit. The independent auditors
Entergy Corporation and Subsidiaries
Notes to Financial Statements
issued their audit reports in December 2017. The audit reports included several recommendations for action by Entergy Mississippi but did not recommend any cost disallowances. In January 2018 the MPSC certified the audit reports to the Mississippi Legislature. In November 2017 the Public Utilities Staff separately engaged a consultant to review the outage at the Grand Gulf Nuclear Station that began in 2016. The review is currently in progress.
In November 2017, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $61.5 million as of September 30, 2017. Entergy Mississippi proposed a two-tiered energy cost factor designed to promote overall rate stability throughout 2018 particularly during the summer months. In January 2018 the MPSC approved the proposed energy cost factors effective for February 2018 bills.
Mississippi Attorney General Complaint
The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. In December 2008 the defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.
The defendant Entergy companies answered the complaint and filed a counterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. In May 2009 the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the Attorney General’s complaint. In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings.
In January 2014 the U.S. Supreme Court issued a decision in which it held that cases brought by attorneys general as the sole plaintiff to enforce state laws were not considered “mass actions” under the Class Action Fairness Act, so as to establish federal subject matter jurisdiction. One day later the Attorney General renewed his motion to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies responded to that motion reiterating the additional grounds asserted for federal question jurisdiction, and the District Court held oral argument on the renewed motion to remand in February 2014. In April 2015 the District Court entered an order denying the renewed motion to remand, holding that the District Court has federal question subject matter jurisdiction. The Attorney General appealed to the U.S. Fifth Circuit Court of Appeals the denial of the motion to remand. In July 2015 the Fifth Circuit issued an order denying the appeal, and the Attorney General subsequently filed a petition for rehearing of the request for interlocutory appeal, which was also denied. In December 2015 the District Court ordered that the parties submit to the court undisputed and disputed facts that are material to the Entergy defendants’ motion for judgment on the pleadings, as well as supplemental briefs regarding the same. Those filings were made in January 2016.
In September 2016 the Attorney General filed a mandamus petition with the U.S. Fifth Circuit Court of Appeals in which the Attorney General asked the Fifth Circuit to order the chief judge to reassign this case to another judge. In September 2016 the District Court denied the Entergy companies’ motion for judgment on the pleadings. The Entergy companies filed a motion seeking to amend the District Court’s order denying the Entergy companies’ motion for judgment on the pleadings and allowing an interlocutory appeal. In October 2016 the Fifth Circuit granted the Attorney General’s motion for writ of mandamus and directed the chief judge to assign the case to a new judge. The case was reassigned in October 2016. In January 2017 the District Court denied the Entergy companies’ motion to amend the order denying the motion for judgment on the pleadings. In June 2017 the District Court issued a case management order setting a trial date in November 2018. Discovery is currently in progress.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy New Orleans
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
Due to higher fuel costs associated in part with the extended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans to cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs associated in part with certain plant outages, Entergy New Orleans has proposed to cap the fuel adjustment charge to be billed in March 2018 to non-transmission Entergy New Orleans legacy customers and Entergy New Orleans Algiers customers at $0.035323 per kWh and $0.025446 per kWh, respectively. Entergy New Orleans has also proposed to cap the fuel adjustment charge to be billed in March 2018 for Entergy New Orleans legacy transmission customers at $0.034609 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Entergy Texas
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT.
In December 2011, Entergy Texas filed with the PUCT a request to refund approximately $43 million, including interest, of fuel cost recovery over-collections through October 2011. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $67 million, including interest and additional over-recoveries through December 2011, over a three-month period. Entergy Texas and the parties requested that interim rates consistent with the settlement be approved effective with the March 2012 billing month, and the PUCT approved the application in March 2012. Entergy Texas completed this refund to customers in May 2012.
In October 2012, Entergy Texas filed with the PUCT a request to refund approximately $78 million, including interest, of fuel cost recovery over-collections through September 2012. Entergy Texas requested that the refund be implemented over a six-month period effective with the January 2013 billing month. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $84 million, including interest and additional over-recoveries through October 2012, to most customers over a three-month period beginning January 2013. The PUCT approved the stipulation in January 2013. Entergy Texas completed this refund to customers in March 2013.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In July 2012, Entergy Texas filed with the PUCT an application to credit its customers approximately $37.5 million, including interest, resulting from the FERC’s October 2011 order in the System Agreement rough production cost equalization proceeding which is discussed below in “System Agreement Cost Equalization Proceedings.” In September 2012 the parties submitted a stipulation resolving the proceeding. The stipulation provided that most Entergy Texas customers would be credited over a four-month period beginning October 2012. The credits were initiated with the October 2012 billing month on an interim basis, and the PUCT subsequently approved the stipulation, also in October 2012.
In August 2014, Entergy Texas filed an application seeking PUCT approval to implement an interim fuel refund of approximately $24.6 million for over-collected fuel costs incurred during the months of November 2012 through April 2014. This refund resulted from (i) applying $48.6 million in bandwidth remedy payments that Entergy Texas received in May 2014 related to the June - December 2005 period to Entergy Texas’s $8.7 million under-recovered fuel balance as of April 30, 2014 and (ii) netting that fuel balance against the $15.3 million bandwidth remedy payment that Entergy Texas made related to calendar year 2013 production costs. Also in August 2014, Entergy Texas filed an unopposed motion for interim rates to implement these refunds for most customers over a two-month period commencing with September 2014. The PUCT issued its order approving the interim relief in August 2014 and Entergy Texas completed the refunds in October 2014. Parties intervened in this matter. Allmatter, and all parties agreed that this casethe proceeding should be bifurcated such that the proposed interim refundsrefund would become final in a separate docket. The current docket would remainproceeding, which refund was approved by the PUCT in placeMarch 2015. In July 2015 certain parties filed briefs in the open proceeding asserting that Entergy Texas should refund to potentially addressretail customers an additional rough$10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production cost equalization-related matterscosts. In October 2015 an ALJ issued a proposal for decision recommending that are not part of the interim refunds discussed above.additional $10.9 million in bandwidth remedy payments be refunded to retail customers. In January 2015,2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a requestmotion for this severance and final approvalrehearing of the interim refund. Both applications are pending.
AtPUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The pending appeals did not stay the PUCT’s decision. In April 2013 open meeting,2016, Entergy Texas filed with the PUCT Commissioners an application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments,
Entergy Corporation and Subsidiaries
Notes to Financial Statements
discussed their viewabove, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a purchased power capacity rider was good public policy.$68 million refund. The ALJ approved the refund on an interim basis to be made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund. The federal appeal of the PUCT’s January 2016 decision was heard in May 2013 adoptingDecember 2016, and the rule allowingFederal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal to the U.S. Court of Appeals for the Fifth Circuit of the Federal District Court ruling. Oral argument was held before the U.S. Court of Appeals for the Fifth Circuit in February 2018, and a decision is pending. The State District Court appeal of the PUCT’s January 2016 decision also remains pending.
In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power capacity rider, subjectcosts for the period April 1, 2013 through March 31, 2016. Under a recent PUCT rule change, a fuel reconciliation is required to be filed at least once every three years and outside of a base rate case filing. During the reconciliation period, Entergy Texas incurred approximately $1.77 billion in Texas jurisdictional eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. Entergy Texas estimated an offsetting adjustmentover-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for load growth. The rule,the subsequent reconciliation period beginning Apri1 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as adopted,a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also includesrequested a processprudence finding for obtaining pre-approvaleach of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT of purchased power agreements.in a prior proceeding. In December 2016, Entergy Texas hasentered into a stipulation and settlement agreement resulting in a $6 million disallowance not exercisedassociated with any particular issue raised and a refund of the optionover-recovery balance of $21 million as of November 30, 2016, to recover its capacity costs undermost customers beginning April 2017 through June 2017. This settlement was developed concurrently with the newstipulation and settlement agreement in the 2016 transmission cost recovery factor rider mechanism, butamendment discussed below, and the terms and conditions in both settlements are interdependent. The fuel reconciliation settlement was approved by the PUCT in March 2017 and the refunds were made.
In June 2017, Entergy Texas filed an application for a fuel refund of approximately $30.7 million for the months of December 2016 through April 2017. For most customers, the refunds flowed through bills for the months of July 2017 through September 2017. The fuel refund was approved by the PUCT in August 2017.
In December 2017, Entergy Texas filed an application for a fuel refund of approximately $30.5 million for the months of May 2017 through October 2017. Also in December 2017, the PUCT’s ALJ approved the refund on an interim basis. For most customers, the refunds flowed through bills beginning January 2018 and will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.through March 2018. A final decision in this matter remains pending.
Retail Rate Proceedings
Filings with the APSC (Entergy Arkansas)
Retail Rates
2015 Base Rate Filing
In March 2013,April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing assumednotified the APSC of Entergy Arkansas’s transitionintent to MISOimplement a forward test year formula rate plan pursuant to Arkansas legislation passed in December 2013,2015, and requested a retail rate increase of $174$268.4 million, including $49 millionwith a net increase in revenue of revenue being transferred from collection in riders to base rates. The filing also proposed a new transmission rider and a capacity cost recovery rider.$167 million. The filing requested a 10.4%10.2% return on common equity. In September 2013, Entergy Arkansas filed testimony reflecting an updated rate increase request of $145 million, with no change to its requested return on common equity of 10.4%. Hearings in the proceeding began in October 2013, and in December 20132015 the APSC issued an order. The order authorizedstaff and intervenors filed direct testimony, with the APSC staff recommending a base rate increaserevenue requirement of $81$217.9 million and included an authorized return on common equity of 9.3%. The order allows Entergy Arkansas to amortize its human capital management costs over a three-and-a-half year period, but also orders Entergy Arkansas to file a detailed report of the Arkansas-specific costs, savings and final payroll changes upon conclusion of the human capital management strategic imperative. The detailed report was subsequently filed in February 2015. The substance of the report will be addressed in Entergy Arkansas’s next base rate filing. New rates under the January 2014 order were implemented in the first billing cycle of March 2014 and were effective as of January 2014. Additionally, in January 2014, Entergy Arkansas filed a petition for rehearing or clarification of several aspects of the APSC’s order, including the 9.3% authorized9.65% return on common equity. In February 2014December 2015, Entergy Arkansas, the APSC granted Entergy Arkansas’s petition for the purpose of considering the additional evidence identified by Entergy Arkansas. In August 2014 the APSC issued an order amendingstaff, and certain aspects of the original order, including providing for a 9.5% authorized return on common equity. Pursuant to theintervenors
Entergy Corporation and Subsidiaries
Notes to Financial Statements
August 2014 order, revisedin the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity. A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. A settlement hearing was held in January 2016. In February 2016 the APSC approved the settlement with one exception that reduced the retail rate increase proposed in the settlement by $5 million. The settling parties agreed to the APSC modifications in February 2016. The new rates arewere effective for all bills rendered after December 31, 2013February 24, 2016 and were implemented inbegan billing with the first billing cycle of October 2014.April 2016. In March 2016, Entergy Arkansas made a compliance filing regarding the new rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.
On January 30, 2015,2016 Formula Rate Plan Filing
In July 2016, Entergy Arkansas filed with the APSC a notice of intent to file a rate case within 60 to 90 days.
Filings with the LPSC
Retail Rates - Electric
(Entergy Gulf States Louisiana)
In November 2011 the LPSC approved a one-year extension of Entergy Gulf States Louisiana’s formula rate plan. In May 2012, Entergy Gulf States Louisiana made its 2016 formula rate plan filing with the LPSC for the 2011 test year. The filing reflected an 11.94%showing Entergy Arkansas’s projected earned return on common equity which was abovefor the earnings bandwidth and indicated a $6.5 million cost of service rate decrease was necessary undertwelve months ended December 31, 2017 test period to be below the formula rate plan.plan bandwidth. The filing also reflectedrequested a $22.9$67.7 million rate decrease for the incremental capacity rider. Subsequently, in August 2012,revenue requirement increase to achieve Entergy Gulf States Louisiana submitted a revised filing that reflected anArkansas’s target earned return on common equity of 11.86%, which indicated a $5.7 million cost of service rate decrease was necessary under9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan. The revised filing also indicated thatplan attachments with an updated request for a reduction$54.4 million revenue requirement increase based on acceptance of $20.3certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved the settlement agreement and the $54.4 million should be reflected inrevenue requirement increase with approximately $25 million of the incremental capacity rider. The rate reductions were implemented,$54.4 million revenue requirement subject to possible future adjustment and refund effectiveto customers with interest. The APSC requested supplemental information for bills rendered insome of Entergy Arkansas’s requested nuclear expenditures. In December 2016 the first billing cycle of September 2012. Subsequently, in December 2012,APSC approved Entergy Gulf States Louisiana submitted a revised evaluation report that reflected expected retail jurisdictional cost of $17 million forArkansas’s formula rate plan compliance tariff, and the first-year capacity charges for the purchase from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy. This rate change was implementedrates became effective with the first billing cycle of January 2013. The 2011 test year filings, as revised, were approved2017. In April 2017, Entergy Arkansas filed a motion consented to by all parties requesting that it be permitted to submit the supplemental information requested by the LPSCAPSC in February 2013.conjunction with its 2017 formula rate plan filing, which was subsequently made in July 2017 and is discussed below. In April 2013,May 2017 the APSC approved the joint motion and proposal to review Entergy Gulf States Louisiana submittedArkansas’s supplemental information on a revised evaluation report increasingconcurrent schedule with the incremental capacity rider by approximately $7.3 million2017 formula rate plan filing. In October 2017, Entergy Arkansas and the parties to reflect the costproceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the docket and providing for recovery of an additional capacity contract.the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and recovery of the 2017 and 2018 nuclear costs.
2017 Formula Rate Plan Filing
In connectionJuly 2017, Entergy Arkansas filed with the APSC its decision2017 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2018 test period to extendbe below the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Gulf States Louisiana, and the required filing was made in February 2013.bandwidth. The filing anticipatedprojected a $129.7 million revenue requirement increase to achieve Entergy Gulf States Louisiana’s integration into MISO. In the filing Entergy Gulf States Louisiana requested, among other relief:
authorization to increase the revenue it collects from customers by approximately $24 million;
an authorizedArkansas’s target earned return on common equity of 10.4%;
authorization to increase depreciation rates embedded in the proposed revenue requirement; and,
authorization to implement a three-year9.75%. Entergy Arkansas’s formula rate plan withis subject to a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would providefour percent annual revenue constraint and the projected annual revenue requirement increase exceeded the four percent, resulting in a meansproposed increase for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior2017 formula rate plan including a 60% to customers/40% toof $70.9 million. In October 2017, Entergy Gulf States Louisiana sharing mechanism for earnings outsideArkansas filed with the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.
Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. Major terms of the settlement include approval of a three-yearAPSC revised formula rate plan (effective for test years 2014-2016) modeled afterattachments that projected a $126.2 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors. The revised formula rate plan in effect for Entergy Gulf States Louisiana for 2011, including the following: (1)filing included a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacityproposed $71.1 million revenue requirement extraordinary items, such asincrease based on a revision to the Ninemile 6 project,four percent constraint calculation. In October 2017, Entergy Arkansas and certain special recovery items; (3) three-year amortization of coststhe parties to achieve savings associated withthe proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the docket and
Entergy Corporation and Subsidiaries
Notes to Financial Statements
the human capital management strategic imperative, with savings to be reflected as they are realized in subsequent years; (4) eight-year amortization of costs incurred in connection with potential development of a new nuclear unit at River Bend, without carrying costs, beginning December 2014, provided, however, that amortization of these costs shall not result in a future rate increase; (5) no change in rates related to test year 2013, except with respect toproviding for recovery of the non-fuel MISO-related costs2017 and any changes to2018 nuclear costs. In December 2017 the additional capacity revenue requirement;APSC approved the settlement agreement and (6) no increase in rates related to test year 2014, except for those items eligible for recovery outside of the earnings sharing mechanism. Existing depreciation rates will not change. Implementation of rate changes for items recoverable outside of the earnings sharing mechanism occurred in December 2014.
Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Gulf States Louisiana submitted a compliance filing in May 2014 reflecting the effects of the estimated MISO cost recovery mechanism$71.1 million revenue requirement and adjustment of the additional capacity mechanism. In November 2014,increase, as well as Entergy Gulf States Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data. Based on this updated filing, a net increase of $5.8 million inArkansas’s formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings are subject to LPSC review in accordance withtariff, and the review process set forth in Entergy Gulf States Louisiana’s formula rate plan.
In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with the LPSC that estimated a first year revenue requirement associated with Ninemile 6 and provided a mechanism to update the revenue requirement as the in-service date approached, which was subsequently approved by the LPSC. In late December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of $26.8 million for Entergy Gulf States Louisiana was filed. The December 2014 estimate forms the basis of rates implementedbecame effective with the first billing cycle of January 2015.2018.
(Entergy Louisiana)Internal Restructuring
In November 20112017, Entergy Arkansas filed an application with the APSC seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy Arkansas to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. The restructuring is subject to regulatory review and approval by the APSC, the FERC, and the NRC. Entergy Arkansas also filed a notice with the Missouri Public Service Commission in December 2017 out of an abundance of caution, although Entergy Arkansas does not serve any retail customers in Missouri. If the APSC approves the restructuring by September 1, 2018, and the restructuring closes on or before December 1, 2018, Entergy Arkansas proposed in its application to credit retail customers $66 million over six years, beginning in 2019. In February 2018, Entergy Arkansas filed supplemental testimony reducing the proposed retail customer credits to $39.6 million over six years. If the APSC, the FERC, and the NRC approvals are obtained, Entergy Arkansas expects the restructuring will be consummated on or before December 1, 2018.
It is currently contemplated that Entergy Arkansas would undertake a multi-step restructuring, which would include the following:
Entergy Arkansas would redeem its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million, which includes call premiums, plus accumulated and unpaid dividends, if any.
Entergy Arkansas would convert from an Arkansas corporation to a Texas corporation.
Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas will allocate substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power will assume substantially all of the liabilities of Entergy Arkansas, in a transaction regarded as a merger under the TXBOC. Entergy Arkansas will remain in existence and hold the membership interests in Entergy Arkansas Power.
Entergy Arkansas will contribute the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power will be a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
Entergy Arkansas will change its name to Entergy Utility Property, Inc., and Entergy Arkansas Power will then change its name to Entergy Arkansas, LLC.
Upon the completion of the restructuring, Entergy Arkansas, LLC will hold substantially all of the assets, and will have assumed substantially all of the liabilities, of Entergy Arkansas. Entergy Arkansas may modify or supplement the steps to be taken to effectuate the restructuring.
Filings with the LPSC approved a one-year extension(Entergy Louisiana)
Retail Rates - Electric
2014 Formula Rate Plan Filing
In connection with the approval of the business combination of Entergy Louisiana’s formula rate plan. In May 2012,Gulf States Louisiana and Entergy Louisiana, made itsthe LPSC authorized the filing of a single, joint, formula rate plan filing with the LPSCevaluation report for the 2011 test year.Entergy Gulf States Louisiana’s and Entergy Louisiana’s 2014 calendar year operations. The filing reflected a 9.63% earned return on common equity, which is within the earnings bandwidthjoint evaluation report was filed in September 2015 and resulted in no cost of service rate change under the formula rate plan. The filing also reflected an $18.1 million rate increase for the incremental capacity rider. In August 2012, Entergy Louisiana submitted a revised filing that reflected an earned return on common equity of 10.38%,9.09%. As such, no adjustment to base formula rate plan revenue was required. The following adjustments were required under the formula rate plan, however: a decrease in the additional capacity mechanism for Entergy Louisiana of $17.8 million; an increase in the additional capacity mechanism for Entergy Gulf States Louisiana of $4.3 million; and a reduction of $5.5 million to the MISO cost recovery
Entergy Corporation and Subsidiaries
Notes to Financial Statements
mechanism to collect approximately $35.7 million on a combined-company basis. Under the order approving the business combination, following completion of the prescribed review period, rates were implemented with the first billing cycle of December 2015, subject to refund. See “Entergy Louisiana and Entergy Gulf States Louisiana Business Combination” below for further discussion of the business combination. In June 2017 the LPSC staff and Entergy Louisiana filed an unopposed joint report of proceedings, which is still withinwas accepted by the earnings bandwidth, resultingLPSC in June 2017, finalizing the results of this proceeding with no costchanges to rates already implemented.
2015 Formula Rate Plan Filing
In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflected an earned return on common equity of service9.07%. As such, no adjustment to base formula rate change.plan revenue was required. The revised filing also indicated thatfollowing other adjustments, however, were required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $15.9$11 million should be reflected into the incremental capacity rider. The rate change wasMISO cost recovery mechanism. Rates were implemented subject to refund, effective for bills renderedwith the first billing cycle of September 2012. Subsequently,2016, subject to refund. Following implementation of the as-filed rates in September 2016, there were several interim updates to Entergy Louisiana’s formula rate plan, including the one submitted in December 2012, Entergy Louisiana submitted a revised evaluation report that reflected two items: 1) a $17 million reduction for2016, reflecting implementation of the first-year capacity charges for the purchase by Entergy Gulf States Louisiana from Entergy Louisianasettlement of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project prudence review described below. In June 2017 the LPSC staff and Entergy Louisiana filed a joint report of proceedings, which was in-serviceaccepted by the LPSC in December 2012. TheseJune 2017, finalizing the results of the May 2016 evaluation report, interim updates, and corresponding proceedings with no changes to rates already implemented.
Extension of MISO Cost Recovery Mechanism Rider
In November 2016, Entergy Louisiana filed with the LPSC a request to extend the MISO cost recovery mechanism rider provision of its formula rate changesplan. In March 2017 the LPSC staff submitted direct testimony generally supportive of a one-year extension of the MISO cost recovery mechanism and the intervenor in the proceeding did not oppose an extension for this period of time. In July 2017 an uncontested joint stipulation authorizing a one-year extension of the MISO cost recovery mechanism rider was approved.
2016 Formula Rate Plan Filing
In May 2017, Entergy Louisiana filed its formula rate plan evaluation report for its 2016 calendar year operations. The evaluation report reflected an earned return on common equity of 9.84%. As such, no adjustment to base formula rate plan revenue was required. Adjustments, however, were implemented, subjectrequired under the formula rate plan; the 2016 formula rate plan evaluation report showed a decrease in formula rate plan revenue of approximately $16.9 million, comprised of a decrease in legacy Entergy Louisiana formula rate plan revenue of $3.5 million, a decrease in legacy Entergy Gulf States Louisiana formula rate plan revenue of $9.7 million, and a decrease in incremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 million in the MISO cost recovery revenue requirement from the present level of $46.8 million to refund, effective$6.3 million. Rates reflecting these adjustments were implemented with the first billing cycle of January 2013.September 2017, subject to refund. In April 2013, Entergy Louisiana andSeptember 2017 the LPSC staff filed a jointissued its report resolving the 2011 test yearindicating that no changes to Entergy Louisiana’s original formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report.
Formula Rate Plan Extension Request
In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications to its terms. Those modifications include: a one-time resetting of
Entergy Corporation and recovery relatedSubsidiaries
Notes to Financial Statements
base rates to the Grand Gulf uprate. This report was approved bymidpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95% for the 2017 test year; narrowing of the formula rate plan bandwidth from a total of 160 basis points to 80 basis points; and a forward-looking mechanism that would allow Entergy Louisiana to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers. Entergy Louisiana requested that the LPSC consider its request on an expedited basis, in April 2013.an effort to maintain Entergy Louisiana’s current cycle for implementing rate adjustments, i.e., September 2018, without the need for filing a full base rate case proceeding. Several parties have intervened in the proceeding and all parties have been participating in settlement discussions.
WithWaterford 3 Replacement Steam Generator Project
Following the completion of the Waterford 3 replacement steam generator project, the LPSC is conductingundertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC Staffstaff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana. An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent. Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. At the hearing the parties maintained the positions reflected in pre-filed testimony. A post-hearing briefing schedule has not been established. Entergy Louisiana believesbelieved that the replacement steam
Entergy Corporation and Subsidiaries
Notes to Financial Statements
generator costs were prudently incurred and applicable legal principles supportsupported their recovery in rates. Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review.
In connection with its decision to extendDecember 2015 the formula rate plan to the 2011 test year, the LPSC requiredALJ issued a proposed recommendation, which was subsequently finalized, concluding that a base rate case be filed by Entergy Louisiana and the required filing was made on February 15, 2013. The filing anticipated Entergy Louisiana’s integration into MISO. In the filing Entergy Louisiana requested, among other relief:
authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service);
an authorized return on common equity of 10.4%;
authorization to increase depreciation rates embedded in the proposed revenue requirement; and,
authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.
Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. The settlement provides for a $10 million rate increase effective with the first billing cycle of December 2014. Major terms of the settlement include approval of a three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain special recovery items; (3) three-year amortization of costs to achieve savings associated with the human capital management strategic imperative, with savings reflected as they are realized in subsequent years; (4) eight-year amortization of costs incurred in connection with potential development of a new nuclear unit at River Bend, without carrying costs, beginning December 2014, provided, however, that amortization of these costs shall not result in a future rate increase; (5) recovery of non-fuel MISO-related costs and any changes to the additional capacity revenue requirement related to test year 2013 effective with the first billing cycle of December 2014; and (6) a cumulative $30 million cap on cost of service increases over the three-year formula rate plan cycle, except for those items outside of the sharing mechanism. Existing depreciation rates will not change.
Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Louisiana submitted a compliance filing in May 2014 reflecting the effects of the $10 million agreed-upon increase in formula rate plan revenue, the estimated MISO cost recovery mechanism revenue requirement, and the adjustment of the additional capacity mechanism. In November 2014, Entergy Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data, as well as providing for a refund and prospective reduction in rates for the true-up of the estimated revenue requirement for the Waterford 3 replacement steam generator project. Based on this updated filing, a net increase of $41.6 million in formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings are subject to LPSC review in accordance with the review process set forth in Entergy Louisiana’s formula rate plan. Additionally, the adjustments of rates made related toprudently managed the Waterford 3 replacement steam generator project, includedincluding the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the December 2014 compliance filing are subjectfourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to final true-up following completionreflect that a portion of the LPSC’s determination regardingassets associated with the prudenceWaterford 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contained significant factual and legal errors.
In October 2016 the parties reached a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectively provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to customers of approximately $71 million as a result of the project.settlement approved by the LPSC was made to customers in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future. Following a review by the parties, an unopposed joint report of proceedings was filed by the LPSC staff and Entergy Louisiana in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Ninemile 6
In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with the LPSC, which was subsequently approved, that estimated a first year revenue requirement associated with Ninemile 6 and provided a mechanism to update the revenue requirement as the in-service date approached, which was subsequently approved by the LPSC.approached. In late Decemberlate-December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of $26.8 million for Entergy Gulf States Louisiana and $51.1 million for Entergy Louisiana was filed. The December 2014 estimate formsformed the basis of rates implemented effective with the first billing cycle of January 2015. In July 2015, Entergy Louisiana will submit project and cost informationsubmitted to the LPSC in mid-2015a compliance filing including an estimate at completion, inclusive of interconnection costs and transmission upgrades, of approximately $648 million, or $76 million less than originally estimated, along with other project details and supporting evidence, to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project. Testimony filed by the LPSC staff generally supported the prudence of the management of the project and recovery of the costs incurred to complete the project. The LPSC staff had questioned the warranty coverage for one element of the project. In October 2016 all parties agreed to a stipulation providing that 100% of Ninemile 6 construction costs was prudently incurred and is eligible for recovery from customers, but reserving the LPSC’s rights to review the prudence of Entergy Louisiana’s actions regarding one element of the project. This stipulation was approved by the LPSC in January 2017.
Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana Plants
In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $474 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.
As a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1. In January 2016, Entergy Louisiana made its compliance filing with the LPSC. Entergy Louisiana, LPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the current deactivation decisions for the ten-year planning horizon. Parties have requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4. No party contests the prudence of the decision to deactivate Willow Glen 2 and 4 or suggests reactivation of these units; however, issues have been raised related to Entergy Louisiana’s decision to give up its transmission service rights in MISO for Willow Glen 2 and 4 rather than placing the units into suspended status for the three-year term permitted by MISO. An evidentiary hearing was held in August 2017 and post-hearing briefs were submitted in October 2017. A decision is expected in 2018.
Retail Rates - Gas (Entergy Gulf States Louisiana)
In January 2012, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2011. The filing showed an earned return on common equity of 10.48%, which is within the earnings bandwidth of 10.5%, plus or minus fifty basis points. In April 2012 the LPSC Staff filed its findings, suggesting adjustments that produced an 11.54% earned return on common equity for the test year and a $0.1 million rate reduction. Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate reduction was effective with the first billing cycle of May 2012.
In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012. The filing showed an earned return on common equity of 11.18%, which results in a $43 thousand rate reduction. In March 2013 the LPSC Staff issued its proposed findings and recommended two adjustments. Entergy Gulf States Louisiana and the LPSC Staff reached agreement regarding the LPSC Staff’s proposed adjustments. As reflected in an unopposed joint report of proceedings filed by Entergy Gulf States Louisiana and the LPSC Staff in May 2013, Entergy Gulf States Louisiana accepted, with modification, the LPSC Staff’s proposed adjustment to property insurance expense and agreed to: (1) a three-year extension of the gas rate stabilization plan with a midpoint return on equity of 9.95%, with a first year midpoint reset; (2) dismissal of a docket initiated by the LPSC to evaluate the allowed return on equity for Entergy Gulf States Louisiana’s gas rate stabilization plan; and (3) presentation to the LPSC by November 2014 by Entergy Gulf States Louisiana and the LPSC Staff of their recommendation for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment. The LPSC approved the agreement in May 2013.
In January 2014, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2013. The filing showed an earned return on common equity of 5.47%, which results in a $1.5 million rate increase. In April 2014 the LPSC Staff issued a report indicating “that Entergy Gulf States Louisiana has properly determined its earnings for the test year ended September 30, 2013.” The $1.5 million rate increase was implemented effective with the first billing cycle of April 2014.
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted
Entergy Corporation and Subsidiaries
Notes to Financial Statements
a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of 10.45% as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20 percent20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding ten percent;10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider will commencecommenced with bills rendered on and after the first billing cycle of April 2015.
Entergy Corporation and Subsidiaries
Notes to Financial Statements2014 Rate Stabilization Plan Filing
In January 2015, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2014. The filing showed an earned return on common equity of 7.20%, which resultsresulted in a $706 thousand rate increase. In April 2015 the LPSC issued findings recommending two adjustments to Entergy Gulf States Louisiana’s as-filed results, and an additional recommendation that did not affect the results. The rateLPSC staff’s recommended adjustments increase if approved, will bethe earned return on equity for the test year to 7.24%. Entergy Gulf States Louisiana accepted the LPSC staff’s recommendations and a revenue increase of $688 thousand was implemented effective with the first billing cycle of May 2015.
2015 Rate Stabilization Plan Filing
In January 2016, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2015. The filing showed an earned return on common equity of 10.22%, which is within the authorized bandwidth, therefore requiring no change in rates. In March 2016 the LPSC staff issued its report stating that the 2015 gas rate stabilization plan filing was in compliance with the exception of several issues that required additional information, explanation, or clarification for which the LPSC staff had reserved the right to further review. In July 2016 the parties to the proceeding filed an unopposed joint report and motion for entry of order accepting the report that indicated no outstanding issues remained in the filing.
In February 2016, Entergy Louisiana filed a motion requesting to extend the term of the gas rate stabilization plan in substantially similar form for an additional three-year term and included a request for sharing of non-jurisdictional compressed natural gas revenues. Following discovery and the filing of testimony by the LPSC staff, Entergy Louisiana and the LPSC submitted a joint motion for hearing an uncontested stipulated settlement resolving the proceeding. A hearing on the stipulation was held in November 2016. The ALJ issued a report of proceedings that was presented with the parties’ stipulation to the LPSC for consideration. The stipulation approving Entergy Louisiana’s requested extension of the rate stabilization plan was approved by the LPSC in December 2016.
2016 Rate Stabilization Plan Filing
In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflected an earned return on common equity of 6.37%. As part of the original filing, pursuant to the extraordinary cost provision of the rate stabilization plan, Entergy Louisiana sought to recover approximately $1.5 million in deferred operation and maintenance expenses incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. Entergy Louisiana requested to recover the prudently incurred August 2016 storm restoration costs over ten years, outside of the rate stabilization plan sharing provisions. As a result, Entergy Louisiana’s filing sought an annual increase in revenue of $1.4 million. Following review of the filing, except for the proposed extraordinary cost recovery, the LPSC staff confirmed Entergy Louisiana’s filing was consistent with the principles and requirements of the rate stabilization plan. The extraordinary cost recovery request associated with the 2016 flood-related deferred operation and maintenance expenses incurred for gas operations was removed from the rate stabilization
Entergy Corporation and Subsidiaries
Notes to Financial Statements
plan pending LPSC consideration in a separate docket. In April 2015.2017 the LPSC approved a joint report of proceedings and Entergy Louisiana submitted a revised evaluation report reflecting a $1.2 million annual increase in revenue with rates implemented with the first billing cycle of May 2017.
In connection with the joint report of proceedings accepted by the LPSC, in May 2017, Entergy Louisiana filed an application to initiate a separate proceeding to recover through the extraordinary cost provision of the gas rate stabilization plan the deferred operation and maintenance expenses of $1.4 million incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. The LPSC staff submitted its direct testimony in the proceeding recommending recovery of $0.9 million. Entergy Louisiana filed rebuttal testimony responding to the LPSC staff’s recommendation. The procedural schedule was suspended to allow the parties to engage in settlement negotiations, and in February 2018 the LPSC staff and Entergy Louisiana filed an unopposed settlement. If approved by the LPSC, the settlement would provide for Entergy Louisiana to recover, over ten years, the approximately $1.4 million in deferred operation and maintenance expense and related carrying charges. The settlement further provides for recovery to commence in May 2018.
2017 Rate Stabilization Plan Filing
In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for test year ended September 30, 2017. The filing of the evaluation report for the test year 2017 reflected an earned return on common equity of 9.06%. This earned return is below the earnings sharing band of the rate stabilization plan and results in a rate increase of $0.1 million. Due to the enactment in late-December 2017 of the Tax Cuts and Jobs Act, Entergy Louisiana did not have adequate time to reflect the effects of this tax legislation in the rate stabilization plan. As a result, Entergy Louisiana will file a supplement to the January 2018 evaluation report to reflect, among other things, a 21% federal corporate income tax rate. Any rate change resulting from the revised rate stabilization plan will become effective in rates in May 2018.
Filings with the MPSC (Entergy Mississippi)
Formula Rate Plan Filings
In September 2009, Entergy Mississippi filed with the MPSC proposed modifications to its formula rate plan rider. In March 2010 the MPSC issued an order: (1) providing the opportunity for a reset of Entergy Mississippi’s return on common equity to a point within the formula rate plan bandwidth and eliminating the 50/50 sharing that had been in the plan, (2) modifying the performance measurement process, and (3) replacing the revenue change limit of two percent of revenues, which was subject to a $14.5 million revenue adjustment cap, with a limit of four percent of revenues, although any adjustment above two percent requires a hearing before the MPSC. The MPSC did not approve Entergy Mississippi’s request to use a projected test year for its annual scheduled formula rate plan filing and, therefore, Entergy Mississippi continued to use a historical test year for its annual evaluation reports under the plan.
In March 2012,2016, Entergy Mississippi submitted its formula rate plan 2016 test year filing showing Entergy Mississippi’s projected earned return for the 2011 test year.2016 calendar year to be below the formula rate plan bandwidth. The filing shows anshowed a $32.6 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of 10.92% for the test year, which is within the earnings bandwidth and results in no change in rates. In February 2013 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provided for no change in rates.
In March 2013, Entergy Mississippi submitted its formula rate plan filing for the 2012 test year. The filing requested a $36.3 million revenue increase to reset Entergy Mississippi’s return on common equity to 10.55%adjustment of 9.96%, which is a point within the formula rate plan bandwidth. In June 2013,2016 the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase includes a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also includes $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.
In March 2017, Entergy Mississippi submitted its formula rate plan 2017 test year filing and 2016 look-back filing showing Entergy Mississippi’s earned return for the historical 2016 calendar year and projected earned return for the 2017 calendar year to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2017, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation in which both parties agreed that the MPSC should approve a $22.3 million rate increase for Entergy Mississippi which, with other adjustments reflected in the stipulation, would have the effect of resettingconfirmed that Entergy Mississippi’s return on common equity to 10.59% when adjustedearned returns for performance underboth the 2016 look-back filing and 2017 test year were within the respective formula rate plan.plan bandwidths. In August 2013June 2017 the MPSC approved the joint stipulation, between Entergy Mississippi and the Mississippi Public Utilities Staff authorizing the rate increase effective with September 2013 bills. Additionally, the MPSC authorized Entergy Mississippi to defer approximately $1.2 millionwhich resulted in MISO-related implementation costs incurredno change in 2012 along with other MISO-related implementation costs incurred in 2013.
In June 2014, Entergy Mississippi filed its first general rate case before the MPSC in almost 12 years. The rate filing laid out Entergy Mississippi’s plans for improving reliability, modernizing the grid, maintaining its workforce, stabilizing rates, utilizing new technologies, and attracting new industry to its service territory. Entergy Mississippi requested a net increase in revenue of $49 million for bills rendered during calendar year 2015, including $30 million resulting from new depreciation rates to update the estimated service life of assets. In addition, the filing proposed, among other things: 1) realigning cost recovery of the Attala and Hinds power plant acquisitions from the power management rider to base rates; 2) including certain MISO-related revenues and expenses in the power management rider; 3) power management rider changes that reflect the changes in costs and revenues that will accompany Entergy Mississippi’s withdrawal from participation in the System Agreement; and 4) a formula rate plan forward test year to allow for known changes in expenses and revenues for the rate effective period. Entergy Mississippi proposed maintaining the current authorized return on common equity of 10.59%. rates.
In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations that addressed the majority of issues in the proceeding. The stipulations provided for:
an approximate $16 million net increase in revenues, which reflected an agreed upon 10.07% return on common equity;
Entergy Corporation and Subsidiaries
Notes to Financial Statements
revision of Entergy Mississippi’s formula rate plan by providing Entergy Mississippi with the ability to reflect known and measurable changes to historical rate base and certain expense amounts; resolving uncertainty around and obviating the need for an additional rate filing in connection with Entergy Mississippi’s withdrawal from participation in the System Agreement; updating depreciation rates; and moving costs associated with the Attala and Hinds generating plants from the power management rider to base rates;
recovery of non-fuel MISO-related costs through a separate rider for that purpose;
a deferral of $6 million in other operation and maintenance expenses associated with the Baxter Wilson outage and a determination that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset over two years beginning in February 2015, and a provision that the capital costs will be reflected in rate base. See Note 8 to the financial statements for further discussion of the Baxter Wilson outage; and
consolidation of the new nuclear generation development costs proceeding with the general rate case proceeding for hearing purposes and a determination that Entergy Mississippi would not further pursue, except as noted below, recovery of the costs that were approved for deferral by the MPSC in November 2011. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. See "New Nuclear Generation Development Costs - Entergy Mississippi" below for further discussion of the new nuclear generation development costs proceeding and subsequent write-off in 2014 of the regulatory asset related to those costs.
In December 2014 the MPSC issued an order accepting the stipulations in their entirety and approving the revenue adjustments and rate changes effective with February 2015 bills.
Filings with the City Council (Entergy New Orleans)
(Entergy Louisiana)Retail Rates
In March 2013,See “Algiers Asset Transfer” below for discussion of the Algiers asset transfer. As a provision of the settlement agreement approved by the City Council in May 2015 providing for the Algiers asset transfer, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy LouisianaNew Orleans’s base rates until rates are implemented from a base rate case that must be filed afor its electric and gas operations in 2018. This provision eliminated the formula rate caseplan applicable to Algiers operations. The limited exceptions included continued implementation of the then-remaining two years of the four-year phased-in rate increase for the Algiers area which isand certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allowed for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans and is regulated by the City Council.under a power purchase agreement with Entergy Louisiana is requesting a rate increase of $13 million over three years, including a 10.4% return on common equity and a formula rate plan mechanism identical(Algiers PPA). The settlement authorized Entergy New Orleans to its LPSC request. In January 2014,recover the City Council Advisors filed direct testimony recommending a rate increase of $5.56 million over three years, including an 8.13% return on common equity. In June 2014 the City Council unanimously approved a settlement that includes the following:
a $9.3 million base rateremaining revenue increase to be phased in on a levelized basis over four years;
recovery of an additional $853 thousand annually through a MISO recovery rider; and
the adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.
The rate increase was effective with bills rendered on and after the first billing cycle of July 2014. Additional compliance filings were made with the Council in October 2014 for approval of the form of certain rate riders, including among others, a Ninemile 6 non-fuel cost recovery interim rider, allowing for contemporaneous recovery of capacity costsrequirement related to the commencement of commercial operationAlgiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Ninemile 6 generating unit and a purchased power capacity costAlgiers MISO recovery rider. The Ninemile 6 cost recovery interim rider was implemented in December 2014 to collect $915 thousand from Entergy Louisiana customers in the Algiers area.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
(Entergy New Orleans)
Formula Rate Plan
In April 2009addition to the City Council approved a three-year formula rate plan forAlgiers PPA, Entergy New Orleans with terms including an 11.1% benchmark electric return on common equity (ROE) withhas a +/-40 basis point bandwidth and a 10.75% benchmark gas ROE with a +/-50 basis point bandwidth. Earnings outside the bandwidth reset to the midpoint benchmark ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans was over- or under-earning. The formula rate plan also included a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure events.
In May 2012, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2011 test year. Subsequent adjustments agreed upon with the City Council Advisors indicate a $4.9 million electric base revenue increase and a $0.05 million gas base revenue increase as necessary under the formula rate plan. As part of the original filing, Entergy New Orleans also requested to increase annual funding for its storm reserve by approximately $5.7 million for five years. On September 26, 2012, Entergy New Orleans made a filing with the City Council that implemented the $4.9 million electric formula rate plan rate increase and the $0.05 million gas formula rate plan rate increase. The new rates were effective with the first billing cycle in October 2012. In August 2013 the City Council unanimously approved a settlement of all issues in the formula rate plan proceeding. Pursuant to the terms of the settlement, Entergy New Orleans implemented an approximately $1.625 million net decrease to the electric rates that were in effect prior to the electric rate increase implemented in October 2012, with no change in gas rates. Entergy New Orleans refunded to customers approximately $6 million over the four-month period from September 2013 through December 2013 to make the electric rate decrease effective as of the first billing cycle of October 2012. Entergy New Orleans had previously recorded provisions for the majority of the refund to customers, but recorded an additional $1.1 million provision in second quarter 2013 as a result of the settlement. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not been extended. Entergy New Orleans is recovering the costs of itsseparate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy of thefrom Ninemile Unit 6 generating station,(Ninemile PPA), which commenced operation in December 2014,2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile Unit 6 rider.rider billed only to Entergy New Orleans customers outside of Algiers.
In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans. The rate settlement providesprovided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and providesprovided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In October 2013 the City Council approved the extension of the current Energy Smart program through December 2014. The City Council approved the use of $3.5 million of rough production cost equalization funds for program costs. In addition, Entergy New Orleans will be allowed to recover its lost contribution to fixed costs and to earn an incentive for meeting program goals. In January 2015 the City Council approved extending the Energy Smart program through March 2015 and using $1.2 million of rough production cost equalization funds to cover program costs for the extended period. Additionally, the City Council approved funding for the Energy Smart 2 programsprogram from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, and with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program
Entergy Corporation and Subsidiaries
Notes to Financial Statements
costs during the period between when existing funds directed to Energy Smart programs are depleted (estimated to be June 2018) and when new rates from the anticipated 2018 combined rate case, which will include a cost recovery mechanism for Energy Smart funding, take effect (estimated to be August 2019). Entergy New Orleans requested that the City Council approve a cost recovery mechanism prior to June 2018. In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist.
Internal Restructuring
In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans, Inc. to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. The restructuring was subject to regulatory review and approval by the City Council and the FERC. In May 2017 the City Council adopted a resolution approving the proposed internal restructuring pursuant to an agreement in principle with the City Council advisors and certain intervenors. Pursuant to the agreement in principle, Entergy New Orleans would credit retail customers $10 million in 2017, $1.4 million in the first quarter of the year after the transaction closes, and $117,500 each month in the second year after the transaction closes until such time as new base rates go into effect as a result of the anticipated 2018 base rate case. Entergy New Orleans began crediting retail customers in June 2017. In June 2017 the FERC approved the transaction and, pursuant to the agreement in principle, Entergy New Orleans will provide additional credits to retail customers of $5 million in each of the years 2018, 2019, and 2020.
In November 2017, pursuant to the agreement in principle, Entergy New Orleans undertook a multi-step restructuring, including the following:
Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc., in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.
Filings with the PUCT and Texas Cities (Entergy Texas)
Retail Rates
2011 Rate Case
In November 2011, Entergy Texas filed a rate case requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year. The rate case also proposed a purchased power recovery rider. On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
current rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased
Entergy Corporation and Subsidiaries
Notes to Financial Statements
power capacity rider is approved in a separate proceeding. In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity. The PUCT Staff, however, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas’s recovery of purchased power capacity costs and Entergy Texas’s proposal to defer its MISO transition expenses. In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase. A hearing was held in late-April through early-May 2012.
In September 2012 the PUCT issued an order approving a $28 million rate increase, effective July 2012. The order includesincluded a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.” The order also providesprovided for increases in depreciation rates and the annual storm reserve accrual. The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measurable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates,rates; and reduced Entergy’s Texas’s fuel reconciliation recovery by $4 million because itthe PUCT disagreed with the line-loss factor used in the calculation. After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believebelieved that it iswas entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties have also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, have appealed various aspects of the PUCT’s order to the Travis County District Court. A hearing was held in July 2014. In October 2014 the Travis County District Court issued an order upholding the PUCT’s decision except as to the line-loss factor issue referenced above, which was found in favor of Entergy Texas. In November 2014, Entergy Texas and other parties, including the PUCT, appealed the Travis County District Court decision andto the PUCT appealedThird Court of Appeals. Oral argument before the court panel was held in September 2015. In April 2016 the Third Court of Appeals issued its opinion affirming the District Court’s decision on the line-loss factor issue.all points. Entergy Texas expectspetitioned the Texas Supreme Court to file briefs duringhear its appeal of the first halfThird Court’s ruling. In September 2017 the Texas Supreme Court denied the petitions for review. Entergy Texas filed a motion for rehearing of 2015.the Texas Supreme Court’s denial of the petition for review. In January 2018 the Texas Supreme Court denied Entergy Texas’s motion for rehearing.
2013 Rate CaseDistribution cost recovery factor (DCRF) rider
In September 2013,2015, Entergy Texas filed to amend its DCRF rider. Entergy Texas requested an increase in recovery under the rider of $6.5 million, for a rate case requesting a $38.6total collection of $10.1 million base rate increase reflecting a 10.4% return on common equity based on an adjusted test year ending March 31, 2013. The rate case also proposed (1) a rough production cost equalization adjustment rider recovering Entergy Texas’s payment to Entergy New Orleans to achieve rough production cost equalization based on calendar year 2012 production costsannually from retail customers. In October 2015 intervenors and (2) a rate case expense rider recovering the cost of the 2013 rate case and certain costs associated with previous rate cases. The rate case filing also included a request to reconcile $0.9 billion of fuel and purchased power costs and fuel revenues covering the period July 2011 through March 2013. The fuel reconciliation also reflects special circumstances fuel cost recovery of approximately $22 million of purchased power capacity costs. In January 2014 the PUCT staff filed direct testimony recommending a retail rate reduction of $0.3 million and a 9.2% return on common equity.opposing, in part, Entergy Texas’s request. In March 2014,November 2015, Entergy Texas and the parties filed an Agreed Motionunopposed settlement agreement and supporting documents. The settlement established an annual revenue requirement of $8.65 million for Interim Rates. The motion explained that the parties to this proceeding have agreed that Entergy Texas should be allowed to implement newamended DCRF rider, with the resulting rates reflecting an $18.5 million base rate increase, effective for usage on and after AprilJanuary 1, 2014, as well as2016. The PUCT approved the settlement agreement in February 2016.
In June 2017, Entergy Texas filed an application to amend its DCRF rider by increasing the total collection from $8.65 million to approximately $19 million. In July 2017, Entergy Texas, the PUCT, and the two other parties in the proceeding entered into an unopposed stipulation and settlement agreement resulting in an amended DCRF annual revenue requirement of $18.3 million, with the resulting rates effective for usage no later than October 1, 2017. In September 2017 the PUCT issued its final order approving the unopposed stipulation and settlement agreement. The amended DCRF rider rates became effective for usage on and after September 1, 2017.
Transmission cost recovery factor (TCRF) rider
In September 2015, Entergy Texas filed for a TCRF rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances involving, among other things, MISO charges, vegetation management costs, and bad debt expenses
Entergy Corporation and Subsidiaries
Notes to Financial Statements
that would reduce the requested increase by approximately $2 million. In addition to those recommended disallowances, a number of parties recommended that Entergy Texas’s request be reduced by an additional $3.4 million to account for rough production cost equalization and rate case expenses.load growth since base rates were last set. A hearing on the merits was held in December 2015. In March 2014 theFebruary 2016 a State Office of Administrative Hearings ALJ issued a proposal for decision recommending that the body assignedPUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In June 2016 the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to heara TCRF. In July 2016 the case, approvedPUCT issued an order generally accepting the motion. proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.
In April 2014,September 2016, Entergy Texas filed with the PUCT a unanimousrequest to amend its TCRF rider. The proposed amended TCRF rider is designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount includes the approximately $10.5 million annually that Entergy Texas is currently authorized to collect through the TCRF rider, as discussed above. In December 2016, concurrent with the 2016 fuel reconciliation stipulation in this case. Among other things,and settlement agreement discussed above, Entergy Texas and the stipulation provides for an $18.5 million base rate increase, recovery over three yearsPUCT reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. As discussed above, the terms of the calendar year 2012 rough production cost equalization charges and rate case expenses, and states a 9.8% return on common equity. In addition, the stipulation finalizes the fuel and purchased power reconciliation covering the period July 2011 through March 2013, with the parties stipulating an immaterial fuel disallowance. No special circumstances recovery of purchased power capacity costs was allowed. In April 2014 the State Office of Administrative Hearings remanded the case back to the PUCT for final processing. In May 2014 thetwo settlements are interdependent. The PUCT approved the settlement and issued a final order in March 2017. Entergy Texas implemented the amended TCRF rider beginning with bills covering usage on and after March 20, 2017.
Advanced Metering Infrastructure (AMI) Filings
Entergy Arkansas
In September 2016, Entergy Arkansas filed an application seeking a finding from the APSC that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Arkansas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $208 million.The filing identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $406 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value of existing meters, which was approximately $57 million at December 31, 2015, that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Deployment of the communications network is expected to begin in 2018. Entergy Arkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings, and the 2018 costs were approved in the 2017 formula rate plan filing. In June 2017 the APSC staff and Arkansas Attorney General filed direct testimony. The APSC staff generally supported Entergy Arkansas’s AMI deployment conditioned on various recommendations. The Arkansas Attorney General’s consultant primarily recommended denial of Entergy Arkansas’s application but alternatively suggested recommendations in the event the APSC approves Entergy Arkansas’s proposal. Entergy Arkansas filed rebuttal testimony in June 2017, substantially accepting the APSC staff’s recommendations. In August 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement. In October 2017 the APSC issued an order finding that Entergy Arkansas’s AMI deployment is in the public interest and approving the settlement agreement subject to a minor modification. Entergy Arkansas expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized over 15 years. Entergy Arkansas has begun discussions with the other parties to implement the items in the settlement agreement including pre-pay and time of use programs.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Louisiana
In November 2016, Entergy Louisiana filed an application seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing included an estimate of implementation costs for AMI of $330 million. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value, approximately $92 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. The communications network deployment is expected to begin by late-2018, after the necessary information technology infrastructure is in place. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. The parties reached an uncontested stipulation permitting implementation of Entergy Louisiana’s proposed AMI system, with modifications to the proposed customer charge. In July 2017 the LPSC approved the stipulation. No motionsEntergy Louisiana expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized at current depreciation rates.
Entergy Mississippi
In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing included an estimate of implementation costs for rehearing wereAMI of $132 million. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15-year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value, approximately $56 million at December 31, 2015, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC, with deployment of the communications network expected to begin in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable. In May 2017 the Mississippi Public Utilities Staff and Entergy Mississippi entered into and filed duringa joint stipulation supporting Entergy Mississippi’s filing, and the statutory rehearing period.MPSC issued an order approving the filing without material changes, finding that Entergy Mississippi’s deployment of AMI is in the public interest and granting a certificate of public convenience and necessity. The MPSC order also confirmed that Entergy Mississippi shall continue to include in rate base the remaining book value of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates.
Entergy New Orleans
In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid. The filing included an estimate of implementation costs for AMI of $75 million. The filing identified a number of quantified and unquantified benefits, and Entergy New
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million. Entergy New Orleans also sought to continue to include in rate base the remaining book value, approximately $21 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Deployment of the information technology infrastructure began in 2017 and deployment of the communications network is expected to begin in 2018. Entergy New Orleans proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. The City Council’s advisors filed testimony in May 2017 recommending the adoption of AMI subject to certain modifications, including the denial of Entergy New Orleans’s proposed customer charge as a cost recovery mechanism. In September 2014,January 2018 a settlement was reached between the City Council’s advisors and Entergy New Orleans. In February 2018 the City Council approved the settlement, which deferred cost recovery to the 2018 Entergy New Orleans rate case, but also stated that an adjustment for 2018-2019 AMI costs can be filed in the rate case and that, for all subsequent AMI costs, the mechanism to be approved in the 2018 rate case will allow for the timely recovery of such costs.
Entergy Texas
In April 2017 the Texas legislature enacted legislation that extends statutory support for AMI deployment to Entergy Texas and directs that if Entergy Texas elects to deploy AMI, it shall do so as rapidly as practicable. In July 2017, Entergy Texas filed an application seeking an order from the PUCT approving Entergy Texas’s deployment of AMI. Entergy Texas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Texas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a distributionnumber of quantified and unquantified benefits, with Entergy Texas showing that its AMI deployment is expected to produce nominal net operational cost recovery factor rider based onsavings to customers of $33 million. Entergy Texas also sought to continue to include in rate base the remaining book value, approximately $41 million at December 31, 2016, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Texas proposed a law that was passed in 2011 allowingseven-year depreciable life for the recoverynew advanced meters, the three-year deployment of increaseswhich is expected to begin in capital costs associated with distribution plant.2019. Entergy Texas requested collectionalso proposed a surcharge tariff to recover the reasonable and necessary costs it has and will incur under the deployment plan for the full deployment of approximately $7 million annually from retail customers.advanced meters. Further, Entergy Texas sought approval of fees that would be charged to customers who choose to opt out of receiving service through an advanced meter and instead receive electric service with a non-standard meter. In October 2017, Entergy Texas and other parties entered into and filed an unopposed stipulation and settlement agreement, permitting deployment of AMI with limited modifications. The parties reached a unanimousPUCT approved the stipulation and settlement authorizing recovery of $3.6 million annually commencing with usage on and after January 1, 2015. A State Office of Administrative Hearings ALJ issued an orderagreement in December 2014 authorizing this recovery on an interim basis and remanded2017. Consistent with the caseapproval, deployment of the communications network is expected to begin in 2018. Entergy Texas expects to recover the PUCT. In February 2015 the PUCT enteredremaining net book value of its existing meters through a final order, making the settlement final and the interim rates permanent.regulatory asset to be amortized at current depreciation rates.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
In June 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed a business combination study report with the LPSC. The report contained a preliminary analysis of the potential combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility, including an overview of the combination that identified its potential customer benefits. Although not part of the business combination, Entergy Louisiana provided notice to the City Council in June 2014 that it would seek authorization to transfer to Entergy New Orleans the assets that currently support the provision of service to Entergy Louisiana’s customers in Algiers. Entergy Louisiana subsequently filed the referenced application with the City Council in October 2014. In the summer of 2014, Entergy Louisiana and Entergy Gulf States Louisiana held technical conferences and face-to-face meetings with LPSC staff and other stakeholders to discuss potential effects of the combination, solicit suggestions and concerns, and identify areas in which additional information might be needed.
On September 30, 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed an application with the LPSC in September 2014 seeking authorization to undertake the transactions that would result in the combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility.
The combination is subject to regulatory review and approval of An uncontested stipulated settlement (stipulated settlement) was filed with the LPSC in July 2015. Through the FERC, andstipulated settlement, the NRC. In June 2014, Entergy submitted an applicationparties agreed to terms upon which to recommend that the NRC for approval of River Bend and Waterford 3 license transfers as part of the steps to complete the business combination. The combination also could be subject to regulatory review of the City Council if Entergy Louisiana continues to own the assetsLPSC find that currently support Entergy Louisiana’s customers in Algiers at the time the combination is effectuated. In November 2014, Entergy Louisiana filed an application with the City Council seeking authorization to undertake the combination. The application provides that if the City Council approves the Algiers asset transfer before the business combination occurs,was in the City Council may not needpublic interest. The stipulated settlement, which was either joined, or unopposed, by all parties to issuethe LPSC proceeding, represented a public interest finding regardingcompromise of stakeholder positions and was the combination. In December 2014,result of an extensive period of analysis, discovery, and negotiation. The stipulated settlement provided $107 million in guaranteed customer benefits during the first nine years following the transaction’s close. Additionally, the combined company would honor the 2013 Entergy Louisiana and Entergy Gulf States Louisiana filed applications withrate case settlements, including the FERC requesting authorizationcommitments that (1) there would be no rate increase for the business combination and the Algiers asset transfer. In January 2015, Entergy Services filed an application with the FERC for financing authority for the combined company. If approvals are obtained from the LPSC, the FERC, the NRC, and, if required, the City Council, Entergy Louisiana andlegacy Entergy Gulf States Louisiana expectcustomers for the combination will be effected in2014 test year, and (2) through the second half of 2015.2016 test year formula rate plan, Entergy Louisiana (as a combined entity)
The procedural schedule in the LPSC business combination proceeding calls for LPSC Staff and intervenor testimony to be filed in March 2015, with a hearing scheduled for June 2015. Entergy Louisiana and Entergy Gulf States Louisiana have requested that the LPSC issue its decision regarding the business combination in August 2015. In the City Council business combination proceeding, the City Council announced through a resolution that it would not initiate an active review of the business combination filing, but instead would establish a business combination docket for the limited purpose of receiving information filings relative to the business combination proceedings at the LPSC.
It is currently contemplated that Entergy Louisiana and Entergy Gulf States Louisiana will undertake multiple steps to effectuate the combination, which steps would include the following:
Each of Entergy Louisiana and Entergy Gulf States Louisiana will redeem or repurchase all of their respective outstanding preferred membership interests (which interests have a $100 million liquidation
Entergy Corporation and Subsidiaries
Notes to Financial Statements
valuewould not raise rates by more than $30 million, net of the $10 million rate increase included in the case of Entergy Louisiana and $10 million liquidation value in the case of Entergy Gulf States Louisiana).
legacy formula rate plan. The stipulated settlement also provided that Entergy Gulf States Louisiana will convert from a Louisiana limited liability company to a Texas limited liability company.
Under the Texas Business Organizations Code (TXBOC),and Entergy Louisiana will allocate substantially allwould be permitted to defer certain external costs that were incurred to achieve the business combination’s customer benefits. In 2015 deferrals of its assets to$16 million for these external costs were recorded, and they are being amortized over a new subsidiary (New Entergy Louisiana) and New Entergy Louisiana will assume all of10-year period. The LPSC approved the liabilities of Entergy Louisiana,business combination in a transaction regarded as a merger underAugust 2015.
On October 1, 2015, the TXBOC. Entergy Louisiana will remain in existence and hold the membership interests in New Entergy Louisiana.
Under the TXBOC, Entergy Gulf States Louisiana will allocate substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana will assume all of the liabilities of Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. Entergy Gulf States Louisiana will remain in existence and hold the membership interests in New Entergy Gulf States Louisiana.
businesses formerly conducted by Entergy Louisiana and Entergy Gulf States Louisiana will contribute the membership interests in New Entergy Louisiana and New Entergy Gulf States Louisiana to an affiliate the common membership interests of which will be owned by Entergy Louisiana, Entergy Gulf States Louisiana and Entergy Corporation.
New Entergy Gulf States Louisiana will mergewere combined into New Entergy Louisiana with New Entergy Louisiana surviving the merger.
Upona single public utility. With the completion of the steps, Newbusiness combination, Entergy Louisiana will holdholds substantially all of the assets, and will havehas assumed all of the liabilities, of Entergy Louisiana and Entergy Gulf States Louisiana. Entergy Louisiana and Entergy Gulf States Louisiana may modify or supplementThe combination was accounted for as a transaction between entities under common control. See Note 3 to the steps to be taken to effectfinancial statements for further discussion of the customer credits resulting from the business combination.
Algiers Asset Transfer (Entergy Louisiana and Entergy New Orleans)
In October 2014, Entergy Louisiana and Entergy New Orleans filed an application with the City Council seeking authorization to undertake a transaction that would result in the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that currently servesupported the provision of service to Entergy Louisiana’s customers in Algiers. The transaction is expected to resultIn April 2015 the FERC issued an order approving the Algiers assets transfer. In May 2015 the parties filed a settlement agreement authorizing the Algiers assets transfer and the settlement agreement was approved by a City Council resolution in the transfer of net assets of approximately $60 million. The Algiers asset transfer is also subject to regulatory review and approval of the FERC. As discussed previously,May 2015. On September 1, 2015, Entergy Louisiana also filed an application with the City Council seeking authorization to undertake the Entergy Louisiana and Entergy Gulf States Louisiana business combination. The application provides that if the City Council approves the Algiers asset transfer before the business combination occurs, the City Council may not need to issue a public interest finding regarding the business combination. If the necessary approvals are obtained from the City Council and the FERC, Entergy Louisiana expects to transfer thetransferred its Algiers assets to Entergy New Orleans for a purchase price of approximately $85 million. Entergy New Orleans paid Entergy Louisiana $59.6 million, including final true-ups, from available cash and issued a note payable to Entergy Louisiana in the second halfamount of 2015. In November 2014 the City Council approved a resolution establishing a procedural schedule that provides for a hearing on the joint application in late-May 2015, with a decision to be rendered no later than June 2015.$25.5 million.
System Agreement Cost Equalization Proceedings
ThePrior to its final termination in 2016, the Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement. Entergy Arkansas terminated its participation in the System Agreement which is a rate schedule thatin December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.
Although the System Agreement has been approved by the FERC. Certainterminated, certain of the Utility operating companies’ retail regulators and other parties are pursuingcontinue to pursue litigation involving the System Agreement at the FERC.FERC and in federal courts. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement.other matters.
In June 2005 the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing. The FERC decision concluded,included, among other things, that:things:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The FERC’s conclusion that the System Agreement no longer roughly equalizes total production costs among the Utility operating companies.
In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs will have to be within +/- 11% of Entergy System average total annual production costs.
In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant will not reflect the actual Vidalia price for the year but is priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs.
The remedy ordered by the FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs and the first reallocation payments were made in 2007.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The FERC’s decision reallocatesreallocated total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth. Under the current circumstances, this will beThis was accomplished by payments from Utility operating companies whose production costs arewere more than 11% below Entergy System average production costs to Utility operating companies whose production costs arewere more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs arewere farthest above the Entergy System average.
The financial consequences of the FERC’s decision are determined by the total production cost of each Utility operating company, which are affected by the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana, Entergy Gulf States Louisiana, Entergy Texas, and Entergy Mississippi are more dependent upon gas-fired generation sources than Entergy Arkansas or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation sources. Therefore, increases in natural gas prices generally increased the amount by which Entergy Arkansas’s total production costs were below the Entergy System average production costs.
The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit. Entergy and the City of New Orleans intervened in the various appeals. The D.C. Circuit issued its decision in April 2008. The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005. The D.C. Circuit remanded the case to the FERC for further proceedings on thesethose two issues.
In October 2011 the FERC issued an order addressing the D.C. Circuit remand on thesethe two issues. On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003. Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that thethis refund ruling will be held in abeyance pending the outcome of the rehearing requests in thatthe interruptible load proceeding. On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered. Pursuant to the October 2011 order, Entergy was required to calculate the additional bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order. As is the case with bandwidth remedy payments, these payments and receipts will ultimately be paid by Utility operating company customers to other Utility operating company customers.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In March 2015, in light of a December 2014 decision by the D.C. Circuit in the interruptible load proceeding, Entergy filed with the FERC a motion to establish a briefing schedule on refund issues and an initial brief addressing refund issues. The initial brief argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in this proceeding. In October 2015 the FERC issued three orders related to the commencement of the remedy on June 1, 2005 and the inclusion of interest for the period June 1, 2005 through December 31, 2005. Specifically, the FERC rejected Entergy’s request for rehearing of its decision to include interest for the seven-month period. The FERC also rejected Entergy’s request for rehearing of the order rejecting the compliance filing with regard to the issue of interest. Finally, the FERC set for hearing and settlement procedures the 2014 compliance filing that included the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005. In setting the compliance filing for hearing, the FERC rejected the APSC’s protest that Entergy Arkansas should not be subject to the filing because Entergy Arkansas would be making the payments during a period following its exit from the System Agreement. In January 2018 the D.C.Circuit affirmed the FERC decision that Entergy Arkansas was subject to the filing.
In December 2011, Entergy filed with the FERC its compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order. The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests. The filing shows the following payments/receipts among the Utility operating companies:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| |
| | Payments (Receipts) |
| | (In Millions) |
| Entergy Arkansas | $156 |
Entergy Gulf States Louisiana | ($75) |
Entergy Louisiana | $— |
| Entergy Mississippi | ($33) |
| Entergy New Orleans | ($5) |
| Entergy Texas | ($43) |
Entergy Arkansas made its payment in January 2012. In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million payment be collected from customers over the 22-month period from March 2012 through December 2013. In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund. The LPSC and the APSC have requested rehearing of the FERC’s October 2011 order. In December 2013 the LPSC filed a petition for a writ of mandamus at the United States Court of Appeals for the D.C. Circuit. In its petition, the LPSC requested that the D.C. Circuit issue an order compelling the FERC to issue a final order on pending rehearing requests. In its response to the LPSC petition, the FERC committed to rule on the pending rehearing request before the end of February. In January 2014 the D.C. Circuit denied the LPSC’s petition. The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests.
In February 2014 the FERC issued a rehearing order addressing its October 2011 order. The FERC denied the LPSC’s request for rehearing on the issues of whether the bandwidth remedy should be made effective earlier than June 1, 2005, and whether refunds should be ordered for the 20-month refund effective period. The FERC granted the LPSC’s rehearing request on the issue of interest on the bandwidth payments/receipts for the June - December 2005 period, requiring that interest be accrued from June 1, 2006 until the date those bandwidth payments/receipts are made. Also in February 2014 the FERC issued an order rejecting the December 2011 compliance filing that calculated the bandwidth payments/receipts for the June - December 2005 period. The FERC order required a new compliance filing that calculates the bandwidth payments/receipts for the June - December 2005 period based on monthly data for the seven individual months including interest pursuant to the February 2014 rehearing order. Entergy has sought rehearing of the February 2014 ordersorder with respect to the FERC’s determinations regarding interest. In April 2014 the LPSC filed a petition for review of the FERC’s October 2011 and February 2014 orders with the U.S. Court of Appeals for the D.C. Circuit. TheIn August 2017 the D.C. Circuit issued a decision addressing the LPSC’s appeal is currently being heldof the FERC’s October 2011 and February 2014 orders. On the issue of the FERC’s implementation of the prospective remedy as of June 2005 and whether the bandwidth remedy should be extended for an additional 17 months in abeyance pending resolutionyears 2004-2005, the D.C. Circuit affirmed the FERC’s implementation of Entergy’sthe remedy and denied the LPSC’s appeal. On the issue of whether the operating companies should be required to issue refunds for the 20-month period from September 2001 to May 2003, the D.C. Circuit granted the FERC’s request for rehearing with respectagency reconsideration and remanded that issue back to the FERC’s determinations regarding interest.FERC for further proceedings as requested by all parties to the appeal.
In April and May 2014, Entergy filed with the FERC an updated compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s February 2014 orders. The filing shows the following net payments and receipts, including interest, among the Utility operating companies:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| |
| | Payments (Receipts) |
| | (In Millions) |
| Entergy Arkansas | $68 |
Entergy Gulf States Louisiana | ($10) |
Entergy Louisiana | $— |
| Entergy Mississippi | ($11) |
| Entergy New Orleans | $2 |
| Entergy Texas | ($49) |
These payments were made in May 2014. The LPSC, City Council, and APSC have filed protests.
Calendar Year 2014 Production Costs
Entergy Corporation and Subsidiaries
Notes to Financial Statements
BasedThe hearing on certain year-to-date information, Entergy preliminarily estimates that no payments and receipts are requiredthe bandwidth calculation for the seven months June 1, 2005 through December 31, 2005 occurred in 2015 to implementJuly 2016. The presiding judge issued an initial decision in November 2016. In the FERC’s remedy based on calendar year 2014 production costs. The actual payments/receipts for 2015, based on calendar year 2014 production costs, will not be calculated untilinitial decision, the presiding judge agreed with the Utility operating companies’ 2014position that: (1) interest on the bandwidth payments for the 2005 test period should be accrued from June 1, 2006 until the date that the bandwidth payments for that calculation are paid, which is consistent with how the Utility operating companies performed the calculation; and (2) a portion of Entergy Louisiana’s 2001-vintage Louisiana state net operating loss accumulated deferred income tax that results from the Vidalia tax deduction should be excluded from the 2005 test period bandwidth calculation. Various participants filed briefs on exceptions and/or briefs opposing exceptions related to the initial decision, including the LPSC, the APSC, the FERC Form 1s have been filed. Oncetrial staff, and Entergy Services. The initial decision is pending before the calculation is completed, it will be filed at the FERC. The level of any payments and receipts is significantly affected by a number of factors, including, among others, weather, the price of alternative fuels, the operating characteristics of the Entergy System generating fleet, and multiple factors affecting the calculation of the non-fuel related revenue requirement components of the total production costs, such as plant investment.
Rough Production Cost Equalization Rates
Each May sincefrom 2007 through 2016 Entergy has filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding. These filings showshowed the following payments/receipts among the Utility operating companies arewere necessary to achieve rough production cost equalization as defined by the FERC’s orders:
| | | | Payments (Receipts) | Payments (Receipts) |
| | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | | 2012 | | 2013 | | 2014 | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | | 2012 | | 2013 | | 2014 |
| | (In Millions) | | | (In Millions) |
| Entergy Arkansas |
| $252 |
| |
| $252 |
| |
| $390 |
| |
| $41 |
| |
| $77 |
| |
| $41 |
| |
| $— |
| |
| $— |
|
| $252 |
| |
| $252 |
| |
| $390 |
| |
| $41 |
| |
| $77 |
| |
| $41 |
| |
| $— |
| |
| $— |
|
| Entergy Gulf States Louisiana |
| ($120 | ) | |
| ($124 | ) | |
| ($107 | ) | |
| $— |
| |
| ($12 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| Entergy Louisiana |
| ($91 | ) | |
| ($36 | ) | |
| ($140 | ) | |
| ($22 | ) | |
| $— |
| |
| ($41 | ) | |
| $— |
| |
| $— |
|
| ($211 | ) | |
| ($160 | ) | |
| ($247 | ) | |
| ($22 | ) | |
| ($12 | ) | |
| ($41 | ) | |
| $— |
| |
| $— |
|
| Entergy Mississippi |
| ($41 | ) | |
| ($20 | ) | |
| ($24 | ) | |
| ($19 | ) | |
| ($40 | ) | |
| $— |
| |
| $— |
| |
| $— |
|
| ($41 | ) | |
| ($20 | ) | |
| ($24 | ) | |
| ($19 | ) | |
| ($40 | ) | |
| $— |
| |
| $— |
| |
| $— |
|
| Entergy New Orleans |
| $— |
| |
| ($7 | ) | |
| $— |
| |
| $— |
| |
| ($25 | ) | |
| $— |
| |
| ($15 | ) | |
| ($15 | ) |
| $— |
| |
| ($7 | ) | |
| $— |
| |
| $— |
| |
| ($25 | ) | |
| $— |
| |
| ($15 | ) | |
| ($15 | ) |
| Entergy Texas |
| ($30 | ) | |
| ($65 | ) | |
| ($119 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $15 |
| |
| $15 |
|
| ($30 | ) | |
| ($65 | ) | |
| ($119 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $15 |
| |
| $15 |
|
Entergy Arkansas is no longerThe Utility operating companies recorded accounts payable or accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy. When accounts payable were recorded, a participantcorresponding regulatory asset was recorded for the right to collect the payments from customers. When accounts receivable were recorded, a corresponding regulatory liability was recorded for the obligations to pass the receipts on to customers. No payments were required in 2016 or 2015 to implement the System Agreement and was not part of theFERC’s remedy based on calendar year 2013 or2015 production costs and 2014 production costs, calculations.respectively. The System Agreement terminated in August 2016.
The APSC has approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas. Entergy Texas proposed arecovered its 2013 rough production cost equalization adjustment riderpayment over three years beginning April 2014. Entergy Texas included its 2014 rough production cost equalization payment as a component of an interim fuel refund made in its September 2013 rate filing, which is pending.2014. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs. See “2007 Rate Filing Based on Calendar Year 2006 Production Costs” below, however, for a discussion of a FERC decision that could result in trapped costs at Entergy Arkansas related to a contract with AmerenUE.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas and, for December 2012 and 2013, Entergy Texas, record accounts payable and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record accounts receivable to reflect theThe following rough production cost equalization payments and receipts required to implement the FERC’s remedy. Entergy Arkansas and, for December 2012 and 2013, Entergy Texas, record a corresponding regulatory asset for the right to collect the payments from customers, and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record corresponding regulatory liabilities for their obligations to pass the receipts on to customers. The regulatory asset and liabilities are shown as “System Agreement cost equalization” on the respective balance sheets.
2007 Rate Filing Based on Calendar Year 2006 Production Costs
Several parties intervened in the 2007 rate proceeding at the FERC, including the APSC, the MPSC, the Council, and the LPSC, which also filed protests. The PUCT also intervened. Intervenor testimony was filed in which the intervenors and also the FERC Staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for nuclear facilities. The effect of the various positions would be to reallocate costs among the Utility operating companies. The Utility operating companies filed rebuttal testimony explaining why the bandwidth payments are properly recoverable under the AmerenUE contract, and explaining why the positions of FERC Staff and intervenors on the other issues should be rejected. A hearing in this proceeding concluded in July 2008, and the ALJ issued an initial decision in September 2008. The ALJ’s initial decision concluded, among other things, that: (1) the decisions to not exercise Entergy Arkansas’s option to purchase the Independence plant in 1996 and 1997 were prudent; (2) Entergy Arkansas properly flowed a portion of the bandwidth payments through to AmerenUE in accordance with the wholesale power contract; and (3) the level of nuclear depreciation and decommissioning expense reflected in the bandwidth calculation should be calculated based on NRC-authorized license life, rather than the nuclear depreciation and decommissioning expense authorized by the retail regulators for purposes of retail ratemaking. Following briefing by the parties, the matter was submitted to the FERC for decision. On January 11, 2010, the FERC issued its decision both affirming and overturning certain of the ALJ’s rulings, including overturning the decision on nuclear depreciation and decommissioning expense. The FERC’s conclusion related to the AmerenUE contract does not permit Entergy Arkansas to recover a portion of its bandwidth payment from AmerenUE. The Utility operating companies requested rehearing of that portion of the decision and requested clarification on certain other portions of the decision.
AmerenUE argued that its wholesale power contract with Entergy Arkansas, pursuant to which Entergy Arkansas sells power to AmerenUE, does not permit Entergy Arkansas to flow through to AmerenUE any portion of Entergy Arkansas’s bandwidth payment. The AmerenUE contract expired in August 2009. In April 2008, AmerenUE filed a complaint with the FERC seeking refunds, plus interest, in the event the FERC ultimately determines that bandwidth payments are not properly recovered under the AmerenUE contract. In response to the FERC’s decision discussed in the previous paragraph, Entergy Arkansas recorded a regulatory provision in the fourth quarter 2009 for a potential refund to AmerenUE.
In May 2012, the FERC issued an order on rehearing in the proceeding. The order may result in the reallocation of costs among the Utility operating companies, although thereproceedings are still FERC decisions pending in other System Agreement proceedings that could affect the rough production cost equalization payments and receipts. The FERC directed Entergy, within 45 days of the issuance of a pending FERC order on rehearing regarding the functionalization of costs in the 2007 rate filing, to file a comprehensive bandwidth recalculation report showing updated payments and receipts in the 2007 rate filing proceeding. The May 2012 FERC order also denied Entergy’s request for rehearing regarding the AmerenUE contract and ordered Entergy Arkansas to refund to AmerenUE the rough production cost equalization payments collected from AmerenUE. Under the terms of the FERC’s order a refund of $30.6 million, including interest, was made in June 2012. Entergy and the LPSC appealed certain aspects of the FERC’s decisions to the U.S. Court of Appeals for the D.C. Circuit. On December 7, 2012, the D.C. Circuit dismissed Entergy’s petition for review as premature because Entergy filed a rehearing request of the May 2012 FERC order and that rehearing request is still pending. The court also ordered that the LPSC’s appeal be held in abeyance and that the parties file
Entergy Corporation and Subsidiaries
Notes to Financial Statements
motions to govern further proceedings within 30 days of the FERC’s completion of the ongoing “Entergy bandwidth proceedings.” On October 16, 2013, the FERC issued two orders related to this proceeding. The first order provided clarification with regard to the derivation of the ratio that should be used to functionalize net operating loss carryforwards for purposes of the annual bandwidth filings. The first order required a compliance filing that Entergy made in November 2013. The second order denied Entergy’s request for rehearing of the FERC’s prior determination that interest should be included on recalculated payment and receipt amounts required in this particular proceeding due to the length of time that had passed. Entergy subsequently appealed certain aspects of the FERC’s decisions to the U.S. Court of Appeals for the D.C. Circuit. On January 23, 2014, the D.C. Circuit returned the LPSC’s appeal to the active docket and consolidated it with Entergy’s petition for appellate review. The appeals are pending. In July 2014 the FERC issued an order accepting Entergy Services’ November 2013 compliance filing. The FERC directed Entergy Services to make a comprehensive bandwidth recalculation report by September 15, 2014 showing all the updated payment/receipt amounts based on the 2006 calendar year data in compliance with all bandwidth formula and bandwidth calculation adjustments that the FERC has accepted or ordered for those years. The FERC also directed the Entergy Operating Companies to make any true-up bandwidth payments associated with the 2006 bandwidth recalculation report with interest following the filing of the comprehensive recalculation report. See discussion below regarding the comprehensive bandwidth recalculation and filings made with the FERC in connection with this proceeding.
2008 Rate Filing Based on Calendar Year 2007 Production Costs
Several parties intervened in the 2008 rate proceeding at the FERC, including the APSC, the LPSC, and AmerenUE, which also filed protests. Several other parties, including the MPSC and the City Council, intervened in the proceeding without filing a protest. In direct testimony filed in January 2009, certain intervenors and the FERC staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for the nuclear and fossil-fueled generating facilities. The effect of these various positions would be to reallocate costs among the Utility operating companies. In addition, three issues were raised alleging imprudence by the Utility operating companies, including whether the Utility operating companies had properly reflected generating units’ minimum operating levels for purposes of making unit commitment and dispatch decisions, whether Entergy Arkansas’s sales to third parties from its retained share of the Grand Gulf nuclear facility were reasonable, prudent, and non-discriminatory, and whether Entergy Louisiana’s long-term Evangeline gas purchase contract was prudent and reasonable.
The parties reached a partial settlement agreement of certain of the issues initially raised in this proceeding. The partial settlement agreement was conditioned on the FERC accepting the agreement without modification or condition, which the FERC did in August 2009. A hearing on the remaining issues in the proceeding was completed in June 2009, and in September 2009 the ALJ issued an initial decision. The initial decision affirms Entergy’s position in the filing, except for two issues that may result in a reallocation of costs among the Utility operating companies. In October 2011 the FERC issued an order on the ALJ’s initial decision. The FERC’s order resulted in a minor reallocation of payments/receipts among the Utility operating companies on one issue in the 2008 rate filing. Entergy made a compliance filing in December 2011 showing the updated payment/receipt amounts. The LPSC filed a protest in response to the compliance filing. In January 2013 the FERC issued an order accepting Entergy’s compliance filing. In the January 2013 order the FERC required Entergy to include interest on the recalculated bandwidth payment and receipt amounts for the period from June 1, 2008 until the date of the Entergy intra-system bill that will reflect the bandwidth recalculation amounts for calendar year 2007. In February 2013, Entergy filed a request for rehearing of the FERC’s ruling requiring interest. In March 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the Fifth Circuit seeking appellate review of the FERC’s earlier orders addressing the ALJ’s initial decision. In July 2014 the FERC issued an order denying Entergy’s rehearing request and decided that it is appropriate to allow interest to be paid on the bandwidth recalculation amounts. The FERC also directed Entergy to file a comprehensive bandwidth recalculation report by September 15, 2014 showing all the updated payment/receipt amounts based on the 2007 calendar year data in compliance with all bandwidth formula and bandwidth calculation adjustments that the FERC has accepted or ordered for that year. The FERC also directed the Entergy Operating Companies to make any true-up bandwidth payments associated with the 2007 bandwidth recalculation report with interest following the filing of the comprehensive
Entergy Corporation and Subsidiaries
Notes to Financial Statements
recalculation report. In August 2014 the Fifth Circuit issued its opinion dismissing in part and denying in part the LPSC petition for review of the FERC’s order. In December 2014 the LPSC petitioned the U.S. Supreme Court for a writ of certiorari of the Fifth Circuit’s decision. In September 2014, Entergy filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking appellate review of the FERC’s interest determination. See discussion below regarding the comprehensive bandwidth recalculation and filings made with the FERC in connection with this proceeding.
2009 Rate Filing Based on Calendar Year 2008 Production Costs
Several parties intervened in the 2009 rate proceeding at the FERC, including the LPSC and Ameren, which also filed protests. In July 2009 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2009, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures were terminated and a hearing before the ALJ was held in April 2010. In August 2010 the ALJ issued an initial decision. The initial decision substantially affirms Entergy’s position in the filing, except for one issue that may result in some reallocation of costs among the Utility operating companies. The LPSC, the FERC trial staff, and Entergy submitted briefs on exceptions in the proceeding. In May 2012 the FERC issued an order affirming the ALJ’s initial decision, or finding certain issues in that decision moot. Rehearing and clarification of FERC’s order have been requested. In January 2013 the LPSC filed a protest of Entergy’s July 2012 compliance filing submitted in response to the FERC’s May 2012 order. In October 2013 the FERC issued orders denying the LPSC’s rehearing request with respect to the FERC’s May 2012 order and addressing Entergy’s compliance filing implementing the FERC’s directives in the May 2012 order. The compliance filing order referred to guidance provided in a separate order issued on that same day in the 2007 rate proceeding with respect to the ratio used to functionalize net operating loss carryforwards for bandwidth purposes and directed Entergy to make an additional compliance filing in the 2009 rate proceeding consistent with the guidance provided in that order. In November 2013 the LPSC sought rehearing of the FERC’s October 2013 order and Entergy submitted its compliance filing implementing the FERC’s directives in the October 2013 order. In August 2014, the FERC issued an order accepting the November 2013 compliance filing that was made in response to the FERC’s October 2013 order. The LPSC appealed to the U.S. Court of Appeals for the Fifth Circuit the FERC’s May 2012 and October 2013 orders. In November 2014 the Fifth Circuit issued its opinion denying the LPSC petition for review of the FERC’s order. In December 2014 the LPSC petitioned the U.S. Supreme Court for a writ of certiorari of the Fifth Circuit’s decision. See discussion below regarding the comprehensive bandwidth recalculation and filings made with the FERC in connection with this proceeding.
Comprehensive Bandwidth Recalculation for 2007, 2008, and 2009 Rate Filing Proceedings
In July 2014 the FERC issued four orders in connection with various Service Schedule MSS-3 rough production cost equalization formula compliance filings and rehearing requests. Specifically, the FERC accepted Entergy Services’ revised methodologies for calculating certain cost components of the formula and affirmed its prior ruling requiring interest on the true-up amounts. The FERC directed that a comprehensive recalculation of the formula be performed for the filing years 2007, 2008, and 2009 based on calendar years 2006, 2007, and 2008 production costs. In September 2014, Entergy filed with the FERC its compliance filing that provides the payments and receipts, including interest, among the Utility operating companies pursuant to the FERC’s orders for the 2007, 2008, and 2009 rate filing proceedings. The filing shows the following additional payments/receipts among the Utility operating companies:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| |
| Payments
(Receipts)
|
| (In Millions) |
Entergy Arkansas | $38 |
Entergy Gulf States Louisiana | ($22) |
Entergy Louisiana | ($16) |
Entergy Mississippi | $16 |
Entergy New Orleans | ($1) |
Entergy Texas | ($15) |
Entergy Arkansas and Entergy Mississippi made the payments in September and October 2014. The updated compliance filings in the 2008 and 2009 rate filing proceedings have not been protested, and one protest was filed at the FERC related to the 2007 rate filing proceeding. The filings are pending at the FERC.ongoing.
2010 Rate Filing Based on Calendar Year 2009 Production Costs
In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010. Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which also filed protests. In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund, and setrefund. After an abeyance of the proceeding for hearing and settlement procedures. Settlement procedures have been terminated, and the ALJ scheduled hearings to begin in March 2011. Subsequently, in January 2011 the ALJ issued an order directing the parties and FERC Staff to show cause why this proceeding should not be stayed pending the issuance of FERC decisions in the prior production cost proceedings currently before the FERC on review. In March 2011 the ALJ issued an order placing this proceeding in abeyance. In October 2013 the FERC issued an order granting clarification and denying rehearing with respect to its October 2011 rehearing order in this proceeding. The FERC clarified that inschedule, a bandwidth proceeding parties can challenge erroneous inputs, implementation errors, or prudence of cost inputs, but challenges to the bandwidth formula itself must be raised in a Federal Power Act section 206 complaint or section 205 filing. Subsequently in October 2013 the presiding ALJ lifted the stay order holding in abeyance the hearing previously ordered by the FERC and directing that the remaining issues proceed to a hearing on the merits. The hearing was held in March 2014 and in December 2015 the presiding ALJFERC issued an initial decisionorder. Among other things, the December 2015 order directed Entergy to submit a compliance filing. In January 2016 the LPSC, the APSC, and Entergy filed requests for rehearing of the FERC’s December 2015 order. In February 2016, Entergy submitted the compliance filing ordered in the December 2015 order. The result of the true-up payments and receipts for the recalculation of production costs resulted in the following payments/receipts among the Utility operating companies:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| |
| Payments (Receipts) |
| (In Millions) |
| Entergy Arkansas | $2 |
| Entergy Louisiana | $6 |
| Entergy Mississippi | ($4) |
| Entergy New Orleans | ($1) |
| Entergy Texas | ($3) |
In September 2016 the FERC accepted the February 2016 compliance filing subject to a further compliance filing made in November 2016. The further compliance filing was required as a result of an order issued in September 2014. Briefs2016 ruling on exception werethe January 2016 rehearing requests filed by the LPSC, the APSC, and Entergy. In the order addressing the rehearing requests, the FERC granted the LPSC’s rehearing request and directed that interest be calculated on the payment/receipt amounts. The FERC also granted the APSC’s and Entergy’s rehearing request and ordered the removal of both securitized asset accumulated deferred income taxes and contra-securitization accumulated deferred income taxes from the calculation. In November 2016, Entergy submitted its compliance filing in October 2014,response to the FERC’s order on rehearing. The compliance filing included a revised refund calculation of the true-up payments and receipts based on 2009 test year data and interest calculations. The LPSC protested the case is pending beforeinterest calculations. In November 2017 the FERC.FERC issued an order rejecting the November 2016 compliance filing. The FERC determined that the payments detailed in the November 2016 compliance filing did not include adequate interest for the payments from Entergy Arkansas to Entergy Louisiana because it did not include interest on the principal portion of the payment that was made in February 2016. In December 2017, Entergy recalculated the interest pursuant to the November 2017 order. As a result of the recalculations, Entergy Arkansas owed very minor payments to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
2011 Rate Filing Based on Calendar Year 2010 Production Costs
In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. In July 2011 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2011, subject to refund, setrefund. After an abeyance of the proceeding for hearing procedures, and then held those proceduresschedule, in abeyance pending FERC decisions in the prior production cost proceedings currently beforeDecember 2014 the FERC on review. In January 2014 the LPSC filed a petition for a writ of mandamus at the United States Court of Appeals for the Fifth Circuit. In its petition, the LPSC requested that the Fifth Circuit issue an order compelling the FERC to issue a final order in several proceedings related to the System Agreement, includingconsolidated the 2011 rate filing based on calendar year 2010 production costs and the 2012 and 2013 rate filings discussed below. In March 2014 the Fifth Circuit rejected the LPSC’s petition for a writ of mandamus. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2011 Rate Filing with the 2012, 2013, and 2014 Rate Filingsrate filings for settlement and hearing procedures. A procedural schedule was adoptedSee discussion below regarding the consolidated settlement and hearing procedures in February 2015, and a hearing on the merits is scheduled for November 2015.connection with this proceeding.
2012 Rate Filing Based on Calendar Year 2011 Production Costs
In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also
Entergy Corporation and Subsidiaries
Notes to Financial Statements
filed a protest. In August 2012 the FERC accepted Entergy’s proposed rates for filing, effective June 2012, subject to refund, setrefund. After an abeyance of the proceeding for hearing procedures, and then held those proceduresschedule, in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2012 Rate Filingrate filing with the 2011, 2013, and 2014 Rate Filingsrate filings for settlement and hearing procedures. A procedural schedule was adoptedSee discussion below regarding the consolidated settlement and hearing procedures in February 2015, and a hearing on the merits is scheduled for November 2015.connection with this proceeding.
2013 Rate Filing Based on Calendar Year 2012 Production Costs
In May 2013, Entergy filed with the FERC the 2013 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments related to including the outcome of a related FERC proceeding in the 2013 cost equalization calculation. In August 2013 the FERC issued an order accepting the 2013 rates, effective June 1, 2013, subject to refund, setrefund. After an abeyance of the proceeding for hearing procedures, and then held those proceduresschedule, in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2013 Rate Filingrate filing with the 2011, 2012, and 2014 Rate Filingsrate filings for settlement and hearing procedures. A procedural schedule was adopted
Entergy Corporation and Subsidiaries
Notes to Financial Statements
See discussion below regarding the consolidated settlement and hearing procedures in February 2015, and a hearing on the merits is scheduled for November 2015.connection with this proceeding.
2014 Rate Filing Based on Calendar Year 2013 Production Costs
In May 2014, Entergy filed with the FERC the 2014 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments. In December 2014 the FERC issued an order accepting the 2014 rates, effective June 1, 2014, subject to refund, set the proceeding for hearing procedures, and consolidated the 2014 Rate Filingrate filing with the 2011, 2012, and 2013 Rate Filingsrate filings for settlement and hearing procedures. A procedural schedule was adoptedSee discussion below regarding the consolidated settlement and hearing procedures in Februaryconnection with this proceeding.
Consolidated 2011, 2012, 2013, and 2014 Rate Filing Proceedings
As discussed above, in December 2014 the FERC consolidated the 2011, 2012, 2013, and 2014 rate filings for settlement and hearing procedures. In May 2015, Entergy filed direct testimony in the consolidated rate filings and the LPSC filed direct testimony concerning its complaint proceeding that is consolidated with the rate filings, challenging certain components of the pending bandwidth calculations for prior years. Hearings occurred in November 2015, and a hearingthe ALJ issued an initial decision in July 2016. In the initial decision, the ALJ generally agreed with Entergy’s bandwidth calculations with one exception on the meritsaccounting related to the Waterford 3 sale/leaseback. Briefs were filed in September 2016 and the proceeding is scheduled forpending.
Utility Operating Company Termination of System Agreement Participation
Entergy Arkansas and Entergy Mississippi ceased participating in the System Agreement effective December 18, 2013 and November 7, 2015, respectively. Entergy Louisiana, Entergy New Orleans, and Entergy Texas terminated participation in the System Agreement on August 31, 2016, which resulted in the termination of the System Agreement in its entirety pursuant to a settlement agreement approved by the FERC in December 2015.
In December 2013 the FERC set one issue for hearing involving whether and how the benefits associated with settlement with Union Pacific regarding certain coal delivery issues should be allocated among Entergy Arkansas and the other Utility operating companies post-termination of the System Agreement. In December 2014 a FERC ALJ issued an initial decision finding that Entergy Arkansas would realize benefits after December 18, 2013 from the 2008 settlement agreement between Entergy Services, Entergy Arkansas, and Union Pacific, related to certain coal delivery issues. The ALJ further found that all of the Utility operating companies should share in those benefits pursuant to a methodology proposed by the MPSC. The Utility operating companies and other parties to the proceeding filed briefs on exceptions and/or briefs opposing exceptions with the FERC challenging various aspects of the December 2014 initial decision. In March 2016 the FERC issued an opinion affirming the December 2014 initial decision with regard to the determination that there were benefits related to the Union Pacific settlement, which were realized post-Entergy Arkansas’s December 2013 withdrawal from the System Agreement, that should be shared with the other Utility operating companies utilizing the methodology proposed by the MPSC and trued-up to actual coal volumes purchased. In May 2016, Entergy made a compliance filing that provided the calculation of Union Pacific settlement benefits utilizing the methodology adopted by the initial decision, trued-up for the actual volumes of coal purchased. The payments were made in May 2016. In August 2016 the FERC issued an order accepting Entergy’s compliance filing. Also in August 2016 the APSC filed a petition for review of the FERC’s March 2016 and August 2016 orders with the U.S. Court of Appeals for the D.C. Circuit. Oral argument before the D.C. Circuit was held on the APSC’s petition in January 2018 and a decision is pending.
In connection with the System Agreement termination settlement agreement, the purchase power agreements, referred to as the jurisdictional separation plan PPAs, between Entergy Texas and Entergy Gulf States Louisiana that were put in place for certain legacy gas units at the time of Entergy Gulf States’s separation into Entergy Texas and Entergy Gulf States Louisiana terminated effective with the System Agreement termination. Similarly, the purchase power agreement between Entergy Gulf States Louisiana and Entergy Texas for the Calcasieu unit also terminated. In
Entergy Corporation and Subsidiaries
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March 2016, Entergy Services filed with the FERC the notices of termination. The jurisdictional separation plan PPAs were the means by which Entergy Texas received payment for its receivable associated with Entergy Louisiana’s Spindletop gas storage facility regulatory asset. As a result of the System Agreement termination settlement agreement, effective with the termination date, Entergy Texas no longer receives payments from Entergy Louisiana related to the Spindletop storage facility, which resulted in a write-off recorded in 2015 by Entergy Texas of $23.5 million ($15.3 million net-of-tax). Upon termination of the System Agreement, other purchase power agreements entered into under Service Schedule MSS-4 of the System Agreement were replaced with updated agreements under a FERC-jurisdictional tariff effective September 1, 2016.
Interruptible Load Proceeding
In April 2007 the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads. In its opinion the D.C. Circuit concluded that the FERCFERC: (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time. The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds. The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change. In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996. In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC’s orders. The LPSC filed a protest to the refund report in December 2007, and the Utility operating companies filed an answer to the protest in January 2008. The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due a refundrefunds under the decision. The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit. The refunds were made in the fourth quarter 2009.
Following the filing of petitioners’ initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC. The D.C. Circuit granted the FERC’s unopposed motion in June 2009. In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate
Entergy Corporation and Subsidiaries
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to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies. In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate. The APSC, the MPSC, and Entergy requested rehearing of the FERC’s decision. In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds. The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.” The LPSC has requested rehearing of the FERC’s June 2011 decision. In July 2011 the refunds made in the fourth quarter 2009 described above were reversed. In October 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding. Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs arewere due. Briefs were submitted and the matter is pending.
In September 2010 the FERC had issued an order setting the refund report filed in the proceeding in November 2007 for hearing and settlement judge procedures. In May 2011, Entergy filed a settlement agreement that resolved all issues relating to the refund report set for hearing. In June 2011 the settlement judge certified the settlement as uncontested and theuncontested. The settlement agreement is currently pending before the FERC. In July 2011, Entergy filed an amended/corrected refund report and a motion to defer action on the settlement agreement until afterwas approved by the FERC rules on the LPSC’s rehearing request regarding the June 2011 decision denying refunds.in September 2016.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Prior to the FERC’s June 2011 order on rehearing, Entergy Arkansas filed an application in November 2010 with the APSC for recovery of the refund that it paid. The APSC denied Entergy Arkansas’s application, and also denied Entergy Arkansas’s petition for rehearing. If the FERC were to order Entergy Arkansas to pay refunds on rehearing in the interruptible load proceeding the APSC’s decision would trap FERC-approved costs at Entergy Arkansas with no regulatory-approved mechanism to recover them. In August 2011, Entergy Arkansas filed a complaint in the United States District Court for the Eastern District of Arkansas asking for a declaratory judgment that the rejection of Entergy Arkansas’s application by the APSC is preempted by the Federal Power Act. The APSC filed a motion to dismiss the complaint. In April 2012 the United States district court dismissed Entergy Arkansas’s complaint without prejudice stating that Entergy Arkansas’s claim is not ripe for adjudication and that Entergy Arkansas did not have standing to bring suit at this time.
In March 2013 the FERC issued an order denying the LPSC’s request for rehearing of the FERC’s June 2011 order wherein the FERC concluded it would exercise its discretion and not order refunds in the interruptible load proceeding. Based on its review of the LPSC’s request for rehearing and the briefs filed as part of the paper hearing established in October 2011, the FERC affirmed its earlier ruling and declined to order refunds under the circumstances of the case. In May 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking review of FERC prior orders in the Interruptible Load Proceedinginterruptible load proceeding that concluded that the FERC would exercise its discretion and not order refunds in the proceeding. Oral argument was held on the appeal in the D.C. Circuit in September 2014. In December 2014 the D.C. Circuit issued an order on the LPSC’s appeal and remanded the case back to the FERC. The D.C. Circuit rejected the LPSC’s argument that there is a presumption in favor of refunds, but it held that the FERC had not adequately explained its decision to deny refunds and directed the FERC “to consider the relevant factors and weigh them against one another.” In March 2015, Entergy filed with the FERC a motion to establish a briefing schedule on remand and an initial brief on remand to address the December 2014 decision by the D.C. Circuit. The initial brief on remand argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in the interruptible load proceeding.
In April 2016 the FERC issued an order on remand that addressed the December 2014 decision by the D.C. Circuit in the interruptible load proceeding. The order on remand affirmed the FERC’s denial of refunds for the 15-month refund effective period. The FERC explained and clarified its policies regarding refunds and concluded that the evidence in the record demonstrated that the relevant equitable factors favored not requiring refunds in this case. The FERC also noted that, under Section 206(c) of the Federal Power Act, in a Section 206 proceeding involving two or more electric utility companies of a registered holding company system, the FERC may order refunds only if it determines the refunds would not cause the registered holding company to experience any reduction in revenues resulting from an inability of an electric utility company in the system to recover the resulting increase in costs. The FERC stated it was not able to find that the Entergy system would not experience a reduction in revenues if refunds were awarded in this proceeding, which further supported the denial of refunds. In May 2016 the LPSC filed a request for rehearing of the FERC’s April 2016 order. In September 2016 the FERC issued an order denying the LPSC’s request for rehearing and reaffirming its denial of refunds for the 15-month refund effective period. The LPSC has appealed the April and September 2016 orders to the U.S. Court of Appeals for the D.C. Circuit. Oral argument before the D.C. Circuit was held before the D.C. Circuit in February 2018 and a decision is pending.
Entergy Arkansas Opportunity Sales Proceeding
In June 2009 the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocateallocated the energy generated by Entergy System resources,resources; (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity,capacity; and (c) violated the provision of the System Agreement that prohibitsprohibited sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challengeschallenged sales made beginning in 2002 and requestsrequested refunds. In July 2009 the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System. In their response,
Entergy Corporation and Subsidiaries
Notes to Financial Statements
the Utility operating companies explained that the System Agreement clearly contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The response further explained thatFERC subsequently ordered a hearing in the FERC already had determined that Entergy Arkansas’s short-term wholesale sales did not trigger the “right-of-first-refusal” provision of the System Agreement. While the D.C. Circuit recently determined that the “right-of-first-refusal” issue was not properly before the FERC at the time of its earlier decision on the issue, the LPSC raised no additional claims or facts that would warrant the FERC reaching a different conclusion.proceeding.
The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies’ customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies’ customers and these customers should be compensated for this harm by Entergy. In subsequent testimony, the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills. The Utility operating companies believe the LPSC’s allegations are without merit. A hearing in the matter was held in August 2010.
In December 2010 the ALJ issued an initial decision. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load, but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. Quantifying the effect of the FERC’s decision will requirerequires re-running intra-system bills for a ten-year period, and the FERC in its decision established further hearing procedures to determine the calculation of the effects. In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision, which are pending with the FERC.
As required by the procedural schedule established in the calculation proceeding, Entergy filed its direct testimony that included a proposed illustrative re-run, consistent with the directives in FERC’s order, of intra-system bills for 2003, 2004, and 2006, the three years with the highest volume of opportunity sales. Entergy’s proposed illustrative re-run of intra-system bills shows that the potential cost for Entergy Arkansas would be up to $12 million for the years 2003, 2004, and 2006, excluding interest, and the potential benefit would be significantly less than that for each of the other Utility operating companies. Entergy’s proposed illustrative re-run of the intra-system bills also shows an offsetting potential benefit to Entergy Arkansas for the years 2003, 2004, and 2006 resulting from the effects of the FERC’s order on System Agreement Service Schedules MSS-1, MSS-2, and MSS-3, and the potential offsetting cost would be significantly less than that for each of the other Utility operating companies. Entergy provided to the LPSC an illustrative intra-system bill recalculation as specified by the LPSC for the years 2003, 2004, and 2006, and the LPSC then filed answering testimony in December 2012. In its testimony the LPSC claims that the damages, excluding interest, that should be paid by Entergy Arkansas to the other Utility operating company’s customers for 2003, 2004, and 2006 are $42 million to Entergy Gulf States, Inc., $7 million to Entergy Louisiana, $23 million to Entergy Mississippi, and $4 million to Entergy New Orleans. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. In April 2013, Entergy filed its rebuttal testimony in that proceeding, including a revised illustrative re-run of the intra-system bills for the years 2003, 2004, and 2006. The revised calculation
Entergy Corporation and Subsidiaries
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determines the re-pricing of the opportunity sales based on consideration of moveable resources only and the removal of exchange energy received by Entergy Arkansas, which increases the potential cost for Entergy Arkansas over the three years 2003, 2004, and 2006 by $2.3 million from the potential costs identified in the Utility operating companies’ prior filings in September and October 2012.decision. A hearing was held in May 2013 to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision.
In August 2013 the presiding judge issued an initial decision in the calculation proceeding. The initial decision concludesconcluded that the methodology proposed by the LPSC, rather than the methodologies proposed by Entergy or the FERC Staff, should be used to calculate the payments that Entergy Arkansas is to make to the other Utility operating companies. The initial decision also concludesconcluded that the other System Agreement service schedules should not be adjusted and that payments by Entergy Arkansas should not be reflected in the rough production cost equalization bandwidth calculations for the applicable years. The initial decision does recognizerecognized that the LPSC’s methodology would result in an inequitable windfall to the other Utility operating companies and, therefore, concludesconcluded that any payments by Entergy Arkansas should be reduced by 20%. The LPSC, the APSC, the City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that the FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.
In April 2016 the FERC issued orders addressing requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denied Entergy’s request for rehearing and affirmed the FERC’s earlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s August 2013 initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed, but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service
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schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account, but ordered further proceedings before an ALJ to address whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.
In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order arguing that payments made by Entergy Arkansas should be reduced as a result of the timing of the LPSC’s approval of certain contracts. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. In September 2017 the FERC issued an order denying the request for rehearing on the issue of whether any payments by Entergy Arkansas to the other Utility operating companies should be reduced due to the timing of the LPSC’s approval of Entergy Arkansas’s wholesale baseload contract with Entergy Louisiana. In November 2017 the FERC issued an order denying all of the remaining requests for rehearing of the April 2016 order. In November 2017, Entergy Services filed a petition for review in the D.C. Circuit of the FERC’s orders in the first two phases of the opportunity sales case. In December 2017 the D.C. Circuit granted Entergy Services’s request to hold the appeal in abeyance pending final resolution of the related proceeding still pending with the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services’s appeal and held all of the appeals in abeyance.
Pursuant to the procedural schedule established in the case, Entergy Services re-ran intra-system bills for the ten-year period 2000-2009 to quantify the effects of the FERC's ruling. In November 2016 the LPSC submitted testimony disputing certain aspects of the calculations. A hearing was held in May 2017. In July 2017, the ALJ issued an initial decision concluding that Entergy Arkansas should pay $86 million plus interest to the other Utility operating companies. In August 2017 the Utility operating companies, the LPSC, the APSC, and FERC staff filed individual briefs on exceptions challenging various aspects of the initial decisiondecision. In September 2017 the Utility operating companies, the LPSC, the APSC, the MPSC, the City Council, and FERC staff filed separate briefs opposing exceptions taken by various parties. The case is pending.pending before the FERC. No payments will be made or received by the Utility operating companies until the FERC issues an order reviewing the initial decision and Entergy submits a subsequent filing to comply with that order.
The effect of the FERC’s decisions thus far in the case would be that Entergy Arkansas will make payments to some or all of the other Utility operating companies. Because further proceedings will still occur in the case, the amount and recipients of payments by Entergy Arkansas are unknown at this time. Based on testimony previously submitted in the case and its assessment of the April 2016 FERC orders, in the first quarter 2016, Entergy Arkansas recorded a liability of $87 million, which includes interest, for its estimated increased costs and payment to the other Utility operating companies. This estimate is subject to change depending on how the FERC resolves the issues that are still outstanding in the case, including its review of the July 2017 initial decision. Entergy Arkansas’s increased costs will be attributed to Entergy Arkansas’s retail and wholesale businesses, and it is not probable that Entergy Arkansas will recover the wholesale portion. Entergy Arkansas, therefore, recorded a deferred fuel regulatory asset in the first quarter 2016 of approximately $75 million, which represents its estimate of the retail portion of the costs. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in November 2017 described above, in the fourth quarter 2017, Entergy Arkansas recorded an additional liability of $35 million and a regulatory asset of $31 million. Because management currently expects to recover the retail portion of the costs through a base rate proceeding or newly proposed rider, the regulatory asset is reflected as Other regulatory assets as of December 31, 2017.
Complaint Against System Energy
In January 2017 the APSC and MPSC filed a complaint with the FERC against System Energy. The complaint seeks a reduction in the return on equity component of the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Entergy Arkansas also sells some of its Grand Gulf capacity and energy to Entergy Louisiana,
Entergy Corporation and Subsidiaries
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Entergy Mississippi, and Entergy New Orleans under separate agreements. The current return on equity under the Unit Power Sales Agreement is 10.94%. The complaint alleges that the return on equity is unjust and unreasonable because current capital market and other considerations indicate that it is excessive. The complaint requests the FERC to institute proceedings to investigate the return on equity and establish a lower return on equity, and also requests that the FERC establish January 23, 2017 as a refund effective date. The complaint includes return on equity analysis that purports to establish that the range of reasonable return on equity for System Energy is between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputes that a return on equity of 8.37% to 8.67% is just and reasonable. The LPSC and the City Council intervened in the proceeding expressing support for the complaint. System Energy is recording a provision against revenue for the potential outcome of this proceeding. In September 2017 the FERC established a refund effective date of January 23, 2017, consolidated the return on equity complaint with the proceeding described in Unit Power Sales Agreement below, and directed the parties to engage in settlement proceedings before an ALJ. If the parties fail to come to an agreement during settlement proceedings, a prehearing conference will be held to establish a procedural schedule for hearing proceedings.
Unit Power Sales Agreement
In August 2017, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The filing proposes limited amendments to the Unit Power Sales Agreement to adopt (1) updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses and (2) updated nuclear decommissioning cost annual revenue requirements, both of which are recovered through the Unit Power Sales Agreement rate formula. The proposed amendments would result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The proposed changes are based on updated depreciation and nuclear decommissioning studies that take into account the renewal of Grand Gulf’s operating license for a term through November 1, 2044. System Energy requested that the FERC accept the amendments effective October 1, 2017.
In September 2017 the FERC accepted System Energy’s proposed Unit Power Sales Agreement amendments, subject to further proceedings to consider the justness and reasonableness of the amendments. Because the amendments propose a rate decrease, the FERC also initiated an investigation under Section 206 of the Federal Power Act to determine if the rate decrease should be lower than proposed. The FERC accepted the proposed amendments effective October 1, 2017, subject to refund pending the outcome of the further settlement and/or hearing proceedings, and established a refund effective date of October 11, 2017 with respect to the rate decrease. The FERC also consolidated the Unit Power Sales Agreement amendment proceeding with the proceeding described in Complaint Against System Energy above, and directed the parties to engage in settlement proceedings before an ALJ. If the parties fail to come to an agreement during settlement proceedings, a prehearing conference will be held to establish a procedural schedule for hearing proceedings.
Storm Cost Recovery Filings with Retail Regulators
Entergy Arkansas
Entergy Arkansas December 2012 Winter Storm
In December 2012 a severe winter storm consisting of ice, snow, and high winds caused significant damage to Entergy Arkansas’s distribution lines, equipment, poles, and other facilities. Total restoration costs for the repair and/or replacement of Entergy Arkansas’s electrical facilities in areas damaged from the winter storm were $63 million, including costs recorded as regulatory assets of approximately $22 million. In the Entergy Arkansas 2013 rate case, the APSC approved inclusion of the construction spending in rate base and approved an increase in the normal storm cost accrual, which will effectively amortize the regulatory asset over a five-year period.
Entergy Gulf States Louisiana and Entergy Louisiana
Hurricane Isaac
In August 2012, Hurricane Isaac caused extensive damage to portions of Entergy’sEntergy Louisiana’s service area in Louisiana, and to a lesser extent in Mississippi and Arkansas.area. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. In January 2013, Entergy Gulf States Louisiana and Entergy Louisiana drew $65 million and $187 million, respectively, from their funded storm reserve escrow accounts. In April 2013, Entergy Gulf States Louisiana and Entergy Louisiana filed a joint application withJune 2014 the LPSC relating to Hurricane Isaac system restoration costs. Specifically, Entergy Gulf States Louisiana and Entergy Louisiana requested that the LPSC determine the amount of such costs that were prudently incurred and are, thus, eligible for recovery from customers. Including carrying costs and additional storm escrow funds for prior storms, Entergy Gulf States Louisiana requested an LPSC determination that $73.8 million in system restoration costs were prudently incurred and Entergy Louisiana requested an LPSC determination that $247.7 million in system restoration costs were prudently incurred. In May 2013, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana's and Entergy Louisiana's storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane
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Isaac system restoration costs incurred by Entergy Gulf States Louisiana and Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of each company’s costs. Following an evidentiary hearing and recommendations by the ALJ, the LPSC voted in June 2014 to approve a series of orders which (i) quantify the amount of Hurricane Isaac system restoration costs prudently incurred ($66.5 million for Entergy Gulf States Louisiana and $224.3 million for Entergy Louisiana); (ii) determine the level of storm reserves to be re-established ($90 million for Entergy Gulf States Louisiana and $200 million for Entergy Louisiana); (iii) authorize Entergy Gulf States Louisiana andauthorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) grant other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Gulf States Louisiana committed to pass on to customers a minimum of $6.9 million of customer benefits through annual customer credits of approximately $1.4 million for five years. Entergy Louisiana committed to pass on to customers a minimum of $23.9$30.8 million of customer benefits through annual customer credits of approximately $4.8$6.2 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.
In July 2014,
Entergy Gulf States Louisiana issued $110 million of 3.78% Series first mortgage bonds due April 2025Corporation and used the proceedsSubsidiaries
Notes to re-establish and replenish its storm damage escrow reserves and for general corporate purposes. In July 2014, Entergy Louisiana issued $190 million of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.Financial Statements
In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $71$314.85 million in bonds under Louisiana Act 55 of the Louisiana Legislature.55. From the $69$309 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $3$16 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $66$293 million directly to Entergy Gulf States Louisiana. Entergy Gulf States Louisiana used the $66$293 million received from the LURC to acquire 662,426.802,935,152.69 Class C preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 7.5% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2014, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1.75 billion.
In August 2014 the LCDA issued another $243.85 million in bonds under Act 55 of the Louisiana Legislature. From the $240 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $13 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $227 million directly to Entergy Louisiana. Entergy Louisiana used the $227 million received from the LURC to acquire 2,272,725.89 Class C preferred, non-voting, membership interest units of Entergy Holdings Company LLC that carry a 7.5% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2014, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1.75 billion.
Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy Entergy Gulf States Louisiana, or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collectcollects a system restoration charge on behalf of the LURC, and remitremits the collections to the bond indenture trustee. Entergy Entergy Gulf States Louisiana, and Entergy Louisiana do not report the collections as revenue because they areEntergy Louisiana is merely acting as the billing and collection agentsagent for the state.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Hurricane Gustav and Hurricane Ike
In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy’sEntergy Louisiana’s service territory. Entergy Gulf States Louisiana and Entergy Louisiana filed their Hurricane Gustav and Hurricane Ike storm cost recovery case with the LPSC in May 2009. In September 2009, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Act 55).Entergy Gulf States Louisiana’s and Entergy Louisiana’s Hurricane Katrina and Hurricane Rita storm costs were financed primarily by Act 55 financings, as discussed below. Entergy Gulf States Louisiana and Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and Act 55 financing savings to customers via a Storm Cost Offset rider.
In December 2009, Entergy Gulf States Louisiana and Entergy Louisiana entered into a stipulation agreement with the LPSC Staff that provides for total recoverable costs of approximately $234 million for Entergy Gulf States Louisiana and $394 million for Entergy Louisiana, including carryingstaff regarding its storm costs. Under this stipulation, Entergy Gulf States Louisiana agrees not to recover $4.4 million and Entergy Louisiana agrees not to recover $7.2 million of their storm restoration spending. The stipulation also permits replenishing Entergy Gulf States Louisiana’s storm reserve in the amount of $90 million and Entergy Louisiana’s storm reserve in the amount of $200 million when the Act 55 financings are accomplished. In March and April 2010, Entergy Gulf States Louisiana, Entergy Louisiana and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that includes these terms and also includes Entergy Gulf States Louisiana’s andincluded Entergy Louisiana’s proposals under theproposal to utilize Act 55 financings,financing, which includesincluded a commitment to pass on to customers a minimum of $15.5 million and $27.8$43.3 million of customer benefits respectively, through a prospective annual rate reductionsreduction of $3.1 million and $5.6$8.7 million for five years. A stipulation hearing was held before the ALJ onIn April 13, 2010. On April 21, 2010 the LPSC approved the settlement and subsequently issued two financing orders and onea ratemaking order intended to facilitate the implementation of the Act 55 financings. In June 2010 the Louisiana State Bond Commission approved the Act 55 financings.financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricane Gustav and Hurricane Ike was reduced by $2.7 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.
In July 2010, the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA)LCDA issued $468.9two series of bonds totaling $713.0 million in bonds under Act 55. From the $462.4$702.7 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $200$290 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $262.4$412.7 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana used $262.4$412.7 million to acquire 2,624,297.114,126,940.15 Class B preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2010, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
In July 2010, the LCDA issued another $244.1 million in bonds under Act 55. From the $240.3 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $90 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $150.3 million directly to Entergy Gulf States Louisiana. From the bond proceeds received by Entergy Gulf States Louisiana from the LURC, Entergy Gulf States Louisiana used $150.3 million to acquire 1,502,643.04 Class B preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2010, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy Entergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collectcollects a system restoration charge on behalf of the LURC, and remitremits the collections to the bond indenture trustee. Entergy Gulf States Louisiana and Entergy Louisiana do not report the collections as revenue because they areEntergy Louisiana is merely acting as the billing and collection agentsagent for the state.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Hurricane Katrina and Hurricane Rita
In August and September 2005, Hurricanes Katrina and Rita caused catastrophic damage to large portions of the Utility’sEntergy Louisiana’s service territories in Louisiana, Mississippi, and Texas, including the effect of extensive flooding that resulted from levee breaks in and around the greater New Orleans area. The storms and flooding resulted in widespread power outages, significant damage to electric distribution, transmission, and generation and gas infrastructure, and the loss of sales and customers due to mandatory evacuations and the destruction of homes and businesses.
territory. In March 2008, Entergy Gulf States Louisiana, Entergy Louisiana and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana,LURC filed at the LPSC an application requesting that the LPSC grant a financing ordersorder authorizing the financing of Entergy Gulf States Louisiana and Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 55. The Louisiana Act 55 of the Louisiana Legislature (Act 55 financings). The Act 55 financings arefinancing is expected to produce additional customer benefits as compared to traditional securitization. Entergy Gulf States Louisiana and Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a Storm Cost Offsetstorm cost offset rider. OnIn April 8, 2008 the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financings,financing, approved requests for the Act 55 financings. Onfinancing. Also in April 10, 2008, Entergy Gulf States Louisiana and Entergy Louisiana and the LPSC Staffstaff filed with the LPSC an uncontested stipulated settlement that includes Entergy Gulf States Louisiana andincluded Entergy Louisiana’s proposalsproposal under the Act 55 financings,financing, which includesincluded a commitment to pass on to customers a minimum of $10 million and $30$40 million of customer benefits respectively, through a prospective annual rate reductionsreduction of $2 million and $6$8 million for five years. On April 16, 2008, theThe LPSC subsequently approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financings.financing. In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financings.financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricanes Katrina and Rita was reduced by $22.3 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.
In July 2008 the LPFA issued $687.7 million in bonds under the aforementioned Act 55. From the $679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 10% annual distribution rate. In August 2008, the LPFA issued $278.4 million in bonds under the aforementioned Act 55. From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $187.7 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC that carry a 10% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2008 and have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
In August 2008, the LPFA issued $278.4 million in bonds under the aforementioned Act 55. From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $187.7 million directly to Entergy Gulf States Louisiana. From the bond proceeds received by Entergy Gulf States Louisiana from the LURC, Entergy Gulf States Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC that carry a 10% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2008 and have a liquidation price of $100 per unit. The preferred
Entergy Corporation and Subsidiaries
Notes to Financial Statements
membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion. In February 2012, Entergy Gulf States Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company LLC, a wholly-owned Entergy subsidiary, to a third party in exchange for $51 million plus accrued but unpaid distributions on the units. The 500,000 preferred membership units are mandatorily redeemable in January 2112.
Entergy Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds issued by the LPFA on their balance sheets because the bonds are the obligation of the LPFA, and there is no recourse against Entergy Entergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collectcollects a system restoration charge on behalf of the LURC, and remitremits the collections to the bond indenture trustee. Entergy Entergy Gulf States Louisiana, and Entergy Louisiana do not report the collections as revenue because they areEntergy Louisiana is merely acting as the billing and collection agent for the state.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Mississippi
On July 1, 2013, Entergy Mississippi andhas approval from the Mississippi Public Utilities Staff entered intoMPSC to collect a joint stipulation, wherein both parties agreed that approximately $32storm damage provision of $1.75 million inper month. If Entergy Mississippi’s accumulated storm restoration costs incurred in 2011 and 2012 were prudently incurred and chargeable todamage provision balance exceeds $15 million, the collection of the storm damage provision while approximately $700,000 in prudently incurred costs were more properly recoverable through the formula rate plan. Entergy Mississippi and the Mississippi Public Utilities Staff also agreedceases until such time that the accumulated storm damage accrual should be increased from $750,000 per month to $1.75 million per month. In September 2013 the MPSC approved the joint stipulation with the increase in the storm damage accrual effective with October 2013 bills. In February 2015, Entergy Mississippi provided notice to the Mississippi Public Utilities Staff that the storm damage accrual would be set to zero effective with the March 2015 billing cycle as a result of Entergy Mississippi's storm damage accrual balance exceeding $15 million as of January 31, 2015, but will return to its current level when the storm damage accrual balanceprovision becomes less than $10 million. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance again exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with November 2016 bills. As of July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision was again less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with September 2017 bills.
Entergy New Orleans
In October 2006, the City Council approved a rate filing settlement agreement that, among other things, authorized a $75 million storm reserve for damage from future storms, which will be created over a ten-year period through a storm reserve rider that began in March 2007. These storm reserve funds are held in a restricted escrow account until needed in response to a storm.
In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair and/or replacement of Entergy New Orleans’s electric facilities damaged by Hurricane Isaac were $47.3 million. Entergy New Orleans withdrew $17.4 million from the storm reserve escrow account to partially offset these costs. In February 2014, Entergy New Orleans made a filing with the City Council seeking certification of the Hurricane Isaac costs. In January 2015 the City Council issued a resolution approving the terms of a joint agreement in principle filed by Entergy New Orleans, Entergy Louisiana, and the City Council Advisors determining, among other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, of which $31.7 million, net of reimbursements from the storm reserve escrow account, remainsremained recoverable from Entergy New Orleans’s electric customers. The resolution also directsdirected Entergy New Orleans to file an application to securitize the unrecovered City Council-approved storm recovery costs of $31.7 million pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64). In addition, the resolution found that it iswas reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achievesachieved the City Council-approved funding level of $75 million. In January 2015, in compliance with that directive, Entergy New Orleans filed with the City Council an application requesting that the City Council grant a financing order authorizing the financing of Entergy New Orleans'sOrleans’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 64.
$98.7 million, including $31.8 million for recovery of Entergy CorporationNew Orleans’s Hurricane Isaac storm recovery costs, including carrying costs, $63.9 million to fund and Subsidiaries
Notesreplenish Entergy New Orleans’s storm reserve, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to Financial Statementsthe financial statements for discussion of the issuance of the securitization bonds in July 2015.
New Nuclear Generation Development Costs
Entergy Gulf States Louisiana and Entergy Louisiana
Entergy Louisiana and Entergy Gulf States Louisiana and Entergy Louisiana have beenwere developing and are preserving a project option for new nuclear generation at River Bend. In March 2010, Entergy Gulf States Louisiana and Entergy Gulf States Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend. At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Gulf States Louisiana and Entergy Gulf States Louisiana be declined on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification. The LPSC directed that Entergy Gulf States Louisiana and Entergy Gulf States Louisiana be permitted to seek recovery of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2014, Entergy Gulf States Louisiana and2017, Entergy Louisiana each havehas a regulatory asset of $29.2$35.8 million on its balance sheet related to these new nuclear generation development costs.
Entergy Mississippi
Pursuant to the Mississippi Baseload Act and the Mississippi Public Utilities Act, Entergy Mississippi had been developing and preserving a project option for new nuclear generation at Grand Gulf Nuclear Station. In October 2010, Entergy Mississippi filed an application with the MPSC requesting that the MPSC determine that it was in the public interest to preserve the option to construct new nuclear generation at Grand Gulf and that the MPSC approve the deferral of Entergy Mississippi’s costs incurred to date and in the future related to this project, including the accrual of AFUDC or similar carrying charges. In October 2011, Entergy Mississippi and the Mississippi Public Utilities Staff filed with the MPSC a joint stipulation that the MPSC approved in November 2011. The stipulation stated that there should be a deferral of the $57 million of costs incurred through September 2011 in connection with planning, evaluation, monitoring, and other and related generation resource development activities for new nuclear generation at Grand Gulf.
In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations in Entergy Mississippi’s general rate case proceeding, which are discussed above. In consideration of the comprehensive terms for settlement in that rate case proceeding, the Mississippi Public Utilities Staff and Entergy Mississippi agreed that Entergy Mississippi would request consolidation of the new nuclear generation development costs proceeding with the rate case proceeding for hearing purposes and will not further pursue, except as noted below, recovery of the costs deferred by MPSC order in the new nuclear generation development docket. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. After considering the progress of the new nuclear generation costs proceeding in light of the joint stipulations, Entergy Mississippi recorded in 2014 a $56.2 million pre-tax charge to recognize that the regulatory asset associated with new nuclear generation development is no longer probable of recovery. In December 2014 the MPSC issued an order accepting in their entirety the October 2014 stipulations, including the findings and terms of the stipulations regarding new nuclear generation development costs.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Texas Power Price Lawsuit
In August 2003, a lawsuit was filed in the district court of Chambers County, Texas by Texas residents on behalf of a purported class of the Texas retail customers of Entergy Gulf States, Inc. who were billed and paid for electric power from January 1, 1994 to the present. The named defendants include Entergy Corporation, Entergy Services, Entergy Power, Entergy Power Marketing Corp., and Entergy Arkansas. Entergy Gulf States, Inc. was not a named defendant, but was alleged to be a co-conspirator. The court granted the request of Entergy Gulf States, Inc. to intervene in the lawsuit to protect its interests.
Plaintiffs allege that the defendants implemented a “price gouging accounting scheme” to sell to plaintiffs and similarly situated utility customers higher priced power generated by the defendants while rejecting less expensive power offered from off-system suppliers. In particular, plaintiffs allege that the defendants manipulated and continue to manipulate the dispatch of generation so that power is purchased from affiliated expensive resources instead of buying cheaper off-system power.
Plaintiffs stated in their pleadings that customers in Texas were charged at least $57 million above prevailing market prices for power. Plaintiffs seek actual, consequential and exemplary damages, costs and attorneys’ fees, and disgorgement of profits. The plaintiffs’ experts have tendered a report calculating damages in a large range, from $153 million to $972 million in present value, under various scenarios as of the date of the report. The Entergy defendants have tendered expert reports challenging the assumptions, methodologies, and conclusions of the plaintiffs’ expert reports.
In March 2012 the state district court found that the case met the requirements to be maintained as a class action under Texas law. In April 2012 the court entered an order certifying the class. The defendants appealed the order to the Texas Court of Appeals – First District and oral argument was held in May 2013. In November 2014 the Texas Court of Appeals - First District reversed the state district court’s class certification order and dismissed the case holding that the state district court lacked subject matter jurisdiction to address the issues. Plaintiffs filed a motion for rehearing and a motion for rehearing en banc. The Entergy defendants filed responsive briefings, and the parties are awaiting rulings by the Court.
NOTE 3. INCOME TAXES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Income taxes from continuing operations for 2014, 2013,2017, 2016, and 20122015 for Entergy Corporation and Subsidiaries consist of the following:
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| | (In Thousands) | (In Thousands) |
| Current: | | | | | | | | | | |
| Federal |
| $90,061 |
| |
| $88,291 |
| |
| ($47,851 | ) |
| $29,595 |
| |
| $45,249 |
| |
| $77,166 |
|
| Foreign | 90 |
| | 101 |
| | 143 |
| — |
| | 68 |
| | 97 |
|
| State | (12,637 | ) | | 20,584 |
| | (41,516 | ) | 15,478 |
| | (14,960 | ) | | 157,829 |
|
| Total | 77,514 |
| | 108,976 |
| | (89,224 | ) | 45,073 |
| | 30,357 |
| | 235,092 |
|
| Deferred and non-current - net | 528,326 |
| | 126,935 |
| | 131,130 |
| 505,010 |
| | (840,465 | ) | | (864,799 | ) |
| Investment tax credit adjustments - net | (16,243 | ) | | (9,930 | ) | | (11,051 | ) | (7,513 | ) | | (7,151 | ) | | (13,220 | ) |
| Income tax expense from continuing operations |
| $589,597 |
| |
| $225,981 |
| |
| $30,855 |
| |
| Income taxes | |
| $542,570 |
| |
| ($817,259 | ) | |
| ($642,927 | ) |
Income taxes for 2017, 2016, and 2015 for Entergy’s Registrant Subsidiaries consist of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2017 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Current: | | | | | | | | | | | | |
| Federal | |
| $16,086 |
| |
| ($84,250 | ) | |
| ($8,845 | ) | |
| ($30,635 | ) | |
| $6,034 |
| |
| $47,674 |
|
| State | | 9,191 |
| | 1,480 |
| | (924 | ) | | (728 | ) | | 310 |
| | 5,314 |
|
| Total | | 25,277 |
| | (82,770 | ) | | (9,769 | ) | | (31,363 | ) | | 6,344 |
| | 52,988 |
|
| Deferred and non-current - net | | 69,753 |
| | 572,988 |
| | 83,501 |
| | 62,946 |
| | 43,102 |
| | 19,243 |
|
| Investment tax credit adjustments - net | | (1,226 | ) | | (4,920 | ) | | 187 |
| | 1,695 |
| | (965 | ) | | (2,262 | ) |
| Income taxes | |
| $93,804 |
| |
| $485,298 |
| |
| $73,919 |
| |
| $33,278 |
| |
| $48,481 |
| |
| $69,969 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2016 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Current: | | | | | | | | | | | | |
| Federal | |
| ($14,748 | ) | |
| ($124,113 | ) | |
| $10,603 |
| |
| ($91,067 | ) | |
| $19,656 |
| |
| $29,628 |
|
| State | | 2,805 |
| | 10,757 |
| | 2,257 |
| | 566 |
| | 1,374 |
| | (25,825 | ) |
| Total | | (11,943 | ) | | (113,356 | ) | | 12,860 |
| | (90,501 | ) | | 21,030 |
| | 3,803 |
|
| Deferred and non-current - net | | 120,942 |
| | 208,157 |
| | 46,984 |
| | 119,345 |
| | 42,982 |
| | 71,051 |
|
| Investment tax credit adjustments - net | | (1,226 | ) | | (5,067 | ) | | 4,010 |
| | (139 | ) | | (915 | ) | | (3,793 | ) |
| Income taxes | |
| $107,773 |
| |
| $89,734 |
| |
| $63,854 |
| |
| $28,705 |
| |
| $63,097 |
| |
| $71,061 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Income taxes for 2014, 2013, and 2012 for Entergy’s Registrant Subsidiaries consist of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2014 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Current: | | | | | | | | | | | | | | |
| Federal | |
| ($34,258 | ) | |
| ($3,857 | ) | |
| ($41,052 | ) | |
| $8,103 |
| |
| ($1,924 | ) | |
| $48,610 |
| |
| $19,908 |
|
| State | | (678 | ) | | (769 | ) | | (422 | ) | | 7,474 |
| | 520 |
| | 4,877 |
| | 15,379 |
|
| Total | | (34,936 | ) | | (4,626 | ) | | (41,474 | ) | | 15,577 |
| | (1,404 | ) | | 53,487 |
| | 35,287 |
|
| Deferred and non-current - net | | 119,841 |
| | 96,446 |
| | 140,348 |
| | 42,305 |
| | 13,952 |
| | (2,418 | ) | | 53,501 |
|
| Investment tax credit adjustments - net | | (1,276 | ) | | (3,038 | ) | | (2,604 | ) | | (2,172 | ) | | (224 | ) | | (1,425 | ) | | (5,478 | ) |
| Income taxes | |
| $83,629 |
| |
| $88,782 |
| |
| $96,270 |
| |
| $55,710 |
| |
| $12,324 |
| |
| $49,644 |
| |
| $83,310 |
|
| | | 2013 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2015 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Current: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Federal | |
| ($13,574 | ) | |
| $12,176 |
| |
| ($30,973 | ) | |
| $2,498 |
| |
| $15,017 |
| |
| $37,199 |
| |
| ($6,199 | ) | |
| $66,966 |
| |
| $101,382 |
| |
| $25,628 |
| |
| ($9,346 | ) | |
| $53,313 |
| |
| ($63,302 | ) |
| State | | 6,122 |
| | (9,939 | ) | | (5,692 | ) | | 4,849 |
| | (1,221 | ) | | (843 | ) | | 15,845 |
| | 6,265 |
| | 35,406 |
| | 6,832 |
| | 1,784 |
| | 2,450 |
| | 26,755 |
|
| Total | | (7,452 | ) | | 2,237 |
| | (36,665 | ) | | 7,347 |
| | 13,796 |
| | 36,356 |
| | 9,646 |
| | 73,231 |
| | 136,788 |
| | 32,460 |
| | (7,562 | ) | | 55,763 |
| | (36,547 | ) |
| Deferred and non-current - net | | 101,253 |
| | 57,620 |
| | 121,416 |
| | 41,150 |
| | (11,952 | ) | | (4,639 | ) | | 60,614 |
| | (31,463 | ) | | 47,220 |
| | 31,149 |
| | 32,890 |
| | (17,599 | ) | | 93,491 |
|
| Investment tax credit adjustments - net | | (2,014 | ) | | (3,038 | ) | | (2,874 | ) | | 1,260 |
| | (225 | ) | | (1,609 | ) | | (1,407 | ) | | (1,227 | ) | | (5,337 | ) | | (1,737 | ) | | (138 | ) | | (914 | ) | | (3,867 | ) |
| Income taxes | |
| $91,787 |
| |
| $56,819 |
| |
| $81,877 |
| |
| $49,757 |
| |
| $1,619 |
| |
| $30,108 |
| |
| $68,853 |
| |
| $40,541 |
| |
| $178,671 |
| |
| $61,872 |
| |
| $25,190 |
| |
| $37,250 |
| |
| $53,077 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2012 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Current: | | | | | | | | | | | | | | |
| Federal | |
| $64,069 |
| |
| ($66,081 | ) | |
| ($132,999 | ) | |
| $3,188 |
| |
| ($9,484 | ) | |
| ($114,677 | ) | |
| ($50,491 | ) |
| State | | 6,712 |
| | 9,535 |
| | (1,269 | ) | | (4,425 | ) | | (1,617 | ) | | 4,933 |
| | (8,544 | ) |
| Total | | 70,781 |
| | (56,546 | ) | | (134,268 | ) | | (1,237 | ) | | (11,101 | ) | | (109,744 | ) | | (59,035 | ) |
| Deferred and non-current - net | | 26,042 |
| | 112,390 |
| | 8,463 |
| | 59,045 |
| | 18,586 |
| | 144,471 |
| | 137,832 |
|
| Investment tax credit adjustments - net | | (2,017 | ) | | (3,228 | ) | | (3,117 | ) | | 871 |
| | (245 | ) | | (1,609 | ) | | (1,682 | ) |
| Income taxes | |
| $94,806 |
| |
| $52,616 |
| |
| ($128,922 | ) | |
| $58,679 |
| |
| $7,240 |
| |
| $33,118 |
| |
| $77,115 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total income taxes for Entergy Corporation and Subsidiaries differ from the amounts computed by applying the statutory income tax rate to income before income taxes. The reasons for the differences for the years 2014, 2013,2017, 2016, and 20122015 are:
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| | (In Thousands) | (In Thousands) |
| Net income attributable to Entergy Corporation |
| $940,721 |
| |
| $711,902 |
| |
| $846,673 |
| |
| Net income (loss) attributable to Entergy Corporation | |
| $411,612 |
| |
| ($583,618 | ) | |
| ($176,562 | ) |
| Preferred dividend requirements of subsidiaries | 19,536 |
| | 18,670 |
| | 21,690 |
| 13,741 |
| | 19,115 |
| | 19,828 |
|
| Consolidated net income | 960,257 |
| | 730,572 |
| | 868,363 |
| |
| Consolidated net income (loss) | | 425,353 |
| | (564,503 | ) | | (156,734 | ) |
| Income taxes | 589,597 |
| | 225,981 |
| | 30,855 |
| 542,570 |
| | (817,259 | ) | | (642,927 | ) |
| Income before income taxes |
| $1,549,854 |
| |
| $956,553 |
| |
| $899,218 |
| |
| Income (loss) before income taxes | |
| $967,923 |
| |
| ($1,381,762 | ) | |
| ($799,661 | ) |
| Computed at statutory rate (35%) |
| $542,449 |
| |
| $334,794 |
| |
| $314,726 |
|
| $338,773 |
| |
| ($483,617 | ) | |
| ($279,881 | ) |
| Increases (reductions) in tax resulting from: | |
| | |
| | |
| |
| | |
| | |
|
| State income taxes net of federal income tax effect | 44,708 |
| | 13,599 |
| | 40,699 |
| 44,179 |
| | 40,581 |
| | 29,944 |
|
| Regulatory differences - utility plant items | 39,321 |
| | 32,324 |
| | 35,527 |
| 39,825 |
| | 33,581 |
| | 32,089 |
|
| Equity component of AFUDC | (21,108 | ) | | (22,356 | ) | | (30,838 | ) | (33,282 | ) | | (23,647 | ) | | (18,191 | ) |
| Amortization of investment tax credits | (12,211 | ) | | (13,535 | ) | | (14,000 | ) | (10,204 | ) | | (10,889 | ) | | (11,136 | ) |
| Flow-through / permanent differences | (18,003 | ) | | (301 | ) | | (14,801 | ) | 8,727 |
| | (19,307 | ) | | (7,872 | ) |
| Net-of-tax regulatory liability | — |
| | (2,899 | ) | | (4,356 | ) | |
| New York tax law change | (21,500 | ) | | — |
| | — |
| |
| Deferred tax asset on additional depreciation (a) | — |
| | — |
| | (155,300 | ) | |
| Termination of business reorganization | — |
| | (27,192 | ) | | — |
| |
| Write-off of regulatory asset for income taxes | — |
| | — |
| | 42,159 |
| |
| Capital losses | — |
| | — |
| | (20,188 | ) | |
| Provision for uncertain tax positions (b) | 32,573 |
| | (59,249 | ) | | (159,957 | ) | |
| Tax legislation enactment (a) | | 560,410 |
| | — |
| | — |
|
| Louisiana business combination | | — |
| | — |
| | (333,655 | ) |
| Entergy Wholesale Commodities restructuring (b) | | (373,277 | ) | | (237,760 | ) | | — |
|
| Act 55 financing settlement (d) | | — |
| | (63,477 | ) | | — |
|
| FitzPatrick disposition | | (44,344 | ) | | — |
| | — |
|
| Provision for uncertain tax positions (c) (d) | | 8,756 |
| | (67,119 | ) | | (56,683 | ) |
| Valuation allowance | — |
| | (31,573 | ) | | — |
| — |
| | 11,411 |
| | — |
|
| Other - net | 3,368 |
| | 2,369 |
| | (2,816 | ) | 3,007 |
| | 2,984 |
| | 2,458 |
|
| Total income taxes as reported |
| $589,597 |
| |
| $225,981 |
| |
| $30,855 |
|
| $542,570 |
| |
| ($817,259 | ) | |
| ($642,927 | ) |
| Effective Income Tax Rate | 38.0 | % | | 23.6 | % | | 3.4 | % | 56.1 | % | | 59.1 | % | | 80.4 | % |
| |
| (a) | See “IncomeOther Tax AuditsMatters- 2004-2005 IRS AuditTax Cuts and Jobs Act” below for discussion of this item.the tax legislation enactment. |
| |
| (b) | See “Other Tax Matters - Entergy Wholesale Commodities Restructuring” below for discussion of the Entergy Wholesale Commodities restructuring. |
| |
| (c) | See “Income Tax Audits - 2008-2009 IRS Audit” below for discussion of the most significant items in 2013 and 2012.for 2015. |
| |
| (d) | See “Income Tax Audits- 2010-2011 IRS Audit” below for discussion of the most significant items for 2016. |
In March 2014, New York enacted legislation that substantially modifies various aspects of New York tax law. The most significant effect of the legislation for Entergy is the adoption of full water's-edge unitary combined reporting, meaning that all of Entergy's domestic entities will be included in New York's combined filing group. The effect of the tax law change resulted in a deferred state income tax reduction of approximately $21.5 million as shown in the table above.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total income taxes for the Registrant Subsidiaries differ from the amounts computed by applying the statutory income tax rate to income before taxes. The reasons for the differences for the years 2014, 2013,2017, 2016, and 20122015 are:
| | | 2014 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2017 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Net income | |
| $121,392 |
| |
| $162,491 |
| |
| $283,531 |
| |
| $74,821 |
| |
| $28,707 |
| |
| $74,804 |
| |
| $96,334 |
| |
| $139,844 |
| |
| $316,347 |
| |
| $110,032 |
| |
| $44,553 |
| |
| $76,173 |
| |
| $78,596 |
|
| Income taxes | | 83,629 |
| | 88,782 |
| | 96,270 |
| | 55,710 |
| | 12,324 |
| | 49,644 |
| | 83,310 |
| | 93,804 |
| | 485,298 |
| | 73,919 |
| | 33,278 |
| | 48,481 |
| | 69,969 |
|
| Pretax income | |
| $205,021 |
| |
| $251,273 |
| |
| $379,801 |
| |
| $130,531 |
| |
| $41,031 |
| |
| $124,448 |
| |
| $179,644 |
| |
| $233,648 |
| |
| $801,645 |
| |
| $183,951 |
| |
| $77,831 |
| |
| $124,654 |
| |
| $148,565 |
|
| Computed at statutory rate (35%) | |
| $71,757 |
| |
| $87,946 |
| |
| $132,930 |
| |
| $45,686 |
| |
| $14,361 |
| |
| $43,557 |
| |
| $62,875 |
| |
| $81,777 |
| |
| $280,576 |
| |
| $64,383 |
| |
| $27,241 |
| |
| $43,629 |
| |
| $51,998 |
|
| Increases (reductions) in tax resulting from: | | | | |
| | |
| | |
| | |
| | |
| | |
| | | | |
| | |
| | |
| | |
| | |
|
| State income taxes net of federal income tax effect | | 9,591 |
| | 6,532 |
| | 5,134 |
| | 5,180 |
| | 1,643 |
| | 3,221 |
| | 6,877 |
| | 11,586 |
| | 31,927 |
| | 6,202 |
| | 2,842 |
| | 527 |
| | 5,635 |
|
| Regulatory differences - utility plant items | | 8,653 |
| | 4,618 |
| | 2,869 |
| | 4,448 |
| | 777 |
| | 4,165 |
| | 13,791 |
| | 7,220 |
| | 12,168 |
| | 1,356 |
| | 619 |
| | 5,581 |
| | 12,880 |
|
| Equity component of AFUDC | | (2,533 | ) | | (2,602 | ) | | (12,010 | ) | | (833 | ) | | (320 | ) | | (1,035 | ) | | (1,774 | ) | | (6,458 | ) | | (18,020 | ) | | (3,383 | ) | | (847 | ) | | (2,353 | ) | | (2,221 | ) |
| Amortization of investment tax credits | | (1,251 | ) | | (3,018 | ) | | (2,576 | ) | | (260 | ) | | (218 | ) | | (1,412 | ) | | (3,476 | ) | | (1,201 | ) | | (4,871 | ) | | (160 | ) | | (124 | ) | | (951 | ) | | (2,896 | ) |
| Flow-through / permanent differences | | (5,082 | ) | | 799 |
| | (1,024 | ) | | 555 |
| | (4,458 | ) | | 393 |
| | (327 | ) | | 3,098 |
| | 3,774 |
| | 1,567 |
| | (3,352 | ) | | 1,428 |
| | (276 | ) |
| Tax legislation enactment (a) | | | (3,090 | ) | | 217,258 |
| | 3,492 |
| | 6,153 |
| | 2,981 |
| | (69 | ) |
| Non-taxable dividend income | | — |
| | (10,590 | ) | | (30,665 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (44,658 | ) | | — |
| | — |
| | — |
| | — |
|
| Provision for uncertain tax positions | | 1,881 |
| | 4,108 |
| | 1,228 |
| | 718 |
| | 405 |
| | 522 |
| | 5,235 |
| | 200 |
| | 5,700 |
| | 228 |
| | 600 |
| | (2,617 | ) | | 4,800 |
|
| Other - net | | 613 |
| | 989 |
| | 384 |
| | 216 |
| | 134 |
| | 233 |
| | 109 |
| | 672 |
| | 1,444 |
| | 234 |
| | 146 |
| | 256 |
| | 118 |
|
| Total income taxes | |
| $83,629 |
| |
| $88,782 |
| |
| $96,270 |
| |
| $55,710 |
| |
| $12,324 |
| |
| $49,644 |
| |
| $83,310 |
| |
| Total income taxes as reported | | |
| $93,804 |
| |
| $485,298 |
| |
| $73,919 |
| |
| $33,278 |
| |
| $48,481 |
| |
| $69,969 |
|
| Effective Income Tax Rate | | 40.8 | % | | 35.3 | % | | 25.3 | % | | 42.7 | % | | 30.0 | % | | 39.9 | % | | 46.4 | % | | 40.1 | % | | 60.5 | % | | 40.2 | % | | 42.8 | % | | 38.9 | % | | 47.1 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2016 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Net income | |
| $167,212 |
| |
| $622,047 |
| |
| $109,184 |
| |
| $48,849 |
| |
| $107,538 |
| |
| $96,744 |
|
| Income taxes | | 107,773 |
| | 89,734 |
| | 63,854 |
| | 28,705 |
| | 63,097 |
| | 71,061 |
|
| Pretax income | |
| $274,985 |
| |
| $711,781 |
| |
| $173,038 |
| |
| $77,554 |
| |
| $170,635 |
| |
| $167,805 |
|
| Computed at statutory rate (35%) | |
| $96,245 |
| |
| $249,123 |
| |
| $60,563 |
| |
| $27,144 |
| |
| $59,722 |
| |
| $58,732 |
|
| Increases (reductions) in tax resulting from: | | |
| | |
| | |
| | |
| | |
| | |
|
| State income taxes net of federal income tax effect | | 11,652 |
| | 29,014 |
| | 5,592 |
| | 3,543 |
| | 449 |
| | 7,001 |
|
| Regulatory differences - utility plant items | | 10,971 |
| | 8,094 |
| | (1,154 | ) | | 2,329 |
| | 4,140 |
| | 9,201 |
|
| Equity component of AFUDC | | (5,985 | ) | | (9,774 | ) | | (2,030 | ) | | (412 | ) | | (2,666 | ) | | (2,780 | ) |
| Amortization of investment tax credits | | (1,201 | ) | | (5,019 | ) | | (160 | ) | | (132 | ) | | (900 | ) | | (3,476 | ) |
| Flow-through / permanent differences | | (3,848 | ) | | (980 | ) | | 764 |
| | (3,609 | ) | | 634 |
| | (883 | ) |
| Act 55 financing settlement (b) | | — |
| | (61,620 | ) | | — |
| | — |
| | (454 | ) | | — |
|
| Non-taxable dividend income | | — |
| | (44,658 | ) | | — |
| | — |
| | — |
| | — |
|
| Provision for uncertain tax positions (b) | | (717 | ) | | (75,871 | ) | | 50 |
| | (300 | ) | | 1,926 |
| | 3,151 |
|
| Other - net | | 656 |
| | 1,425 |
| | 229 |
| | 142 |
| | 246 |
| | 115 |
|
| Total income taxes as reported | |
| $107,773 |
| |
| $89,734 |
| |
| $63,854 |
| |
| $28,705 |
| |
| $63,097 |
| |
| $71,061 |
|
| Effective Income Tax Rate | | 39.2 | % | | 12.6 | % | | 36.9 | % | | 37.0 | % | | 37.0 | % | | 42.3 | % |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2015 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Net income | |
| $161,948 |
| |
| $161,662 |
| |
| $252,464 |
| |
| $82,159 |
| |
| $11,683 |
| |
| $57,881 |
| |
| $113,664 |
| |
| $74,272 |
| |
| $446,639 |
| |
| $92,708 |
| |
| $44,925 |
| |
| $69,625 |
| |
| $111,318 |
|
| Income taxes | | 91,787 |
| | 56,819 |
| | 81,877 |
| | 49,757 |
| | 1,619 |
| | 30,108 |
| | 68,853 |
| | 40,541 |
| | 178,671 |
| | 61,872 |
| | 25,190 |
| | 37,250 |
| | 53,077 |
|
| Pretax income | |
| $253,735 |
| |
| $218,481 |
| |
| $334,341 |
| |
| $131,916 |
| |
| $13,302 |
| |
| $87,989 |
| |
| $182,517 |
| |
| $114,813 |
| |
| $625,310 |
| |
| $154,580 |
| |
| $70,115 |
| |
| $106,875 |
| |
| $164,395 |
|
| Computed at statutory rate (35%) | |
| $88,807 |
| |
| $76,468 |
| |
| $117,019 |
| |
| $46,171 |
| |
| $4,656 |
| |
| $30,796 |
| |
| $63,881 |
| |
| $40,185 |
| |
| $218,859 |
| |
| $54,103 |
| |
| $24,540 |
| |
| $37,406 |
| |
| $57,538 |
|
| Increases (reductions) in tax resulting from: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| State income taxes net of federal income tax effect | | 10,954 |
| | 7,719 |
| | 11,365 |
| | 4,564 |
| | 1,012 |
| | (897 | ) | | 5,900 |
| | 6,643 |
| | 23,650 |
| | 5,219 |
| | 2,887 |
| | 1,621 |
| | 6,403 |
|
| Regulatory differences - utility plant items | | 7,938 |
| | 4,865 |
| | 2,140 |
| | 2,603 |
| | 453 |
| | 3,256 |
| | 11,070 |
| | 7,299 |
| | 3,013 |
| | 2,383 |
| | 2,201 |
| | 3,703 |
| | 12,167 |
|
| Equity component of AFUDC | | (3,820 | ) | | (2,822 | ) | | (10,278 | ) | | (764 | ) | | (322 | ) | | (1,626 | ) | | (2,724 | ) | | (4,979 | ) | | (5,420 | ) | | (1,083 | ) | | (451 | ) | | (1,987 | ) | | (2,973 | ) |
| Amortization of investment tax credits | | (1,989 | ) | | (3,018 | ) | | (2,846 | ) | | (260 | ) | | (216 | ) | | (1,596 | ) | | (3,476 | ) | | (1,201 | ) | | (5,252 | ) | | (160 | ) | | (111 | ) | | (900 | ) | | (3,476 | ) |
| Flow-through / permanent differences | | 2,540 |
| | 2,377 |
| | 1,269 |
| | 1,702 |
| | (4,402 | ) | | 2,467 |
| | (491 | ) | | (4,062 | ) | | 2,460 |
| | 431 |
| | (4,539 | ) | | 530 |
| | 618 |
|
| Net-of-tax regulatory liability | | — |
| | — |
| | (2,899 | ) | | — |
| | — |
| | — |
| | — |
| |
| Termination of business reorganization | | (6,753 | ) | | (3,619 | ) | | (3,834 | ) | | (4,177 | ) | | (501 | ) | | (3,542 | ) | | (13 | ) | |
| Non-taxable dividend income | | — |
| | (9,612 | ) | | (27,341 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (44,658 | ) | | — |
| | — |
| | — |
| | — |
|
| Provision for uncertain tax positions | | (6,527 | ) | | (15,557 | ) | | (3,088 | ) | | (326 | ) | | 795 |
| | 1,027 |
| | (5,353 | ) | |
| Provision for uncertain tax positions (c) | | | (3,978 | ) | | (15,377 | ) | | 756 |
| | 525 |
| | (3,365 | ) | | (17,313 | ) |
| Other - net | | 637 |
| | 18 |
| | 370 |
| | 244 |
| | 144 |
| | 223 |
| | 59 |
| | 634 |
| | 1,396 |
| | 223 |
| | 138 |
| | 242 |
| | 113 |
|
| Total income taxes | |
| $91,787 |
| |
| $56,819 |
| |
| $81,877 |
| |
| $49,757 |
| |
| $1,619 |
| |
| $30,108 |
| |
| $68,853 |
| |
| Total income taxes as reported | | |
| $40,541 |
| |
| $178,671 |
| |
| $61,872 |
| |
| $25,190 |
| |
| $37,250 |
| |
| $53,077 |
|
| Effective Income Tax Rate | | 36.2 | % | | 26.0 | % | | 24.5 | % | | 37.7 | % | | 12.2 | % | | 34.2 | % | | 37.7 | % | | 35.3 | % | | 28.6 | % | | 40.0 | % | | 35.9 | % | | 34.9 | % | | 32.3 | % |
| |
| (a) | See “Other Tax Matters - Tax Cuts and Jobs Act” below for discussion of the tax legislation enactment. |
| |
| (b) | See “Income Tax Audits- 2010-2011 IRS Audit” below for discussion of the most significant items for Entergy Louisiana. |
| |
| (c) | See “Income Tax Audits- 2008-2009 IRS Audit” below for discussion of the most significant items for Entergy Louisiana and System Energy. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2012 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Net income | |
| $152,365 |
| |
| $158,977 |
| |
| $281,081 |
| |
| $46,768 |
| |
| $17,065 |
| |
| $41,971 |
| |
| $111,866 |
|
| Income taxes (benefit) | | 94,806 |
| | 52,616 |
| | (128,922 | ) | | 58,679 |
| | 7,240 |
| | 33,118 |
| | 77,115 |
|
| Pretax income | |
| $247,171 |
| |
| $211,593 |
| |
| $152,159 |
| |
| $105,447 |
| |
| $24,305 |
| |
| $75,089 |
| |
| $188,981 |
|
| Computed at statutory rate (35%) | |
| $86,510 |
| |
| $74,058 |
| |
| $53,256 |
| |
| $36,906 |
| |
| $8,507 |
| |
| $26,281 |
| |
| $66,143 |
|
| Increases (reductions) resulting from: | | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| State income taxes net of federal income tax effect | | 11,282 |
| | 5,087 |
| | 1,976 |
| | 3,944 |
| | 505 |
| | 3,115 |
| | 6,652 |
|
| Regulatory differences - utility plant items | | 6,778 |
| | 8,472 |
| | 312 |
| | 2,619 |
| | 2,289 |
| | 3,668 |
| | 11,389 |
|
| Equity component of AFUDC | | (2,495 | ) | | (3,042 | ) | | (12,919 | ) | | (1,383 | ) | | (276 | ) | | (1,587 | ) | | (9,136 | ) |
| Amortization of investment tax credits | | (1,992 | ) | | (3,204 | ) | | (3,089 | ) | | (264 | ) | | (240 | ) | | (1,596 | ) | | (3,480 | ) |
| Net-of-tax regulatory liability | | — |
| | — |
| | (4,356 | ) | | — |
| | — |
| | — |
| | — |
|
| Flow-through / permanent differences | | 3,427 |
| | (7,646 | ) | | 1,397 |
| | 1,961 |
| | (4,385 | ) | | 1,585 |
| | (357 | ) |
| Non-taxable dividend income | | — |
| | (9,836 | ) | | (27,336 | ) | | — |
| | — |
| | — |
| | — |
|
| Expense (benefit) of Entergy Corporation expenses | | (19,403 | ) | | (17,703 | ) | | — |
| | 14,449 |
| | 2,758 |
| | — |
| | (10,241 | ) |
| Provision for uncertain tax positions | | 11,227 |
| | 8,745 |
| | (143,583 | ) | | 870 |
| | (2,095 | ) | | 1,651 |
| | 17,966 |
|
| Change in regulatory recovery | | — |
| | (553 | ) | | 7,854 |
| | — |
| | — |
| | — |
| | — |
|
| Other - net | | (528 | ) | | (1,762 | ) | | (2,434 | ) | | (423 | ) | | 177 |
| | 1 |
| | (1,821 | ) |
| Total income taxes | |
| $94,806 |
| |
| $52,616 |
| |
| ($128,922 | ) | |
| $58,679 |
| |
| $7,240 |
| |
| $33,118 |
| |
| $77,115 |
|
| Effective Income Tax Rate | | 38.4 | % | | 24.9 | % | | (84.7 | %) | | 55.6 | % | | 29.8 | % | | 44.1 | % | | 40.8 | % |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Significant components of accumulated deferred income taxes and taxes accrued for Entergy Corporation and Subsidiaries as of December 31, 20142017 and 20132016 are as follows:
| | | | 2014 | | 2013 | 2017 | | 2016 |
| | (In Thousands) | (In Thousands) |
| Deferred tax liabilities: | | | | | | |
| Plant basis differences - net |
| ($8,128,096 | ) | |
| ($7,941,319 | ) |
| ($3,963,798 | ) | |
| ($6,362,905 | ) |
| Regulatory assets | (922,161 | ) | | (922,312 | ) | — |
| | (584,572 | ) |
| Nuclear decommissioning trusts | (1,248,737 | ) | | (1,100,439 | ) | |
| Nuclear decommissioning trusts/receivables | | (1,657,808 | ) | | (1,739,977 | ) |
| Pension, net funding | (324,881 | ) | | (299,951 | ) | (350,743 | ) | | (429,896 | ) |
| Combined unitary state taxes | (162,340 | ) | | (183,934 | ) | (24,645 | ) | | (33,063 | ) |
| Power purchase agreements | (110,889 | ) | | (8,096 | ) | (19,621 | ) | | (993 | ) |
| Other | (500,424 | ) | | (404,749 | ) | (249,327 | ) | | (251,719 | ) |
| Total | (11,397,528 | ) | | (10,860,800 | ) | (6,265,942 | ) | | (9,403,125 | ) |
| Deferred tax assets: | |
| | |
| |
| | |
|
| Nuclear decommissioning liabilities | 874,493 |
| | 754,828 |
| 964,945 |
| | 1,399,468 |
|
| Regulatory liabilities | 458,230 |
| | 403,370 |
| 841,370 |
| | 255,272 |
|
| Pension and other post-employment benefits | 586,455 |
| | 469,190 |
| 343,817 |
| | 539,456 |
|
| Sale and leaseback | 153,308 |
| | 176,119 |
| 122,397 |
| | 135,866 |
|
| Compensation | 74,692 |
| | 125,552 |
| 75,217 |
| | 99,300 |
|
| Accumulated deferred investment tax credit | 100,442 |
| | 106,777 |
| 59,285 |
| | 92,375 |
|
| Provision for allowances and contingencies | 160,551 |
| | 66,026 |
| 126,391 |
| | 188,390 |
|
| Net operating loss carryforwards | 457,758 |
| | 548,756 |
| 467,255 |
| | 334,025 |
|
| Capital losses and miscellaneous tax credits | 12,146 |
| | 13,140 |
| 16,738 |
| | 18,470 |
|
| Valuation allowance | (27,387 | ) | | (28,146 | ) | (137,283 | ) | | (104,277 | ) |
| Other | 58,334 |
| | 109,606 |
| 54,058 |
| | 59,079 |
|
| Total | 2,909,022 |
| | 2,745,218 |
| 2,934,190 |
| | 3,017,424 |
|
| Noncurrent accrued taxes (including unrecognized tax benefits) | (606,560 | ) | | (400,276 | ) | |
| Non-current accrued taxes (including unrecognized tax benefits) | | (956,547 | ) | | (991,704 | ) |
| Accumulated deferred income taxes and taxes accrued |
| ($9,095,066 | ) | |
| ($8,515,858 | ) |
| ($4,288,299 | ) | |
| ($7,377,405 | ) |
Entergy’s estimated tax attributes carryovers and their expiration dates as of December 31, 20142017 are as follows:
|
| | | | |
| Carryover Description | | Carryover Amount | | Year(s) of expiration |
| | | | | |
| Federal net operating losses | | $12.310.7 billion | | 2023-20342023-2037 |
| State net operating losses | | $10.29.6 billion | | 2015-20332018-2037 |
| Miscellaneous federal and state credits | | $97.696.6 million | | 2015-20342018-2036 |
As a result of the accounting for uncertain tax positions, the amount of the deferred tax assets reflected in the financial statements is less than the amount of the tax effect of the federal and state net operating loss carryovers, tax credit carryovers, and other tax attributes reflected on income tax returns. Because it is more likely than not that the benefit from certain state net operating loss and credit carryovers will not be utilized, a valuation allowanceallowances of $21.2$106 million hasas of December 31, 2017 and $62 million as of December 31, 2016 have been provided on the deferred tax assets relating to these state net operating loss and credit carryovers.
In the third quarter 2013, Entergy reduced a Additionally, valuation allowance by $44allowances totaling $31 million ($28as of December 31, 2017 and $42.3 million netas of the federal income tax effect) that hadDecember 31, 2016 have been provided on adeferred tax assets related to federal and state net operating loss carryover duejurisdictions in which Entergy does not currently expect to the prospective utilizationbe able to utilize separate company tax return losses, preventing realization of such loss carryover.deferred tax assets.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Significant components of accumulated deferred income taxes and taxes accrued for the Registrant Subsidiaries as of December 31, 20142017 and 20132016 are as follows:
| | | 2014 | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2017 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) | | (In Thousands) |
| Deferred tax liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant basis differences - net |
| ($1,657,503 | ) | |
| ($1,233,761 | ) | |
| ($1,515,091 | ) | |
| ($753,576 | ) | |
| ($186,153 | ) | |
| ($771,135 | ) | |
| ($668,779 | ) | |
| ($1,289,827 | ) | |
| ($1,583,100 | ) | |
| ($571,682 | ) | |
| ($85,515 | ) | |
| ($526,596 | ) | |
| ($359,931 | ) |
| Regulatory assets | (198,662 | ) | | (106,287 | ) | | (274,432 | ) | | (30,114 | ) | | — |
| | (202,402 | ) | | (110,087 | ) | |
| Nuclear decommissioning trusts | (130,524 | ) | | (43,611 | ) | | (62,551 | ) | | — |
| | — |
| | — |
| | (74,063 | ) | |
| Nuclear decommissioning trusts/receivables | | | (181,911 | ) | | (164,395 | ) | | — |
| | — |
| | — |
| | (119,184 | ) |
| Pension, net funding | (93,355 | ) | | (46,403 | ) | | (53,190 | ) | | (27,861 | ) | | (13,285 | ) | | (25,616 | ) | | (23,440 | ) | | (99,971 | ) | | (102,138 | ) | | (26,413 | ) | | (13,040 | ) | | (20,700 | ) | | (21,871 | ) |
| Deferred fuel | (82,050 | ) | | (3,034 | ) | | (500 | ) | | (5,303 | ) | | (407 | ) | | 2,045 |
| | (120 | ) | | (16,530 | ) | | (1,329 | ) | | (19,005 | ) | | (1,894 | ) | | — |
| | (272 | ) |
| Power purchase agreements | (17,073 | ) | | (67,083 | ) | | — |
| | 2,129 |
| | 13 |
| | 847 |
| | — |
| |
| Other | (33,827 | ) | | (8,850 | ) | | (75,432 | ) | | (11,423 | ) | | (11,500 | ) | | (22,546 | ) | | (19,802 | ) | | (23,079 | ) | | (98,307 | ) | | (11,306 | ) | | (23,610 | ) | | (8,236 | ) | | (5,955 | ) |
| Total | (2,212,994 | ) | | (1,509,029 | ) | | (1,981,196 | ) | | (826,148 | ) | | (211,332 | ) | | (1,018,807 | ) | | (896,291 | ) | | (1,611,318 | ) | | (1,949,269 | ) | | (628,406 | ) | | (124,059 | ) | | (555,532 | ) | | (507,213 | ) |
| Deferred tax assets: | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Regulatory liabilities | 145,466 |
| | 70,068 |
| | 111,533 |
| | 7,214 |
| | 29,580 |
| | 4,079 |
| | 90,290 |
| | 227,489 |
| | 368,156 |
| | 102,676 |
| | 23,526 |
| | 25,428 |
| | 91,271 |
|
| Nuclear decommissioning liabilities | (43,134 | ) | | 48,815 |
| | 97,323 |
| | — |
| | — |
| | — |
| | (62,571 | ) | | 132,464 |
| | 58,891 |
| | — |
| | — |
| | — |
| | 63,180 |
|
| Pension and other post-employment benefits | (17,534 | ) | | 88,606 |
| | 70,055 |
| | (7,288 | ) | | (7,504 | ) | | (15,053 | ) | | (1,413 | ) | | (16,252 | ) | | 98,596 |
| | (4,865 | ) | | (9,618 | ) | | (12,044 | ) | | (516 | ) |
| Sale and leaseback | — |
| | — |
| | 45,136 |
| | — |
| | — |
| | — |
| | 108,172 |
| | — |
| | 19,915 |
| | — |
| | — |
| | — |
| | 102,482 |
|
| Accumulated deferred investment tax credit | 14,791 |
| | 33,941 |
| | 24,922 |
| | 2,436 |
| | 332 |
| | 5,158 |
| | 18,862 |
| | 8,913 |
| | 35,323 |
| | 2,212 |
| | 488 |
| | 2,516 |
| | 9,832 |
|
| Provision for allowances and contingencies | (7,149 | ) | | 43,512 |
| | 82,293 |
| | 19,590 |
| | 10,986 |
| | 8,017 |
| | 133 |
| | 4,367 |
| | 80,516 |
| | 11,898 |
| | 24,234 |
| | 4,383 |
| | — |
|
| Power purchase agreements | | | — |
| | (6,924 | ) | | 1,129 |
| | — |
| | — |
| | — |
|
| Unbilled/deferred revenues | 12,322 |
| | (18,553 | ) | | (6,463 | ) | | 12,956 |
| | 3,395 |
| | 11,573 |
| | — |
| | 6,195 |
| | (18,263 | ) | | 4,847 |
| | 1,811 |
| | 7,736 |
| | — |
|
| Compensation | 2,085 |
| | 641 |
| | (483 | ) | | (846 | ) | | 475 |
| | 4,155 |
| | — |
| | 2,566 |
| | 4,387 |
| | 1,466 |
| | 723 |
| | 1,224 |
| | 332 |
|
| Net operating loss carryforwards | 105,063 |
| | — |
| | 241,803 |
| | — |
| | — |
| | — |
| | — |
| | 16,172 |
| | 44 |
| | 10,255 |
| | — |
| | 1,690 |
| | — |
|
| Capital losses and miscellaneous tax credits | — |
| | — |
| | — |
| | 3,504 |
| | — |
| | — |
| | — |
| | 2,678 |
| | — |
| | 5,736 |
| | — |
| | — |
| | — |
|
| Other | 258 |
| | 8,102 |
| | 7,406 |
| | 5,887 |
| | 2,891 |
| | 3,850 |
| | 2,000 |
| | 473 |
| | 21,922 |
| | 1,307 |
| | 388 |
| | 1,133 |
| | — |
|
| Total | 212,168 |
| | 275,132 |
| | 673,525 |
| | 43,453 |
| | 40,155 |
| | 21,779 |
| | 155,473 |
| | 385,065 |
| | 662,563 |
| | 136,661 |
| | 41,552 |
| | 32,066 |
| | 266,581 |
|
| Noncurrent accrued taxes (including unrecognized tax benefits) | 9,367 |
| | (388,230 | ) | | (24,278 | ) | | (12,481 | ) | | (19,502 | ) | | (48,921 | ) | | (81,528 | ) | |
| Non-current accrued taxes (including unrecognized tax benefits) | | | 35,584 |
| | (763,665 | ) | | 2,939 |
| | (200,795 | ) | | (21,176 | ) | | (535,788 | ) |
| Accumulated deferred income taxes and taxes accrued |
| ($1,991,459 | ) | |
| ($1,622,127 | ) | |
| ($1,331,949 | ) | |
| ($795,176 | ) | |
| ($190,679 | ) | |
| ($1,045,949 | ) | |
| ($822,346 | ) | |
| ($1,190,669 | ) | |
| ($2,050,371 | ) | |
| ($488,806 | ) | |
| ($283,302 | ) | |
| ($544,642 | ) | |
| ($776,420 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2016 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Deferred tax liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant basis differences - net | |
| ($1,613,195 | ) | |
| ($1,259,173 | ) | |
| ($1,347,534 | ) | |
| ($727,545 | ) | |
| ($196,726 | ) | |
| ($759,263 | ) | |
| ($698,151 | ) | |
| ($1,857,554 | ) | |
| ($2,357,599 | ) | |
| ($820,971 | ) | |
| ($177,242 | ) | |
| ($835,671 | ) | |
| ($651,394 | ) |
| Regulatory assets | | (212,339 | ) | | (102,362 | ) | | (255,068 | ) | | (33,277 | ) | | — |
| | (205,402 | ) | | (113,849 | ) | | (109,241 | ) | | (219,750 | ) | | (25,309 | ) | | (36,301 | ) | | (153,914 | ) | | (39,879 | ) |
| Nuclear decommissioning trusts | | (110,004 | ) | | (32,574 | ) | | (50,248 | ) | | — |
| | — |
| | — |
| | (58,308 | ) | | (144,250 | ) | | (119,544 | ) | | — |
| | — |
| | — |
| | (83,891 | ) |
| Pension, net funding | | (79,589 | ) | | (45,342 | ) | | (50,630 | ) | | (24,392 | ) | | (11,606 | ) | | (23,598 | ) | | (21,187 | ) | | (123,889 | ) | | (122,465 | ) | | (34,284 | ) | | (16,307 | ) | | (28,371 | ) | | (29,357 | ) |
| Deferred fuel | | (26,946 | ) | | (4,361 | ) | | (512 | ) | | (21,823 | ) | | 63 |
| | (470 | ) | | (129 | ) | | (14,774 | ) | | (1,778 | ) | | (12,770 | ) | | (5,229 | ) | | (2,808 | ) | | (1,137 | ) |
| Power purchase agreements | | (7,053 | ) | | (20,234 | ) | | — |
| | — |
| | 13 |
| | 1,269 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | | (62,046 | ) | | (25,694 | ) | | (69,194 | ) | | (10,732 | ) | | (13,446 | ) | | (58,963 | ) | | (8,969 | ) | | (47,785 | ) | | (22,136 | ) | | (12,474 | ) | | (18,536 | ) | | (8,812 | ) | | (2,051 | ) |
| Total | | (2,111,172 | ) | | (1,489,740 | ) | | (1,773,186 | ) | | (817,769 | ) | | (221,702 | ) | | (1,046,427 | ) | | (900,593 | ) | | (2,297,493 | ) | | (2,843,272 | ) | | (905,808 | ) | | (253,615 | ) | | (1,029,576 | ) | | (807,709 | ) |
| Deferred tax assets: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Regulatory liabilities | | 120,966 |
| | 60,176 |
| | 94,019 |
| | 8,357 |
| | 35,764 |
| | 7,952 |
| | 76,135 |
| | 5,768 |
| | 175,973 |
| | 18,833 |
| | 25,240 |
| | 15,814 |
| | 13,644 |
|
| Nuclear decommissioning liabilities | | (64,571 | ) | | 49,439 |
| | 92,206 |
| | — |
| | — |
| | — |
| | (71,898 | ) | | 124,206 |
| | 55,408 |
| | — |
| | — |
| | — |
| | 53,113 |
|
| Pension and other post-employment benefits | | (12,132 | ) | | 73,136 |
| | 62,999 |
| | (1,345 | ) | | 1,532 |
| | (13,417 | ) | | (2,073 | ) | | (24,467 | ) | | 145,401 |
| | (8,042 | ) | | (12,070 | ) | | (19,096 | ) | | (1,182 | ) |
| Sale and leaseback | | — |
| | — |
| | 52,054 |
| | — |
| | — |
| | — |
| | 124,065 |
| | — |
| | 33,383 |
| | — |
| | — |
| | — |
| | 102,483 |
|
| Accumulated deferred investment tax credit | | 15,281 |
| | 35,297 |
| | 25,913 |
| | 3,263 |
| | 416 |
| | 5,651 |
| | 20,956 |
| | 13,848 |
| | 54,509 |
| | 3,315 |
| | 239 |
| | 4,527 |
| | 15,936 |
|
| Provision for allowances and contingencies | | 12,313 |
| | 14,784 |
| | 3,347 |
| | 13,066 |
| | 8,535 |
| | 5,980 |
| | — |
| | (1,497 | ) | | 124,309 |
| | 21,817 |
| | 36,466 |
| | 5,904 |
| | — |
|
| Power purchase agreements | | | (3,094 | ) | | 29,827 |
| | 1,905 |
| | — |
| | 140 |
| | — |
|
| Unbilled/deferred revenues | | 37,825 |
| | (22,340 | ) | | 3,026 |
| | 6,791 |
| | 4,226 |
| | 10,655 |
| | — |
| | 6,799 |
| | (35,006 | ) | | 5,085 |
| | 3,751 |
| | 11,902 |
| | — |
|
| Compensation | | 7,131 |
| | 4,701 |
| | 3,470 |
| | 1,778 |
| | 1,696 |
| | 6,774 |
| | 822 |
| | 2,787 |
| | 5,309 |
| | 1,492 |
| | 685 |
| | 1,587 |
| | 360 |
|
| Net operating loss carryforwards | | 85,875 |
| | — |
| | 230,592 |
| | 19,400 |
| | — |
| | — |
| | — |
| | 69,524 |
| | 17,125 |
| | — |
| | — |
| | — |
| | — |
|
| Capital losses and miscellaneous tax credits | | — |
| | — |
| | — |
| | 6,173 |
| | — |
| | — |
| | — |
| | 2,074 |
| | — |
| | 4,487 |
| | — |
| | — |
| | — |
|
| Other | | 3,682 |
| | 4,939 |
| | 4,148 |
| | 4,224 |
| | 2,930 |
| | 3,807 |
| | 2,001 |
| | 174 |
| | 17,110 |
| | 1,152 |
| | 496 |
| | 2,955 |
| | — |
|
| Total | | 206,370 |
| | 220,132 |
| | 571,774 |
| | 61,707 |
| | 55,099 |
| | 27,402 |
| | 150,008 |
| | 196,122 |
| | 623,348 |
| | 50,044 |
| | 54,807 |
| | 23,733 |
| | 184,354 |
|
| Noncurrent accrued taxes (including unrecognized tax benefits) | | 22,565 |
| | (279,269 | ) | | 25,512 |
| | (6,290 | ) | | (5,015 | ) | | (37,777 | ) | | 10,302 |
| |
| Non-current accrued taxes (including unrecognized tax benefits) | | | (85,252 | ) | | (471,194 | ) | | (5,567 | ) | | (136,145 | ) | | (21,804 | ) | | (489,510 | ) |
| Accumulated deferred income taxes and taxes accrued | |
| ($1,882,237 | ) | |
| ($1,548,877 | ) | |
| ($1,175,900 | ) | |
| ($762,352 | ) | |
| ($171,618 | ) | |
| ($1,056,802 | ) | |
| ($740,283 | ) | |
| ($2,186,623 | ) | |
| ($2,691,118 | ) | |
| ($861,331 | ) | |
| ($334,953 | ) | |
| ($1,027,647 | ) | |
| ($1,112,865 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The Registrant Subsidiaries’ estimated tax attributes carryovers and their expiration dates as of December 31, 20142017 are as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | | | | | | | | | | | | | |
| Federal net operating losses | |
| $1.3 | billion | |
| $151 | million | |
| $2.1 | billion | | — | |
| $55 | million | | — | |
| $392 | million |
| Year(s) of expiration | | 2029-2034 |
| | 2029-2032 |
| | 2029-2034 |
| | N/A | | 2031-2034 |
| | N/A | | 2030-2032 |
|
| | | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| State net operating losses | |
| $235 | million | |
| $580 | million | |
| $3 | billion | | — | |
| $24 | million | | — | | — |
| Year(s) of expiration | | 2015-2028 |
| | 2024-2027 |
| | 2024-2029 |
| | N/A | | 2026-2029 |
| | N/A | | N/A |
| | | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Misc. federal credits | |
| $1 | million | |
| $6 | million | |
| $13 | million | |
| $1 | million | | — | | — | |
| $10 | million |
| Year(s) of expiration | | 2029-2033 |
| | 2029-2033 |
| | 2026-2033 |
| | 2029-2033 |
| | N/A | | N/A | | 2029-2033 |
|
| | | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| State credits | | — | | — | | — | |
| $9.5 | million | | — | |
| $3.4 | million | |
| $15.7 | million |
| Year(s) of expiration | | N/A | | N/A | | N/A | | 2015-2019 |
| | N/A | | 2026 |
| | 2015-2019 |
|
|
| | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | | | | | | | | | | |
| Federal net operating losses | | $77 million | | $4.3 billion | | $86.6 million | | $1.1 billion | | — | | — |
| Year(s) of expiration | | 2030-2037 | | 2035-2037 | | 2030-2037 | | 2037 | | N/A | | N/A |
| | | | | | | | | | | | |
| State net operating losses | | — | | $5 billion | | — | | $1.2 billion | | — | | — |
| Year(s) of expiration | | N/A | | 2029-2037 | | N/A | | 2037 | | N/A | | N/A |
| | | | | | | | | | | | |
| Misc. federal credits | | $2.7 million | | $1.7 million | | $2.7 million | | $2.1 million | | $0.6 million | | $2.5 million |
| Year(s) of expiration | | 2029-2036 | | 2029-2036 | | 2029-2036 | | 2029-2036 | | 2029-2036 | | 2029-2036 |
| | | | | | | | | | | | |
| State credits | | — | | — | | $4.9 million | | — | | $3.2 million | | $10 million |
| Year(s) of expiration | | N/A | | N/A | | 2018-2021 | | N/A | | 2026 | | 2018-2021 |
As a result of the accounting for uncertain tax positions, the amount of the deferred tax assets reflected in the financial statements is less than the amount of the tax effect of the federal and state net operating loss carryovers and tax credit carryovers.
Unrecognized tax benefits
Accounting standards establish a “more-likely-than-not” recognition threshold that must be met before a tax benefit can be recognized in the financial statements. If a tax deduction is taken on a tax return, but does not meet the more-likely-than-not recognition threshold, an increase in income tax liability, above what is payable on the tax return, is required to be recorded. A reconciliation of Entergy’s beginning and ending amount of unrecognized tax benefits is as follows:
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| | (In Thousands) | (In Thousands) |
| Gross balance at January 1 |
| $4,593,224 |
| |
| $4,170,403 |
| |
| $4,387,780 |
|
| $3,909,855 |
| |
| $2,611,585 |
| |
| $4,736,785 |
|
| Additions based on tax positions related to the current year | 348,543 |
| | 162,338 |
| | 163,612 |
| 1,120,687 |
| | 1,532,782 |
| | 1,850,705 |
|
| Additions for tax positions of prior years | 11,637 |
| | 410,108 |
| | 1,517,797 |
| 283,683 |
| | 368,404 |
| | 59,815 |
|
Reductions for tax positions of prior years | (213,401 | ) | | (103,360 | ) | | (476,873 | ) | (442,379 | ) | | (265,653 | ) | | (3,966,535 | ) |
| Settlements | — |
| | (43,620 | ) | | (1,421,913 | ) | — |
| | (337,263 | ) | | (68,227 | ) |
| Lapse of statute of limitations | (3,218 | ) | | (2,645 | ) | | — |
| — |
| | — |
| | (958 | ) |
| Gross balance at December 31 | 4,736,785 |
| | 4,593,224 |
| | 4,170,403 |
| 4,871,846 |
| | 3,909,855 |
| | 2,611,585 |
|
| Offsets to gross unrecognized tax benefits: | |
| | |
| | |
| |
| | |
| | |
|
| Credit and loss carryovers | (4,295,643 | ) | | (4,400,498 | ) | | (4,022,535 | ) | |
| Unrecognized tax benefits net of unused tax attributes and payments (a) |
| $441,142 |
| |
| $192,726 |
| |
| $147,868 |
| |
| Carryovers and refund claims | | (3,945,524 | ) | | (2,922,085 | ) | | (1,264,483 | ) |
| Cash paid to taxing authorities | | (10,000 | ) | | (10,000 | ) | | — |
|
| Unrecognized tax benefits net of unused tax attributes, refund claims and payments (b) | |
| $916,322 |
| |
| $977,770 |
| |
| $1,347,102 |
|
| |
| (a) | The primary reduction for 2015 is related to the nuclear decommissioning costs treatment discussed in “Income Tax Audits - 2008-2009 IRS Audit” below. |
| |
| (b) | Potential tax liability above what is payable on tax returns |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The balances of unrecognized tax benefits include $516$1,462 million, $176$1,240 million, and $203$955 million as of December 31, 2014, 2013,2017, 2016, and 2012,2015, respectively, which, if recognized, would lower the effective income tax rates. Because of the effect of deferred tax accounting, the remaining balances of unrecognized tax benefits of $4.221 billion, $4.417 billion,$3,410 million, $2,670 million, and $3.968 billion$1,657 million as of December 31, 2014, 2013,2017, 2016, and 2012,2015, respectively, if disallowed, would not affect the annual effective income tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.
Entergy accrues interest expense, if any, related to unrecognized tax benefits in income tax expense. Entergy’s December 31, 2014, 2013,2017, 2016, and 20122015 accrued balance for the possible payment of interest is approximately $127$38 million, $96.4$30 million, and $146.3$27 million, respectively.
A reconciliation of the Registrant Subsidiaries’ beginning and ending amount of unrecognized tax benefits for 2014, 2013,2017, 2016, and 20122015 is as follows:
| | | 2014 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2017 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Gross balance at January 1, 2014 | |
| $347,713 |
| |
| $465,075 |
| |
| $611,605 |
| |
| $16,186 |
| |
| $51,679 |
| |
| $13,017 |
| |
| $265,185 |
| |
| Gross balance at January 1, 2017 | | |
| $2,503 |
| |
| $2,440,339 |
| |
| $12,206 |
| |
| $166,230 |
| |
| $15,946 |
| |
| $472,372 |
|
Additions based on tax positions related to the current year | | 14,511 |
| | 55,053 |
| | 96,196 |
| | 3,928 |
| | 2,235 |
| | 4,225 |
| | 2,744 |
| | 8,974 |
| | 32,843 |
| | 2,105 |
| | 509,183 |
| | 1,747 |
| | 909 |
|
| Additions for tax positions of prior years | | 1,767 |
| | 5,204 |
| | 1,720 |
| | 319 |
| | 37 |
| | 303 |
| | 566 |
| | 3,682 |
| | 235,331 |
| | 1,267 |
| | 13,364 |
| | 3,115 |
| | 1,432 |
|
| Reductions for tax positions of prior years | | (1,079 | ) | | (7,995 | ) | | (20,929 | ) | | (289 | ) | | (188 | ) | | (267 | ) | | (10,253 | ) | | (132,875 | ) | | (190,056 | ) | | (456 | ) | | (9,233 | ) | | (4,409 | ) | | (29,202 | ) |
| Settlements | | — |
| | — |
| | — |
| | — |
| | — |
| | (14 | ) | | — |
| |
| Gross balance at December 31, 2014 | | 362,912 |
| | 517,337 |
| | 688,592 |
| | 20,144 |
| | 53,763 |
| | 17,264 |
| | 258,242 |
| |
| Gross balance at December 31, 2017 | | | (117,716 | ) | | 2,518,457 |
| | 15,122 |
| | 679,544 |
| | 16,399 |
| | 445,511 |
|
| Offsets to gross unrecognized tax benefits: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Loss carryovers | | (361,043 | ) | | (89,448 | ) | | (650,540 | ) | | (6,992 | ) | | (20,735 | ) | | (241 | ) | | (163,124 | ) | | — |
| | (1,591,907 | ) | | (15,122 | ) | | (441,374 | ) | | (638 | ) | | (12,536 | ) |
| Unrecognized tax benefits net of unused tax attributes and payments | |
| $1,869 |
| |
| $427,889 |
| |
| $38,052 |
| |
| $13,152 |
| |
| $33,028 |
| |
| $17,023 |
| |
| $95,118 |
| |
| ($117,716 | ) | |
| $926,550 |
| |
| $— |
| |
| $238,170 |
| |
| $15,761 |
| |
| $432,975 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2016 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Gross balance at January 1, 2016 | |
| $25,445 |
| |
| $1,690,661 |
| |
| $19,482 |
| |
| $53,897 |
| |
| $13,462 |
| |
| $478,318 |
|
| Additions based on tax positions related to the current year (a) | | 16,868 |
| | 931,720 |
| | 2,662 |
| | 33,912 |
| | 2,002 |
| | 5,318 |
|
| Additions for tax positions of prior years | | 2,463 |
| | 157,586 |
| | 336 |
| | 129,784 |
| | 2,888 |
| | 601 |
|
| Reductions for tax positions of prior years | | (41,957 | ) | | (144,068 | ) | | (10,219 | ) | | (29,821 | ) | | (1,849 | ) | | (10,266 | ) |
| Settlements | | (316 | ) | | (195,560 | ) | | (55 | ) | | (21,542 | ) | | (557 | ) | | (1,599 | ) |
| Gross balance at December 31, 2016 | | 2,503 |
| | 2,440,339 |
| | 12,206 |
| | 166,230 |
| | 15,946 |
| | 472,372 |
|
| Offsets to gross unrecognized tax benefits: | | |
| | |
| | |
| | |
| | |
| | |
|
| Loss carryovers | | — |
| | (1,783,093 | ) | | (2,373 | ) | | (27,320 | ) | | (376 | ) | | (90,028 | ) |
| Unrecognized tax benefits net of unused tax attributes and payments | |
| $2,503 |
| |
| $657,246 |
| |
| $9,833 |
| |
| $138,910 |
| |
| $15,570 |
| |
| $382,344 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2015 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Gross balance at January 1, 2013 | |
| $344,669 |
| |
| $465,721 |
| |
| $536,673 |
| |
| $16,841 |
| |
| $52,018 |
| |
| $13,954 |
| |
| $260,346 |
| |
| Gross balance at January 1, 2015 | | |
| $362,912 |
| |
| $1,205,929 |
| |
| $20,144 |
| |
| $53,763 |
| |
| $17,264 |
| |
| $258,242 |
|
Additions based on tax positions related to the current year | | 6,427 |
| | 7,276 |
| | 10,611 |
| | 957 |
| | 583 |
| | 2,170 |
| | 4,170 |
| | 2,196 |
| | 1,367,058 |
| | 566 |
| | 472 |
| | 657 |
| | 472,304 |
|
| Additions for tax positions of prior years | | 1,228 |
| | 7,189 |
| | 118,025 |
| | 401 |
| | 3,506 |
| | 587 |
| | 8,391 |
| | 1,057 |
| | 7,992 |
| | 8,140 |
| | 48 |
| | 2,914 |
| | 913 |
|
| Reductions for tax positions of prior years | | (3,943 | ) | | (15,045 | ) | | (38,428 | ) | | (1,941 | ) | | (962 | ) | | (4,186 | ) | | (967 | ) | | (340,720 | ) | | (859,430 | ) | | — |
| | (386 | ) | | (3,981 | ) | | (253,141 | ) |
| Settlements | | (668 | ) | | (66 | ) | | (15,276 | ) | | (72 | ) | | (3,466 | ) | | 492 |
| | (6,755 | ) | | — |
| | (30,888 | ) | | (9,368 | ) | | — |
| | (3,392 | ) | | — |
|
| Gross balance at December 31, 2013 | | 347,713 |
| | 465,075 |
| | 611,605 |
| | 16,186 |
| | 51,679 |
| | 13,017 |
| | 265,185 |
| |
| Gross balance at December 31, 2015 | | | 25,445 |
| | 1,690,661 |
| | 19,482 |
| | 53,897 |
| | 13,462 |
| | 478,318 |
|
| Offsets to gross unrecognized tax benefits: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Loss carryovers | | (345,674 | ) | | (136,151 | ) | | (611,605 | ) | | (16,186 | ) | | (22,078 | ) | | (266 | ) | | (225,286 | ) | | (3,613 | ) | | (893,764 | ) | | (1,016 | ) | | (506 | ) | | (276 | ) | | (133,611 | ) |
| Unrecognized tax benefits net of unused tax attributes and payments | |
| $2,039 |
| |
| $328,924 |
| |
| $— |
| |
| $— |
| |
| $29,601 |
| |
| $12,751 |
| |
| $39,899 |
| |
| $21,832 |
| |
| $796,897 |
| |
| $18,466 |
| |
| $53,391 |
| |
| $13,186 |
| |
| $344,707 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2012 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Gross balance at January 1, 2012 | |
| $335,493 |
| |
| $390,493 |
| |
| $446,187 |
| |
| $11,052 |
| |
| $56,052 |
| |
| $19,225 |
| |
| $281,183 |
|
| Additions based on tax positions related to the current year | | 10,409 |
| | 8,974 |
| | 67,721 |
| | 8,401 |
| | 497 |
| | 1,656 |
| | 8,715 |
|
| Additions for tax positions of prior years | | 429,232 |
| | 392,548 |
| | 331,432 |
| | 4,057 |
| | 445 |
| | 4,834 |
| | 271,172 |
|
| Reductions for tax positions of prior years | | (39,534 | ) | | (50,518 | ) | | (169,465 | ) | | (5,703 | ) | | (2,506 | ) | | (11,649 | ) | | (20,934 | ) |
| Settlements | | (390,931 | ) | | (275,776 | ) | | (139,202 | ) | | (966 | ) | | (2,470 | ) | | (112 | ) | | (279,790 | ) |
| Gross balance at December 31, 2012 | | 344,669 |
| | 465,721 |
| | 536,673 |
| | 16,841 |
| | 52,018 |
| | 13,954 |
| | 260,346 |
|
| Offsets to gross unrecognized tax benefits: | | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Loss carryovers | | (342,127 | ) | | (160,955 | ) | | (536,673 | ) | | (16,841 | ) | | (35,511 | ) | | (1,593 | ) | | (249,424 | ) |
| Unrecognized tax benefits net of unused tax attributes and payments | |
| $2,542 |
| |
| $304,766 |
| |
| $— |
| |
| $— |
| |
| $16,507 |
| |
| $12,361 |
| |
| $10,922 |
|
| |
| (a) | The primary additions for Entergy Louisiana in 2016 and for Entergy New Orleans in 2017 are related to the mark-to-market treatment discussed in “Other Tax Matters - Tax Accounting Methods” below. |
| |
| (b) | The primary addition for Entergy Louisiana and System Energy is related to the nuclear decommissioning costs treatment discussed in “Other Tax Matters - Tax Accounting Methods” below. |
The Registrant Subsidiaries’ balances of unrecognized tax benefits included amounts which, if recognized, would have reduced income tax expense as follows:
| | | | December 31, | December 31, |
| | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
| Entergy Arkansas |
| $2.6 |
| |
| $0.6 |
| |
| $0.6 |
|
| $2.6 |
| |
| $3.6 |
| |
| $4.5 |
|
| Entergy Gulf States Louisiana |
| $91.9 |
| |
| $44.0 |
| |
| $44.0 |
| |
| Entergy Louisiana |
| $175.4 |
| |
| $87.9 |
| |
| $92.4 |
|
| $575.8 |
| |
| $473.3 |
| |
| $692.7 |
|
| Entergy Mississippi |
| $3.9 |
| |
| $3.9 |
| |
| $3.9 |
|
| $— |
| |
| $— |
| |
| $8.1 |
|
| Entergy New Orleans |
| $50.7 |
| |
| $— |
| |
| $— |
|
| $31.7 |
| |
| $33.6 |
| |
| $50.7 |
|
| Entergy Texas |
| $10.5 |
| |
| $10.1 |
| |
| $8.6 |
|
| $4.4 |
| |
| $7.0 |
| |
| $5.2 |
|
| System Energy |
| $3.7 |
| |
| $3.3 |
| |
| $3.5 |
|
| $— |
| |
| $— |
| |
| $0.7 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The Registrant Subsidiaries accrue interest and penalties related to unrecognized tax benefits in income tax expense. Penalties have not been accrued. Accrued balances for the possible payment of interest are as follows:
| | | | December 31, | December 31, |
| | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
| Entergy Arkansas |
| $17.0 |
| |
| $15.2 |
| |
| $21.8 |
|
| $1.6 |
| |
| $1.4 |
| |
| $1.3 |
|
| Entergy Gulf States Louisiana |
| $21.0 |
| |
| $17.0 |
| |
| $33.1 |
| |
| Entergy Louisiana |
| $1.2 |
| |
| $1.0 |
| |
| $0.9 |
|
| $14.1 |
| |
| $8.4 |
| |
| $9.3 |
|
| Entergy Mississippi |
| $2.8 |
| |
| $2.1 |
| |
| $2.4 |
|
| $1.0 |
| |
| $0.8 |
| |
| $0.4 |
|
| Entergy New Orleans |
| $1.3 |
| |
| $0.9 |
| |
| $0.1 |
|
| $2.1 |
| |
| $1.5 |
| |
| $1.8 |
|
| Entergy Texas |
| $1.0 |
| |
| $0.8 |
| |
| $0.7 |
|
| $0.4 |
| |
| $1.2 |
| |
| $1.2 |
|
| System Energy |
| $23.8 |
| |
| $19.0 |
| |
| $33.2 |
|
| $8.5 |
| |
| $3.7 |
| |
| $0.7 |
|
Income Tax Litigation
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In October 2010 the U.S. Tax Court entered a decision in favor of Entergy regarding the ability to credit the U.K. Windfall Tax against U.S. income tax as a foreign tax credit. The U.K. Windfall Tax relates to Entergy’s former investment in London Electricity.
The IRS filed an appeal of the U.K. Windfall Tax decision with the U.S. Court of Appeals for the Fifth Circuit in December 2010. Oral arguments were heard in November 2011. In June 2012 the U.S. Court of Appeals for the Fifth Circuit unanimously affirmed the U.S. Tax Court decision. As a result of this decision, Entergy reversed its liability for uncertain tax positions associated with this issue. On September 4, 2012, the U.S. Solicitor General, on behalf of the Commissioner of Internal Revenue, petitioned the U.S. Supreme Court for a writ of certiorari to review the Fifth Circuit judgment.
Concurrent with the Tax Court’s issuance of a favorable decision regarding the above issues, the Tax Court issued a favorable decision in a separate proceeding, PPL Corp. v. Commissioner, regarding the creditability of the U.K. Windfall Tax. The IRS appealed the PPL decision to the United States Court of Appeals for the Third Circuit. In December 2011 the Third Circuit reversed the Tax Court’s holding in PPL Corp. v. Commissioner, stating that the U.K. tax was not eligible for the foreign tax credit. PPL Corp. petitioned the U.S. Supreme Court for a writ of certiorari to review the U.S. Court of Appeals for the Third Circuit decision. On October 29, 2012, the U.S. Supreme Court granted PPL Corp.’s petition for certiorari. The Solicitor General’s petition for writ of certiorari in Entergy’s case was held pending the disposition of the PPL case.
On May 20, 2013, the U.S. Supreme Court issued a unanimous decision in PPL’s favor, holding that the U.K. Windfall Tax is a creditable tax for U.S. federal income tax purposes. On May 28, 2013, the Supreme Court denied the petition for certiorari filed by the Commissioner of Internal Revenue in Entergy’s U.K. Windfall Tax case, allowing the decision in Entergy’s favor from the United States Court of Appeals for the Fifth Circuit to become final.
Income Tax Audits
Entergy and its subsidiaries file U.S. federal and various state and foreign income tax returns. IRS examinations are substantially completedcomplete for years before 2009.2012. All state taxing authorities’ examinations are completedcomplete for years before 2005.2010. Entergy regularly negotiates with the IRS to achieve settlements. The resolution of audit issues could result in significant changes to the amounts of unrecognized tax benefits in the next twelve months.
2004-20052006-2007 IRS Audit
In June 2009, Entergy filed a formal protest withthe first quarter 2015, the IRS Appeals Division indicating disagreement with certain issues containedfinalized tax and interest computations from the 2006-2007 audit that resulted in the 2004-2005 Revenue Agent’s Report (RAR). The most significant issue disputed was the
Entergy Corporation and Subsidiaries
NotesEntergy’s provision for uncertain tax positions related to Financial Statements
inclusion of nuclear decommissioning liabilities in cost of goods sold for the nuclear power plants owned by the Utility resulting from an Application for Change in Accounting Method for tax purposes (the “2004 CAM”).
During the fourth quarter 2012, Entergy settled the position relating to the 2004 CAM. Under the settlement Entergy conceded its tax position, resulting in an increase in taxable incomeaccrued interest of approximately $2.97 billion$20 million, including decreases of approximately $4 million for the tax years 2004 - 2007. The settlement provides thatEntergy Arkansas, $11 million for Entergy Louisiana, is entitled to additional tax depreciation of approximately $547and $1 million for years 2006 and beyond. The deferred tax asset net of interest charges associated with the settlement is $155 million for Entergy. There was a related increase to Entergy Louisiana’s member’s equity account.System Energy.
2008-2009 IRS Audit
In the third quarter 2008, Entergy Louisiana and Entergy Gulf States Louisiana received $679 million and $274.7 million, respectively, from the Louisiana Utilities Restoration Corporation (“LURC”). These receipts from LURC were from the proceeds of a Louisiana Act 55 financing of the costs incurred to restore service following Hurricane Katrina and Hurricane Rita. See Note 2 to the financial statements for further details regarding the financings.
In June 2012, Entergy effectively settled the tax treatment of the storm restoration, which resulted in an increase to 2008 taxable income of $129 million for Entergy Louisiana and $104 million for Entergy Gulf States Louisiana and a reduction of income tax expense of $172 million, including $143 million for Entergy Louisiana and $20 million for Entergy Gulf States Louisiana. Under the terms of an LPSC-approved settlement related to the Louisiana Act 55 financings, Entergy Louisiana and Entergy Gulf States Louisiana recorded, respectively, a $137 million ($84 million net-of-tax) and a $28 million ($17 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect their obligations to customers with respect to the settlement.
In the fourth quarter 2009, Entergy filed Applications for Change in Accounting Method (the “2009 CAM”) for tax purposes with the IRS for certain costs under Section 263A of the Internal Revenue Code. In the Applications, Entergy proposed to treat the nuclear decommissioning liability associated with the operation of its nuclear power plants as a production cost properly includable in cost of goods sold. The effect of the 2009 CAM was a $5.7 billion reduction in 2009 taxable income. The 2009 CAM was adjusted to $9.3 billion in 2012.
In the fourth quarter 2012, the IRS disallowed the reduction to 2009 taxable income related to the 2009 CAM. In the third quarter 2013, the Internal Revenue Service issued its RARRevenue Agent Report (RAR) for the tax years 2008-2009. As a result of the issuance of this RAR, Entergy and the IRS resolved all of the 2008-2009 issues described above except for the 2009 CAM. Entergy disagreesdisagreed with the IRS’s disallowance of the 2009 CAM and filed a protest with the IRS Appeals Division in October 2013.
In August 2015, Entergy and the IRS agreed on October 24, 2013. Two conferences with the Appeals Division have taken place during 2014.treatment of the 2009 position regarding nuclear decommissioning liabilities from the 2008-2009 audit. The resolutionagreement provides that Entergy is entitled to deduct approximately $118 million of this issue isthe $9.3 billion claimed in process.2009. The agreement effectively settled all matters pertaining to the 2009 tax year and increased Entergy’s 2009 federal income tax liability by $2.4 million.
2010-2011 IRS Audit
The IRS completed its examination of the 2010 and 2011 tax years and issued its 2010-2011 RAR in June 2016. Entergy agreed to all proposed adjustments contained in the RAR. As a result of the issuance of the RAR, by the IRS effectively settled all other issues, which resulted in an adjustmentEntergy Louisiana was able to the provision for uncertainrecognize previously unrecognized tax positions.
Other Tax Mattersbenefits as follows:
Entergy regularly negotiates withand the IRS to achieve settlements. The resolutionagreed that $148.6 million of the nuclear decommissioning liability audit issue, discussed above, could resultproceeds received by Entergy Louisiana in significant changes2010 from the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, for the financing of Hurricane Gustav and Hurricane Ike storm costs pursuant to Act 55 of the amountsLouisiana Regular Session of 2007 (Louisiana Act 55) were not taxable. Because the treatment of the financing is settled, Entergy recognized previously unrecognized tax benefits totaling $63.5 million, of which Entergy Louisiana recorded $61.6 million. Entergy Louisiana also accrued a regulatory liability of $16.1 million ($9.9 million net-of-tax) in accordance with the next twelve months.terms of Entergy Louisiana’s previous settlement agreement approved by the LPSC regarding Entergy Louisiana’s obligation to pay to customers savings associated with the Act 55 financing.
In September 2013 the U.S. Treasury DepartmentEntergy and the IRS issued final regulations that provide guidance on the deductibility and capitalization of costs incurred associated with tangible property. Entergy and the Registrant Subsidiaries filed with the IRS an automatic application for change in accounting method which is in compliance with the final regulations and the safe harbor provisions of the relevant IRS Revenue Procedures. Entergy estimates that the effect of this accounting method change will result in a net increase to Entergy’s taxable income of approximately $548 million, which will be recognized over a four year period beginning withagreed upon the tax year ended 2014. The adoptiontreatment of Entergy Louisiana’s regulatory liability related to the final regulations and safe harbor method results in approximate changes in the Registrant Subsidiaries taxableVidalia purchased power agreement. As a result, Entergy Louisiana recognized a previously unrecognized tax benefit of $74.5 million.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
income as follows: an increase of $157 million for Entergy Arkansas, an increase of $42 million for Entergy Gulf States Louisiana, an increase of $49 million for Entergy Louisiana, an increase of $23 million for Entergy Mississippi, an increase of $169 million for Entergy Texas, a decrease of $11 million for Entergy New Orleans, and an increase of $34 million for System Energy.Other Tax Matters
In March 2013, Entergy Louisiana distributed to its parent, Entergy Louisiana Holdings, Inc., Louisiana income tax credits of $20.6 million, which resulted in a decrease in Entergy Louisiana’s member’s equity account.Tax Cuts and Jobs Act
TheDeferred tax liabilities and assets have been adjusted for the effect of the enactment of H.R. 1, also known as the Tax Increase PreventionCuts and Jobs Act of 2014 was enacted in(the Act), signed by President Trump on December 2014.22, 2017. The most significant provisions affectingeffect of the Act for Entergy and the Registrant Subsidiaries wereis the change in the federal corporate income tax rate from 35% to 21%, effective January 1, 2018. Other significant provisions and their effect on Entergy and the Registrant Subsidiaries are summarized below.
The Act limits the deduction for net business interest expense in certain circumstances. The new limitation does not apply to interest expense, however, that is properly allocable to a one-yeartrade or business that furnishes or sells electrical energy, gas, or steam through a local distribution system, or transports gas or steam by pipeline if the rates for such furnishing or sale are subject to ratemaking by a government entity or instrumentality or by a public utility commission. Accordingly, the potential interest expense disallowance is not expected to have a material effect on Entergy’s or the Registrant Subsidiaries’ interest deductions.
The Act extends and modifies the additional first-year depreciation deduction (bonus depreciation). The Act excludes from bonus-eligible qualified property, however, any property used in a trade or business that furnishes or sells electrical energy, gas, or steam through a local distribution system, or transportation of gas or steam by pipeline if the rates for furnishing those services are subject to ratemaking by a government entity or instrumentality or by a public utility commission. Accordingly, the extension of 50% bonus depreciation and the research and experimentation tax credit. These provisionsmodifications generally do not apply to Entergy or the Registrant Subsidiaries.
The Act limits the net operating loss (NOL) deduction for a given year to 80% of taxable income, effective with respect to losses arising in tax years beginning after December 31, 2017. Only NOLs generated after December 31, 2017 are subject to the 80% limitation. Prior law generally provided a two-year carryback and 20-year carryforward for NOLs. The Act provides for the indefinite carryforward of NOLs arising in tax years ending after December 31, 2017, as opposed to the current 20-year carryforward. Because of the indefinite carryforward, the new limitations on NOL utilization are not expected to have a material effect on Entergy or the Registrant Subsidiaries.
The Act also modified Internal Revenue Code section 162(m), which limits the deduction for compensation with respect to certain covered employees to no more than $1 million per year. The Act includes performance-based compensation in the annual computation of the section 162 limitation. The changes are expected to result in an immediate cash flow benefitincrease in disallowed compensation expense, but this limitation is not expected to have a material effect on Entergy or the Registrant Subsidiaries.
Other provisions that are not expected to have a material effect on Entergy or the Registrant Subsidiaries include the following:
repeal of the corporate alternative minimum tax (AMT),
modification to the capital contribution rules under Internal Revenue Code section 118,
repeal of domestic production activities deduction, and
fundamental changes to the taxation of multinational entities.
With respect to the federal corporate income tax rate change from 35% to 21%, Entergy and the Registrant Subsidiaries believe it is probable that a significant portion of the decrease in the net accumulated deferred income tax liability, which is often referred to as “excess ADIT,” will be returned to customers. Accordingly, it is appropriate for Entergy and the Registrant Subsidiaries to establish a regulatory liability for the probable reduction in future revenue. Entergy’s December 31, 2017 balance sheet reflects a regulatory liability of $2.9 billion due to a re-measurement of deferred tax assets and liabilities resulting from the income tax rate change. Entergy’s regulatory liability for income taxes includes a gross-up at the applicable tax rate because of the effect that excess ADIT has on the ratemaking formula. The regulatory liability for income taxes includes the effect of a) the reduction of the net deferred tax liability resulting
Entergy Corporation and Subsidiaries
Notes to Financial Statements
in excess ADIT, b) the tax gross-up of excess ADIT, and c) the effect of the new tax rate on the previous net regulatory asset for income taxes. For the same reasons, the Registrant Subsidiaries’ December 31, 2017 balance sheets reflect net regulatory liabilities for income taxes as follows: Entergy Arkansas, $986 million; Entergy Louisiana, $725 million; Entergy Mississippi, $411 million; Entergy New Orleans, $119 million; Entergy Texas, $413 million; and System Energy, $246 million.
Excess ADIT is generally classified into two categories: 1) the portion that is subject to the normalization requirements of the Act, i.e., “protected”, and 2) the portion that is not subject to such normalization provisions, referred to as “unprotected”. The Act provides that the normalization method of accounting for income taxes is required for excess ADIT associated with public utility property. The Act provides for the use of the average rate assumption method (ARAM) for the determination of the timing of the return of excess ADIT associated with such property. Under ARAM, the excess ADIT is reduced over the remaining life of the asset. Remaining asset lives vary for each Registrant Subsidiary, but the average life of public utility property is typically 30 years or longer. Entergy will return the protected portion of the excess ADIT in conformity with the normalization requirements. The Registrant Subsidiaries’ net regulatory liability for income taxes includes protected excess ADIT as follows: Entergy Arkansas, $554 million; Entergy Louisiana, $782 million; Entergy Mississippi, $274 million; Entergy New Orleans, $71 million; Entergy Texas, $276 million; and System Energy, $217 million.
The return period of the unprotected excess ADIT is subject to the regulatory process in each jurisdiction and has yet to be determined. Further, a portion of the unprotected excess ADIT amount is associated with amounts previously securitized and may be treated differently than other unprotected excess ADIT consistent with applicable agreements and/or not be subject to the same schedule for the return to customers as the remaining unprotected excess ADIT. The Registrant Subsidiaries’ net regulatory liability for income taxes includes unprotected excess ADIT as follows: Entergy Arkansas, $467 million; Entergy Louisiana, $410 million; Entergy Mississippi, $162 million; Entergy New Orleans, $37 million; Entergy Texas, $198 million; and System Energy, $76 million. In addition to the protected and unprotected excess ADIT amounts, the net regulatory liability for income taxes includes other regulatory assets and liabilities for income taxes associated with AFUDC, which is described in Note 1 to the financial statements.
For a discussion of the proceedings commenced or other responses by Entergy’s regulators to the Act, see Note 2 to the financial statements.
Not all of Entergy’s excess ADIT is included in ratemaking. Consequently, Entergy recorded a net decrease in deferred tax assets of $560 million for which there is a corresponding charge to income tax expense for the year ended December 31, 2017. The corresponding income tax expense (or benefit) recorded by the Registrant Subsidiaries is as follows: Entergy Arkansas, ($3 million); Entergy Louisiana, $217 million; Entergy Mississippi, $3 million; Entergy New Orleans, $6 million; Entergy Texas, $3 million; and System Energy, $0.
Included in the effect of the computation of the changes in deferred tax assets and liabilities is the recognition threshold and measurement of uncertain tax positions resulting in unrecognized tax benefits. The final economic outcome of such unrecognized tax benefits is generally the result of a negotiated settlement with the IRS that often differs from the amount that is recorded as realizable under GAAP. The intrinsic uncertainty with respect to all such tax positions means that the difference between current estimates of such amounts likely to be realized and actual amounts realized upon settlement may have an effect on income tax expense and the regulatory liability for income taxes in future periods.
Entergy’s accounting for the effects of the Act is complete using the best estimates and information available to it at this time. Entergy anticipates that the Act, including the federal corporate income tax rate change, however, will continue to have ramifications that require adjustments in the future as certain events occur. These events include: 1) the evaluation by regulators in all of Entergy’s jurisdictions regarding the ratemaking treatment of the Act and excess ADIT; 2) the filing of all applicable federal and state income tax returns that include any tax elections that may change estimates accrued in the year-end recording process; and 3) additional guidance, interpretations, or rulings by the U.S. Department of the Treasury or the IRS. The potential exists for these types of events to result in cash flowfuture adjustments
Entergy Corporation and Subsidiaries
Notes to Financial Statements
because of the difference in the federal corporate income tax rate between past and future periods and the effect of the tax rate change on ratemaking. In turn, these items also will potentially affect the regulatory liability for income taxes.
Louisiana Business Combination
In October 2015 two of Entergy’s Louisiana utilities, Entergy Gulf States Louisiana and Entergy Louisiana, combined their businesses into a legal entity which is identified as Entergy Louisiana herein. The structure of the business combination generated both a permanent difference and a temporary difference under FASB ASC Topic 740. The permanent difference resulted from recognition of the Waterford 3 and River Bend decommissioning liabilities as part of the business combination. Recognition of such decommissioning liabilities required Entergy to also recognize a taxable gain. The taxable gain resulted in a temporary difference because the gain provided for an increase in tax basis. Entergy Louisiana maintained a carryover tax basis in the assets received; and, to the extent that the increase in tax basis will provide additional tax depreciation, Entergy recorded a deferred tax asset. Entergy Louisiana obtained the corresponding deferred tax asset in the business combination. The permanent tax benefit net of ancillary tax charges was approximately $334 million. Consistent with the terms of the stipulated settlement in the business combination proceeding, electric customers of Entergy Louisiana will realize customer credits associated with the business combination. Accordingly, in October 2015, Entergy recorded a regulatory liability of $107 million ($66 million net-of-tax) which partially offsets the effect of the aforementioned deferred tax asset. The deferred tax asset and the regulatory liability, net-of-tax, increased Entergy Louisiana’s member’s equity by $268 million. See Note 2 to the financial statements for further discussion of the business combination.
Entergy Wholesale Commodities Restructuring
The tax classification of the entity that owned FitzPatrick changed in the second quarter 2016. The change in tax classification required Entergy to recognize the plant’s nuclear decommissioning liability for income tax purposes resulting in a tax accounting permanent difference that reduced income tax expense, net of unrecognized tax benefits, by $238 million. The accrual of the nuclear decommissioning liability also required Entergy to recognize a gain for income tax purposes, a significant portion of which resulted in an increase in tax basis of the assets. Recognition of the gain and the increase in tax basis of the assets represents a tax accounting temporary difference. Entergy sold FitzPatrick on March 31, 2017. The removal of the contingencies regarding the sale of the plant and the receipt of NRC approval for the sale allowed Entergy to re-determine the plant’s tax basis. The re-determined basis resulted in a $44 million income tax benefit in the first quarter 2017.
In the second quarter 2017, Entergy changed the tax classification of legal entities that own Entergy Wholesale Commodities nuclear power plants. The change in tax classification required Entergy to recognize the plants’ nuclear decommissioning liabilities for income tax purposes resulting in a tax accounting permanent difference that reduced income tax expense, net of unrecognized tax benefits, by $373 million. The accrual of the nuclear decommissioning liabilities also required Entergy to recognize a gain for income tax purposes, a portion of which resulted in an increase in tax basis of the assets. Recognition of the gain and the increase in tax basis of the assets represents a tax accounting temporary difference.
Tax Accounting Methods
In the fourth quarter 2015, System Energy and Entergy Louisiana adopted a new method of accounting for income tax return purposes in which the companies’ nuclear decommissioning costs will be treated as production costs of electricity includable in cost of goods sold. The new method results in a reduction of taxable income of $1.2 billion for System Energy and $2.2 billion for Entergy Louisiana.
In 2016, Entergy Louisiana elected mark-to-market income tax treatment for various wholesale electric power purchase and sale agreements, including Entergy Louisiana’s contract to purchase electricity from the Vidalia hydroelectric facility and from System Energy under the Unit Power Sales Agreement. The election resulted in a future period.$2.2
Entergy Corporation and Subsidiaries
Notes to Financial Statements
billion deductible temporary difference. In 2017, Entergy New Orleans also elected mark-to-market income tax treatment with respect to the Unit Power Sales Agreement resulting in a $1.1 billion deductible temporary difference.
Accounting Pronouncements
In the first quarter 2017, Entergy implemented ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.” Entergy will now prospectively recognize all income tax effects related to share-based payments through the income statement. In the first quarter 2017, stock option expirations, along with other stock compensation activity, resulted in the write-off of $11.5 million of deferred tax assets. Entergy’s stock-based compensation plans are discussed in Note 12 to the financial statements.
NOTE 4. REVOLVING CREDIT FACILITIES, LINES OF CREDIT, AND SHORT-TERM BORROWINGS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy Corporation has in place a credit facility that has a borrowing capacity of $3.5 billion and expires in March 2019. Entergy Corporation also hasAugust 2022. The facility permits the ability to issueissuance of letters of credit against 50%$20 million of the total borrowing capacity of the credit facility. The commitment fee is currently 0.275%0.225% of the undrawn commitment amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior unsecured debt ratings of Entergy Corporation. The weighted average interest rate for the year ended December 31, 20142017 was 1.93%2.55% on the drawn portion of the facility. Following is a summary of the borrowings outstanding and capacity available under the facility as of December 31, 2014.2017.
| | Capacity (a) | | Borrowings | | Letters of Credit | | Capacity Available | | Borrowings | | Letters of Credit | | Capacity Available |
(In Millions) | | $3,500 | | $695 | | $9 | | $2,796 | | $210 | | $6 | | $3,284 |
Entergy Corporation’s credit facility requires itEntergy to maintain a consolidated debt ratio, as defined, of 65% or less of its total capitalization. Entergy is in compliance with this covenant. If Entergy fails to meet this ratio, or if Entergy Corporation or one of the Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the facility maturity date may occur.
Entergy Corporation has a commercial paper program with a Board-approved program limit of up to $1.52 billion. AtAs of December 31, 2014,2017, Entergy Corporation had $484 million$1.467 billion of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 20142017 was 0.88%1.49%.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 20142017 as follows:
|
| | | | | | | | |
| | | | | | | | Amount Drawn
as of
|
| Company | | Expiration Date | | Amount of Facility | | Interest Rate (a) | | Amount Drawn as of December 31, 20142017 | | Letters of Credit Outstanding as of December 31, 2017 |
| Entergy Arkansas | | April 20152018 | | $20 million (b) | | 1.67%2.82% | | — | | — |
| Entergy Arkansas | | March 2019August 2022 | | $150 million (c) | | 1.67%2.82% | | — |
Entergy Gulf States Louisiana | | March 2019 | | $150 million (d) | | 1.42% | | — |
| Entergy Louisiana | | March 2019August 2022 | | $200350 million (e)(c) | | 1.42%2.82% | | — | | $9.1 million |
| Entergy Mississippi | | May 2018 | | $10 million (d) | | 3.07% | | — | | — |
| Entergy Mississippi | | May 20152018 | | $1020 million (f)(d) | | 1.67%3.07% | | — | | — |
| Entergy Mississippi | | May 20152018 | | $35 million (f)(d) | | 1.67%3.07% | | — | | — |
| Entergy Mississippi | | May 2015 | | $20 million (f) | | 1.67% | | — |
Entergy Mississippi | | May 20152018 | | $37.5 million (f)(d) | | 1.67%3.07% | | — | | — |
| Entergy New Orleans | | November 20152018 | | $25 million (c) | | 1.92%3.04% | | — | | $0.8 million |
| Entergy Texas | | March 2019August 2022 | | $150 million (g)(c) | | 1.67%3.07% | | — | | $25.6 million |
| |
| (a) | The interest rate is the estimated interest rate as of December 31, 20142017 that would behave been applied to outstanding borrowings under the facility. |
| |
| (b) | Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable at Entergy Arkansas’s option. |
| |
| (c) | The credit facility allows Entergy Arkansas to issuepermits the issuance of letters of credit against 50%a portion of the borrowing capacity of the facility. As of December 31, 2014, no letters of credit were outstanding.facility as follows: $5 million for Entergy Arkansas; $15 million for Entergy Louisiana; $10 million for Entergy New Orleans; and $30 million for Entergy Texas. |
| |
| (d) | The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, no letters of credit were outstanding. |
| |
(e) | The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, no letters of credit were outstanding. |
| |
(f) | Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option. |
| |
(g) | The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, $1.3 million in letters of credit were outstanding. |
The commitment fees on the credit facilities range from 0.125%0.075% to 0.275% of the undrawn commitment amount. Each of the credit facilities requires the Registrant Subsidiary borrower to maintain a debt ratio, as defined, of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In addition, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each entered into one or more uncommitted standby letter of credit facilities as a means to post collateral to support its obligations related to MISO. Following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2014:2017:
|
| | | | | | | |
| Company | | | Amount of Uncommitted Facility | | Letter of Credit Fee | | Letters of Credit Issued as of December 31, 2014 2017 (a) |
| Entergy Arkansas | | | $25 million | | 0.70% | | $2.01.0 million |
Entergy Gulf States Louisiana | | | $75125 million | | 0.70% | | $27.929.7 million |
Entergy LouisianaMississippi | | $40 million | | 0.70% | | $15.3 million |
| Entergy New Orleans | | $15 million | | 1.00% | | $1.4 million |
| Entergy Texas | | $50 million | | 0.70% | | $4.7 million |
Entergy Mississippi | | | $40 million | | 0.70% | | $14.4 million |
Entergy Mississippi | | | $40 million | | 1.50% | | — |
Entergy New Orleans | | | $15 million | | 0.75% | | $8.1 million |
Entergy Texas | | | $50 million | | 0.70% | | $24.522.8 million |
| |
| (a) | As of December 31, 2017, letters of credit posted with MISO covered financial transmission right exposure of $0.2 million for Entergy Arkansas, $0.1 million for Entergy Mississippi, and $0.05 million for Entergy Texas. See Note 15 to the financial statements for discussion of financial transmission rights. |
The short-term borrowings of the Registrant Subsidiaries are limited to amounts authorized by the FERC. The current FERC-authorized limits are effective through October 31, 2015.2019. In addition to borrowings from commercial
Entergy Corporation and Subsidiaries
Notes to Financial Statements
banks, these companies are authorized under a FERC order tomay also borrow from the Entergy System money pool.pool and from other internal short-term borrowing arrangements. The money pool is anand the other internal borrowing arrangements are inter-company borrowing arrangementarrangements designed to reduce the Utility subsidiaries’ dependence on external short-term borrowings. Borrowings from the money poolinternal and external short-termshort term borrowings combined may not exceed the FERC-authorized limits. The following are the FERC-authorized limits for short-term borrowings and the outstanding short-term borrowings as of December 31, 20142017 (aggregating both money poolinternal and external short-term borrowings) for the Registrant Subsidiaries:
|
| | | |
| Authorized | | Borrowings |
| (In Millions) |
Entergy Arkansas | $250 | | — |
Entergy Gulf States Louisiana | $200 | | — |
Entergy Louisiana | $250 | | — |
Entergy Mississippi | $175 | | — |
Entergy New Orleans | $100 | | — |
Entergy Texas | $200 | | — |
System Energy | $200 | | — |
|
| | | |
| | Authorized | | Borrowings |
| | (In Millions) |
| Entergy Arkansas | $250 | | $166 |
| Entergy Louisiana | $450 | | — |
| Entergy Mississippi | $175 | | — |
| Entergy New Orleans | $150 | | — |
| Entergy Texas | $200 | | — |
| System Energy | $200 | | — |
Entergy Nuclear Vermont Yankee Credit Facilities
In January 2015, Entergy Nuclear Vermont Yankee entered intohas a credit facility guaranteed by Entergy Corporation with a borrowing capacity of $60$145 million whichthat expires in January 2018.November 2020. Entergy Nuclear Vermont Yankee does not have the ability to issue letters of credit against thisthe credit facility. This facility provides working capital to Entergy Nuclear Vermont Yankee for general business purposes including, without limitation, the decommissioning of Entergy Nuclear Vermont Yankee’s nuclear facilities.Yankee. The commitment fee is currently 0.25%0.20% of the undrawn commitment amount. As of December 31, 2017, $104 million in cash borrowings were outstanding under the credit facility. The weighted average interest rate that would have applied to any outstanding borrowings atfor the time Entergy Nuclear Vermont Yankee entered into the facilityyear ended December 31, 2017 was 1.92%2.64% on the drawn portion of the facility.
Also in January 2015, Entergy Nuclear Vermont Yankee entered intoalso had an uncommitted credit facility guaranteed by Entergy Corporation
with a borrowing capacity of $85 million which expiresthat expired in January 2018. Entergy Nuclear Vermont Yankee does not haveAs of December 31, 2017, there were no cash borrowings outstanding under the ability to issue letters of credit against this facility. This facility provides an additional funding source to Entergy Nuclear Vermont Yankee for general business purposes including, without limitation, the decommissioning of Entergy Nuclear Vermont Yankee’s nuclear facilities. The weighted averageestimated interest rate that
Entergy Corporation and Subsidiaries
Notes to Financial Statements
for the year ended December 31, 2017 would have applied to any outstanding borrowings at the time Entergy Nuclear Vermont Yankee entered into the facility was 1.92%been 3.07% on the drawn portion of the facility.
Variable Interest Entities (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy)
See Note 1817 to the financial statements for a discussion of the consolidation of the nuclear fuel company variable interest entities (VIE). The nuclear fuel company variable interest entities have credit facilities and also issue commercial paper toTo finance the acquisition and ownership of nuclear fuel, as followsthe nuclear fuel company VIEs have credit facilities and three of the four VIEs also issue commercial paper, details of which follow as of December 31, 2014:2017:
| | Company | | Expiration Date | | Amount of Facility | | Weighted Average Interest Rate on Borrowings (a) | | Amount Outstanding as of December 31, 2014 | | Expiration Date | | Amount of Facility | | Weighted Average Interest Rate on Borrowings (a) | | Amount Outstanding as of December 31, 2017 |
| | | (Dollars in Millions) | | (Dollars in Millions) |
| Entergy Arkansas VIE | | June 2016 | | $85 | | 1.61% | | $48.0 | | May 2019 | | $80 | | 2.87% | |
| $74.9 | (b) |
| Entergy Gulf States Louisiana VIE | | June 2016 | | $100 | | n/a | | $— | |
| Entergy Louisiana VIE | | June 2016 | | $90 | | 1.54% | | $46.0 | |
| Entergy Louisiana River Bend VIE | | | May 2019 | | $105 | | 2.38% | |
| $65.7 |
|
| Entergy Louisiana Waterford VIE | | | May 2019 | | $85 | | 2.64% | |
| $79.9 | (c) |
| System Energy VIE | | June 2016 | | $125 | | 1.68% | | $20.4 | | May 2019 | | $120 | | 2.52% | |
| $67.8 | (d) |
| |
| (a) | Includes letter of credit fees and bank fronting fees on commercial paper issuances by the nuclear fuel company variable interest entities for Entergy Arkansas, Entergy Louisiana, and System Energy. The nuclear fuel company variable interest entity for Entergy Gulf States Louisiana does not issue commercial paper, but borrows directly on its bank credit facility. |
Amounts outstanding on the 124
Entergy Gulf States Louisiana nuclear fuel Corporation and Subsidiaries
Notes to Financial Statements
company variable interest entity’s credit facility, if any, are included in long-term debtentity for Entergy Louisiana River Bend does not issue commercial paper, but borrows directly on its balance sheet and commercial paper outstanding for the other nuclear fuel company variable interest entities is classified as a current liability on the respective balance sheets. bank credit facility.
| |
| (b) | Includes borrowings on the credit facility and commercial paper. Commercial paper is classified as a current liability and the amount outstanding for Entergy Arkansas VIE as of December 31, 2017 was $50 million. |
| |
| (c) | Includes borrowings on the credit facility and commercial paper. Commercial paper is classified as a current liability and the amount outstanding for Entergy Louisiana Waterford VIE as of December 31, 2017 was $43.5 million. |
| |
| (d) | Includes borrowings on the credit facility and commercial paper. Commercial paper is classified as a current liability and the amount outstanding for System Energy VIE as of December 31, 2017 was $17.8 million. |
The commitment fees on the credit facilities are 0.10% of the undrawn commitment amount for the Entergy
Louisiana and Arkansas, Entergy Gulf States Louisiana, VIEs and 0.125% of the undrawn commitment amount for the Entergy
Arkansas and System Energy VIEs. Each credit facility requires the respective lessee of nuclear fuel (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, or Entergy Corporation as guarantor for System Energy) to maintain a consolidated debt ratio, as defined, of 70% or less of its total capitalization.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The nuclear fuel company variable interest entities had notes payable that are included in debt on the respective balance sheets as of December 31, 20142017 as follows:
|
| | | | |
| Company | | Description | | Amount |
| | | | |
Entergy Arkansas VIE | | 3.23% Series J due July 2016 | | $55 million |
Entergy Arkansas VIE | | 2.62% Series K due December 2017 | | $60 million |
| Entergy Arkansas VIE | | 3.65% Series L due July 2021 | | $90 million |
Entergy Gulf States LouisianaArkansas VIE | | 3.25%3.17% Series QM due July 2017December 2023 | | $7540 million |
Entergy Gulf States Louisiana River Bend VIE | | 3.38% Series R due August 2020 | | $70 million |
Entergy Louisiana VIE | | 3.30% Series F due March 2016 | | $20 million |
Entergy Louisiana VIE | | 3.25% Series G due July 2017 | | $25 million |
Entergy LouisianaWaterford VIE | | 3.92% Series H due February 2021 | | $40 million |
System EnergyEntergy Louisiana Waterford VIE | | 5.33%3.22% Series GI due April 2015December 2023 | | $60 million |
System Energy VIE | | 4.02% Series H due February 2017 | | $5020 million |
| System Energy VIE | | 3.78% Series I due October 2018 | | $85 million |
In accordance with regulatory treatment, interest on the nuclear fuel company variable interest entities’ credit facilities, commercial paper, and long-term notes payable is reported in fuel expense.
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through October 20152019 for issuances by its nuclear fuel company variable interest entity.entities.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 5. LONG - TERM DEBT (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Long-term debt for Entergy Corporation and subsidiaries as of December 31, 20142017 and 20132016 consisted of:
|
| | | | | | | | | | | | | | |
Type of Debt and Maturity | | Weighted Average Interest Rate December 31, 2014 | | Interest Rate Ranges at December 31, | | Outstanding at December 31, |
| 2014 | | 2013 | | 2014 | | 2013 |
| | | | | | | | | (In Thousands) |
| Mortgage Bonds | | | | | | | | | | |
| 2014-2019 | | 6.49% | | 3.25%-7.13% | | 1.88%-7.13% | |
| $1,650,000 |
| |
| $2,110,000 |
|
| 2020-2024 | | 4.18% | | 3.05%-5.60% | | 3.05%-5.60% | | 3,483,303 |
| | 3,008,363 |
|
| 2025-2029 | | 4.54% | | 3.78%-5.66% | | 4.44%-5.66% | | 762,859 |
| | 462,914 |
|
| 2032-2039 | | 6.16% | | 5.90%-6.38% | | 5.90%-7.88% | | 660,000 |
| | 980,000 |
|
| 2040-2064 | | 5.28% | | 4.70%-6.20% | | 4.70%-6.20% | | 2,215,000 |
| | 1,410,000 |
|
| Governmental Bonds (a) | | | | | | | | | | |
| 2015-2017 | | 1.75% | | 1.55%-2.88% | | 1.55%-2.88% | | 86,655 |
| | 86,655 |
|
| 2021-2022 | | 5.31% | | 2.375%-5.88% | | 2.375%-5.88% | | 291,000 |
| | 291,000 |
|
| 2028-2030 | | 5.00% | | 5.00% | | 5.00% | | 198,680 |
| | 198,680 |
|
| Securitization Bonds | | | | | | | | | | |
| 2016-2023 | | 3.88% | | 2.04%-5.93% | | 2.04%-5.93% | | 785,059 |
| | 883,243 |
|
| Variable Interest Entities Notes Payable (Note 4) | | | | | | | | | | |
| 2014-2021 | | 3.53% | | 2.62%-5.33% | | 1.38%-5.69% | | 630,000 |
| | 634,800 |
|
| Entergy Corporation Notes | | | | | | | | | | |
| due September 2015 | | n/a | | 3.625% | | 3.625% | | 550,000 |
| | 550,000 |
|
| due January 2017 | | n/a | | 4.70% | | 4.70% | | 500,000 |
| | 500,000 |
|
| due September 2020 | | n/a | | 5.125% | | 5.125% | | 450,000 |
| | 450,000 |
|
| Note Payable to NYPA | | (b) | | (b) | | (b) | | 79,638 |
| | 95,011 |
|
| 5 Year Credit Facility (Note 4) | | n/a | | 1.93% | | 1.96% | | 695,000 |
| | 255,000 |
|
| Long-term DOE Obligation (c) | | — | | — | | — | | 181,329 |
| | 181,253 |
|
| Waterford 3 Lease Obligation (d) | | n/a | | 7.45% | | 7.45% | | 128,488 |
| | 148,716 |
|
| Grand Gulf Lease Obligation (d) | | n/a | | 5.13% | | 5.13% | | 50,671 |
| | 97,414 |
|
| Term Loan - Entergy Arkansas | | n/a | | — | | 1.13% | | — |
| | 250,000 |
|
| Unamortized Premium and Discount - Net | | | | | | | | (12,529 | ) | | (11,172 | ) |
| Other | | | | | | | | 14,331 |
| | 14,367 |
|
| Total Long-Term Debt | | | | | | | | 13,399,484 |
| | 12,596,244 |
|
| Less Amount Due Within One Year | | | | | | | | 899,375 |
| | 457,095 |
|
| Long-Term Debt Excluding Amount Due Within One Year | | | | | | | |
| $12,500,109 |
| |
| $12,139,149 |
|
| Fair Value of Long-Term Debt (e) | | | | | | | |
| $13,607,242 |
| |
| $12,439,785 |
|
|
| | | | | | | | | | | | | | |
| Type of Debt and Maturity | | Weighted Average Interest Rate December 31, 2017 | | Interest Rate Ranges at December 31, | | Outstanding at December 31, |
| 2017 | | 2016 | | 2017 | | 2016 |
| | | | | | | | | (In Thousands) |
| Mortgage Bonds | | | | | | | | | | |
| 2018-2022 | | 4.39% | | 2.55%-7.125% | | 2.55%-7.125% | |
| $2,550,000 |
| |
| $2,550,000 |
|
| 2023-2027 | | 3.72% | | 2.40%-5.59% | | 2.40%-5.59% | | 4,735,000 |
| | 3,765,000 |
|
| 2028-2031 | | 3.06% | | 2.85%-3.25% | | 2.85%-3.25% | | 1,125,000 |
| | 1,125,000 |
|
| 2044-2066 | | 5.00% | | 4.70%-5.625% | | 4.70%-5.625% | | 2,960,000 |
| | 2,960,000 |
|
| Governmental Bonds (a) | | | | | | | | | | |
| 2017-2022 | | 5.20% | | 2.375%-5.875% | | 1.55%-5.875% | | 179,000 |
| | 233,700 |
|
| 2028-2030 | | 3.45% | | 3.375%-3.50% | | 3.375%-3.50% | | 198,680 |
| | 198,680 |
|
| Securitization Bonds | | | | | | | | | | |
| 2018-2027 | | 3.79% | | 2.04%-5.93% | | 2.04%-5.93% | | 551,499 |
| | 669,310 |
|
| Variable Interest Entities Notes Payable (Note 4) | | | | | | | | | | |
| 2017-2023 | | 3.48% | | 3.17%-3.92% | | 2.62%-4.02% | | 345,000 |
| | 555,000 |
|
| Entergy Corporation Notes | | | | | | | | | | |
| due September 2020 | | n/a | | 5.125% | | 5.125% | | 450,000 |
| | 450,000 |
|
| due July 2022 | | n/a | | 4.00% | | 4.00% | | 650,000 |
| | 650,000 |
|
| due September 2026 | | n/a | | 2.95% | | 2.95% | | 750,000 |
| | 750,000 |
|
| 5 Year Credit Facility (Note 4) | | n/a | | 2.55% | | 2.23% | | 210,000 |
| | 700,000 |
|
| Vermont Yankee Credit Facility (Note 4) | | n/a | | 2.64% | | 2.17% | | 103,500 |
| | 44,500 |
|
| Entergy Arkansas VIE Credit Facility (Note 4) | | n/a | | 2.87% | | — | | 24,900 |
| | — |
|
| Entergy Louisiana River Bend VIE Credit Facility (Note 4) | | n/a | | 2.38% | | — | | 65,650 |
| | — |
|
| Entergy Louisiana Waterford VIE Credit Facility (Note 4) | | n/a | | 2.64% | | — | | 36,360 |
| | — |
|
| System Energy VIE Credit Facility (Note 4) | | n/a | | 2.52% | | — | | 50,000 |
| | — |
|
| Long-term DOE Obligation (b) | | — | | — | | — | | 183,435 |
| | 181,853 |
|
| Waterford 3 Lease Obligation (c) | | n/a | | — | | 8.09% | | — |
| | 57,492 |
|
| Waterford Series Collateral Trust Mortgage Notes due 2017 (c) | | n/a | | — | | (d) | | — |
| | 42,703 |
|
| Grand Gulf Lease Obligation (c) | | n/a | | 5.13% | | 5.13% | | 34,356 |
| | 34,359 |
|
| Unamortized Premium and Discount - Net | | | | | | | | (13,911 | ) | | (19,397 | ) |
| Unamortized Debt Issuance Costs | | | | | | | | (126,033 | ) | | (128,849 | ) |
| Other | | | | | | | | 12,830 |
| | 13,204 |
|
| Total Long-Term Debt | | | | | | | | 15,075,266 |
| | 14,832,555 |
|
| Less Amount Due Within One Year | | | | | | | | 760,007 |
| | 364,900 |
|
| Long-Term Debt Excluding Amount Due Within One Year | | | | | | | |
| $14,315,259 |
| |
| $14,467,655 |
|
| Fair Value of Long-Term Debt (e) | | | | | | | |
| $15,367,453 |
| |
| $14,815,535 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
| (a) | Consists of pollution control revenue bonds and environmental revenue bonds, some of which are secured by collateral first mortgage bonds. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
(b) | These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%. |
| |
(c)(b) | Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service. The contracts include a one-time fee for generation prior to April 7, 1983. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt. |
| |
(d)(c) | See Note 10 to the financial statements for further discussion of the Waterford 3 lease obligation and Entergy Louisiana’s acquisition of the equity participant’s beneficial interest in the Waterford 3 leased assets and for further discussion of the Grand Gulf lease obligations.obligation. |
| |
| (d) | This note did not have a stated interest rate, but had an implicit interest rate of 7.458%. |
| |
| (e) | The fair value excludes lease obligations of $128 million at Entergy Louisiana and $51$34 million at System Energy and long-term DOE obligations of $181$183 million at Entergy Arkansas, and the note payable to NYPA of $80 million at Entergy, and includes debt due within one year. Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 1615 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported trades. |
The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2014,2017, for the next five years are as follows:
|
| | | |
| | Amount |
| | (In Thousands) |
| 2015 |
| $310,566 |
|
| 2016 |
| $765,821 |
|
| 2017 |
| $266,801 |
|
| 2018 |
| $1,336,396 |
|
| 2019 |
| $1,492,107 |
|
|
| | | |
| | Amount |
| | (In Thousands) |
| 2018 |
| $760,000 |
|
| 2019 |
| $857,679 |
|
| 2020 |
| $898,500 |
|
| 2021 |
| $960,764 |
|
| 2022 |
| $1,304,431 |
|
In November 2000, Entergy’s non-utility nuclear business purchased the FitzPatrick and Indian Point 3 power plants in a seller-financed transaction. Entergy issued notes to NYPA with seven annual installmentsAs part of approximately $108 million commencing one year from the date of the closing, and eight annual installments of $20 million commencing eight years from the date of the closing. These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%. In accordance with the purchase agreement with NYPA, Entergy recorded a liability representing the purchasenet present value of Indian Point 2 in 2001 resulted inthe payments Entergy becomingwould be liable to NYPA for an additional $10each year that the FitzPatrick and Indian Point 3 power plants would run beyond their respective original NRC license expiration date. In October 2015, Entergy announced a planned shutdown of FitzPatrick at the end of its fuel cycle. As a result of the announcement, Entergy reduced this liability by $26.4 million per year for 10 years, beginning in September 2003. This liability was recorded uponpursuant to the terms of the purchase ofagreement. In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 2 in September 2001.3 and FitzPatrick plants to Entergy. As part of the trust transfer agreement, the original decommissioning agreements were amended, and the Entergy subsidiaries’ obligation to make additional license extension payments to NYPA was eliminated. In July 2003 a payment of $102 million was made prior to maturity onthe third quarter 2016, Entergy removed the note payable to NYPA. Under a provision in a letter of credit supporting these notes, if certain of$35.1 million from the Utility operating companies or System Energy were to default on other indebtedness, Entergy could be required to post collateral to support the letter of credit.consolidated balance sheet.
Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through October 2015.2019. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2015.2018. Entergy New Orleans has also obtained long-term financing authorization from the City Council that extends through July 2016.June 2018, as the City Council has concurrent jurisdiction with the FERC over such issuances.
Capital Funds Agreement
Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:
maintain System Energy’s equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);
Entergy Corporation and Subsidiaries
Notes to Financial Statements
permit the continued commercial operation of Grand Gulf;
pay in full all System Energy indebtedness for borrowed money when due; and
enable System Energy to make payments on specific System Energy debt, under supplementsa supplement to the agreement assigning System Energy’s rights in the agreement as security for the specific debt.
Long-term debt for the Registrant Subsidiaries as of December 31, 2017 and 2016 consisted of:
|
| | | | | | | | |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| Entergy Arkansas | | | | |
| Mortgage Bonds: | | | | |
| 3.75% Series due February 2021 | |
| $350,000 |
| |
| $350,000 |
|
| 3.05% Series due June 2023 | | 250,000 |
| | 250,000 |
|
| 3.7% Series due June 2024 | | 375,000 |
| | 375,000 |
|
| 3.5% Series due April 2026 | | 600,000 |
| | 380,000 |
|
| 4.95% Series due December 2044 | | 250,000 |
| | 250,000 |
|
| 4.90% Series due December 2052 | | 200,000 |
| | 200,000 |
|
| 4.75% Series due June 2063 | | 125,000 |
| | 125,000 |
|
| 4.875% Series due September 2066 | | 410,000 |
| | 410,000 |
|
| Total mortgage bonds | | 2,560,000 |
| | 2,340,000 |
|
| Governmental Bonds (a): | | | | |
| 1.55% Series due 2017, Jefferson County (d) | | — |
| | 54,700 |
|
| 2.375% Series due 2021, Independence County (d) | | 45,000 |
| | 45,000 |
|
| Total governmental bonds | | 45,000 |
| | 99,700 |
|
| Variable Interest Entity Notes Payable and Credit Facility (Note 4): | | | | |
| 2.62% Series K due December 2017 | | — |
| | 60,000 |
|
| 3.65% Series L due July 2021 | | 90,000 |
| | 90,000 |
|
| 3.17% Series M due December 2023 | | 40,000 |
| | 40,000 |
|
| Credit Facility due May 2019, weighted avg rate 2.87% | | 24,900 |
| | — |
|
| Total variable interest entity notes payable and credit facility | | 154,900 |
| | 190,000 |
|
| Securitization Bonds: | | | | |
| 2.30% Series Senior Secured due August 2021 | | 35,764 |
| | 49,548 |
|
| Total securitization bonds | | 35,764 |
| | 49,548 |
|
| Other: | | | | |
| Long-term DOE Obligation (b) | | 183,435 |
| | 181,853 |
|
| Unamortized Premium and Discount – Net | | 5,307 |
| | 984 |
|
| Unamortized Debt Issuance Costs | | (34,049 | ) | | (34,357 | ) |
| Other | | 2,042 |
| | 2,057 |
|
| Total Long-Term Debt | | 2,952,399 |
| | 2,829,785 |
|
| Less Amount Due Within One Year | | — |
| | 114,700 |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $2,952,399 |
| |
| $2,715,085 |
|
| Fair Value of Long-Term Debt (c) | |
| $2,865,844 |
| |
| $2,623,910 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Long-term debt for the Registrant Subsidiaries as of December 31, 2014 and 2013 consisted of:
|
| | | | | | | | |
| | | 2014 | | 2013 |
| | | (In Thousands) |
| Entergy Arkansas | | | | |
| Mortgage Bonds: | | | | |
| 5.0% Series due July 2018 | |
| $— |
| |
| $115,000 |
|
| 3.75% Series due February 2021 | | 350,000 |
| | 350,000 |
|
| 3.05% Series due June 2023 | | 250,000 |
| | 250,000 |
|
| 3.7% Series due June 2024 | | 375,000 |
| | — |
|
| 5.66% Series due February 2025 | | 175,000 |
| | 175,000 |
|
| 5.9% Series due June 2033 | | 100,000 |
| | 100,000 |
|
| 6.38% Series due November 2034 | | 60,000 |
| | 60,000 |
|
| 5.75% Series due November 2040 | | 225,000 |
| | 225,000 |
|
| 4.95% Series due December 2044 | | 250,000 |
| | — |
|
| 4.9% Series due December 2052 | | 200,000 |
| | 200,000 |
|
| 4.75% Series due June 2063 | | 125,000 |
| | 125,000 |
|
| Total mortgage bonds | | 2,110,000 |
| | 1,600,000 |
|
| Governmental Bonds (a): | | | | |
| 1.55% Series due 2017, Jefferson County (d) | | 54,700 |
| | 54,700 |
|
| 2.375% Series due 2021, Independence County (d) | | 45,000 |
| | 45,000 |
|
| Total governmental bonds | | 99,700 |
| | 99,700 |
|
| Variable Interest Entity Notes Payable (Note 4): | | | | |
| 5.69% Series I due July 2014 | | — |
| | 70,000 |
|
| 3.23% Series J due July 2016 | | 55,000 |
| | 55,000 |
|
| 2.62% Series K due December 2017 | | 60,000 |
| | 60,000 |
|
| 3.65% Series L due July 2021 | | 90,000 |
| | — |
|
| Total variable interest entity notes payable | | 205,000 |
| | 185,000 |
|
| Securitization Bonds: | | | | |
| 2.30% Series Senior Secured due August 2021 | | 76,185 |
| | 88,986 |
|
| Total securitization bonds | | 76,185 |
| | 88,986 |
|
| Other: | | | | |
| Long-term DOE Obligation (b) | | 181,329 |
| | 181,253 |
|
| Term Loan due January 2015, weighted avg rate 1.13% | | — |
| | 250,000 |
|
| Unamortized Premium and Discount – Net | | (2,960 | ) | | (1,242 | ) |
| Other | | 2,089 |
| | 2,105 |
|
| Total Long-Term Debt | | 2,671,343 |
| | 2,405,802 |
|
| Less Amount Due Within One Year | | — |
| | 70,000 |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $2,671,343 |
| |
| $2,335,802 |
|
| Fair Value of Long-Term Debt (c) | |
| $2,517,633 |
| |
| $2,142,527 |
|
|
| | | | | | | | |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| Entergy Louisiana | | | | |
| Mortgage Bonds: | | | | |
| 6.0% Series due May 2018 | |
| $375,000 |
| |
| $375,000 |
|
| 6.50% Series due September 2018 | | 300,000 |
| | 300,000 |
|
| 3.95% Series due October 2020 | | 250,000 |
| | 250,000 |
|
| 4.8% Series due May 2021 | | 200,000 |
| | 200,000 |
|
| 3.3% Series due December 2022 | | 200,000 |
| | 200,000 |
|
| 4.05% Series due September 2023 | | 325,000 |
| | 325,000 |
|
| 5.59% Series due October 2024 | | 300,000 |
| | 300,000 |
|
| 5.40% Series due November 2024 | | 400,000 |
| | 400,000 |
|
| 3.78% Series due April 2025 | | 110,000 |
| | 110,000 |
|
| 3.78% Series due April 2025 | | 190,000 |
| | 190,000 |
|
| 4.44% Series due January 2026 | | 250,000 |
| | 250,000 |
|
| 2.40% Series due October 2026 | | 400,000 |
| | 400,000 |
|
| 3.12% Series due September 2027 | | 450,000 |
| | — |
|
| 3.25% Series due April 2028 | | 425,000 |
| | 425,000 |
|
| 3.05% Series due June 2031 | | 325,000 |
| | 325,000 |
|
| 5.0% Series due July 2044 | | 170,000 |
| | 170,000 |
|
| 4.95% Series due January 2045 | | 450,000 |
| | 450,000 |
|
| 5.25% Series due July 2052 | | 200,000 |
| | 200,000 |
|
| 4.70% Series due June 2063 | | 100,000 |
| | 100,000 |
|
| 4.875% Series due September 2066 | | 270,000 |
| | 270,000 |
|
| Total mortgage bonds | | 5,690,000 |
| | 5,240,000 |
|
| Governmental Bonds (a): | | | | |
| 3.375 % Series due 2028, Louisiana Public Facilities Authority (d) | | 83,680 |
| | 83,680 |
|
| 3.50% Series due 2030, Louisiana Public Facilities Authority (d) | | 115,000 |
| | 115,000 |
|
| Total governmental bonds | | 198,680 |
| | 198,680 |
|
| Variable Interest Entity Notes Payable and Credit Facilities (Note 4): | | | | |
| 3.25% Series G due July 2017 | | — |
| | 25,000 |
|
| 3.25% Series Q due July 2017 | | — |
| | 75,000 |
|
| 3.38% Series R due August 2020 | | 70,000 |
| | 70,000 |
|
| 3.92% Series H due February 2021 | | 40,000 |
| | 40,000 |
|
| 3.22% Series I due December 2023 | | 20,000 |
| | 20,000 |
|
| Credit Facility due May 2019, weighted avg rate 2.38% | | 65,650 |
| | — |
|
| Credit Facility due May 2019, weighted avg rate 2.64% | | 36,360 |
| | — |
|
| Total variable interest entity notes payable and credit facilities | | 232,010 |
| | 230,000 |
|
| Securitization Bonds: | | | | |
| 2.04% Series Senior Secured due September 2023 | | 79,228 |
| | 100,972 |
|
| Total securitization bonds | | 79,228 |
| | 100,972 |
|
| Other: | | | | |
| Waterford 3 Lease Obligation (Note 10) (e) | | — |
| | 57,492 |
|
| Waterford Series Collateral Trust Mortgage Notes due 2017 (Note 10) (f) | | — |
| | 42,703 |
|
| Unamortized Premium and Discount - Net | | (13,877 | ) | | (14,917 | ) |
| Unamortized Debt Issuance Costs | | (48,540 | ) | | (48,972 | ) |
| Other | | 6,570 |
| | 6,833 |
|
| Total Long-Term Debt | | 6,144,071 |
| | 5,812,791 |
|
| Less Amount Due Within One Year | | 675,002 |
| | 200,198 |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $5,469,069 |
| |
| $5,612,593 |
|
| Fair Value of Long-Term Debt (c) | |
| $6,389,774 |
| |
| $5,929,488 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | |
| | | 2014 | | 2013 |
| | | (In Thousands) |
| Entergy Gulf States Louisiana | | | | |
| Mortgage Bonds: | | | | |
| 6.0% Series due May 2018 | |
| $375,000 |
| |
| $375,000 |
|
| 3.95% Series due October 2020 | | 250,000 |
| | 250,000 |
|
| 5.59% Series due October 2024 | | 300,000 |
| | 300,000 |
|
| 3.78% Series due April 2025 | | 110,000 |
| | — |
|
| 6.2% Series due July 2033 | | 240,000 |
| | 240,000 |
|
| 6.18% Series due March 2035 | | 85,000 |
| | 85,000 |
|
| Total mortgage bonds | | 1,360,000 |
| | 1,250,000 |
|
| Governmental Bonds (a): | | | | |
| 2.875% Series due 2015, Louisiana Public Facilities Authority (d) | | 31,955 |
| | 31,955 |
|
| 5.0% Series due 2028, Louisiana Public Facilities Authority (d) | | 83,680 |
| | 83,680 |
|
| Total governmental bonds | | 115,635 |
| | 115,635 |
|
| Variable Interest Entity Notes Payable (Note 4): | | | | |
| 3.25% Series Q due July 2017 | | 75,000 |
| | 75,000 |
|
| 3.38% Series R due August 2020 | | 70,000 |
| | 70,000 |
|
| Credit Facility due June 2016, weighted avg rate 1.38% | | — |
| | 14,800 |
|
| Total variable interest entity notes payable | | 145,000 |
| | 159,800 |
|
| Other: | | | | |
| Unamortized Premium and Discount – Net | | (1,422 | ) | | (1,574 | ) |
| Other | | 3,604 |
| | 3,604 |
|
| Total Long-Term Debt | | 1,622,817 |
| | 1,527,465 |
|
| Less Amount Due Within One Year | | 31,955 |
| | — |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $1,590,862 |
| |
| $1,527,465 |
|
| Fair Value of Long-Term Debt (c) | |
| $1,743,143 |
| |
| $1,631,308 |
|
|
| | | | | | | | |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| Entergy Mississippi | | | | |
| Mortgage Bonds: | | | | |
| 6.64% Series due July 2019 | |
| $150,000 |
| |
| $150,000 |
|
| 3.1% Series due July 2023 | | 250,000 |
| | 250,000 |
|
| 3.75% Series due July 2024 | | 100,000 |
| | 100,000 |
|
| 3.25% Series due December 2027 | | 150,000 |
| | — |
|
| 2.85% Series due June 2028 | | 375,000 |
| | 375,000 |
|
| 4.90% Series due October 2066 | | 260,000 |
| | 260,000 |
|
| Total mortgage bonds | | 1,285,000 |
| | 1,135,000 |
|
| Other: | | | | |
| Unamortized Premium and Discount – Net | | (1,155 | ) | | (766 | ) |
Unamortized Debt Issuance Costs
| | (13,723 | ) | | (13,318 | ) |
| Total Long-Term Debt | | 1,270,122 |
| | 1,120,916 |
|
| Less Amount Due Within One Year | | — |
| | — |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $1,270,122 |
| |
| $1,120,916 |
|
| Fair Value of Long-Term Debt (c) | |
| $1,285,741 |
| |
| $1,086,203 |
|
|
| | | | | | | | |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| Entergy New Orleans | | | | |
| Mortgage Bonds: | | | | |
| 5.10% Series due December 2020 | |
| $25,000 |
| |
| $25,000 |
|
| 3.9% Series due July 2023 | | 100,000 |
| | 100,000 |
|
| 4.0% Series due June 2026 | | 85,000 |
| | 85,000 |
|
| 5.0% Series due December 2052 | | 30,000 |
| | 30,000 |
|
| 5.50% Series due April 2066 | | 110,000 |
| | 110,000 |
|
| Total mortgage bonds | | 350,000 |
| | 350,000 |
|
| Securitization Bonds: | | | | |
| 2.67% Series Senior Secured due June 2027 | | 76,707 |
| | 87,307 |
|
| Total securitization bonds | | 76,707 |
|
| 87,307 |
|
| Other: | | | | |
| Payable to Entergy Louisiana due November 2035 | | 18,423 |
| | 20,527 |
|
| Unamortized Premium and Discount – Net | | (206 | ) | | (245 | ) |
Unamortized Debt Issuance Costs
| | (8,054 | ) | | (8,595 | ) |
| Total Long-Term Debt | | 436,870 |
| | 448,994 |
|
| Less Amount Due Within One Year | | 2,077 |
| | 2,104 |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $434,793 |
| |
| $446,890 |
|
| Fair Value of Long-Term Debt (c) | |
| $455,968 |
| |
| $455,459 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | |
| | | 2014 | | 2013 |
| | | (In Thousands) |
| Entergy Louisiana | | | | |
| Mortgage Bonds: | | | | |
| 1.875% Series due December 2014 | |
| $— |
| |
| $250,000 |
|
| 6.50% Series due September 2018 | | 300,000 |
| | 300,000 |
|
| 4.8% Series due May 2021 | | 200,000 |
| | 200,000 |
|
| 3.3% Series due December 2022 | | 200,000 |
| | 200,000 |
|
| 4.05% Series due September 2023 | | 325,000 |
| | 325,000 |
|
| 5.40% Series due November 2024 | | 400,000 |
| | 400,000 |
|
| 3.78% Series due April 2025 | | 190,000 |
| | — |
|
| 4.44% Series due January 2026 | | 250,000 |
| | 250,000 |
|
| 6.4% Series due October 2034 | | — |
| | 70,000 |
|
| 6.3% Series due September 2035 | | — |
| | 100,000 |
|
| 6.0% Series due March 2040 | | 150,000 |
| | 150,000 |
|
| 5.875% Series due June 2041 | | 150,000 |
| | 150,000 |
|
| 5.0% Series due July 2044 | | 170,000 |
| | — |
|
| 4.95% Series due January 2045 | | 250,000 |
| | — |
|
| 5.25% Series due July 2052 | | 200,000 |
| | 200,000 |
|
| 4.7% Series due June 2063 | | 100,000 |
| | 100,000 |
|
| Total mortgage bonds | | 2,885,000 |
| | 2,695,000 |
|
| Governmental Bonds (a): | | | | |
| 5.0% Series due 2030, Louisiana Public Facilities Authority (d) | | 115,000 |
| | 115,000 |
|
| Total governmental bonds | | 115,000 |
| | 115,000 |
|
| Variable Interest Entity Notes Payable (Note 4): | | | | |
| 5.69% Series E due July 2014 | | — |
| | 50,000 |
|
| 3.30% Series F due March 2016 | | 20,000 |
| | 20,000 |
|
| 3.25% Series G due July 2017 | | 25,000 |
| | 25,000 |
|
| 3.92% Series H due February 2021 | | 40,000 |
| | — |
|
| Total variable interest entity notes payable | | 85,000 |
| | 95,000 |
|
| Securitization Bonds: | | | | |
| 2.04% Series Senior Secured due June 2021 | | 143,064 |
| | 164,993 |
|
| Total securitization bonds | | 143,064 |
| | 164,993 |
|
| Other: | | | | |
| Waterford 3 Lease Obligation 7.45% (Note 10) | | 128,488 |
| | 148,716 |
|
| Unamortized Premium and Discount - Net | | (3,719 | ) | | (2,962 | ) |
| Other | | 3,746 |
| | 3,769 |
|
| Total Long-Term Debt | | 3,356,579 |
| | 3,219,516 |
|
| Less Amount Due Within One Year | | 19,525 |
| | 320,231 |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $3,337,054 |
| |
| $2,899,285 |
|
| Fair Value of Long-Term Debt (c) | |
| $3,447,404 |
| |
| $3,148,877 |
|
|
| | | | | | | | |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| Entergy Texas | | | | |
| Mortgage Bonds: | | | | |
| 7.125% Series due February 2019 | |
| $500,000 |
| |
| $500,000 |
|
| 2.55% Series due June 2021 | | 125,000 |
| | 125,000 |
|
| 4.1% Series due September 2021 | | 75,000 |
| | 75,000 |
|
| 3.45% Series due December 2027 | | 150,000 |
| | — |
|
| 5.15% Series due June 2045 | | 250,000 |
| | 250,000 |
|
| 5.625% Series due June 2064 | | 135,000 |
| | 135,000 |
|
| Total mortgage bonds | | 1,235,000 |
| | 1,085,000 |
|
| Securitization Bonds: | | | | |
| 5.79% Series Senior Secured, Series A due October 2018 | | — |
| | 23,584 |
|
| 3.65% Series Senior Secured, Series A due August 2019 | | 30,769 |
| | 74,899 |
|
| 5.93% Series Senior Secured, Series A due June 2022 | | 110,431 |
| | 114,400 |
|
| 4.38% Series Senior Secured, Series A due November 2023 | | 218,600 |
| | 218,600 |
|
| Total securitization bonds | | 359,800 |
| | 431,483 |
|
| Other: | | | | |
| Unamortized Premium and Discount - Net | | (1,498 | ) | | (1,579 | ) |
Unamortized Debt Issuance Costs
| | (10,366 | ) | | (10,809 | ) |
| Other | | 4,214 |
| | 4,312 |
|
| Total Long-Term Debt | | 1,587,150 |
| | 1,508,407 |
|
| Less Amount Due Within One Year | | — |
| | — |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $1,587,150 |
| |
| $1,508,407 |
|
| Fair Value of Long-Term Debt (c) | |
| $1,661,902 |
| |
| $1,600,156 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | |
| | | 2014 | | 2013 |
| | | (In Thousands) |
| Entergy Mississippi | | | | |
| Mortgage Bonds: | | | | |
| 3.25% Series due June 2016 | |
| $125,000 |
| |
| $125,000 |
|
| 4.95% Series due June 2018 | | — |
| | 95,000 |
|
| 6.64% Series due July 2019 | | 150,000 |
| | 150,000 |
|
| 3.1% Series due July 2023 | | 250,000 |
| | 250,000 |
|
| 3.75% Series due July 2024 | | 100,000 |
| | — |
|
| 6.0% Series due November 2032 | | 75,000 |
| | 75,000 |
|
| 6.25% Series due April 2034 | | 100,000 |
| | 100,000 |
|
| 6.20% Series due April 2040 | | 80,000 |
| | 80,000 |
|
| 6.0% Series due May 2051 | | 150,000 |
| | 150,000 |
|
| Total mortgage bonds | | 1,030,000 |
| | 1,025,000 |
|
| Governmental Bonds (a): | | | | |
| 4.90% Series due 2022, Independence County (d) | | 30,000 |
| | 30,000 |
|
| Total governmental bonds | | 30,000 |
| | 30,000 |
|
| Other: | | | | |
| Unamortized Premium and Discount – Net | | (1,162 | ) | | (1,330 | ) |
| Total Long-Term Debt | | 1,058,838 |
| | 1,053,670 |
|
| Less Amount Due Within One Year | | — |
| | — |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $1,058,838 |
| |
| $1,053,670 |
|
| Fair Value of Long-Term Debt (c) | |
| $1,102,741 |
| |
| $1,067,006 |
|
|
| | | | | | | | |
| | | 2014 | | 2013 |
| | | (In Thousands) |
| Entergy New Orleans | | | | |
| Mortgage Bonds: | | | | |
| 5.10% Series due December 2020 | |
| $25,000 |
| |
| $25,000 |
|
| 3.9% Series due July 2023 | | 100,000 |
| | 100,000 |
|
| 5.6% Series due September 2024 | | 33,303 |
| | 33,363 |
|
| 5.65% Series due September 2029 | | 37,859 |
| | 37,914 |
|
| 5.0% Series due December 2052 | | 30,000 |
| | 30,000 |
|
| Total mortgage bonds | | 226,162 |
| | 226,277 |
|
| Other: | | | | |
| Unamortized Premium and Discount – Net | | (296 | ) | | (333 | ) |
| Total Long-Term Debt | | 225,866 |
| | 225,944 |
|
| Less Amount Due Within One Year | | — |
| | — |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $225,866 |
| |
| $225,944 |
|
| Fair Value of Long-Term Debt (c) | |
| $226,349 |
| |
| $217,692 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | |
| | | 2014 | | 2013 |
| | | (In Thousands) |
| Entergy Texas | | | | |
| Mortgage Bonds: | | | | |
| 3.60% Series due June 2015 | |
| $200,000 |
| |
| $200,000 |
|
| 7.125% Series due February 2019 | | 500,000 |
| | 500,000 |
|
| 4.1% Series due September 2021 | | 75,000 |
| | 75,000 |
|
| 7.875% Series due June 2039 | | — |
| | 150,000 |
|
| 5.625% Series due June 2064 | | 135,000 |
| | — |
|
| Total mortgage bonds | | 910,000 |
| | 925,000 |
|
| Securitization Bonds: | | | | |
| 2.12% Series Senior Secured, Series A due February 2016 | | 13,816 |
| | 54,047 |
|
| 5.79% Series Senior Secured, Series A due October 2018 | | 74,194 |
| | 97,414 |
|
| 3.65% Series Senior Secured, Series A due August 2019 | | 144,800 |
| | 144,800 |
|
| 5.93% Series Senior Secured, Series A due June 2022 | | 114,400 |
| | 114,400 |
|
| 4.38% Series Senior Secured, Series A due November 2023 | | 218,600 |
| | 218,600 |
|
| Total securitization bonds | | 565,810 |
| | 629,261 |
|
| Other: | | | | |
| Unamortized Premium and Discount - Net | | (1,769 | ) | | (2,211 | ) |
| Other | | 4,890 |
| | 4,889 |
|
| Total Long-Term Debt | | 1,478,931 |
| | 1,556,939 |
|
| Less Amount Due Within One Year | | 200,000 |
| | — |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $1,278,931 |
| |
| $1,556,939 |
|
| Fair Value of Long-Term Debt (c) | |
| $1,629,124 |
| |
| $1,726,623 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | | | 2014 | | 2013 | | 2017 | | 2016 |
| | | (In Thousands) | | (In Thousands) |
| System Energy | | | | | | | | |
| Mortgage Bonds: | | | | | | | | |
| 4.1% Series due April 2023 | |
| $250,000 |
| |
| $250,000 |
| |
| $250,000 |
| |
| $250,000 |
|
| Total mortgage bonds | | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
|
| Governmental Bonds (a): | | | | | | | | |
| 5.875% Series due 2022, Mississippi Business Finance Corp. | | 216,000 |
| | 216,000 |
| | 134,000 |
| | 134,000 |
|
| Total governmental bonds | | 216,000 |
| | 216,000 |
| | 134,000 |
| | 134,000 |
|
| Variable Interest Entity Notes Payable (Note 4): | | | | | |
| 5.33% Series G due April 2015 | | 60,000 |
| | 60,000 |
| |
| Variable Interest Entity Notes Payable and Credit Facility (Note 4): | | | | | |
| 4.02% Series H due February 2017 | | 50,000 |
| | 50,000 |
| | — |
| | 50,000 |
|
| 3.78% Series I due October 2018 | | 85,000 |
| | 85,000 |
| | 85,000 |
| | 85,000 |
|
| Total variable interest entity notes payable | | 195,000 |
| | 195,000 |
| |
| Credit Facility due May 2019, weighted avg rate 2.52% | | | 50,000 |
| | — |
|
| Total variable interest entity notes payable and credit facility | | | 135,000 |
| | 135,000 |
|
| Other: | | | | | | | | |
| Grand Gulf Lease Obligation 5.13% (Note 10) | | 50,671 |
| | 97,414 |
| | 34,356 |
| | 34,359 |
|
| Unamortized Premium and Discount – Net | | (867 | ) | | (981 | ) | | (415 | ) | | (503 | ) |
| Unamortized Debt Issuance Costs | | | (1,455 | ) | | (1,727 | ) |
| Other | | 2 |
| | 3 |
| | 2 |
| | 3 |
|
| Total Long-Term Debt | | 710,806 |
| | 757,436 |
| | 551,488 |
| | 551,132 |
|
| Less Amount Due Within One Year | | 76,310 |
| | 48,653 |
| | 85,004 |
| | 50,003 |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $634,496 |
| |
| $708,783 |
| |
| $466,484 |
| |
| $501,129 |
|
| Fair Value of Long-Term Debt (c) | |
| $677,475 |
| |
| $664,890 |
| |
| $529,119 |
| |
| $529,520 |
|
| |
| (a) | Consists of pollution control revenue bonds and environmental revenue bonds. |
| |
| (b) | Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service. The contracts include a one-time fee for generation prior to April 7, 1983. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt. |
| |
| (c) | The fair value excludes lease obligations of $128 million at Entergy Louisiana and $51$34 million at System Energy and long-term DOE obligations of $181$183 million at Entergy Arkansas, and includes debt due within one year. Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 1615 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported trades. |
| |
| (d) | The bonds are secured by a series of collateral first mortgage bonds. |
| |
| (e) | The interest rate as of December 31, 2016 was 8.09%. See Note 10 to the financial statements for further discussion of Entergy Louisiana’s acquisition of the equity participant’s beneficial interest in the Waterford 3 leased assets in March 2016. |
| |
| (f) | This note did not have a stated interest rate, but had an implicit interest rate of 7.458%. |
The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2014,2017, for the next five years are as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| 2015 |
| $— |
| |
| $31,955 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $200,000 |
| |
| $60,000 |
|
| 2016 |
| $55,000 |
| |
| $— |
| |
| $20,000 |
| |
| $125,000 |
| |
| $— |
| |
| $13,816 |
| |
| $— |
|
| 2017 |
| $114,700 |
| |
| $75,000 |
| |
| $25,000 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $50,000 |
|
| 2018 |
| $— |
| |
| $375,000 |
| |
| $300,000 |
| |
| $— |
| |
| $— |
| |
| $74,194 |
| |
| $85,000 |
|
| 2019 |
| $— |
| |
| $— |
| |
| $— |
| |
| $150,000 |
| |
| $— |
| |
| $644,800 |
| |
| $— |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) |
| 2018 |
| $— |
| |
| $675,000 |
| |
| $— |
| |
| $2,077 |
| |
| $— |
| |
| $85,000 |
|
| 2019 |
| $24,900 |
| |
| $102,010 |
| |
| $150,000 |
| |
| $1,979 |
| |
| $530,769 |
| |
| $50,000 |
|
| 2020 |
| $— |
| |
| $320,000 |
| |
| $— |
| |
| $26,838 |
| |
| $— |
| |
| $— |
|
| 2021 |
| $520,764 |
| |
| $240,000 |
| |
| $— |
| |
| $1,618 |
| |
| $200,000 |
| |
| $— |
|
| 2022 |
| $— |
| |
| $200,000 |
| |
| $— |
| |
| $1,326 |
| |
| $110,431 |
| |
| $134,000 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas Securitization Bonds
In June 2010 the APSC issued a financing order authorizing the issuance of bonds to recover Entergy Arkansas’s January 2009 ice storm damage restoration costs, including carrying costs of $11.5 million and $4.6 million of up-front financing costs. In August 2010, Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, issued $124.1 million of storm cost recovery bonds. The bonds have a coupon of 2.30% and an expected maturity date of August 2021.. Although the principal amount is not due until the date given above,August 2021, Entergy Arkansas Restoration Funding expects to make principal payments on the bonds over the next fivethree years in the amount of $13.2 million for 2015, $13.4 million for 2016, $13.8 million for 2017, $14.1 million for 2018, and $14.4 million for 2019.2019, and $7.3 million for 2020. With the proceeds, Entergy Arkansas Restoration Funding purchased from Entergy Arkansas the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy Arkansas balance sheet. The creditors of Entergy Arkansas do not have recourse to the assets or revenues of Entergy Arkansas Restoration Funding, including the storm recovery property, and the creditors of Entergy Arkansas Restoration Funding do not have recourse to the assets or revenues of Entergy Arkansas. Entergy Arkansas has no payment obligations to Entergy Arkansas Restoration Funding except to remit storm recovery charge collections.
Entergy Louisiana Securitization Bonds – Little Gypsy
In August 2011 the LPSC issued a financing order authorizing the issuance of bonds to recover Entergy Louisiana’s investment recovery costs associated with the cancelledcanceled Little Gypsy repowering project. In September 2011, Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, issued $207.2 million of senior secured investment recovery bonds. The bonds have an interest rate of 2.04% and an expected maturity date of June 2021.. Although the principal amount is not due until the date given above,September 2023, Entergy Louisiana Investment Recovery Funding expects to make principal payments on the bonds over the next fivefour years in the amounts of $20.5 million for 2015, $21.6 million for 2016, $21.7 million for 2017, $22.3 million for 2018, and $22.7 million for 2019.2019, $23.2 million for 2020, and $11 million for 2021. With the proceeds, Entergy Louisiana Investment Recovery Funding purchased from Entergy Louisiana the investment recovery property, which is the right to recover from customers through an investment recovery charge amounts sufficient to service the bonds. In accordance with the financing order, Entergy Louisiana will apply the proceeds it received from the sale of the investment recovery property as a reimbursement for previously-incurred investment recovery costs. The investment recovery property is reflected as a regulatory asset on the consolidated Entergy Louisiana balance sheet. The creditors of Entergy Louisiana do not have recourse to the assets or revenues of Entergy Louisiana Investment Recovery Funding, including the investment recovery property, and the creditors of Entergy Louisiana Investment Recovery Funding do not have recourse to the assets or revenues of Entergy Louisiana. Entergy Louisiana has no payment obligations to Entergy Louisiana Investment Recovery Funding except to remit investment recovery charge collections.
Entergy New Orleans Securitization Bonds - Hurricane Isaac
In May 2015 the City Council issued a financing order authorizing the issuance of securitization bonds to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs of $31.8 million, including carrying costs, the costs of funding and replenishing the storm recovery reserve in the amount of $63.9 million, and approximately $3 million of up-front financing costs associated with the securitization. In July 2015, Entergy New Orleans Storm Recovery Funding I, L.L.C., a company wholly owned and consolidated by Entergy New Orleans, issued $98.7 million of storm cost recovery bonds. The bonds have a coupon of 2.67%. Although the principal amount is not due until June 2027, Entergy New Orleans Storm Recovery Funding expects to make principal payments on the bonds over the next five years in the amounts of $11 million for 2018, $11.2 million for 2019, $11.6 million for 2020, $11.9 million for 2021, and $12.2 million for 2022. With the proceeds, Entergy New Orleans Storm Recovery Funding purchased from Entergy New Orleans the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy New Orleans balance sheet. The creditors of Entergy New Orleans do not have recourse to the assets or revenues of Entergy New Orleans Storm Recovery Funding, including the storm recovery property, and the creditors of Entergy New Orleans Storm Recovery Funding do not have recourse to the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
assets or revenues of Entergy New Orleans. Entergy New Orleans has no payment obligations to Entergy New Orleans Storm Recovery Funding except to remit storm recovery charge collections.
Entergy Texas Securitization Bonds - Hurricane Rita
In April 2007 the PUCT issued a financing order authorizing the issuance of securitization bonds to recover $353 million of Entergy Texas’s Hurricane Rita reconstruction costs and up to $6 million of transaction costs, offset by $32 million of related deferred income tax benefits. In June 2007, Entergy Gulf States Reconstruction Funding I, LLC, a company that is now wholly-owned and consolidated by Entergy Texas, issued $329.5 million of senior secured transition bonds (securitization bonds) as follows:
|
| | | |
| | Amount |
| | (In Thousands) |
| Senior Secured Transition Bonds, Series A: | |
|
| Tranche A-1 (5.51%) due October 2013 |
| $93,500 |
|
| Tranche A-2 (5.79%) due October 2018 | 121,600 |
|
| Tranche A-3 (5.93%) due June 2022 (a) | 114,400 |
|
| Total senior secured transition bonds |
| $329,500 |
|
(a) As of December 31, 2017 the remaining amount outstanding on Tranche A-3 was $110.4 million.
Although the principal amount of each tranche is not due until the dates given above, Entergy Gulf States Reconstruction Funding expects to make principal payments on the bonds over the next fivefour years in the amounts of $24.6 million for 2015, $26 million for 2016, $27.6 million for 2017, $29.2 million for 2018, and $30.9 million for 2019.2019, $32.8 million for 2020, and $17.5 million for 2021. All of the scheduled principal payments for 2015-2016 are for Tranche A-2, $23.6 million of the scheduled principal payments for 2017 are for Tranche A-2 and $4 million of the scheduled principal payments for 20172018-2021 are for Tranche A-3. All of the scheduled principal payments for 2018-2019 are for Tranche A-3.A-1 and Tranche A-2 have been paid.
With the proceeds, Entergy Gulf States Reconstruction Funding purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of Entergy Gulf States Reconstruction Funding, including the transition property, and the creditors of Entergy Gulf States Reconstruction Funding do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to Entergy Gulf States Reconstruction Funding except to remit transition charge collections.
Entergy Texas Securitization Bonds - Hurricane Ike and Hurricane Gustav
In September 2009 the PUCT authorized the issuance of securitization bonds to recover $566.4 million of Entergy Texas’s Hurricane Ike and Hurricane Gustav restoration costs, plus carrying costs and transaction costs, offset by insurance proceeds. In November 2009, Entergy Texas Restoration Funding, LLC (Entergy Texas Restoration Funding), a company wholly-owned and consolidated by Entergy Texas, issued $545.9 million of senior secured transition bonds (securitization bonds), as follows:
|
| | | |
| | Amount |
| | (In Thousands) |
Senior Secured Transition BondsBonds: | |
|
| Tranche A-1 (2.12%) due February 2016 |
| $182,500 |
|
| Tranche A-2 (3.65%) due August 2019 (a) | 144,800 |
|
| Tranche A-3 (4.38%) due November 2023 | 218,600 |
|
| Total senior secured transition bonds |
| $545,900 |
|
(a) As of December 31, 2017 the remaining amount outstanding on Tranche A-2 was $30.8 million.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Although the principal amount of each tranche is not due until the dates given above, Entergy Texas Restoration Funding expects to make principal payments on the bonds over the next five years in the amount of $41.2 million for 2015, $42.6 million for 2016, $44.1 million for 2017, $45.8 million for 2018, and $47.6 million for 2019. A total of $13.82019, $49.8 million offor 2020, $52 million for 2021, and $54.3 million for 2022. Of the scheduled principal payments for 2015 are for Tranche A-1 and $27.4 million are for Tranche A-2. All
Entergy Corporation and Subsidiaries
Notes to Financial Statements
of the scheduled principal payments for 2016-2017 are for Tranche A-2,2018, $30.8 million of the scheduled principal payments for 2018 are for Tranche A-2 and $15 million are for Tranche A-3. All of the scheduled principle payments for 20192019-2022 are for Tranche A-3. Tranche A-1 has been paid.
With the proceeds, Entergy Texas Restoration Funding purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of Entergy Texas Restoration Funding, including the transition property, and the creditors of Entergy Texas Restoration Funding do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to Entergy Texas Restoration Funding except to remit transition charge collections.
NOTE 6. PREFERRED EQUITY (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)
The number of shares and units authorized and outstanding and dollar value of preferred stock, preferred membership interests, and non-controlling interest for Entergy Corporation subsidiaries as of December 31, 20142017 and 20132016 are presented below. All series of the Utility preferred stock are redeemable at the option of the related company.
|
| | | | | | | | | | | | | | | | | | | | |
| | | Shares/Units Authorized | | Shares/Units Outstanding | | | | |
| | | 2014 | | 2013 | | 2014 | | 2013 | | 2014 | | 2013 |
| Entergy Corporation | | | | | | | | (Dollars in Thousands) |
| Utility: | | | | | | | | | | | | |
| Preferred Stock or Preferred Membership Interests without sinking fund: | | | | | | | | | | | | |
| Entergy Arkansas, 4.32%-6.45% Series | | 3,413,500 |
| | 3,413,500 |
| | 3,413,500 |
| | 3,413,500 |
| |
| $116,350 |
| |
| $116,350 |
|
| Entergy Gulf States Louisiana, Series A 8.25% | | 100,000 |
| | 100,000 |
| | 100,000 |
| | 100,000 |
| | 10,000 |
| | 10,000 |
|
| Entergy Louisiana, 6.95% Series (a) | | 1,000,000 |
| | 1,000,000 |
| | 840,000 |
| | 840,000 |
| | 84,000 |
| | 84,000 |
|
| Entergy Mississippi, 4.36%-6.25% Series | | 1,403,807 |
| | 1,403,807 |
| | 1,403,807 |
| | 1,403,807 |
| | 50,381 |
| | 50,381 |
|
| Entergy New Orleans, 4.36%-5.56% Series | | 197,798 |
| | 197,798 |
| | 197,798 |
| | 197,798 |
| | 19,780 |
| | 19,780 |
|
| Total Utility Preferred Stock or Preferred Membership Interests without sinking fund | | 6,115,105 |
| | 6,115,105 |
| | 5,955,105 |
| | 5,955,105 |
| | 280,511 |
| | 280,511 |
|
| Entergy Wholesale Commodities: | | | | | | | | | | | | |
| Preferred Stock without sinking fund: | | | | | | | | | | | | |
| Entergy Finance Holding, Inc. 8.75% (b) | | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
| | 24,249 |
| | 24,249 |
|
| Total Subsidiaries’ Preferred Stock without sinking fund | | 6,365,105 |
| | 6,365,105 |
| | 6,205,105 |
| | 6,205,105 |
| |
| $304,760 |
| |
| $304,760 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | | Shares/Units Authorized | | Shares/Units Outstanding | | | | |
| | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
| Entergy Corporation | | | | | | | | (Dollars in Thousands) |
| Utility: | | | | | | | | | | | | |
| Preferred Stock or Preferred Membership Interests without sinking fund: | | | | | | | | | | | | |
| Entergy Arkansas, 4.32%-4.72% Series | | 313,500 |
| | 313,500 |
| | 313,500 |
| | 313,500 |
| |
| $31,350 |
| |
| $31,350 |
|
| Entergy Utility Holding Company, LLC, 7.5% Series (a) | | 110,000 |
| | 110,000 |
| | 110,000 |
| | 110,000 |
| | 107,425 |
| | 107,425 |
|
| Entergy Utility Holding Company, LLC, 6.25% Series (b) | | 15,000 |
| | — |
| | 15,000 |
| | — |
| | 14,398 |
| | — |
|
| Entergy Mississippi, 4.36%-4.92% Series | | 203,807 |
| | 203,807 |
| | 203,807 |
| | 203,807 |
| | 20,381 |
| | 20,381 |
|
| Entergy New Orleans, 4.36%-5.56% Series | | — |
| | 197,798 |
| | — |
| | 197,798 |
| | — |
| | 19,780 |
|
| Total Utility Preferred Stock or Preferred Membership Interests without sinking fund | | 642,307 |
| | 825,105 |
| | 642,307 |
| | 825,105 |
| | 173,554 |
| | 178,936 |
|
| Entergy Wholesale Commodities: | | | | | | | | | | | | |
| Preferred Stock without sinking fund: | | | | | | | | | | | | |
| Entergy Finance Holding, Inc. 8.75% (c) | | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
| | 24,249 |
| | 24,249 |
|
| Total Subsidiaries’ Preferred Stock without sinking fund | | 892,307 |
| | 1,075,105 |
| | 892,307 |
| | 1,075,105 |
| |
| $197,803 |
| |
| $203,185 |
|
| |
| (a) | In 2007, Entergy Louisiana Holdings, an Entergy subsidiary, purchased 160,000Dollar amount outstanding is net of these shares from the holders.$2,575 thousand of preferred stock issuance costs. |
| |
| (b) | Dollar amount outstanding is net of $602 thousand of preferred stock issuance costs. |
| |
| (c) | Dollar amount outstanding is net of $751 thousand of preferred stock issuance costs. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In November 2017, Entergy Utility Holding Company, LLC issued 15,000 shares of $1,000 par value 6.25% Series B Preferred Membership Interests, all of which are outstanding as of December 31, 2017. The distributions are cumulative and payable quarterly. These units are redeemable on or after February 28, 2038, at Entergy Utility Holding Company, LLC’s option, at the fixed redemption price of $1,000 per share.
In October 2015, Entergy Utility Holding Company, LLC issued 110,000 shares of $1,000 par value 7.5% Series A Preferred Membership Interests, all of which are outstanding as of December 31, 2017. The distributions are cumulative and payable quarterly. These units are redeemable on or after January 1, 2036, at Entergy Utility Holding Company, LLC’s option, at the fixed redemption price of $1,000 per share.
In December 2013, Entergy Finance Holding, Inc. issued 250,000 shares of $100 par value 8.75% Series Preferred Stock, all of which are outstanding as of December 31, 2014.2017. The dividends are cumulative and payable quarterly. The preferred stock is redeemable on or after December 16, 2023, at Entergy Finance Holding, Inc.’s option, at the fixed redemption price of $100 per share.
The number of shares and units authorized and outstanding and dollar value of preferred stock and membership interests for Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans as of December 31, 20142017 and 20132016 are presented below. All series of the Utility operating companies’ preferred stock and membership interests are redeemable at the respective company’s option at the call prices presented. Dividends and distributions paid on all of Entergy’s preferred stock and membership interests series are eligible for the dividends received deduction. The dividends received deduction is limited by Internal Revenue Code section 244 for the following preferred stock series: Entergy Arkansas 4.72%, Entergy Mississippi 4.56%, and Entergy New Orleans 4.75%.
| | | | | Shares Authorized and Outstanding | | | | Call Price per Share as of December 31, | | Shares Authorized and Outstanding | | | | Call Price per Share as of December 31, |
| | | 2014 | | 2013 | | 2014 | | 2013 | | 2014 | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 |
| Entergy Arkansas Preferred Stock | | | | | | (Dollars in Thousands) | | | | | | | | (Dollars in Thousands) | | |
| Without sinking fund: | | | | | | | | | | | | | | | | | | | | |
| Cumulative, $100 par value: | | | | | | | | | | | | | | | | | | | | |
| 4.32% Series | | 70,000 |
| | 70,000 |
| |
| $7,000 |
| |
| $7,000 |
| |
| $103.65 |
| | 70,000 |
| | 70,000 |
| |
| $7,000 |
| |
| $7,000 |
| |
| $103.65 |
|
| 4.72% Series | | 93,500 |
| | 93,500 |
| | 9,350 |
| | 9,350 |
| |
| $107.00 |
| | 93,500 |
| | 93,500 |
| | 9,350 |
| | 9,350 |
| |
| $107.00 |
|
| 4.56% Series | | 75,000 |
| | 75,000 |
| | 7,500 |
| | 7,500 |
| |
| $102.83 |
| | 75,000 |
| | 75,000 |
| | 7,500 |
| | 7,500 |
| |
| $102.83 |
|
| 4.56% 1965 Series | | 75,000 |
| | 75,000 |
| | 7,500 |
| | 7,500 |
| |
| $102.50 |
| | 75,000 |
| | 75,000 |
| | 7,500 |
| | 7,500 |
| |
| $102.50 |
|
| 6.08% Series | | 100,000 |
| | 100,000 |
| | 10,000 |
| | 10,000 |
| |
| $102.83 |
| |
| Cumulative, $25 par value: | | | | | | | | | | | |
| 6.45% Series | | 3,000,000 |
| | 3,000,000 |
| | 75,000 |
| | 75,000 |
| |
| $25 |
| |
| Total without sinking fund | | 3,413,500 |
| | 3,413,500 |
| |
| $116,350 |
| |
| $116,350 |
| | | | 313,500 |
| | 313,500 |
| |
| $31,350 |
| |
| $31,350 |
| | |
|
| | | | | | | | | | | | | | | | | | |
| | | Units Authorized and Outstanding | | | | Call Price per Unit as of December 31, |
| | | 2014 | | 2013 | | 2014 | | 2013 | | 2014 |
Entergy Gulf States Louisiana Preferred Membership Interests | | | | | | (Dollars in Thousands) | | |
| Without sinking fund: | | | | | | | | | | |
| Cumulative, $100 liquidation value: | | | | | | | | | | |
| 8.25% Series (a) | | 100,000 |
| | 100,000 |
| |
| $10,000 |
| |
| $10,000 |
| |
| $— |
|
| Total without sinking fund | | 100,000 |
| | 100,000 |
| |
| $10,000 |
| |
| $10,000 |
| | |
|
| | | | | | | | | | | | | | | | | | |
| | | Shares Authorized and Outstanding | | | | Call Price per Share as of December 31, |
| | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 |
| Entergy Mississippi Preferred Stock | | | | | | (Dollars in Thousands) | | |
| Without sinking fund: | | | | | | | | | | |
| Cumulative, $100 par value: | | | | | | | | | | |
| 4.36% Series | | 59,920 |
| | 59,920 |
| |
| $5,992 |
| |
| $5,992 |
| |
| $103.86 |
|
| 4.56% Series | | 43,887 |
| | 43,887 |
| | 4,389 |
| | 4,389 |
| |
| $107.00 |
|
| 4.92% Series | | 100,000 |
| | 100,000 |
| | 10,000 |
| | 10,000 |
| |
| $102.88 |
|
| Total without sinking fund | | 203,807 |
| | 203,807 |
| |
| $20,381 |
| |
| $20,381 |
| | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | | | |
| | | Units Authorized and Outstanding | | | | Call Price per Unit as of December 31, |
| | | 2014 | | 2013 | | 2014 | | 2013 | | 2014 |
| Entergy Louisiana Preferred Membership Interests | | | | | | (Dollars in Thousands) | | |
| Without sinking fund: | | | | | | | | | | |
| Cumulative, $100 liquidation value: | | | | | | | | | | |
| 6.95% Series | | 1,000,000 |
| | 1,000,000 |
| |
| $100,000 |
| |
| $100,000 |
| |
| $100 |
|
| Total without sinking fund | | 1,000,000 |
| | 1,000,000 |
| |
| $100,000 |
| |
| $100,000 |
| | |
|
| | | | | | | | | | | | | | | | | | |
| | | Shares Authorized and Outstanding | | | | Call Price per Share as of December 31, |
| | | 2014 | | 2013 | | 2014 | | 2013 | | 2014 |
| Entergy Mississippi Preferred Stock | | | | | | (Dollars in Thousands) | | |
| Without sinking fund: | | | | | | | | | | |
| Cumulative, $100 par value: | | | | | | | | | | |
| 4.36% Series | | 59,920 |
| | 59,920 |
| |
| $5,992 |
| |
| $5,992 |
| |
| $103.86 |
|
| 4.56% Series | | 43,887 |
| | 43,887 |
| | 4,389 |
| | 4,389 |
| |
| $107.00 |
|
| 4.92% Series | | 100,000 |
| | 100,000 |
| | 10,000 |
| | 10,000 |
| |
| $102.88 |
|
| Cumulative, $25 par value | | | | | | | | | | |
| 6.25% Series | | 1,200,000 |
| | 1,200,000 |
| | 30,000 |
| | 30,000 |
| |
| $25 |
|
| Total without sinking fund | | 1,403,807 |
| | 1,403,807 |
| |
| $50,381 |
| |
| $50,381 |
| | |
| | | | | Shares Authorized and Outstanding | | | | Call Price per Share as of December 31, | | Shares Authorized and Outstanding | | | | | | Call Price per
Share as of
December 31, |
| | | 2014 | | 2013 | | 2014 | | 2013 | | 2014 | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 |
| Entergy New Orleans Preferred Stock | | | | | | (Dollars in Thousands) | | | Entergy New Orleans Preferred Stock | | | | | (Dollars in Thousands) | | |
| Without sinking fund: | | | | | | | | | | | | | | | | | | | | |
| Cumulative, $100 par value: | | | | | | | | | | | | | | | | | | | | |
4.36% Series | | 60,000 |
| | 60,000 |
| |
| $6,000 |
| |
| $6,000 |
| |
| $104.58 |
| | — |
| | 60,000 |
| |
| $— |
| |
| $6,000 |
| |
| $— |
|
4.75% Series | | 77,798 |
| | 77,798 |
| | 7,780 |
| | 7,780 |
| |
| $105.00 |
| | — |
| | 77,798 |
| | — |
| | 7,780 |
| |
| $— |
|
5.56% Series | | 60,000 |
| | 60,000 |
| | 6,000 |
| | 6,000 |
| |
| $102.59 |
| | — |
| | 60,000 |
| | — |
| | 6,000 |
| |
| $— |
|
| Total without sinking fund | | 197,798 |
| | 197,798 |
| |
| $19,780 |
| |
| $19,780 |
| | | | — |
| | 197,798 |
| |
| $— |
| |
| $19,780 |
| | |
| |
| (a) | In November 2017, Entergy New Orleans redeemed its $6 million of 4.36% Series, is callable at par on$7.8 million of 4.75% Series, and after December 15, 2015.$6 million of 5.56% Series of preferred membership interests as part of a multi-step internal restructuring. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 7. COMMON EQUITY (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Common Stock
Common stock and treasury stock shares activity for Entergy for 2014, 2013,2017, 2016, and 20122015 is as follows:
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| | Common Shares Issued | |
Treasury Shares | | Common Shares Issued | | Treasury Shares | | Common Shares Issued | | Treasury Shares | Common Shares Issued | |
Treasury Shares | | Common Shares Issued | | Treasury Shares | | Common Shares Issued | | Treasury Shares |
| Beginning Balance, January 1 | 254,752,788 |
| | 76,381,936 |
| | 254,752,788 |
| | 76,945,239 |
| | 254,752,788 |
| | 78,396,988 |
| 254,752,788 |
| | 75,623,363 |
| | 254,752,788 |
| | 76,363,763 |
| | 254,752,788 |
| | 75,512,079 |
|
| Repurchases | — |
| | 2,154,490 |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | 1,468,984 |
|
| Issuances: | |
| | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
| | |
|
| Employee Stock-Based Compensation Plans | — |
| | (3,019,475 | ) | | — |
| | (557,734 | ) | | — |
| | (1,446,305 | ) | — |
| | (1,377,363 | ) | | — |
| | (729,073 | ) | | — |
| | (610,409 | ) |
| Directors’ Plan | — |
| | (4,872 | ) | | — |
| | (5,569 | ) | | — |
| | (5,444 | ) | — |
| | (10,865 | ) | | — |
| | (11,327 | ) | | — |
| | (6,891 | ) |
| Ending Balance, December 31 | 254,752,788 |
| | 75,512,079 |
| | 254,752,788 |
| | 76,381,936 |
| | 254,752,788 |
| | 76,945,239 |
| 254,752,788 |
| | 74,235,135 |
| | 254,752,788 |
| | 75,623,363 |
| | 254,752,788 |
| | 76,363,763 |
|
Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors’ Plan), twothree Equity Ownership Plans of Entergy Corporation and Subsidiaries, the Equity Awards Plan of Entergy Corporation and Subsidiaries, and certain other stock benefit plans. The Directors’ Plan awards to non-employee directors a portion of their compensation in the form of a fixed dollar value of shares of Entergy Corporation common stock.
In October 2010 the Board granted authority for a $500 million share repurchase program. As of December 31, 2014,2017, $350 million of authority remains under the $500 million share repurchase program.
Dividends declared per common share were $3.32$3.50 in 2014, 2013,2017, $3.42 in 2016, and 2012.$3.34 in 2015.
Retained EarningsSystem Energy paid its parent, Entergy Corporation, distributions out of its common stock of $21 million in 2017 and Dividend Restrictions$40 million in 2016.
Provisions within the articles of incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred equity. As of December 31, 2014, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively. Entergy Corporation received dividend payments from subsidiaries totaling $893 million in 2014, $702 million in 2013, and $439 million in 2012.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Retained Earnings and Dividend Restrictions
Provisions within the articles of incorporation relating to preferred stock of each of Entergy Arkansas and Entergy Mississippi could restrict the payment of cash dividends or other distributions on their common and preferred equity if such payment were to occur when, or result in, a ratio of common stock equity to total capitalization of 25% or less. Entergy Corporation received dividend payments and distributions from subsidiaries totaling $201 million in 2017, $165 million in 2016, and $615 million in 2015.
Comprehensive Income
Accumulated other comprehensive income (loss) is included in the equity section of the balance sheets of Entergy Entergy Gulf States Louisiana, and Entergy Louisiana. The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 20142017 by component:
| | | | Cash flow
hedges
net
unrealized
gain (loss) | | Pension
and
other
postretirement
liabilities | |
Net
unrealized
investment
gains (loss) | | Foreign
currency
translation | | Total
Accumulated
Other
Comprehensive
Income (Loss) | Cash flow
hedges
net
unrealized
gain (loss) | | Pension
and
other
postretirement
liabilities | |
Net
unrealized
investment
gain (loss) | | Foreign
currency
translation | | Total
Accumulated
Other
Comprehensive
Income (Loss) |
| | (In Thousands) | (In Thousands) |
| | | | | | | | | | | | | | | | | | | |
| Beginning balance, December 31, 2013 |
| ($81,777 | ) | |
| ($288,223 | ) | |
| $337,256 |
| |
| $3,420 |
| |
| ($29,324 | ) | |
| Beginning balance, January 1, 2017 | |
| $3,993 |
| |
| ($469,446 | ) | |
| $429,734 |
| |
| $748 |
| |
| ($34,971 | ) |
| Other comprehensive income (loss) before reclassifications | 52,433 |
| | (278,361 | ) | | 99,900 |
| | (751 | ) | | (126,779 | ) | 28,602 |
| | (104,029 | ) | | 171,099 |
| | (748 | ) | | 94,924 |
|
| Amounts reclassified from accumulated other comprehensive income (loss) | 127,462 |
| | (3,205 | ) | | (10,461 | ) | | — |
| | 113,796 |
| (70,072 | ) | | 42,376 |
| | (55,788 | ) | | — |
| | (83,484 | ) |
| Net other comprehensive income (loss) for the period | 179,895 |
| | (281,566 | ) | | 89,439 |
| | (751 | ) | | (12,983 | ) | (41,470 | ) | | (61,653 | ) | | 115,311 |
| | (748 | ) | | 11,440 |
|
| Ending balance, December 31, 2014 |
| $98,118 |
| |
| ($569,789 | ) | |
| $426,695 |
| |
| $2,669 |
| |
| ($42,307 | ) | |
| Ending balance, December 31, 2017 | |
| ($37,477 | ) | |
| ($531,099 | ) | |
| $545,045 |
| |
| $— |
| |
| ($23,531 | ) |
The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 20132016 by component:
|
| | | | | | | | | | | | | | | | | | | |
| | Cash flow
hedges
net
unrealized
gain (loss) | | Pension
and
other
postretirement
liabilities | |
Net
unrealized
investment
gains (loss) | | Foreign
currency
translation | | Total
Accumulated
Other
Comprehensive
Income (Loss) |
| | (In Thousands) |
| | | | | | | | | | |
| Beginning balance, December 31, 2012 |
| $79,905 |
|
|
| ($590,712 | ) |
|
| $214,547 |
|
|
| $3,177 |
| |
| ($293,083 | ) |
| Other comprehensive income (loss) before reclassifications | (133,312 | ) | | 260,567 |
| | 143,936 |
| | 243 |
| | 271,434 |
|
Amounts reclassified from
accumulated other comprehensive
income (loss) | (28,370 | ) | | 41,922 |
| | (21,227 | ) | | — |
| | (7,675 | ) |
| Net other comprehensive income (loss) for the period | (161,682 | ) | | 302,489 |
| | 122,709 |
| | 243 |
| | 263,759 |
|
| Ending balance, December 31, 2013 |
| ($81,777 | ) | |
| ($288,223 | ) | |
| $337,256 |
| |
| $3,420 |
| |
| ($29,324 | ) |
|
| | | | | | | | | | | | | | | | | | | |
| | Cash flow
hedges
net
unrealized
gain (loss) | | Pension
and
other
postretirement
liabilities | |
Net
unrealized
investment
gain (loss) | | Foreign
currency
translation | | Total
Accumulated
Other
Comprehensive
Income (Loss) |
| | (In Thousands) |
| | | | | | | | | | |
| Beginning balance, January 1, 2016 |
| $105,970 |
|
|
| ($466,604 | ) |
|
| $367,557 |
|
|
| $2,028 |
| |
| $8,951 |
|
| Other comprehensive income (loss) before reclassifications | 87,740 |
| | (26,997 | ) | | 68,465 |
| | (1,280 | ) | | 127,928 |
|
Amounts reclassified from
accumulated other comprehensive income (loss) | (189,717 | ) | | 24,155 |
| | (6,288 | ) | | — |
| | (171,850 | ) |
| Net other comprehensive income (loss) for the period | (101,977 | ) | | (2,842 | ) | | 62,177 |
| | (1,280 | ) | | (43,922 | ) |
| Ending balance, December 31, 2016 |
| $3,993 |
| |
| ($469,446 | ) | |
| $429,734 |
| |
| $748 |
| |
| ($34,971 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The following table presents changes in accumulated other comprehensive income (loss) for Entergy Gulf States Louisiana and Entergy Louisiana for the year ended December 31, 2014:2017:
|
| | | | | | | | |
| | | Pension and Other Postretirement Liabilities |
| | | Entergy Gulf States Louisiana | |
Entergy Louisiana |
| | | (In Thousands) |
| | | | | |
| Beginning balance, December 31, 2013 | |
| ($28,202 | ) | |
| ($9,635 | ) |
| Other comprehensive income (loss) before reclassifications | | (25,677 | ) | | (15,078 | ) |
Amounts reclassified from accumulated other comprehensive income (loss) | | 532 |
| | (1,163 | ) |
| Net other comprehensive income (loss) for the period | | (25,145 | ) | | (16,241 | ) |
| Ending balance, December 31, 2014 | |
| ($53,347 | ) | |
| ($25,876 | ) |
|
| | | | |
| | Pension and Other Postretirement Liabilities |
| | (In Thousands) |
| | |
| Beginning balance, January 1, 2017 | |
| ($48,442 | ) |
| Other comprehensive income (loss) before reclassifications | | 3,462 |
|
| Amounts reclassified from accumulated other comprehensive income (loss) | | (1,420 | ) |
| Net other comprehensive income (loss) for the period | | 2,042 |
|
| Ending balance, December 31, 2017 | |
| ($46,400 | ) |
The following table presents changes in accumulated other comprehensive income (loss) for Entergy Gulf States Louisiana and Entergy Louisiana for the year ended December 31, 2013:2016:
|
| | | | | | | | |
|
| Pension and Other Postretirement Liabilities |
| | | Entergy Gulf States Louisiana | |
Entergy Louisiana |
|
| (In Thousands) |
| | | | | |
| Beginning balance, December 31, 2012 | |
| ($65,229 | ) | |
| ($46,132 | ) |
| Other comprehensive income (loss) before reclassifications | | 33,233 |
| | 33,869 |
|
Amounts reclassified from accumulated other comprehensive income (loss) | | 3,794 |
| | 2,628 |
|
| Net other comprehensive income (loss) for the period | | 37,027 |
| | 36,497 |
|
| Ending balance, December 31, 2013 | |
| ($28,202 | ) | |
| ($9,635 | ) |
|
| | | | |
| | Pension and Other
Postretirement Liabilities |
| | (In Thousands) |
| | |
| Beginning balance, January 1, 2016 | |
| ($56,412 | ) |
| Other comprehensive income (loss) before reclassifications | | 8,926 |
|
| Amounts reclassified from accumulated other comprehensive income (loss) | | (956 | ) |
| Net other comprehensive income (loss) for the period | | 7,970 |
|
| Ending balance, December 31, 2016 | |
| ($48,442 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy for the yearyears ended December 31, 20142017 and 2016 are as follows:
|
| | | | | | |
| | Amounts
reclassified
from
AOCI
| | Income Statement Location |
| | (In Thousands) | | |
| | | | |
Cash flow hedges net unrealized gain (loss) | | | | |
Power contracts | |
| ($193,297 | ) | | Competitive business operating revenues |
Interest rate swaps | | (2,799 | ) | | Miscellaneous - net |
Total realized gain (loss) on cash flow hedges | | (196,096 | ) | | |
| | 68,634 |
| | Income taxes |
Total realized gain (loss) on cash flow hedges (net of tax) | |
| ($127,462 | ) | | |
| | | | |
Pension and other postretirement liabilities | | |
| | |
Amortization of prior-service costs | |
| $20,294 |
| | (a) |
Amortization of loss | | (35,836 | ) | | (a) |
Settlement loss | | (3,643 | ) | | (a) |
Total amortization | | (19,185 | ) | | |
| | 22,390 |
| | Income taxes |
Total amortization (net of tax) | |
| $3,205 |
| | |
| | | | |
Net unrealized investment gain (loss) | | | | |
Realized gain (loss) | |
| $20,511 |
| | Interest and investment income |
| | (10,050 | ) | | Income taxes |
Total realized investment gain (loss) (net of tax) | |
| $10,461 |
| | |
| | | | |
Total reclassifications for the period (net of tax) | |
| ($113,796 | ) | | |
|
| | | | | | | | | | |
| | | Amounts reclassified from AOCI | | Income Statement Location |
| | | 2017 | | 2016 | | |
| | | (In Thousands) | | |
| Cash flow hedges net unrealized gain (loss) | | | | | | |
| Power contracts | |
| $108,606 |
| |
| $293,268 |
| | Competitive business operating revenues |
| Interest rate swaps | | (803 | ) | | (1,395 | ) | | Miscellaneous - net |
| Total realized gain (loss) on cash flow hedges | | 107,803 |
| | 291,873 |
| | |
| | | (37,731 | ) | | (102,156 | ) | | Income taxes |
| Total realized gain (loss) on cash flow hedges (net of tax) | |
| $70,072 |
| |
| $189,717 |
| | |
| | | | |
| | |
| Pension and other postretirement liabilities | | |
| | |
| | |
| Amortization of prior-service costs | |
| $26,251 |
| |
| $29,414 |
| | (a) |
| Acceleration of prior-service cost due to curtailment | | — |
| | (1,045 | ) | | (a) |
| Amortization of loss | | (86,002 | ) | | (60,693 | ) | | (a) |
| Settlement loss | | (7,544 | ) | | (2,007 | ) | | (a) |
| Total amortization | | (67,295 | ) | | (34,331 | ) | | |
| | | 24,919 |
| | 10,176 |
| | Income taxes |
| Total amortization (net of tax) | |
| ($42,376 | ) | |
| ($24,155 | ) | | |
| | | | |
| | |
| Net unrealized investment gain (loss) | | | |
| | |
| Realized gain (loss) | |
| $109,388 |
| |
| $12,329 |
| | Interest and investment income |
| | | (53,600 | ) | | (6,041 | ) | | Income taxes |
| Total realized investment gain (loss) (net of tax) | |
| $55,788 |
| |
| $6,288 |
| | |
| | | | |
| | |
| Total reclassifications for the period (net of tax) | |
| $83,484 |
| |
| $171,850 |
| | |
|
| |
| (a) | These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension and other postretirement cost. See Note 11 to the financial statements for additional details. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy Louisiana for the yearyears ended December 31, 20132017 and 2016 are as follows:
|
| | | | | | |
| | Amounts | | | | | | | | | | | | | | | Amounts reclassified from AOCI | | Income Statement Location | | | | 2017 | | 2016 | | | | | | (In Thousands) | | | | | | | | | | | | Pension and other postretirement liabilities | | | | | | | | Amortization of prior-service costs | |
| $7,734 |
| |
| $7,786 |
| | (a) | | Amortization of loss | | (5,327 | ) | | (6,281 | ) | | (a) | | Total amortization | | 2,407 |
| | 1,505 |
| | | | | | (987 | ) | | (549 | ) | | Income taxes | | Total amortization (net of tax) | | 1,420 |
| | 956 |
| | | | | | | |
| | | | Total reclassifications for the period (net of tax) | |
| $1,420 |
| |
| $956 |
| | |
reclassified
from
AOCI
| | Income Statement Location |
| | (In Thousands) | | |
|
|
|
|
|
Cash flow hedges net unrealized gain (loss) | |
| |
|
Power contracts |
|
| $47,019 |
|
| Competitive business operating revenues |
Interest rate swaps |
| (1,565 | ) |
| Miscellaneous - net |
Total realized gain (loss) on cash flow hedges |
| 45,454 |
|
|
|
|
| (17,084 | ) |
| Income taxes |
Total realized gain (loss) on cash flow hedges (net of tax) |
|
| $28,370 |
|
|
|
|
|
|
|
|
Pension and other postretirement liabilities | | |
| |
|
Amortization of prior-service costs | |
| $10,556 |
| | (a) |
Acceleration of prior-service cost due to curtailment | | 315 |
| | (a) |
Amortization of loss |
| (68,130 | ) |
| (a) |
Settlement loss |
| (11,612 | ) |
| (a) |
Total amortization |
| (68,871 | ) |
|
|
|
| 26,949 |
|
| Income taxes |
Total amortization (net of tax) |
|
| ($41,922 | ) |
|
|
|
|
|
|
|
Net unrealized investment gain (loss) |
|
|
|
|
Realized gain (loss) |
|
| $41,622 |
|
| Interest and investment income |
|
| (20,395 | ) |
| Income taxes |
Total realized investment gain (loss) (net of tax) |
|
| $21,227 |
|
|
|
|
|
|
|
|
Total reclassifications for the period (net of tax) | |
| $7,675 |
| |
|
|
| |
| (a) | These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension and other postretirement cost. See Note 11 to the financial statements for additional details. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy Gulf States Louisiana and Entergy Louisiana for the year ended December 31, 2014 are as follows:
|
| | | | | | | | | | |
| | | Amounts reclassified from AOCI | | |
| | | Entergy Gulf States Louisiana | |
Entergy Louisiana | | Income Statement Location |
| | | (In Thousands) | | |
| | | | | | | |
| Pension and other postretirement liabilities | | | | | | |
| Amortization of prior-service costs | |
| $2,237 |
| |
| $3,377 |
| | (a) |
| Amortization of loss | | (3,126 | ) | | (1,511 | ) | | (a) |
| Total amortization | | (889 | ) | | 1,866 |
| | |
| | | 357 |
| | (703 | ) | | Income tax expense (benefit) |
| Total amortization (net of tax) | | (532 | ) | | 1,163 |
| | |
| | | | | | | |
| Total reclassifications for the period (net of tax) | |
| ($532 | ) | |
| $1,163 |
| | |
|
| |
(a) | These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension cost. See Note 11 to the financial statements for additional details. |
Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy Gulf States Louisiana and Entergy Louisiana for the year ended December 31, 2013 are as follows:
|
| | | | | | | | | | |
|
| Amounts reclassified from AOCI |
|
|
| | Entergy Gulf States Louisiana | |
Entergy Louisiana | | Income Statement Location |
| | (In Thousands) | | |
|
|
|
|
|
|
|
| Pension and other postretirement liabilities | |
|
|
| |
|
| Amortization of prior-service costs | |
| $941 |
| |
| $508 |
| | (a) |
| Acceleration of prior-service cost due to curtailment | | 91 |
| | 41 |
| | (a) |
| Amortization of loss | | (7,644 | ) | | (5,050 | ) | | (a) |
| Total amortization |
| (6,612 | ) |
| (4,501 | ) |
|
|
|
| 2,818 |
| | 1,873 |
|
| Income taxes |
| Total amortization (net of tax) |
| (3,794 | ) |
| (2,628 | ) |
|
|
|
|
|
|
|
|
|
| Total reclassifications for the period (net of tax) | |
| ($3,794 | ) | |
| ($2,628 | ) | |
|
|
| |
(a) | These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension cost. See Note 11 to the financial statements for additional details. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 8. COMMITMENTS AND CONTINGENCIES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy and the Registrant Subsidiaries are involved in a number of legal, regulatory, and tax proceedings before various courts, regulatory commissions, and governmental agencies in the ordinary course of business. While management is unable to predict the outcome of such proceedings, management does not believe that the ultimate resolution of these matters will have a material effect on Entergy’s results of operations, cash flows, or financial condition. Entergy discusses regulatory proceedings in Note 2 to the financial statements and discusses tax proceedings in Note 3 to the financial statements.
Vidalia Purchased Power Agreement
Entergy Louisiana has an agreement extending through the year 2031 to purchase energy generated by a hydroelectric facility known as the Vidalia project. Entergy Louisiana made payments under the contract of approximately $152.8$122.9 million in 2014, $181.12017, $158.7 million in 2013,2016, and $125.0$146 million in 2012.2015. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $148.5$129 million in 2015,2018, and a total of $2.06$1.68 billion for the years 20162019 through 2031. Entergy Louisiana currently recovers the costs of the purchased energy through its fuel adjustment clause.
In an LPSC-approved settlement related to tax benefits from the tax treatment of the Vidalia contract, Entergy Louisiana agreed to credit rates by $11 million each year for up to 10 years, beginning in October 2002. In addition, in accordance with an LPSC settlement, Entergy Louisiana credited rates in August 2007 by $11.3 million (including interest) as a result of a settlement with the IRS of the 2001 tax treatment of the Vidalia contract. In August 2011, Entergy agreed to a settlement with the IRS regarding the mark-to-market income tax treatment of various wholesale electric power purchase and sale contracts, including the Vidalia contract. The agreement with the IRS effectively settled the tax treatment of such contracts which allowed Entergy Louisiana to propose a final settlement with the LPSC regarding Entergy Louisiana’s obligation to customers related to the Vidalia contract. In October 2011 the LPSC approved a final settlement under which Entergy Louisiana agreed to provide credits to the fuel adjustment clause resulting from the IRS settlement to customers by crediting billings an additional $20.235 million per year for 15 years beginning January 2012. Entergy Louisiana recorded a regulatory charge and a corresponding regulatory liability to reflect this obligation. Entergy Louisiana’s useThe settlement agreement allowed for an adjustment to the credits if, among other things, there was a change in the applicable federal or state income tax rate. As a result of the cash benefitenactment of the proceeds is not reflectedTax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate base for ratemaking purposes.from 35% to 21%, the Vidalia purchased power regulatory liability was reduced by $30.5 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
ANO Damage, Outage, and NRC Reviews
OnIn March 31, 2013, during a scheduled refueling outage at ANO 1, a contractor-owned and operated heavy-lifting apparatus collapsed while moving the generator stator out of the turbine building. The collapse resulted in the death of an ironworker and injuries to several other contract workers, caused ANO 2 to shut down, and damaged the ANO turbine building. The turbine building serves both ANO 1 and 2 and is a non-radiological area of the plant. ANO 2 reconnected to the grid on April 28, 2013 and ANO 1 reconnected to the grid on August 7, 2013. The total cost of assessment, restoration of off-site power, site restoration, debris removal, and replacement of damaged property and equipment was approximately $95 million. Entergy Arkansas is pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. During 2014, Entergy Arkansas collected $50 million from Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants. Litigation remains pending.
In addition, Entergy Arkansas incurred replacement power costs for ANO 2 power during its outage and incurred incremental replacement power costs for ANO 1 power because the outage extended beyond the originally-planned duration of the refueling outage. In February 2014 the APSC approved Entergy Arkansas’s request to exclude from the calculation of its revised energy cost rate $65.9 million of deferred fuel and purchased energy costs incurred in 2013 as a result of the ANO stator incident. The APSC authorized Entergy Arkansas to retain the $65.9 million in its deferred fuel balance with recovery to be reviewed in a later period after more information regarding various claims associated with the ANO stator incident is available.
Entergy Arkansas is pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. Entergy is a member of Nuclear Electric Insurance Limited (NEIL), a mutual
Entergy Corporation and Subsidiaries
Notes to Financial Statements
insurance company that provides property damage coverage to the members’ nuclear generating plants, including ANO. NEIL has notified Entergy that it believes that a $50 million course of construction sublimit applies to any loss associated with the lifting apparatus failure and stator drop at ANO. Entergy has responded that it disagrees with NEIL’s position and is evaluating its options for enforcing its rights under the policy. During 2014, Entergy Arkansas collected $50 million from NEIL. On In July 12, 2013,2017, Entergy Arkansas filed for a complaintchange in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a proceeding for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs previously noted, subject to certain timelines and conditions set forth in the Circuit Court in Pope County, Arkansas against the owner of the heavy-lifting apparatus that collapsed, an engineering firm, a contractor, and certain individuals asserting claims of breach of contract, negligence, and gross negligence in connection with their responsibility for the stator drop.settlement agreement.
Shortly after the stator incident, the NRC deployed an augmented inspection team to review the plant’s response. In July 2013 a second team of NRC inspectors visited ANO to evaluate certain items that were identified as requiring follow-up inspection to determine whether performance deficiencies existed. In March 2014 the NRC issued an inspection report on the follow-up inspection that discussed two preliminary findings, one that was preliminarily determined to be “red with high safety significance” for Unit 1 and one that was preliminarily determined to be “yellow with substantial safety significance” for Unit 2, with the NRC indicating further that these preliminary findings may warrant additional regulatory oversight. This report also noted that one additional item related to flood barrier effectiveness was still under review.
In May 2014 the NRC met with Entergy during a regulatory conference to discuss the preliminary red and yellow findings and Entergy’s response to the findings. During the regulatory conference, Entergy presented information on the facts and assumptions the NRC used to assess the potential findings. The NRC used the information provided by Entergy at the regulatory conference to finalize its decision regarding the inspection team’s findings. In a letter dated June 23, 2014 the NRC classified both findings as “yellow with substantial safety significance.” In an assessment follow-up letter for ANO dated July 29, 2014, the NRC stated that given the two yellow findings, it determined that the performance at ANO is in the “degraded cornerstone column,” or column 3, of the NRC’s reactor oversight process action matrix beginning the first quarter 2014. Corrective actions in response to the NRC’s findings have been taken and remain ongoing at ANO. The NRC plans to conduct supplemental inspection activity to review the actions taken to address the yellow findings. Entergy will continue to interact with the NRC to address the NRC’s findings.
In September 2014March 2015, after several NRC inspections and regulatory conferences, the NRC issued an inspection report on the flood barrier effectiveness issue that was still under review at the timea letter notifying Entergy of the March 2014 inspection report. While Entergy believes that the flood barrier issues that ledits decision to the finding have been addressed atmove ANO NRC processes still required that the NRC assess the safety significance of the deficiencies. In its September 2014 inspection report, the NRC discussed a preliminary finding of “yellow with substantial safety significance” for the Unit 1 and Unit 2 auxiliary and emergency diesel fuel storage buildings. The NRC indicated that these preliminary findings may warrant additional regulatory oversight. Entergy requested a public regulatory conference regarding the inspection, and the conference was held on October 28, 2014. During the regulatory conference, Entergy presented information related to the facts and assumptions used by the NRC in arriving at its preliminary finding of “yellow with substantial safety significance.” In January 2015 the NRC issued its final risk significance determination for the flood barrier violation originally cited in the September 2014 report. The NRC’s final risk significance determination was classified as “yellow with substantial safety significance.”
The NRC’s January 2015 letter did not advise ANO of the additional level of oversight that will result from the yellow finding related to the flood barrier issue, and it stated that the NRC would inform ANO of this decision by separate correspondence. The yellow finding may result in ANO being placed into the “multiple/repetitive degraded cornerstone column”column,” or Column 4, of the NRC’s reactor oversight process action matrix.Reactor Oversight Process Action Matrix. Placement into this column would requireColumn 4 requires significant additional NRC inspection activities at the ANO site, including a review of the site’s root cause evaluation associated with the flood barrier effectiveness and stator issues, an assessment of the effectiveness of the site’s corrective action program, an additional design basis inspection, a safety culture assessment, and possibly other inspection activities consistent with the NRC’s Inspection Procedure. TheEntergy Arkansas incurred incremental costs of approximately $53 million in 2015 to prepare for the NRC inspection that began in early 2016. Excluding remediation and response costs that may result from the additional NRC inspection activities, at the site areEntergy Arkansas also incurred approximately $44 million in 2016 in support of NRC inspection activities and to implement Entergy Arkansas’s performance improvement initiatives developed in 2015. A lesser amount of incremental expense is expected to increase ANO’s operating costs.be ongoing annually after 2016, until ANO transitions out of Column 4.
The NRC completed the supplemental inspection required for ANO’s Column 4 designation in February 2016, and published its inspection report in June 2016. In its inspection report, the NRC concluded that the ANO site is being operated safely and that Entergy understands the depth and breadth of performance concerns associated with ANO’s performance decline. Also in June 2016, the NRC issued a confirmatory action letter to confirm the actions Entergy Arkansas has taken and will continue to take to improve performance at ANO. The NRC will verify the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Baxter Wilson Plant Eventcompletion of those actions through quarterly follow-up inspections, the results of which will determine when ANO should transition out of Column 4. There have been no significant issues arising from the follow-up inspections.
Pilgrim NRC Oversight and Planned Shutdown
OnIn September 11, 2013, Entergy Mississippi’s Baxter Wilson (Unit 1) power plant experienced2015 the NRC placed Pilgrim in its “multiple/repetitive degraded cornerstone column,” or Column 4, of its Reactor Oversight Process Action Matrix due to its finding of continuing weaknesses in Pilgrim’s corrective action program that contributed to repeated unscheduled shutdowns and equipment failures. The preliminary estimate of direct costs of Pilgrim’s response to a significant unplanned outage event. Entergy Mississippi completed the repairsplanned NRC enhanced inspection ranges from $45 million to the unit in December 2014. As of December 31, 2014, Entergy Mississippi incurred $22.3$60 million, of capital spending and $26.6which $50 million has been incurred through the end of 2017 in operation and maintenance expensesexpense. The estimate does not include potential capital expenditures, which will be charged directly to returnexpense when incurred, or other costs to address issues that may arise in the unitinspection.
Entergy determined in October 2015 that it would close Pilgrim no later than June 1, 2019 because of poor market conditions that led to service.reduced revenues, a poor market design that failed to properly compensate nuclear generators for the benefits they provide, and increased operational costs. The damagedecision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision to place the plant in Column 4. Entergy determined in April 2016 that it intends to refuel Pilgrim in 2017 and then cease operations May 31, 2019. Pilgrim currently has approximately 677 MW of Capacity Supply Obligations in ISO New England through May 2019.
See Note 14 to the financial statements for discussion of the impairment of the Pilgrim plant and related long-lived assets.
Spent Nuclear Fuel Litigation
Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was covereddenied. The zero spent fuel fee went into effect prospectively in May 2014. Management cannot predict the potential timing or magnitude of future spent fuel fee revisions that may occur.
Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts. As a result of the DOE’s failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy’s nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. Beginning in November 2003 these subsidiaries have pursued litigation to recover the damages caused by the DOE’s delay in performance. Following are details of final judgments recorded by Entergy Mississippi’s property insurance policy, subjectin 2016 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In December 2015 the U.S. Court of Federal Claims issued a $20 million deductible. As of December 31, 2014, Entergy Mississippi recorded an insurance receivable of $28.2 million forjudgment in the amount expectedof $81 million in favor of Entergy Nuclear Indian Point 3 and Entergy Nuclear FitzPatrick in the first round Indian Point 3/FitzPatrick damages case, and Entergy received the payment from the U.S. Treasury in June 2016. The effect of recording the Indian Point 3 proceeds was a reduction to beplant, other operation and maintenance expense, and depreciation expense. The Indian Point 3 damages awarded included $45 million related to costs previously capitalized and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $45 million, Entergy recorded $8 million as a reduction to previously-recorded depreciation expense. Entergy reduced its Indian Point 3 plant asset balance by the remaining $37 million. The effect of recording the FitzPatrick proceeds was a reduction to plant and other operation and maintenance expense. The FitzPatrick damages awarded included $32 million related to costs previously capitalized and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $32 million, Entergy recorded $1 million as a reduction to previously-recorded depreciation expense, a $10 million reduction to bring its remaining FitzPatrick plant asset balance to zero, and the excess was recorded as a reduction to other operations and maintenance expense. See Note 14 for further discussion on the fair value analysis performed for FitzPatrick and the related impairment charge.
In April 2016 the U.S. Court of Federal Claims issued a partial judgment in the amount of $42 million in favor of Entergy Louisiana and against the DOE in the first round River Bend damages case. Entergy Louisiana received payment from the U.S. Treasury in August 2016. The effects of recording the final judgment in the third quarter 2016 were reductions to plant, nuclear fuel expense, other operation and maintenance expense, and depreciation expense. The River Bend damages awarded included $17 million related to costs previously capitalized, $23 million related to costs previously recorded as nuclear fuel expense, and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $17 million, Entergy Louisiana recorded $3 million as a reduction to previously-recorded depreciation expense. Entergy Louisiana reduced its insurance policy, allocating $12.9River Bend plant asset balance by the remaining $14 million. In September 2016 the U.S. Court of Federal Claims issued a further judgment in the River Bend case in the amount of $5 million. Entergy Louisiana recorded a receivable for that amount, and subsequently received payment from the U.S. Treasury in January 2017. The River Bend damages awarded included $2 million related to costs previously recorded as nuclear fuel expense and $3 million related to costs previously recorded as other operation and maintenance expense. In May 2017 the U.S. Court of Federal Claims issued a final judgment in the expected insurancefirst round River Bend damages case for $0.6 million, awarding certain cask loading costs that had not previously been adjudicated by the court.
In May 2016, Entergy Nuclear Vermont Yankee and the DOE entered into a stipulation agreement and the U.S. Court of Federal Claims issued a judgment in the amount of $19 million in favor of Entergy Nuclear Vermont Yankee and against the DOE in the second round Vermont Yankee damages case. Entergy received payment from the U.S. Treasury in June 2016. The effect of recording the proceeds was a reduction to capital spendingother operation and $15.3maintenance expense and depreciation expense. The damages awarded included $15 million related to costs previously capitalized and $4 million related to costs previously recorded as other operation and maintenance expense. Of the $15 million, Entergy recorded $2 million as a reduction to previously-recorded depreciation expense. The remaining $13 million would have been recorded as a reduction to Vermont Yankee’s plant asset balance, but was recorded as a reduction to other operation and maintenance expense because Vermont Yankee’s plant asset balance is fully impaired.
In June 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $49 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case. System Energy received payment from the U.S. Treasury in August 2016. The effects of recording the judgment in the third quarter 2016 were reductions to plant, nuclear fuel expense, other operation and maintenance expense, and depreciation expense. The amounts of Grand Gulf damages awarded related to System Energy’s 90% ownership of Grand Gulf included $16 million related to costs previously capitalized, $19 million related to costs previously recorded as nuclear fuel expense, and $9 million related to costs previously recorded as other operation and maintenance expense. Of the $16 million, System Energy recorded $5 million as a reduction to previously-recorded depreciation expense. System Energy reduced its Grand Gulf plant asset balance by the remaining $11 million.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In July 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $31 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case. Entergy Arkansas received payment from the U.S. Treasury in October 2016. The effects of recording the judgment were reductions to plant, nuclear fuel expense, and other operation and maintenance expense. The ANO damages awarded included $6 million related to costs previously capitalized, $19 million related to costs previously recorded as nuclear fuel expense, $5 million related to costs previously recorded as other operation and maintenance expense, and $1 million related to costs previously recorded as taxes other than income taxes.
In August 2016 the U.S. Court of Federal Claims issued a partial judgment in the amount of $53 million in favor of Entergy Louisiana and against the DOE in the first round Waterford 3 damages case. Entergy Louisiana received payment from the U.S. Treasury in November 2016. The effects of recording the judgment were reductions to plant, nuclear fuel expense, other operation and maintenance expense, and depreciation expense. The Waterford 3 damages awarded included $41 million related to costs previously capitalized, $10 million related to costs previously recorded as nuclear fuel expense, and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $41 million, Entergy Louisiana recorded $3 million as a reduction to previously-recorded depreciation expense.
In September 2016 the U.S. Court of Federal Claims issued a judgment in the Entergy Nuclear Palisades case in the amount of $14 million. Entergy Nuclear Palisades recorded a receivable for that amount, and subsequently received payment from the U.S. Treasury in January 2017. The effects of recording the judgment were reductions to plant and other operation and maintenance expenses. In June 2014, Entergy Mississippi filed a rate case with the MPSC, which includes recovery of theThe Palisades damages awarded included $11 million related to costs associated with Baxter Wilson (Unit 1) repair activities, net of applicable insurance proceeds. In December 2014 the MPSC issued an order that provided for a deferral of $6previously capitalized and $3 million inrelated to costs previously recorded as other operation and maintenance expenses associated withexpense. Of the Baxter Wilson outage$11 million, Entergy recorded $1 million as a reduction to previously-recorded depreciation expense. Entergy reduced its Palisades plant asset balance by the remaining $10 million. The Court previously issued a partial judgment in the case in the amount of $21 million, which was paid by the U.S. Treasury in October 2015.
In October 2016 the U.S. Court of Federal Claims issued a judgment in the second round Entergy Nuclear Indian Point 2 case in the amount of $34 million. Entergy Nuclear Indian Point 2 recorded a receivable for that amount, and thatsubsequently received payment from the regulatoryU.S. Treasury in January 2017. The effects of recording the judgment were reductions to plant and other operation and maintenance expenses. The Indian Point 2 damages awarded included $14 million related to costs previously capitalized, $15 million related to costs previously recorded as other operation and maintenance expense, $3 million related to previously recorded decommissioning expense, and $2 million related to costs previously recorded as taxes other than income taxes. Of the $14 million, Entergy recorded $3 million as a reduction to previously-recorded depreciation expense. Entergy reduced its Indian Point 2 plant asset should accrue carrying costs, with amortizationbalance by the remaining $11 million.
Management cannot predict the timing or amount of any potential recoveries on other claims filed by Entergy subsidiaries, and cannot predict the timing of any eventual receipt from the DOE of the regulatory asset to occur over two years beginning in February 2015, and provided that the capital costs will be reflected in rate base. The final accountingU.S. Court of costs to return the unit to service and insurance proceeds will be addressed in Entergy Mississippi’s next formula rate plan filing.Federal Claims damage awards.
Nuclear Insurance
Third Party Liability Insurance
The Price-Anderson Act requires that reactor licensees purchase insurance and participate in a secondary insurance pool that provides insurance coverage for the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act requires nuclear power plants to show evidence of financial protection in the event of a nuclear accident. This protection must consist of two layers of coverage:
| |
| 1. | The primary level is private insurance underwritten by American Nuclear Insurers (ANI) and provides public liability insurance coverage of $450 million for each operating reactor (prior to January 1, 2017, the primary level of insurance was $375 million.million). If this amount is not sufficient to cover claims arising from an accident, the second level, Secondary Financial Protection, applies. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
the second level, Secondary Financial Protection, applies. In 2016 the NRC approved Vermont Yankee’s exemption request to lower their limits from $375 million to $100 million effective April 15, 2016.
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| 2. | Within the Secondary Financial Protection level, each nuclear reactor has a contingent obligation to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, regardless of proximity to the incident or fault, up to a maximum of approximately $127.3 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.4$1.146 billion). This consists of a $121.3 million maximum retrospective premium plus a five percent surcharge, which equates to $127.3 million, that may beis payable if needed, at a rate that is currently set at $19.0approximately $19 million per year per incident per nuclear power reactor. |
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| 3. | In the event that one or more acts of terrorism cause a nuclear power plant accident, which results in third-party damages – off-site property and environmental damage, off-site bodily injury, and on-site third-party bodily injury (i.e. contractors);, the primary level provided by ANI combined with the Secondary Financial Protection would provide $13.6approximately $13 billion in coverage. The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $100 billion in coverage in excess of existing coverage for a terrorist event. The Terrorism Risk Insurance Reauthorization Act of 2007 expired on December 31, 2014. However, The Terrorism Risk Insurance Reauthorization Act of 2015 was signed intoUnder current law, by the President of the United States on January 12, 2015 thereby extending the Terrorism Risk Insurance Act for six years until December 31,extends through 2020. |
Currently, 104102 nuclear reactors are participating in the Secondary Financial Protection program. Effective April 15, 2016 the NRC granted Vermont Yankee’s exemption request and it was allowed to withdraw from participation in this layer of financial protection. The product of the maximum retrospective premium assessment to the nuclear power industry and the number of nuclear power reactorsSecondary Financial Protection program provides over $13.2approximately $13 billion in secondary layer insurance coverage to compensate the public in the event of a nuclear power reactor accident. The Price-Anderson Act provides that all potential liability for a nuclear accident is limited to the amounts of insurance coverage available under the primary and secondary layers.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas hasand Entergy Louisiana each have two licensed reactors and Entergy Gulf States Louisiana, Entergy Louisiana, andreactors. System Energy each havehas one licensed reactor (10% of Grand Gulf is owned by a non-affiliated company (SMEPA)(Cooperative Energy) that would share on a pro-rata basis in any retrospective premium assessment to System Energy under the Price-Anderson Act). The Entergy Wholesale Commodities segment includes the ownership, operation, and decommissioning of nuclear power reactors and the ownership of the shutdown Indian Point 1 reactor and Big Rock Point facility.
Property Insurance
Entergy’s nuclear owner/licensee subsidiaries are members of NEIL, a mutual insurance company that provides property damage coverage, including decontamination and premature decommissioning expense, to the members’ nuclear generating plants. Effective April 1, 2014,The property damage insurance limits procured by Entergy was insured against such losses perfor its Utility plants and Entergy Wholesale Commodity plants are in compliance with the following structures:financial protection requirements of the NRC.
The Utility Plantsplants’ (ANO 1 and 2, Grand Gulf, River Bend, and Waterford 3)
Primary Layer (per plant) - property damage insurance limits are $1.5 billion per occurrence
Blanket Excess Layer (shared among the Utility plants) - at each plant with an additional $100 million per occurrence that is shared among the plants. Property damage from earthquake and volcanic eruption is excluded from the first $500 million in coverage for all Utility plants. Property damage from flood is excluded from the first $500 million in coverage at ANO 1 and 2 and Grand Gulf. Property damage from flood is included in the first $500 million for Waterford 3 and River Bend. Property damage from wind for all of the Utility nuclear plants includes a deductible of $10 million plus an additional 10% of the amount of the loss in excess of $10 million, up to a total maximum deductible of $50 million.
Total limit
The Entergy Wholesale Commodities’ plants (Pilgrim, Palisades, Indian Point, Vermont Yankee, and Big Rock Point) have property damage insurance limits as follows: Vermont Yankee - $50 million per occurrence; Big Rock Point - $500 million per occurrence; Pilgrim and Palisades - $1.115 billion per occurrence; and Indian Point - $1.6 billion per occurrence
Deductibles:
$2.5occurrence. For losses that are considered non-nuclear in nature, the property damage insurance limit at Pilgrim, Palisades, and Indian Point is $500 million per occurrence - Turbine/generatorand at Vermont Yankee is $50 million. Property damage
$2.5 from wind and flood at Indian Point includes a deductible of $10 million per occurrence - Other than turbine/generator damage
$10 million per occurrence plus an additional 10% of the amount aboveof the loss in excess of $10 million, - Damageup to a maximum deductible of $50 million, but property damage from a windstorm, flood, earthquake orand volcanic eruption
Note: ANO 1 and 2 share in the primary and blanket excess layers with common policies because the policies are issued on a per site basis. Flood and earthquake coverage are at Indian Point is excluded from the primary layer’s first $500 million. Property damage from wind at Pilgrim includes a deductible of $10 million plus an additional 10% of the amount of the loss in coverage. Entergy currently purchases flood coverage at Waterford 3 and River Bend for the primary layer’s first $500excess of $10 million, in coverage.up to a maximum
Entergy Wholesale Commodities Plants (FitzPatrick, Pilgrim, and Palisades)
Primary Layer (per plant) - $1.115 billion per occurrence
Total limit (per plant) - $1.115 billion per occurrence
Deductibles:
$2.5 million per occurrence - Turbine/generator damage
$2.5 million per occurrence - Other than turbine/generator damage
$10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption
Note: Flood and earthquake coverage are excluded from the primary layer’s first $500 million in coverage. Entergy currently purchases flood and earthquake coverage at Palisades for the primary layer’s first $500 million in coverage.
Entergy Wholesale Commodities Plant (Indian Point)
Primary Layer (per plant) - $1.5 billion per occurrence
Excess Layer - $100 million per occurrence
Total limit - $1.6 billion per occurrence
Deductibles:
$2.5 million per occurrence - Turbine/generator damage
$2.5 million per occurrence - Other than turbine/generator damage
$10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption
Note: The Indian Point Units share in the primary and excess layers with common policies because the policies are issued on a per site basis. Flood and earthquake coverage are excluded from the primary layer’s first $500 million
Entergy Corporation and Subsidiaries
Notes to Financial Statements
in coverage. Entergy currently purchases flood coverage at Indian Point for the primary layer’s first $500 million in coverage.
Entergy Wholesale Commodities Plant (Vermont Yankee)
Primary Layer (per plant) - $1.06 billion per occurrence
Total limit - $1.06 billion per occurrence
Deductibles:
$2.5deductible of $50 million, per occurrence - Turbine/generatorbut property damage
$2.5 million per occurrence - Other than turbine/generator damage
$10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, orand volcanic eruption
Note: Flood and earthquake coverage are at Pilgrim is excluded from the primary layer’s first $500 million in coverage. Entergy currently purchasesmillion. Property damage from wind, flood, earthquake, and earthquake coveragevolcanic eruption at Vermont Yankee forand Palisades includes a deductible of $10 million plus an additional 10% of the primary layer’s first $500amount of the loss in excess of $10 million, in coverage.up to a maximum deductible of $50 million.
Entergy Wholesale Commodities Plant (Big Rock Point)
Primary Layer (per plant) - $500 million per occurrence
Total limit - $500 million per occurrence
Note: FloodThe value of the insured property at the time of an accident at Pilgrim, Palisades, and earthquake coverage are excludedVermont Yankee has been changed from the primary layer’s first $500 million in coverage. Entergy currently purchases flood and earthquake coverage at Big Rock Point for the primary layer’s first $500 million in coverage.replacement cost to actual cash value.
In addition, Waterford 3 and Grand Gulf and the Entergy Wholesale Commodities plants, with the exception of Vermont Yankee, are also covered under NEIL’s Accidental Outage Coverage program. Due to Entergy’s gradual exit from the shutdown of the Vermont Yankee Nuclear Power Plant in December 2014, and the required 12 week deductible waiting periodmerchant/wholesale power business, Entergy no longer purchases Accidental Outage Coverage for its non-regulated, non-generation assets. Accidental outage coverage provides indemnification for the accidental outage coverage to take effect, accidental outage coverage was removed effective October 1, 2014. This coverage provides certain fixed indemnitiesactual cost incurred in the event of an unplanned outage that resultsresulting from a covered NEIL primary property damage loss,covered under the NEIL Primary Property Insurance policy, subject to a deductible period. The payoutindemnification for damage resulting fromthe actual cost incurred is based on market power prices at the time of the loss. For non-nuclear events, the maximum indemnity, under this policy, is limited to a $327.6 million per occurrence sub-limit. The following summarizes this coverage effective October 1, 2014:occurrence. After the deductible period has passed, weekly indemnities for an unplanned outage, covered under NEIL’s Accidental Outage Coverage program, would be paid according to the amounts listed below:
Waterford 3
$2.95 million100% of the weekly indemnity for each week for the first payment period of 52 weeks; then
$413 million maximum indemnity
Deductible: 26 week deductible period
Grand Gulf
$400,00080% of the weekly indemnity (total for four policies)each week for the second payment period of 52 weeks; and thereafter
$56 million maximum indemnity (total for four policies)
Deductible: 26 week deductible period
Indian Point 2, Indian Point 3, and Palisades
$4.5 million80% of the weekly indemnity for an additional 58 weeks for the third and final payment period.
$490 million maximum indemnity
Deductible: 12 week deductible period
FitzPatrick and Pilgrim
$4 million weekly indemnity
$490 million maximum indemnity
Deductible: 12 week deductible period
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the property damage and accidental outage insurance programs, all NEIL insured plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. Effective April 1, 2014,2017, the maximum amounts of such possible assessments per occurrence were as follows:
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| | Assessments |
| | (In Millions) |
| Utility: | |
| Entergy Arkansas | $32.2 |
Entergy Gulf States Louisiana | $25.540.3 |
| Entergy Louisiana | $26.149.4 |
| Entergy Mississippi | $0.090.11 |
| Entergy New Orleans | $0.090.11 |
| Entergy Texas | N/A |
| System Energy | $21.522.3 |
| | |
| Entergy Wholesale Commodities | $— |
Potential assessments for the Entergy Wholesale Commodities plants are covered by insurance obtained through NEIL’s reinsurers.
Entergy maintains property insurance for its nuclear units in excess of the NRC’s minimum requirement of $1.06 billion per site for nuclear power plant licensees. NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations. Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors.
In the event that one or more acts of terrorism causes property damage under one or more or all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first property damage occurs, the maximum recovery under all such nuclear insurance policies shall be an aggregate ofnot exceeding $3.24 billion plus the additional amounts recovered for such losses from reinsurance, indemnity, and any other sources applicable to such losses. The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $100 billion in coverage in excess of existing coverage for a terrorist event. The Terrorism Risk Insurance Reauthorization Act of 2007 expired on December 31, 2014. However, The Terrorism Risk Insurance Reauthorization Act of 2015 was signed into law by the President of the United States on January 12, 2015 thereby extending the Terrorism Risk Insurance Act for six years until December 31, 2020.
Conventional Property Insurance
Entergy’s conventional property insurance program provides coverage of up to $400 million on an Entergy system-wide basis for all operational perils (direct physical loss or damage due to machinery breakdown, electrical failure, fire, lightning, hail, or explosion) on an “each and every loss” basis; up to $400 million in coverage for certain natural perils (direct physical loss or damage due to earthquake, tsunami, and flood) on an annual aggregate basis; up to $125 million for certain other natural perils (direct physical loss or damage due to a named windstorm and associated storm surge) on an annual aggregate basis; and up to $400 million in coverage for all other natural perils not previously stated (direct physical loss or damage due to a tornado, ice storm, or any other natural peril except named windstorm and associated storm surge, earthquake, tsunami, and flood) on an “each and every loss” basis. The conventional property insurance program provides up to $50 million in coverage for the Entergy New Orleans gas distribution system on an “each and every loss” basis. This $50 million limit is subject to: the $400 million annual aggregate limit for the natural perils of earthquake, tsunami, and flood; the $125 million annual aggregate limit for the natural perils of named windstorm and associated storm surge. The coverage is subject to a $40 million self-insured retention per occurrence for the natural perils of named windstorm and associated storm surge, earthquake, flood, and tsunami; and a $20 million
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Non-Nuclear Property Insurance
Entergy’s non-nuclear property insurance program provides coverage on a system-wide basis for Entergy’s non-nuclear assets. The insurance program provides coverage up to $400 million per occurrence, “each and every loss” basis in excess of a $20 million self-insured retention per occurrence for operational perilswith the exception of the following: earthquake shock, flood, and all other natural perils not previously stated, which includes tornadonamed windstorm, including associated storm surge. For earthquake shock and ice storm, but excludesflood, the insurance program provides coverage up to $400 million on an annual aggregate basis in excess of a $40 million self-insured retention. For named windstorm and associated storm surge, the insurance program provides coverage up to $125 million on an annual aggregate basis in excess of a $40 million self-insured retention. The coverage provided by the insurance program for the Entergy New Orleans gas distribution system is limited to $50 million per occurrence and is subject to the same annual aggregate limits and retentions listed above for earthquake tsunami,shock, flood, and flood.named windstorm, including associated storm surge.
Covered property generally includes power plants, substations, facilities, inventories, and gas distribution-related properties. Excluded property generally includes above-ground transmission and distribution lines, poles, and towers fortowers. For substations valued at $5 million or less, coverage for named windstorm and associated storm surge is excluded. This coverage is in place for Entergy Corporation, the Registrant Subsidiaries, and certain other Entergy subsidiaries, including the owners of the nuclear power plants in the Entergy Wholesale Commodities segment. Entergy also purchases $300 million in terrorism insurance coverage for its conventional property. The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $100 billion in coverage in excess of existing coverage for a terrorist event. The Terrorism Risk Insurance Reauthorization Act of 2007 expired on December 31, 2014. However, The Terrorism Risk Insurance Reauthorization Act of 2015 was signed intoUnder current law, by the President of the United States on January 12, 2015 thereby extending the Terrorism Risk Insurance Act for six years until December 31,extends through 2020.
InPrior to June 1, 2017, Entergy purchased additional coverage for some of its non-regulated, non-generation assets in addition to the insurance procured via the conventional property insurance program,program. The policy served to buy-down the conventional property insurance policy’s $20 million deductible and was placed on a scheduled location basis. Due to Entergy’s gradual exit from the merchant/wholesale power business, effective June 1, 2017, Entergy has purchasedno longer purchases this additional coverage ($20 million per occurrence) for some of its non-regulated, non-generation assets. This policy serves to buy-down the $20 million deductible and is placed on a scheduled location basis. The applicable deductibles are $100,000 to $250,000, except for properties that are damaged by flooding and properties whose values are greater than $20 million; these properties have a $500,000 deductible. Four nuclear locations have a $2.5 million deductible, which coincides with the nuclear property insurance deductible at each respective nuclear site.
Gas System Rebuild Insurance Proceeds (Entergy New Orleans)
Entergy New Orleans received insurance proceeds for future construction expenditures associated with rebuilding its gas system, and the October 2006 City Council resolution approving the settlement of Entergy New Orleans’s rate and storm-cost recovery filings requires Entergy New Orleans to record those proceeds in a designated sub-account of other deferred credits until the proceeds are spent on the rebuild project. This other deferred credit is shown as “Gas system rebuild insurance proceeds” on Entergy New Orleans’s balance sheet.
Employment and Labor-related Proceedings
The Registrant Subsidiaries and other Entergy subsidiaries are responding to various lawsuits in both state and federal courts and to other labor-related proceedings filed by current and former employees, recognized bargaining representatives, and third parties not selected for open positions or providing services directly or indirectly to one or more of the Registrant Subsidiaries and other Entergy subsidiaries. Generally, the amount of damages being sought is not specified in these proceedings. These actions include, but are not limited to, allegations of wrongful employment actions; wage disputes and other claims under the Fair Labor Standards Act or its state counterparts; claims of race, gender, age, and disability discrimination; disputes arising under collective bargaining agreements; unfair labor practice proceedings and other administrative proceedings before the National Labor Relations Board or concerning the National Labor Relations Act; claims of retaliation; claims of harassment and hostile work environment; and claims for or regarding benefits under various Entergy Corporation-sponsored plans. Entergy and the Registrant Subsidiaries are responding to these lawsuits and proceedings and deny liability to the claimants. Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position, results of operation, or cash flows of Entergy or the Utility operating companies.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Asbestos Litigation (Entergy Gulf States Louisiana,Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
Numerous lawsuits have been filed in federal and state courts, primarily in Texas and Louisiana, primarily by contractor employees who worked in the 1940-1980s timeframe, primarily against Entergy Gulf States Louisiana and Entergy Texas, and to a lesser extent the other Utility operating companies, as premises owners of power plants, for damages caused by alleged exposure to asbestos. Many other defendants are named in these lawsuits as well. Currently, there are approximately 400200 lawsuits involving
Entergy Corporation and Subsidiaries
Notes to Financial Statements
approximately 4,000500 claimants. Management believes that adequate provisions have been established to cover any exposure. Additionally, negotiations continue with insurers to recover reimbursements. Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position, results of operation, or cash flows of the Utility operating companies.
Grand Gulf - Related Agreements
Capital Funds Agreement (Entergy Corporation and System Energy)
System Energy has entered into agreements with Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans whereby they are obligated to purchase their respective entitlements of capacity and energy from System Energy’s interest in Grand Gulf, and to make payments that, together with other available funds, are adequate to cover System Energy’s operating expenses. System Energy would have to secure funds from other sources, including Entergy Corporation’s obligations under the Capital Funds Agreement, to cover any shortfalls from payments received from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under these agreements.
Unit Power Sales Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
System Energy has agreed to sell all of its share of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans in accordance with specified percentages (Entergy Arkansas-36%, Entergy Louisiana-14%, Entergy Mississippi-33%, and Entergy New Orleans-17%) as ordered by the FERC. Charges under this agreement are paid in consideration for the purchasing companies’ respective entitlement to receive capacity and energy and are payable irrespective of the quantity of energy delivered. The agreement will remain in effect until terminated by the parties and the termination is approved by the FERC, most likely upon Grand Gulf’s retirement from service. In December 2016 the NRC granted the extension of Grand Gulf’s operating license to 2044. Monthly obligations are based on actual capacity and energy costs. The average monthly payments for 20142017 under the agreement are approximately $20.2$19.5 million for Entergy Arkansas, $8.0$7.8 million for Entergy Louisiana, $17.4$17 million for Entergy Mississippi, and $9.8$9.4 million for Entergy New Orleans. See Note 2 to the financial statements for discussion of the complaint filed with the FERC against System Energy seeking a reduction in the return on equity component of the Unit Power Sales Agreement.
Availability Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (Entergy Arkansas-17.1%, Entergy Louisiana-26.9%, Entergy Mississippi-31.3%, and Entergy New Orleans-24.7%) in amounts that, when added to amounts received under the Unit Power Sales Agreement or otherwise, are adequate to cover all of System Energy’s operating expenses as defined, including an amount sufficient to amortize the cost of Grand Gulf 2 over 27 years (See Reallocation Agreement terms below) and expenses incurred in connection with a permanent shutdown of Grand Gulf. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Reallocation Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans entered into the Reallocation Agreement relating to the sale of capacity and energy from Grand Gulf and the related costs, in which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans agreed to assume all of Entergy Arkansas’s responsibilities and obligations with respect to Grand Gulf under the Availability Agreement. The FERC’s decision allocating a portion of Grand Gulf capacity and energy to Entergy Arkansas supersedes the Reallocation Agreement as it relates to Grand Gulf. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (Entergy Louisiana-26.23%, Entergy Mississippi-43.97%, and Entergy New Orleans-29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect Entergy Arkansas’s obligation to System Energy’s lenders under the assignments referred to in the preceding paragraph. Entergy Arkansas would be liable for its share of such amounts if Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans were unable to meet their contractual obligations. No payments of any amortization amounts will be required so long as amounts paid to System Energy under the Unit Power Sales Agreement, including other funds available to System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future.
Reimbursement Agreement (System Energy)
In December 1988, in two separate but substantially identical transactions, System Energy sold and leased back undivided ownership interests in Grand Gulf for the aggregate sum of $500 million. During the term of the leases, System Energy is required to maintain letters of credit for the equity investors to secure certain amounts payable to the equity investors under the transactions.
Under the provisions of the reimbursement agreement relating to the letters of credit, System Energy has agreed to a number of covenants regarding the maintenance of certain capitalization and fixed charge coverage ratios. System Energy agreed, during the term of the reimbursement agreement, to maintain a ratio of debt to total liabilities and equity less than or equal to 70%. In addition, System Energy must maintain, with respect to each fiscal quarter during the term of the reimbursement agreement, a ratio of adjusted net income to interest expense of at least 1.50 times earnings. As of December 31, 2014, System Energy was in compliance with these covenants.
NOTE 9. ASSET RETIREMENT OBLIGATIONS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Accounting standards require companies to record liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of the assets. For Entergy, substantially all of its asset retirement obligations consist of its liability for decommissioning its nuclear power plants. In addition, an insignificant amount of removal costs associated with non-nuclear power plants is also included in the decommissioning line item on the balance sheets.
These liabilities are recorded at their fair values (which are the present values of the estimated future cash outflows) in the period in which they are incurred, with an accompanying addition to the recorded cost of the long-lived asset. The asset retirement obligation is accreted each year through a charge to expense, to reflect the time value of money for this present value obligation. The accretion will continue through the completion of the asset retirement activity. The amounts added to the carrying amounts of the long-lived assets will be depreciated over the useful lives
Entergy Corporation and Subsidiaries
Notes to Financial Statements
of the assets. The application of accounting standards related to asset retirement obligations is earnings neutral to the rate-regulated business of the Registrant Subsidiaries.
In accordance with ratemaking treatment and as required by regulatory accounting standards, the depreciation provisions for the Registrant Subsidiaries include a component for removal costs that are not asset retirement obligations under accounting standards. In accordance with regulatory accounting principles, the Registrant Subsidiaries have recorded regulatory assets (liabilities) in the following amounts to reflect their estimates of the difference between estimated incurred removal costs and estimated removal costs recovered in rates:
| | | | December 31, | December 31, |
| | 2014 | | 2013 | 2017 | | 2016 |
| | (In Millions) | (In Millions) |
| Entergy Arkansas | $59.0 | | $18.6 | $176.9 | | $128.5 |
| Entergy Gulf States Louisiana | ($36.9) | | ($35.3) | |
| Entergy Louisiana | ($45.7) | | ($37.0) | ($32.4) | | ($53.9) |
| Entergy Mississippi | $76.3 | | $64.3 | $91.6 | | $82.0 |
| Entergy New Orleans | $35.2 | | $34.9 | $44.8 | | $40.1 |
| Entergy Texas | $18.9 | | $15.1 | $55.2 | | $33.5 |
| System Energy | $55.7 | | $56.0 | $67.9 | | $69.7 |
The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2014 by Entergy were as follows:
|
| | | | | | | | | | | | | | | | | |
| | Liabilities as of December 31, 2013 | | Accretion | | Change in Cash Flow Estimate | | Spending | | Liabilities as of December 31, 2014 |
| | (In Millions) |
| Utility: | | | | | | | | | |
| Entergy Arkansas | $723.8 | |
| $47.0 |
| |
| $47.6 |
| |
| $— |
| |
| $818.4 |
|
| Entergy Gulf States Louisiana | $403.1 | |
| $23.5 |
| |
| $20.0 |
| |
| $— |
| |
| $446.6 |
|
| Entergy Louisiana | $479.1 | |
| $24.6 |
| |
| $— |
| |
| $— |
| |
| $503.7 |
|
| Entergy Mississippi | $6.4 | |
| $0.4 |
| |
| $— |
| |
| $— |
| |
| $6.8 |
|
| Entergy New Orleans | $2.3 | |
| $0.2 |
| |
| $— |
| |
| $— |
| |
| $2.5 |
|
| Entergy Texas | $4.3 | |
| $0.3 |
| |
| $— |
| |
| $— |
| |
| $4.6 |
|
| System Energy | $616.2 | |
| $41.8 |
| |
| $99.9 |
| |
| $— |
| |
| $757.9 |
|
| Entergy Wholesale Commodities | $1,698.2 | |
| $139.7 |
| |
| $101.6 |
| |
| ($21.7 | ) | |
| $1,917.8 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The cumulative decommissioning and retirement cost liabilities and expenses recorded in 20132017 and 2016 by Entergy were as follows:
| | | | Liabilities as of December 31, 2012 | | Accretion | | Change in Cash Flow Estimate | | Spending | | Liabilities as of December 31, 2013 | Liabilities as of December 31, 2016 | | Accretion | | Change in Cash Flow Estimate | | Spending | | Dispositions | | Liabilities as of December 31, 2017 |
| | (In Millions) | (In Millions) |
| Utility: | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas |
| $680.7 |
| |
| $43.1 |
| |
| $— |
| |
| $— |
| |
| $723.8 |
|
| $924.4 |
| |
| $56.8 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $981.2 |
|
| Entergy Gulf States Louisiana |
| $380.8 |
| |
| $22.3 |
| |
| $— |
| |
| $— |
| |
| $403.1 |
| |
| Entergy Louisiana |
| $418.1 |
| |
| $21.6 |
| |
| $39.4 |
| |
| $— |
| |
| $479.1 |
| 1,082.7 |
| | 57.8 |
| | — |
| | — |
| | — |
| | 1,140.5 |
|
| Entergy Mississippi |
| $6.0 |
| |
| $0.4 |
| |
| $— |
| |
| $— |
| |
| $6.4 |
| 8.7 |
| | 0.5 |
| | — |
| | — |
| | — |
| | 9.2 |
|
| Entergy New Orleans |
| $2.2 |
| |
| $0.1 |
| |
| $— |
| |
| $— |
| |
| $2.3 |
| 2.9 |
| | 0.2 |
| | — |
| | — |
| | — |
| | 3.1 |
|
| Entergy Texas |
| $4.1 |
| |
| $0.2 |
| |
| $— |
| |
| $— |
| |
| $4.3 |
| 6.5 |
| | 0.3 |
| | — |
| | — |
| | — |
| | 6.8 |
|
| System Energy |
| $478.4 |
| |
| $35.5 |
| |
| $102.3 |
| |
| $— |
| |
| $616.2 |
| 854.2 |
| | 43.4 |
| | (35.9 | ) | | — |
| | — |
| | 861.7 |
|
| Entergy Wholesale Commodities |
| $1,543.3 |
| |
| $125.3 |
| |
| $38.6 |
| |
| ($9.0 | ) | |
| $1,698.2 |
| |
| Total | | 2,879.4 |
| | 159.0 |
| | (35.9 | ) | | — |
| | — |
| | 3,002.5 |
|
| | | | | | | | | | | | | |
| Entergy Wholesale Commodities: | | Entergy Wholesale Commodities: | | | | | | | | | |
| Big Rock Point | | 37.9 |
| | 3.1 |
| | — |
| | (2.1 | ) | | — |
| | 38.9 |
|
| FitzPatrick | | 714.3 |
| (a) | 13.9 |
| | — |
| | (0.9 | ) | | (727.3 | ) | (b) | — |
|
| Indian Point 1 | | 207.6 |
| | 17.7 |
| | — |
| | (7.7 | ) | | — |
| | 217.6 |
|
| Indian Point 2 | | 653.1 |
| | 55.8 |
| | — |
| | (0.2 | ) | | — |
| | 708.7 |
|
| Indian Point 3 | | 641.1 |
| | 53.5 |
| | — |
| | (0.1 | ) | | — |
| | 694.5 |
|
| Palisades | | 500.3 |
| | 41.3 |
| | (68.7 | ) | | (2.5 | ) | | — |
| | 470.4 |
|
| Pilgrim | | 602.3 |
| | 52.8 |
| | — |
| | (3.7 | ) | | — |
| | 651.4 |
|
| Vermont Yankee | | 470.5 |
| | 34.4 |
| | — |
| | (103.4 | ) | | — |
| | 401.5 |
|
| Other (c) | | 0.3 |
| | — |
| | — |
| | — |
| | — |
| | 0.3 |
|
| Total | | 3,827.4 |
| | 272.5 |
| | (68.7 | ) | | (120.6 | ) | | (727.3 | ) | | 3,183.3 |
|
| | | | | | | | | | | | | |
| Entergy Total | |
| $6,706.8 |
| |
| $431.5 |
| |
| ($104.6 | ) | |
| ($120.6 | ) | |
| ($727.3 | ) | |
| $6,185.8 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Liabilities as of December 31, 2015 | | Liabilities Incurred | | Accretion | | Change in Cash Flow Estimate | | Spending | | Liabilities as of December 31, 2016 | |
| | (In Millions) | |
| Utility: | | | | | | | | | | | | |
| Entergy Arkansas |
| $872.3 |
| |
| $— |
| |
| $53.6 |
| |
| $— |
| |
| ($1.5 | ) | |
| $924.4 |
| |
| Entergy Louisiana | 1,027.9 |
| | — |
| | 54.8 |
| | — |
| | — |
| | 1,082.7 |
| |
| Entergy Mississippi | 8.3 |
| | — |
| | 0.4 |
| | — |
| | — |
| | 8.7 |
| |
| Entergy New Orleans | 2.7 |
| | — |
| | 0.2 |
| | — |
| | — |
| | 2.9 |
| |
| Entergy Texas | 6.1 |
| | — |
| | 0.4 |
| | — |
| | — |
| | 6.5 |
| |
| System Energy | 803.4 |
| | — |
| | 50.8 |
| | — |
| | — |
| | 854.2 |
| |
| Total | 2,720.7 |
| | — |
| | 160.2 |
| | — |
| | (1.5 | ) | | 2,879.4 |
| |
| | | | | | | | | | | | | |
| Entergy Wholesale Commodities: | |
|
| |
|
| |
|
| |
|
| |
| Big Rock Point | 28.0 |
| | — |
| | 2.2 |
| | 10.1 |
| | (2.4 | ) | | 37.9 |
| |
| FitzPatrick | — |
| (d) | 696.2 |
| | 18.1 |
| | — |
| | — |
| | 714.3 |
| (a) |
| Indian Point 1 | 197.9 |
| | — |
| | 17.1 |
| | (0.3 | ) | | (7.1 | ) | | 207.6 |
| |
| Indian Point 2 | 390.1 |
| | — |
| | 33.0 |
| | 230.0 |
| | — |
| | 653.1 |
| |
| Indian Point 3 | — |
| (d) | 466.3 |
| | 12.1 |
| | 162.7 |
| | — |
| | 641.1 |
| |
| Palisades | 342.0 |
| | — |
| | 29.5 |
| | 128.8 |
| | — |
| | 500.3 |
| |
| Pilgrim | 551.2 |
| | — |
| | 48.4 |
| | 3.2 |
| | (0.5 | ) | | 602.3 |
| |
| Vermont Yankee | 560.0 |
| | — |
| | 39.3 |
| | — |
| | (128.8 | ) | | 470.5 |
| |
| Other (c) | 0.3 |
| | — |
| | — |
| | — |
| | — |
| | 0.3 |
| |
| Total | 2,069.5 |
| | 1,162.5 |
| | 199.7 |
| | 534.5 |
| | (138.8 | ) | | 3,827.4 |
| |
| | | | | | | | | | | | | |
| Entergy Total |
| $4,790.2 |
| |
| $1,162.5 |
| |
| $359.9 |
| |
| $534.5 |
| |
| ($140.3 | ) | |
| $6,706.8 |
| |
| |
| (a) | The FitzPatrick asset retirement obligation was classified as held for sale within other non-current liabilities on the consolidated balance sheet as of December 31, 2016. See Note 14 to the financial statements for discussion of the sale of the FitzPatrick plant to Exelon in March 2017. |
| |
| (b) | See Note 14 to the financial statements for discussion of the sale of the FitzPatrick plant to Exelon in March 2017. |
| |
| (c) | See “Coal Combustion Residuals” below for additional discussion regarding the asset retirement obligations related to coal combustion residuals management. |
| |
| (d) | See “Entergy Wholesale Commodities” in “Nuclear Plant Decommissioning” below for additional discussion regarding the decommissioning agreements with NYPA and the associated asset retirement obligations. |
Nuclear Plant Decommissioning
Entergy periodically reviews and updates estimated decommissioning costs. The actual decommissioning costs may vary from the estimates because of the timing of plant decommissioning, regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment. As described below, during 20142017 and 20132016, Entergy updated decommissioning cost estimates for certain nuclear power plants.
In 2014, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study. The revised estimates resulted in a $47.6 million increase in the decommissioning cost liabilities, along with a corresponding increase in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.Utility
See Note 1 to the financial statements for further discussion of the shutdown of Vermont Yankee and the December 2013 settlement agreement involving Entergy and Vermont parties. In accordance with the settlement agreement, Entergy Vermont Yankee provided to the Vermont parties, in 2014, a site assessment study of the costs and tasks of radiological decommissioning, spent nuclear fuel management, and site restoration for Vermont Yankee. Entergy Vermont Yankee also filed its Post-Shutdown Decommissioning Activities Report (PSDAR) for Vermont Yankee with the NRC in December 2014. As part of the development of the site assessment study and PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2014. The revised estimate, along with reassessment of the assumptions regarding the timing of decommissioning cash flows, resulted in a $101.6 million increase in the decommissioning cost liability and a corresponding impairment charge.
In the fourthsecond quarter 2014, Entergy Gulf States Louisiana recorded a revision to its estimated decommissioning cost liability for River Bend as a result of a revised decommissioning cost study. The revised estimate resulted in a $20 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining useful life of the unit.
In the fourth quarter 2014,2017, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $99.9$35.9 million increase
Entergy Corporation and Subsidiaries
Notes to Financial Statements
reduction in its decommissioning cost liability, along with a corresponding increasereduction in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.
Entergy Wholesale Commodities
In August 2013 the first quarter 2013, Entergy Wholesale Commodities recordedBoard approved a revisionplan to its estimated decommissioning cost liability for a nuclear site as a result of a revised decommissioning cost study. The revised estimate resulted in a $46.6 million reduction in the decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset.
Entergy Corporationclose and Subsidiaries
Notes to Financial Statements
In the third quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability fordecommission Vermont Yankee as a resultat the end of a revised decommissioning cost study. The revised estimate resulted in a $58 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the plant. The asset retirement cost asset was included in the carrying value used to write down Vermont Yankee and related assets to their fair values in third quarter 2013. See Note 1 to the financial statements for further discussion of the resulting impairment charge recorded in third quarter 2013.
In the fourth quarter 2013, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $102.3 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.
In the fourth quarter 2013, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $39.4 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.
In the fourth quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee. As a result of the settlement agreement regarding the remaining operation and decommissioning of Vermont Yankee, Entergy reassessed its assumptions regarding the timing of decommissioning cash flows. The reassessment resulted in a $27.2 million increase in the decommissioning cost liability and a corresponding impairment charge, which will not result in future cash expenditures. See Note 1 to the financial statements for further discussion of the Vermont Yankee plant.
In the second quarter 2012, Entergy Wholesale Commodities recorded a reduction of $60.6 million in the estimated decommissioning cost liability for a plant as a result of a revised decommissioning cost study. The revised estimate resulted in a credit to decommissioning expense of $49 million, reflecting the excess of the reduction in the liability over the amount of the undepreciated asset retirement costs asset.
2014. Vermont Yankee submitted notification of permanent cessation of operations and permanent removal of fuel from the reactor in January 2015 after final shutdown in December 2014. The PSDAR for Vermont Yankee, including a site specific cost estimate, was submitted to the NRC in December 2014. Vermont Yankee’s future certifications to satisfy the NRC’s financial assurance requirements will now be based on the site specific cost estimate, including the estimated cost of managing spent fuel, rather than the NRC minimum formula for estimating decommissioning costs. Entergy expects that amounts available in Vermont Yankee’s decommissioning trust fund, including expected earnings, together with the credit facilities entered into in January 2015 that are expected to be repaid with recoveries from DOE litigation related to spent fuel storage, will be sufficient to cover expected costs of decommissioning, spent fuel management costs, and site restoration. Filings with the NRC for planned shutdown activities will determine whether any other financial assurance may be required and will specifically address funding for spent fuel management, which will be required until the federal government takes possession of the fuel and removes it from the site, per its current obligation.
Entergy expects that amounts available in Vermont Yankee’s decommissioning trust fund, including expected earnings, together with borrowings under its credit facility that are expected to be repaid with recoveries from DOE litigation related to spent fuel storage, and the site restoration trust, will be sufficient to cover Vermont Yankee’s expected costs of decommissioning, spent fuel management costs, and site restoration. See Note 4 to the financial statements for discussion of the credit facility and Note 16 to the financial statements for discussion of the decommissioning trust fund. In June 2015 the NRC staff issued an exemption from its regulations to allow Vermont Yankee to use its decommissioning trust fund to pay for approximately $225 million of estimated future spent fuel management costs that will not be paid for using funds from its credit facility. In August 2015, Vermont and two Vermont utilities filed a petition in the U.S. Court of Appeals for the D.C. Circuit challenging the NRC’s issuance of that exemption. In February 2016 the court dismissed the petition as premature because Vermont and the utilities had requested the NRC to reconsider a number of issues related to Vermont Yankee's use of the decommissioning trust fund including its use to pay for spent fuel management expenses pursuant to the exemption granted in June 2015. In October 2016 the NRC denied Vermont's and the utilities' request for a hearing and other relief but directed the NRC staff to conduct an assessment of any environmental impacts associated with the exemption. In December 2017 the NRC issued its final environmental assessment, concluding that the exemption did not, and will not, have a significant effect on the environment.
In the fourth quarter 2016, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Palisades as a result of a revised decommissioning cost study. The revised estimate resulted in a $129 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the plant on October 1, 2018, subject to regulatory approval. The asset retirement cost asset was included in the Palisades carrying value that was written down to fair value in the fourth quarter 2016. See Note 14 to the financial statements for discussion of the impairment of the value and planned shutdown of the Palisades plant.
In the third quarter 2017, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Palisades. The revised estimate resulted in a $68.7 million reduction in its decommissioning cost liability, along with a corresponding reduction in the plant asset. The reduction in its estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to continue to operate the plant until May 31, 2022.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning truststrust funds and the decommissioning liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specifyspecified their decommissioning obligations. NYPA hashad the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assignsassigned the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. IfUnder the original agreements, if the decommissioning liabilities arewere retained by NYPA, the Entergy subsidiaries willwould perform the decommissioning of
Entergy Corporation and Subsidiaries
Notes to Financial Statements
the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts.trust funds. At the time of the acquisition of the plants Entergy recorded ana contract asset which is $599.9 million as of December 31, 2014, representing itsthat represented an estimate of the present value of the difference between the stipulated contract amount for decommissioning the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
plants less the decommissioning costs estimated in independent decommissioning cost studies. The asset iswas increased by monthly accretion based on the applicable discount rate necessary to ultimately provide for the estimated future value of the decommissioning contract. The monthly accretion iswas recorded as interest income.
In the third quarter 2015, Entergy Wholesale Commodities recorded a revision to the contract asset for the FitzPatrick plant. Due to a change in expectation regarding the timing of decommissioning cash flows, the result was a write down of the contract asset from $335 million to $131 million, for a charge of $204 million.
In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy. As a result of the agreement with NYPA, in the third quarter 2016 Entergy removed the contract asset from its balance sheet, and recorded receivables for the beneficial interests in the decommissioning trust funds and asset retirement obligations for the decommissioning liabilities. The transaction was contingent upon receiving approval from the NRC, which was received in January 2017. The decommissioning trust funds for the Indian Point 3 and FitzPatrick plants were transferred to Entergy by NYPA in January 2017. In March 2017, Entergy sold the FitzPatrick plant to Exelon, and as part of the transaction, the FitzPatrick decommissioning trust fund, along with the decommissioning obligation for that plant, was transferred to Exelon. See Note 14 to the financial statements for discussion of the sale of FitzPatrick.
In the fourth quarter 2016, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liabilities for Indian Point 1, Indian Point 2, and Indian Point 3 as a result of revised decommissioning cost studies. The revised estimates resulted in a $392 million increase in the decommissioning cost liabilities, along with a corresponding increase in the related asset retirement cost assets. The increase in the estimated decommissioning cost liabilities resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the Indian Point 2 plant no later than April 2020 and the Indian Point 3 plant no later than April 2021. The asset retirement cost assets were included in the carrying value that was written down to fair value in the fourth quarter 2016. See Note 14 to the financial statements for discussion of the impairment of the value and planned shutdown of Indian Point Energy Center.
As the Entergy Wholesale Commodities nuclear plants individually approach and begin decommissioning, the Entergy Wholesale Commodities plant owners will submit filings with the NRC for planned shutdown activities. These filings with the NRC will determine whether any other financial assurance may be required. The plants’ owners are required to provide the NRC with a biennial report (annually for units that have shut down or will shut down within five years), based on values as of December 31, addressing the owners’ ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, the Entergy Wholesale Commodities plant owners may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy maintains decommissioning trust funds that are committed to meeting its obligations for the costs of decommissioning the nuclear power plants. The fair values of the decommissioning trust funds and the related asset retirement obligation regulatory assets (liabilities) of Entergy as of December 31, 20142017 and 2016 are as follows:
| | | | | | | | 2017 | | 2016 |
| | Decommissioning Trust Fair Values | | Regulatory Asset (Liability) | Decommissioning Trust Fair Values | | Regulatory Asset (Liability) | | Decommissioning
Trust Fair Values | | Regulatory
Asset (Liability) |
| | (In Millions) | (In Millions) | | (In Millions) |
| Utility: | | | | | | | | | | |
| ANO 1 and ANO 2 |
| $769.9 |
| |
| $247.6 |
|
| $944.9 |
| | $337.9 | |
| $834.7 |
| |
| $316.3 |
|
| River Bend |
| $637.7 |
| |
| ($25.5 | ) |
| $818.2 |
| | ($30.6) | |
| $712.8 |
| |
| ($28.4 | ) |
| Waterford 3 |
| $383.6 |
| |
| $145.5 |
|
| $493.9 |
| | $188.9 | |
| $427.9 |
| |
| $172.8 |
|
| Grand Gulf |
| $679.8 |
| |
| $80.4 |
|
| $905.7 |
| | $169.1 | |
| $780.5 |
| |
| $142.5 |
|
| Entergy Wholesale Commodities |
| $2,899.9 |
| |
| $— |
|
| $4,049.3 |
| | $— | |
| $2,968.0 |
| |
| $— |
|
As a result of the agreement with NYPA discussed above, in the third quarter 2016, Entergy maintainsremoved the contract asset from its balance sheet, and recorded receivables of $1.5 billion for the beneficial interests in the decommissioning trust funds that are committed to meeting its obligations for Indian Point 3 and FitzPatrick. At December 31, 2016, the costs of decommissioning the nuclear power plants. The fair values of the decommissioning trust funds held by NYPA were $719 million for the Indian Point 3 plant and $785 million for the related asset retirement obligationFitzPatrick plant. See Note 16 to the financial statements for further discussion of the transfer of the decommissioning trust funds held by NYPA to Entergy.
Coal Combustion Residuals
In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained two primary regulatory assets (liabilities)options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of RCRA Subtitle C; or (2) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes under Subtitle D of RCRA. Under both options, CCRs that are beneficially reused in certain processes would remain excluded from hazardous waste regulation. In April 2015 the EPA published the final CCR rule with the material being regulated under the second scenario presented above - as non-hazardous wastes regulated under RCRA Subtitle D. The final regulations create new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria. Entergy asbelieves that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse. In December 2016, the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for permit programs. In September 2017 the EPA agreed to reconsider certain provisions of December 31, 2013 are as follows:
|
| | | | | | | |
| | Decommissioning Trust Fair Values | | Regulatory Asset (Liability) |
| | (In Millions) |
| Utility: | | | |
| ANO 1 and ANO 2 |
| $710.9 |
| |
| $219.1 |
|
| River Bend |
| $573.7 |
| |
| ($28.7 | ) |
| Waterford 3 |
| $347.3 |
| |
| $128.5 |
|
| Grand Gulf |
| $603.9 |
| |
| $60.8 |
|
| Entergy Wholesale Commodities |
| $2,667.3 |
| |
| $— |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 10. LEASES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
General
As of December 31, 2014,2017, Entergy had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities with minimum lease payments as follows (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf and Waterford 3 sale and leaseback transactions,transaction, all of which are discussed elsewhere):
| | Year | | Operating Leases | | Capital Leases | | Operating Leases | | Capital Leases |
| | | (In Thousands) | | (In Thousands) |
| 2015 | |
| $90,010 |
| |
| $4,615 |
| |
| 2016 | | 77,060 |
| | 4,457 |
| |
| 2017 | | 62,103 |
| | 4,457 |
| |
| 2018 | | 49,630 |
| | 3,672 |
| |
| $80,368 |
| |
| $3,018 |
|
| 2019 | | 47,527 |
| | 2,887 |
| | 82,516 |
| | 2,887 |
|
| 2020 | | | 67,385 |
| | 2,887 |
|
| 2021 | | | 58,507 |
| | 2,887 |
|
| 2022 | | | 43,760 |
| | 2,887 |
|
| Years thereafter | | 95,530 |
| | 27,664 |
| | 96,550 |
| | 19,004 |
|
| Minimum lease payments | | 421,860 |
| | 47,752 |
| | 429,086 |
| | 33,570 |
|
| Less: Amount representing interest | | — |
| | 15,773 |
| | — |
| | 10,051 |
|
| Present value of net minimum lease payments | |
| $421,860 |
| |
| $31,979 |
| |
| $429,086 |
| |
| $23,519 |
|
Total rental expenses for all leases (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf and Waterford 3 sale and leaseback transactions) amounted to $59$53.1 million in 2014, $63.72017, $44.4 million in 2013,2016, and $69.9$63.9 million in 2012.2015.
As of December 31, 20142017 the Registrant Subsidiaries had a capital lease and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities with minimum lease payments as follows (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf and Waterford 3 sale and leaseback transactions,lease obligation, all of which are discussed elsewhere):
CapitalOperating Leases
| | Year | | Entergy Mississippi | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (in Thousands) | | (In Thousands) |
| 2015 | |
| $1,570 |
| |
| 2016 | | 1,570 |
| |
| 2017 | | 1,570 |
| |
| 2018 | | 785 |
| |
| $17,009 |
| |
| $21,814 |
| |
| $11,771 |
| |
| $1,646 |
| |
| $3,469 |
|
| 2019 | | — |
| | 17,665 |
| | 22,875 |
| | 10,611 |
| | 1,579 |
| | 2,893 |
|
| 2020 | | | 11,483 |
| | 17,790 |
| | 8,969 |
| | 1,382 |
| | 1,934 |
|
| 2021 | | | 9,363 |
| | 13,762 |
| | 7,059 |
| | 1,033 |
| | 1,299 |
|
| 2022 | | | 6,834 |
| | 10,067 |
| | 5,007 |
| | 662 |
| | 862 |
|
| Years thereafter | | — |
| | 23,598 |
| | 19,443 |
| | 5,817 |
| | 1,797 |
| | 2,173 |
|
| Minimum lease payments | | 5,495 |
| |
| $85,952 |
| |
| $105,751 |
| |
| $49,234 |
| |
| $8,099 |
| |
| $12,630 |
|
| Less: Amount representing interest | | 656 |
| |
| Present value of net minimum lease payments | |
| $4,839 |
| |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Operating Leases
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Year | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| 2015 | |
| $28,647 |
| |
| $12,643 |
| |
| $11,006 |
| |
| $6,885 |
| |
| $2,115 |
| |
| $5,837 |
|
| 2016 | | 23,674 |
| | 10,880 |
| | 9,695 |
| | 5,388 |
| | 1,856 |
| | 5,111 |
|
| 2017 | | 16,501 |
| | 10,035 |
| | 7,784 |
| | 4,020 |
| | 1,587 |
| | 4,239 |
|
| 2018 | | 10,736 |
| | 9,100 |
| | 6,343 |
| | 3,376 |
| | 1,264 |
| | 3,707 |
|
| 2019 | | 11,365 |
| | 10,795 |
| | 5,003 |
| | 3,073 |
| | 1,087 |
| | 2,719 |
|
| Years thereafter | | 8,412 |
| | 26,671 |
| | 5,458 |
| | 3,212 |
| | 2,227 |
| | 2,981 |
|
| Minimum lease payments | |
| $99,335 |
| |
| $80,124 |
| |
| $45,289 |
| |
| $25,954 |
| |
| $10,136 |
| |
| $24,594 |
|
Rental Expenses
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Year | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) |
| 2014 | |
| $12.0 |
| |
| $10.9 |
| |
| $9.8 |
| |
| $4.3 |
| |
| $1.2 |
| |
| $3.8 |
| |
| $2.0 |
|
| 2013 | |
| $12.0 |
| |
| $10.9 |
| |
| $10.1 |
| |
| $4.6 |
| |
| $1.3 |
| |
| $4.1 |
| |
| $2.5 |
|
| 2012 | |
| $12.6 |
| |
| $11.9 |
| |
| $11.2 |
| |
| $5.5 |
| |
| $1.5 |
| |
| $6.4 |
| |
| $1.5 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Year | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) |
| 2017 | |
| $7.5 |
| |
| $23.0 |
| |
| $5.6 |
| |
| $2.5 |
| |
| $3.4 |
| |
| $2.2 |
|
| 2016 | |
| $8.0 |
| |
| $17.8 |
| |
| $4.0 |
| |
| $0.9 |
| |
| $2.8 |
| |
| $1.6 |
|
| 2015 | |
| $13.6 |
| |
| $21.8 |
| |
| $5.4 |
| |
| $1.6 |
| |
| $4.0 |
| |
| $2.9 |
|
In addition to the above rental expense, railcar operating lease payments and oil tank facilities lease payments are recorded in fuel expense in accordance with regulatory treatment. Railcar operating lease payments were $4.8$4.0 million in 2014, $8.62017, $3.4 million in 2013,2016, and $8.5$4.7 million in 20122015 for Entergy Arkansas and $1.7$0.3 million in 2014, $2.22017, $0.3 million in 2013,2016, and $1.7$1.1 million in 20122015 for Entergy Gulf States Louisiana. Oil tank facilities lease payments for Entergy Mississippi were $1.6 million in 2014, $3.42017, $1.6 million in 2013,2016, and $3.4$1.6 million in 2012.2015.
Power Purchase Agreements
As of December 31, 2014,2017, Entergy Texas had a power purchase agreement that is accounted for as an operating lease under the accounting standards. The lease payments are recovered in fuel expense in accordance with regulatory treatment. The minimum lease payments under the power purchase agreement are as follows:
| | Year | | Entergy Texas (a) | | Entergy | | Entergy Texas (a) | | Entergy |
| | | (In Thousands)
| | (In Thousands) |
| 2015 | |
| $28,450 |
| |
| $28,450 |
| |
| 2016 | | 29,104 |
| | 29,104 |
| |
| 2017 | | 29,772 |
| | 29,772 |
| |
| 2018 | | 30,458 |
| | 30,458 |
| |
| $30,458 |
| |
| $30,458 |
|
| 2019 | | 31,158 |
| | 31,158 |
| | 31,159 |
| | 31,159 |
|
| 2020 | | | 31,876 |
| | 31,876 |
|
| 2021 | | | 32,609 |
| | 32,609 |
|
| 2022 | | | 10,180 |
| | 10,180 |
|
| Years thereafter | | 74,664 |
| | 74,664 |
| | — |
| | — |
|
| Minimum lease payments | | 223,606 |
| | 223,606 |
| |
| $136,282 |
| |
| $136,282 |
|
(a) Amounts reflect 100% of minimum payments. Under a separate contract, Entergy Gulf States Louisiana purchases 50% of the capacity and energy from the power purchase agreement from Entergy Texas.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
| (a) | Amounts reflect 100% of minimum payments. Under a separate contract, which expires May 31, 2022, Entergy Louisiana purchases 50% of the capacity and energy from the power purchase agreement from Entergy Texas. |
Total capacity expense under the power purchase agreement accounted for as an operating lease at Entergy Texas was $29.2$34.1 million in 2014, $28.62017, $26.1 million in 2013,2016, and $19.2$29.9 million in 2012.2015.
SaleSales and Leaseback Transactions
Waterford 3 Lease ObligationsObligation
In 1989, in three separate but substantially identical transactions, Entergy Louisiana sold and leased back undivided interests in Waterford 3 for the aggregate sum of $353.6 million. The leases were scheduled to expire in July 2017. AtEntergy Louisiana was required to report the sale-leaseback as a financing transaction in its financial statements.
In December 2015, Entergy Louisiana agreed to purchase the undivided interests in Waterford 3 that were previously being leased. The purchase was accomplished in a two-step transaction in which Entergy Louisiana first
Entergy Corporation and Subsidiaries
Notes to Financial Statements
acquired the equity participant’s beneficial interest in the leased assets, followed by a termination of the leases and transfer of the leased assets to Entergy Louisiana when the outstanding lessor debt is paid.
In March 2016, Entergy Louisiana completed the first step in the two-step transaction by acquiring the equity participant’s beneficial interest in the leased assets. Entergy Louisiana paid $60 million in cash and $52 million through the issuance of a non-interest bearing collateral trust mortgage note, payable in installments through July 2017. Entergy Louisiana continued to make payments on the lessor debt that remained outstanding and which matured in January 2017. The combination of payments on the $52 million collateral trust mortgage note issued and the debt service on the lessor debt was equal in timing and amount to the remaining lease payments due from the closing of the transaction through the end of the lease terms,term in July 2017.
Throughout the term of the lease, Entergy Louisiana hashad accrued a liability for the optionamount it expected to repurchasepay to retain the leaseduse of the undivided interests in Waterford 3 at fair market value orthe end of the lease term. Since the sale-leaseback transaction was accounted for as a financing transaction, the accrual of this liability was accounted for as additional interest expense. As of December 2015, the balance of this liability was $62.7 million. Upon entering into the agreement to renewpurchase the leases for either fair market value or, under certain conditions, a fixed rate. Inequity participant’s beneficial interest in the event that Entergy Louisiana does not renew or purchase theundivided interests, Entergy Louisiana would surrender such interestsreduced the balance of the liability to $60 million, and their associated entitlementrecorded the $2.7 million difference as a credit to interest expense. The $60 million remaining liability was eliminated upon payment of Waterford 3’s capacity and energy.
Entergy Louisiana issued $208.2 million of non-interest bearing first mortgage bonds as collateral for the equitycash portion of certain amounts payable under the leases.
Upon the occurrence of certain events, Entergy Louisiana may be obligated to assume the outstanding bonds used to finance the purchase of the interestsprice in the unit and to pay an amount sufficient to withdraw from the lease transaction. Such events include lease events of default, events of loss, deemed loss events, or certain adverse “Financial Events.” “Financial Events” include, among other things, failure by Entergy Louisiana, following the expiration of any applicable grace or cure period, to maintain (i) total equity capital (including preferred membership interests) at least equal to 30% of adjusted capitalization, or (ii) a fixed charge coverage ratio of at least 1.50 computed on a rolling 12 month basis. As of December 31, 2014, Entergy Louisiana was in compliance with these provisions.2016.
As of December 31, 2014,2016, Entergy Louisiana, in connection with the Waterford 3 sale and leaseback transactions,lease obligation, had a future minimum lease paymentspayment (reflecting an overall implicitinterest rate of 7.45%8.09%) of $57.5 million, including $2.3 million in interest, due January 2017 that arewas recorded as long-term debt, as follows:debt.
|
| | | |
| | Amount |
| | (In Thousands) |
| | |
| 2015 |
| $28,827 |
|
| 2016 | 16,938 |
|
| 2017 | 106,335 |
|
| 2018 | — |
|
| 2019 | — |
|
| Years thereafter | — |
|
| Total | 152,100 |
|
| Less: Amount representing interest | 23,612 |
|
| Present value of net minimum lease payments |
| $128,488 |
|
Grand Gulf Lease Obligations
In 1988, in two separate but substantially identical transactions, System Energy sold and leased back undivided ownership interests in Grand Gulf for the aggregate sum of $500 million. The initial term of the leases was to expireexpired in July 2015. In December 2013, System Energy exercised its options to renewrenewed the leases for fair market value with a renewal term for one lease expiring in July 2018 and the renewal term of the other leaseterms expiring in July 2036. At the end of the new lease renewal terms, System Energy has the option to repurchase the leased interests in Grand Gulf or renew the leases at fair market value. In the event that System Energy does not renew or purchase the interests, System Energy would surrender such interests and their associated entitlement of Grand Gulf’s capacity and energy.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
System Energy is required to report the sale-leaseback as a financing transaction in its financial statements. For financial reporting purposes, System Energy expenses the interest portion of the lease obligation and the plant depreciation. However, operating revenues include the recovery of the lease payments because the transactions are accounted for as a sale and leaseback for ratemaking purposes. Consistent with a recommendation contained in a FERC audit report, System Energy initially recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and continues to record this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance for the regulatory asset at the end of the lease term. The amount was a net regulatory liability of $62.9 million and $61.6$55.6 million as of December 31, 20142017 and 2013, respectively.2016.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
As of December 31, 2014,2017, System Energy, in connection with the Grand Gulf sale and leaseback transactions, had future minimum lease payments (reflecting an implicit rate of 5.13%) that are recorded as long-term debt, as follows:
| | | | Amount | Amount |
| | (In Thousands) | (In Thousands) |
| | | |
| 2015 |
| $52,253 |
| |
| 2016 | 13,750 |
| |
| 2017 | 13,750 |
| |
| 2018 | 13,750 |
|
| $17,188 |
|
| 2019 | 13,750 |
| 17,188 |
|
| 2020 | | 17,188 |
|
| 2021 | | 17,188 |
|
| 2022 | | 17,188 |
|
| Years thereafter | 233,750 |
| 240,625 |
|
| Total | 341,003 |
| 326,565 |
|
| Less: Amount representing interest | 290,332 |
| 292,209 |
|
| Present value of net minimum lease payments |
| $50,671 |
|
| $34,356 |
|
NOTE 11. RETIREMENT, OTHER POSTRETIREMENT BENEFITS, AND DEFINED CONTRIBUTION PLANS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Qualified Pension Plans
Entergy has nineeight qualified pension plans covering substantially all employees. The “EntergyEntergy Corporation Retirement Plan for Non-Bargaining Employees” “Entergy (Non-Bargaining Plan I), the Entergy Corporation Retirement Plan for Bargaining Employees” “Entergy (Bargaining Plan I),the Entergy Corporation Retirement Plan II for Non-Bargaining Employees” “Entergy (Non-Bargaining Plan II), the Entergy Corporation Retirement Plan II for Bargaining Employees,” “Entergy the Entergy Corporation Retirement Plan IV for Non-Bargaining Employees,”III, and “Entergythe Entergy Corporation Retirement Plan IV for Bargaining Employees”Employees are non-contributory final average pay plans and provide pension benefits that are based on employees’ credited service and compensation during employment. The “EntergyEffective as of the close of business on December 31, 2016, the Entergy Corporation Retirement Plan III” isIV for Non-Bargaining Employees (Non-Bargaining Plan IV) was merged with and into Non-Bargaining Plan II. At the close of business on December 31, 2016, the liabilities for the accrued benefits and the assets attributable to such liabilities of all participants in Non-Bargaining Plan IV were assumed by and transferred to Non-Bargaining Plan II. There was no loss of vesting or benefit options or reduction of accrued benefits to affected participants as a final average payresult of this plan that provides pension benefits that are based on employees’ credited service and compensation during the final years before retirement and includes a mandatory employee contribution of 3% of earnings during the first 10 years of plan participation, and allows voluntary contributions from 1% to 10% of earnings for a limited group of employees.merger. Non-bargaining employees hired or rehiredwhose most recent date of hire is after June 30, 2014 participate in the “EntergyEntergy Corporation Cash Balance Plan for Non-Bargaining Employees.”Employees (Non-Bargaining Cash Balance Plan). Certain bargaining employees hired or rehired after June 30, 2014, or such later date provided for in their applicable collective bargaining agreements, participate in the “EntergyEntergy Corporation Cash Balance Plan for Bargaining Employees.”Employees (Bargaining Cash Balance Plan). The Registrant Subsidiaries participate in these four plans: “Entergy Corporation RetirementNon-Bargaining Plan forI, Bargaining Plan I, Non-Bargaining Employees,” “Entergy Corporation Retirement Plan for Bargaining Employees,” “Entergy Corporation Cash Balance Plan, for Non-Bargaining Employees,” and “EntergyBargaining Cash Balance Plan for Bargaining Employees.”Plan.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The assets of the sevensix final average pay qualified pension plans are held in a master trust established by Entergy, and the assets of the two cash balance pension plans are held in a second master trust established by Entergy. Each pension plan has an undivided beneficial interest in each of the investment accounts in its respective master trust that is maintained by a trustee. Use of the master trusts permits the commingling of the trust assets of the pension plans of Entergy Corporation and its Registrant Subsidiaries for investment and administrative purposes. Although assets in the master trusts are commingled, the trustee maintains supporting records for the purpose of allocating the trust level equity in net earnings (loss) and the administrative expenses of the investment accounts in each trust to the various participating pension plans in that particular trust. The fair value of the trusts’ assets is determined by the trustee and certain investment managers. For each trust, the trustee calculates a daily earnings factor, including realized and
Entergy Corporation and Subsidiaries
Notes to Financial Statements
unrealized gains or losses, collected and accrued income, and administrative expenses, and allocates earnings to each plan in the master trusts on a pro rata basis.
Within each pension plan, the record of each Registrant Subsidiary’s beneficial interest in the plan assets is maintained by the plan’s actuary and is updated quarterly. Assets for each Registrant Subsidiary are increased for investment net income and contributions, and are decreased for benefit payments. A plan’s investment net income/loss (i.e. interest and dividends, realized and unrealized gains and losses and expenses) is allocated to the Registrant Subsidiaries participating in that plan based on the value of assets for each Registrant Subsidiary at the beginning of the quarter adjusted for contributions and benefit payments made during the quarter.
Entergy Corporation and its subsidiaries fund pension costsplans in accordance withan amount not less than the minimum required contribution guidelines established byunder the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts. The Registrant Subsidiaries’ pension costs are recovered from customers as a component of cost of service in each of their respective jurisdictions.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Components of Qualified Net Pension Cost and Other Amounts Recognized as a Regulatory Asset and/or Accumulated Other Comprehensive Income (AOCI)
Entergy Corporation and its subsidiaries’ total 2014, 2013,2017, 2016, and 20122015 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| | (In Thousands) | (In Thousands) |
| Net periodic pension cost: | |
| | |
| | |
| |
| | |
| | |
|
| Service cost - benefits earned during the period |
| $140,436 |
| |
| $172,280 |
| |
| $150,763 |
|
| $133,641 |
| |
| $143,244 |
| |
| $175,046 |
|
| Interest cost on projected benefit obligation | 290,076 |
| | 263,296 |
| | 260,929 |
| 260,824 |
| | 261,613 |
| | 302,777 |
|
| Expected return on assets | (361,462 | ) | | (328,227 | ) | | (317,423 | ) | (408,225 | ) | | (389,465 | ) | | (394,618 | ) |
| Amortization of prior service cost | 1,600 |
| | 2,125 |
| | 2,733 |
| 261 |
| | 1,079 |
| | 1,561 |
|
| Recognized net loss | 145,095 |
| | 213,194 |
| | 167,279 |
| 227,720 |
| | 195,298 |
| | 235,922 |
|
| Curtailment loss | — |
| | 16,318 |
| | — |
| — |
| | 3,084 |
| | 374 |
|
| Special termination benefit | 732 |
| | 13,139 |
| | — |
| — |
| | — |
| | 76 |
|
| Net periodic pension costs |
| $216,477 |
| |
| $352,125 |
| |
| $264,281 |
|
| $214,221 |
| |
| $214,853 |
| |
| $321,138 |
|
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | |
| Arising this period: | | | | | | | | | | |
| Net (gain)/loss |
| $1,389,912 |
| |
| ($894,150 | ) | |
| $552,303 |
| |
| Net loss | |
| $368,067 |
| |
| $203,229 |
| |
| $50,762 |
|
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | |
| Amortization of prior service cost | (1,600 | ) | | (2,125 | ) | | (2,733 | ) | (261 | ) | | (1,079 | ) | | (1,561 | ) |
| Acceleration of prior service cost to curtailment | — |
| | (1,307 | ) | | — |
| — |
| | (1,045 | ) | | (374 | ) |
| Amortization of net loss | (145,095 | ) | | (213,194 | ) | | (167,279 | ) | (227,720 | ) | | (195,298 | ) | | (235,922 | ) |
| Total | 1,243,217 |
| | (1,110,776 | ) | | 382,291 |
|
| $140,086 |
| |
| $5,807 |
| |
| ($187,095 | ) |
| Total recognized as net periodic pension (income)/cost, regulatory asset, and/or AOCI (before tax) |
| $1,459,694 |
| |
| ($758,651 | ) | |
| $646,572 |
| |
| Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax) | |
| $354,307 |
| |
| $220,660 |
| |
| $134,043 |
|
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year: | | | | | | | | | | |
| Prior service cost |
| $1,561 |
| |
| $1,600 |
| |
| $2,268 |
|
| $398 |
| |
| $261 |
| |
| $1,079 |
|
| Net loss |
| $237,013 |
| |
| $146,958 |
| |
| $219,805 |
|
| $274,104 |
| |
| $227,720 |
| |
| $195,321 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The Registrant Subsidiaries’ total 2014, 2013,2017, 2016, and 20122015 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, for their employees included the following components:
| | | 2014 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2017 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Net periodic pension cost: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost - benefits earned during the period | |
| $20,090 |
| |
| $11,524 |
| |
| $14,182 |
| |
| $6,094 |
| |
| $2,666 |
| |
| $5,142 |
| |
| $5,785 |
| |
| $20,358 |
| |
| $27,698 |
| |
| $5,890 |
| |
| $2,500 |
| |
| $5,455 |
| |
| $6,145 |
|
Interest cost on projected benefit obligation | | 59,537 |
| | 29,114 |
| | 37,870 |
| | 17,273 |
| | 8,164 |
| | 17,746 |
| | 13,561 |
| | 51,776 |
| | 59,235 |
| | 14,927 |
| | 7,163 |
| | 13,569 |
| | 12,364 |
|
| Expected return on assets | | (73,218 | ) | | (37,950 | ) | | (45,796 | ) | | (22,794 | ) | | (10,019 | ) | | (23,723 | ) | | (16,619 | ) | | (81,707 | ) | | (92,067 | ) | | (24,526 | ) | | (11,199 | ) | | (24,722 | ) | | (18,650 | ) |
| Amortization of prior service cost | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| |
| Recognized net loss | | 35,956 |
| | 15,923 |
| | 24,523 |
| | 9,415 |
| | 5,796 |
| | 9,356 |
| | 9,500 |
| | 46,560 |
| | 49,417 |
| | 12,213 |
| | 6,632 |
| | 9,241 |
| | 11,857 |
|
| Net pension cost | |
| $42,365 |
| |
| $18,611 |
| |
| $30,779 |
| |
| $9,988 |
| |
| $6,607 |
| |
| $8,521 |
| |
| $12,229 |
| |
| $36,987 |
| |
| $44,283 |
| |
| $8,504 |
| |
| $5,096 |
| |
| $3,543 |
| |
| $11,716 |
|
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | |
| $300,907 |
| |
| $125,090 |
| |
| $193,842 |
| |
| $88,199 |
| |
| $38,161 |
| |
| $65,363 |
| |
| $60,763 |
| |
| $51,569 |
| |
| $57,510 |
| |
| $14,681 |
| |
| $8,601 |
| |
| $1,109 |
| |
| $27,733 |
|
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of prior service cost | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) | |
| Amortization of net loss | | (35,956 | ) | | (15,923 | ) | | (24,523 | ) | | (9,415 | ) | | (5,796 | ) | | (9,356 | ) | | (9,500 | ) | | (46,560 | ) | | (49,417 | ) | | (12,213 | ) | | (6,632 | ) | | (9,241 | ) | | (11,857 | ) |
| Total | |
| $264,951 |
| |
| $109,167 |
| |
| $169,319 |
| |
| $78,784 |
| |
| $32,365 |
| |
| $56,007 |
| |
| $51,261 |
| |
| $5,009 |
| |
| $8,093 |
| |
| $2,468 |
| |
| $1,969 |
| |
| ($8,132 | ) | |
| $15,876 |
|
Total recognized as net periodic pension income regulatory asset, and/or AOCI (before tax) | |
| $307,316 |
| |
| $127,778 |
| |
| $200,098 |
| |
| $88,772 |
| |
| $38,972 |
| |
| $64,528 |
| |
| $63,490 |
| |
| Total recognized as net periodic pension (income)/cost, regulatory asset, and/or AOCI (before tax) | | |
| $41,996 |
| |
| $52,376 |
| |
| $10,972 |
| |
| $7,065 |
| |
| ($4,589 | ) | |
| $27,592 |
|
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | |
| $54,254 |
| |
| $23,098 |
| |
| $36,704 |
| |
| $14,896 |
| |
| $8,053 |
| |
| $12,950 |
| |
| $13,055 |
| |
| $53,650 |
| |
| $57,800 |
| |
| $14,438 |
| |
| $7,816 |
| |
| $10,503 |
| |
| $14,859 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2016 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Net periodic pension cost: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost - benefits earned during the period | |
| $25,229 |
| |
| $14,258 |
| |
| $17,044 |
| |
| $7,295 |
| |
| $3,264 |
| |
| $6,475 |
| |
| $7,242 |
| |
| $20,724 |
| |
| $28,194 |
| |
| $6,250 |
| |
| $2,625 |
| |
| $5,664 |
| |
| $6,263 |
|
Interest cost on projected benefit obligation | | 54,473 |
| | 26,741 |
| | 34,857 |
| | 15,802 |
| | 7,462 |
| | 16,303 |
| | 12,170 |
| | 52,219 |
| | 59,478 |
| | 15,245 |
| | 7,256 |
| | 14,228 |
| | 11,966 |
|
| Expected return on assets | | (66,951 | ) | | (34,982 | ) | | (41,948 | ) | | (21,139 | ) | | (9,117 | ) | | (22,277 | ) | | (17,249 | ) | | (79,087 | ) | | (88,383 | ) | | (23,923 | ) | | (10,748 | ) | | (24,248 | ) | | (17,836 | ) |
| Amortization of prior service cost | | 23 |
| | 9 |
| | 83 |
| | 10 |
| | 2 |
| | 6 |
| | 9 |
| |
| Recognized net loss | | 49,517 |
| | 23,374 |
| | 34,107 |
| | 13,189 |
| | 7,878 |
| | 13,302 |
| | 9,560 |
| | 43,745 |
| | 47,783 |
| | 11,938 |
| | 6,460 |
| | 9,358 |
| | 10,415 |
|
| Curtailment loss | | 4,938 |
| | 805 |
| | 3,542 |
| | 767 |
| | 343 |
| | 1,559 |
| | — |
| |
| Special termination benefit | | 1,784 |
| | 808 |
| | 1,631 |
| | 359 |
| | 581 |
| | 855 |
| | 1,970 |
| |
| Net pension cost | |
| $69,013 |
| |
| $31,013 |
| |
| $49,316 |
| |
| $16,283 |
| |
| $10,413 |
| |
| $16,223 |
| |
| $13,702 |
| |
| $37,601 |
| |
| $47,072 |
| |
| $9,510 |
| |
| $5,593 |
| |
| $5,002 |
| |
| $10,808 |
|
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net gain | |
| ($177,105 | ) | |
| ($98,610 | ) | |
| ($123,234 | ) | |
| ($52,525 | ) | |
| ($25,419 | ) | |
| ($55,772 | ) | |
| ($35,511 | ) | |
| Net loss | | |
| $60,968 |
| |
| $46,742 |
| |
| $10,942 |
| |
| $5,463 |
| |
| $3,816 |
| |
| $20,805 |
|
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of prior service cost | | (23 | ) | | (9 | ) | | (83 | ) | | (10 | ) | | (2 | ) | | (6 | ) | | (9 | ) | |
| Amortization of net loss | | (49,517 | ) | | (23,374 | ) | | (34,107 | ) | | (13,189 | ) | | (7,878 | ) | | (13,302 | ) | | (9,560 | ) | | (43,745 | ) | | (47,783 | ) | | (11,938 | ) | | (6,460 | ) | | (9,358 | ) | | (10,415 | ) |
| Total | |
| ($226,645 | ) | |
| ($121,993 | ) | |
| ($157,424 | ) | |
| ($65,724 | ) | |
| ($33,299 | ) | |
| ($69,080 | ) | |
| ($45,080 | ) | |
| $17,223 |
| |
| ($1,041 | ) | |
| ($996 | ) | |
| ($997 | ) | |
| ($5,542 | ) | |
| $10,390 |
|
Total recognized as net periodic pension income, regulatory asset, and/or AOCI (before tax) | |
| ($157,632 | ) | |
| ($90,980 | ) | |
| ($108,108 | ) | |
| ($49,441 | ) | |
| ($22,886 | ) | |
| ($52,857 | ) | |
| ($31,378 | ) | |
| Total recognized as net periodic pension (income)/ cost, regulatory asset, and/or AOCI (before tax) | | |
| $54,824 |
| |
| $46,031 |
| |
| $8,514 |
| |
| $4,596 |
| |
| ($540 | ) | |
| $21,198 |
|
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $2 |
| |
| Net loss | |
| $35,984 |
| |
| $15,935 |
| |
| $24,360 |
| |
| $9,421 |
| |
| $5,802 |
| |
| $9,363 |
| |
| $9,510 |
| |
| $46,560 |
| |
| $49,417 |
| |
| $12,213 |
| |
| $6,632 |
| |
| $9,241 |
| |
| $11,857 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2012 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2015 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Net periodic pension cost: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost - benefits earned during the period | |
| $22,169 |
| |
| $12,273 |
| |
| $14,675 |
| |
| $6,410 |
| |
| $2,824 |
| |
| $5,684 |
| |
| $5,920 |
| |
| $26,646 |
| |
| $34,396 |
| |
| $7,929 |
| |
| $3,395 |
| |
| $6,582 |
| |
| $7,827 |
|
Interest cost on projected benefit obligation | | 55,686 |
| | 25,679 |
| | 35,201 |
| | 16,279 |
| | 7,608 |
| | 16,823 |
| | 12,987 |
| | 61,885 |
| | 69,465 |
| | 18,007 |
| | 8,432 |
| | 17,414 |
| | 13,970 |
|
| Expected return on assets | | (65,763 | ) | | (34,370 | ) | | (40,836 | ) | | (20,945 | ) | | (8,860 | ) | | (22,325 | ) | | (16,436 | ) | | (80,102 | ) | | (90,803 | ) | | (24,420 | ) | | (10,899 | ) | | (24,887 | ) | | (18,271 | ) |
| Amortization of prior service cost | | 200 |
| | 19 |
| | 208 |
| | 30 |
| | 7 |
| | 15 |
| | 13 |
| |
| Recognized net loss | | 40,772 |
| | 16,173 |
| | 28,197 |
| | 10,532 |
| | 6,878 |
| | 10,179 |
| | 9,001 |
| | 54,254 |
| | 59,802 |
| | 14,896 |
| | 8,053 |
| | 12,950 |
| | 13,055 |
|
| Net pension cost | |
| $53,064 |
| |
| $19,774 |
| |
| $37,445 |
| |
| $12,306 |
| |
| $8,457 |
| |
| $10,376 |
| |
| $11,485 |
| |
| $62,683 |
| |
| $72,860 |
| |
| $16,412 |
| |
| $8,981 |
| |
| $12,059 |
| |
| $16,581 |
|
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | |
| $105,133 |
| |
| $77,207 |
| |
| $76,163 |
| |
| $27,106 |
| |
| $14,282 |
| |
| $28,745 |
| |
| $10,266 |
| |
| Net (gain)/loss | | |
| $16,687 |
| |
| $16,618 |
| |
| $6,329 |
| |
| $1,853 |
| |
| ($4,488 | ) | |
| $101 |
|
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of prior service cost | | (200 | ) | | (19 | ) | | (208 | ) | | (30 | ) | | (7 | ) | | (15 | ) | | (13 | ) | |
| Amortization of net loss | | (40,772 | ) | | (16,173 | ) | | (28,197 | ) | | (10,532 | ) | | (6,878 | ) | | (10,179 | ) | | (9,001 | ) | | (54,254 | ) | | (59,802 | ) | | (14,896 | ) | | (8,053 | ) | | (12,950 | ) | | (13,055 | ) |
| Total | |
| $64,161 |
| |
| $61,015 |
| |
| $47,758 |
| |
| $16,544 |
| |
| $7,397 |
| |
| $18,551 |
| |
| $1,252 |
| |
| ($37,567 | ) | |
| ($43,184 | ) | |
| ($8,567 | ) | |
| ($6,200 | ) | |
| ($17,438 | ) | |
| ($12,954 | ) |
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax) | |
| $117,225 |
| |
| $80,789 |
| |
| $85,203 |
| |
| $28,850 |
| |
| $15,854 |
| |
| $28,927 |
| |
| $12,737 |
| |
| Total recognized as net periodic pension (income)/cost, regulatory asset, and/or AOCI (before tax) | | |
| $25,116 |
| |
| $29,676 |
| |
| $7,845 |
| |
| $2,781 |
| |
| ($5,379 | ) | |
| $3,627 |
|
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | |
| $23 |
| |
| $9 |
| |
| $83 |
| |
| $10 |
| |
| $2 |
| |
| $6 |
| |
| $10 |
| |
| Net loss | |
| $50,175 |
| |
| $23,731 |
| |
| $34,906 |
| |
| $13,375 |
| |
| $8,046 |
| |
| $13,494 |
| |
| $9,717 |
| |
| $43,747 |
| |
| $47,809 |
| |
| $11,938 |
| |
| $6,460 |
| |
| $9,358 |
| |
| $10,414 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Qualified PensionObligations, Plan Assets, Funded Status, Amounts Recognized in the Balance Sheet
Qualified pension obligations, plan assets, funded status, amounts recognized in the Consolidated Balance Sheets for Entergy Corporation and its Subsidiaries as of December 31, 20142017 and 20132016 are as follows:
| | | | December 31, | | | | | |
| | 2014 | | 2013 | 2017 | | 2016 |
| | (In Thousands) | (In Thousands) |
| Change in Projected Benefit Obligation (PBO) | |
| | |
| |
| | |
|
| Balance at beginning of year |
| $5,770,999 |
| |
| $6,096,639 |
| |
| Balance at January 1 | |
| $7,142,567 |
| |
| $6,848,238 |
|
| Service cost | 140,436 |
| | 172,280 |
| 133,641 |
| | 143,244 |
|
| Interest cost | 290,076 |
| | 263,296 |
| 260,824 |
| | 261,613 |
|
| Curtailment | — |
| | 15,011 |
| — |
| | 2,039 |
|
| Special termination benefit | 732 |
| | 13,139 |
| |
| Actuarial loss/(gain) | 1,284,049 |
| | (571,990 | ) | |
| Actuarial loss | | 767,849 |
| | 209,360 |
|
| Employee contributions | 560 |
| | 598 |
| 40 |
| | 23 |
|
| Benefits paid | (256,310 | ) | | (217,974 | ) | (317,834 | ) | | (321,950 | ) |
| Balance at end of year |
| $7,230,542 |
| |
| $5,770,999 |
| |
| Balance at December 31 | |
| $7,987,087 |
| |
| $7,142,567 |
|
| Change in Plan Assets | |
| | |
| |
| | |
|
| Fair value of assets at beginning of year |
| $4,429,237 |
| |
| $3,832,860 |
| |
| Fair value of assets at January 1 | |
| $5,171,202 |
| |
| $4,707,433 |
|
| Actual return on plan assets | 255,599 |
| | 650,386 |
| 808,007 |
| | 395,596 |
|
| Employer contributions | 398,880 |
| | 163,367 |
| 409,901 |
| | 390,100 |
|
| Employee contributions | 560 |
| | 598 |
| 40 |
| | 23 |
|
| Benefits paid | (256,310 | ) | | (217,974 | ) | (317,834 | ) | | (321,950 | ) |
| Fair value of assets at end of year |
| $4,827,966 |
| |
| $4,429,237 |
| |
| Fair value of assets at December 31 | |
| $6,071,316 |
| |
| $5,171,202 |
|
| Funded status |
| ($2,402,576 | ) | |
| ($1,341,762 | ) |
| ($1,915,771 | ) | |
| ($1,971,365 | ) |
| Amount recognized in the balance sheet | | | | | | |
| Non-current liabilities |
| ($2,402,576 | ) | |
| ($1,341,762 | ) |
| ($1,915,771 | ) | |
| ($1,971,365 | ) |
| Amount recognized as a regulatory asset | | | | | | |
| Prior service cost |
| $3,704 |
| |
| $5,027 |
| |
| Net loss | 2,451,172 |
| | 1,494,117 |
|
| $2,418,206 |
| |
| $2,326,349 |
|
| |
| $2,454,876 |
| |
| $1,499,144 |
| |
| Amount recognized as AOCI (before tax) | | | | | | |
| Prior service cost |
| $1,015 |
| |
| $1,292 |
|
| $398 |
| |
| $659 |
|
| Net loss | 671,682 |
| | 383,920 |
| 667,766 |
| | 619,276 |
|
| |
| $672,697 |
| |
| $385,212 |
|
| $668,164 |
| |
| $619,935 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Qualified Pension Obligations, Plan Assets, Funded Status, and Amounts Recognizedpension obligations, plan assets, funded status, amounts recognized in the Balance SheetSheets for the Registrant Subsidiaries as of December 31, 20142017 and 20132016 are as follows:
| | | 2014 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2017 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Change in Projected Benefit Obligation (PBO) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at beginning of year | |
| $1,192,640 |
| |
| $579,862 |
| |
| $761,350 |
| |
| $345,824 |
| |
| $163,707 |
| |
| $356,080 |
| |
| $270,789 |
| |
| Balance at January 1 | | |
| $1,454,310 |
| |
| $1,624,233 |
| |
| $419,201 |
| |
| $197,464 |
| |
| $386,366 |
| |
| $335,381 |
|
| Service cost | | 20,090 |
| | 11,524 |
| | 14,182 |
| | 6,094 |
| | 2,666 |
| | 5,142 |
| | 5,785 |
| | 20,358 |
| | 27,698 |
| | 5,890 |
| | 2,500 |
| | 5,455 |
| | 6,145 |
|
| Interest cost | | 59,537 |
| | 29,114 |
| | 37,870 |
| | 17,273 |
| | 8,164 |
| | 17,746 |
| | 13,561 |
| | 51,776 |
| | 59,235 |
| | 14,927 |
| | 7,163 |
| | 13,569 |
| | 12,364 |
|
| Actuarial loss | | 279,781 |
| | 113,883 |
| | 180,763 |
| | 81,600 |
| | 35,131 |
| | 58,556 |
| | 55,410 |
| | 131,729 |
| | 147,704 |
| | 38,726 |
| | 19,507 |
| | 25,339 |
| | 45,471 |
|
| Benefits paid | | (66,330 | ) | | (24,389 | ) | | (37,624 | ) | | (18,622 | ) | | (7,113 | ) | | (19,026 | ) | | (11,233 | ) | | (77,417 | ) | | (73,170 | ) | | (21,195 | ) | | (8,738 | ) | | (20,009 | ) | | (15,312 | ) |
| Balance at end of year | |
| $1,485,718 |
| |
| $709,994 |
| |
| $956,541 |
| |
| $432,169 |
| |
| $202,555 |
| |
| $418,498 |
| |
| $334,312 |
| |
| Balance at December 31 | | |
| $1,580,756 |
| |
| $1,785,700 |
| |
| $457,549 |
| |
| $217,896 |
| |
| $410,720 |
| |
| $384,049 |
|
| Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of assets at beginning of year | |
| $896,295 |
| |
| $469,295 |
| |
| $561,892 |
| |
| $281,837 |
| |
| $122,960 |
| |
| $295,751 |
| |
| $196,328 |
| |
Fair value of assets at January 1 | | |
| $1,041,592 |
| |
| $1,169,147 |
| |
| $314,349 |
| |
| $142,488 |
| |
| $317,576 |
| |
| $235,144 |
|
| Actual return on plan assets | | 52,092 |
| | 26,744 |
| | 32,716 |
| | 16,196 |
| | 6,988 |
| | 16,916 |
| | 11,265 |
| | 161,868 |
| | 182,261 |
| | 48,572 |
| | 22,104 |
| | 48,952 |
| | 36,387 |
|
| Employer contributions | | 95,464 |
| | 30,176 |
| | 54,549 |
| | 21,839 |
| | 10,509 |
| | 17,072 |
| | 21,261 |
| | 79,625 |
| | 87,503 |
| | 19,116 |
| | 9,893 |
| | 17,004 |
| | 18,213 |
|
| Benefits paid | | (66,330 | ) | | (24,389 | ) | | (37,624 | ) | | (18,622 | ) | | (7,113 | ) | | (19,026 | ) | | (11,233 | ) | | (77,417 | ) | | (73,170 | ) | | (21,195 | ) | | (8,738 | ) | | (20,009 | ) | | (15,312 | ) |
Fair value of assets at end of year | |
| $977,521 |
| |
| $501,826 |
| |
| $611,533 |
| |
| $301,250 |
| |
| $133,344 |
| |
| $310,713 |
| |
| $217,621 |
| |
| Fair value of assets at December 31 | | |
| $1,205,668 |
| |
| $1,365,741 |
| |
| $360,842 |
| |
| $165,747 |
| |
| $363,523 |
| |
| $274,432 |
|
| Funded status | |
| ($508,197 | ) | |
| ($208,168 | ) | |
| ($345,008 | ) | |
| ($130,919 | ) | |
| ($69,211 | ) | |
| ($107,785 | ) | |
| ($116,691 | ) | |
| ($375,088 | ) | |
| ($419,959 | ) | |
| ($96,707 | ) | |
| ($52,149 | ) | |
| ($47,197 | ) | |
| ($109,617 | ) |
Amounts recognized in the balance sheet (funded status) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Non-current liabilities | |
| ($508,197 | ) | |
| ($208,168 | ) | |
| ($345,008 | ) | |
| ($130,919 | ) | |
| ($69,211 | ) | |
| ($107,785 | ) | |
| ($116,691 | ) | |
| ($375,088 | ) | |
| ($419,959 | ) | |
| ($96,707 | ) | |
| ($52,149 | ) | |
| ($47,197 | ) | |
| ($109,617 | ) |
Amounts recognized as regulatory asset | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
|
| Net loss | |
| $722,119 |
| |
| $272,695 |
| |
| $468,779 |
| |
| $198,972 |
| |
| $102,141 |
| |
| $176,522 |
| |
| $172,463 |
| |
| $706,783 |
| |
| $701,324 |
| |
| $191,877 |
| |
| $96,913 |
| |
| $145,412 |
| |
| $185,774 |
|
| Amounts recognized as AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | |
| $— |
| |
| $40,748 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $44,765 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2016 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Change in Projected Benefit Obligation (PBO) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at beginning of year | |
| $1,274,886 |
| |
| $623,068 |
| |
| $817,745 |
| |
| $369,852 |
| |
| $174,585 |
| |
| $382,176 |
| |
| $282,841 |
| |
| Balance at January 1 | | |
| $1,400,511 |
| |
| $1,564,710 |
| |
| $408,604 |
| |
| $191,064 |
| |
| $383,627 |
| |
| $311,542 |
|
| Service cost | | 25,229 |
| | 14,258 |
| | 17,044 |
| | 7,295 |
| | 3,264 |
| | 6,475 |
| | 7,242 |
| | 20,724 |
| | 28,194 |
| | 6,250 |
| | 2,625 |
| | 5,664 |
| | 6,263 |
|
| Interest cost | | 54,473 |
| | 26,741 |
| | 34,857 |
| | 15,802 |
| | 7,462 |
| | 16,303 |
| | 12,170 |
| | 52,219 |
| | 59,478 |
| | 15,245 |
| | 7,256 |
| | 14,228 |
| | 11,966 |
|
| Curtailment | | 4,938 |
| | 805 |
| | 3,542 |
| | 767 |
| | 343 |
| | 1,559 |
| | — |
| |
| Special termination benefit | | 1,784 |
| | 808 |
| | 1,631 |
| | 359 |
| | 581 |
| | 855 |
| | 1,970 |
| |
| Actuarial gain | | (110,943 | ) | | (64,119 | ) | | (80,794 | ) | | (31,684 | ) | | (16,276 | ) | | (33,792 | ) | | (23,882 | ) | |
| Actuarial loss | | | 62,187 |
| | 48,357 |
| | 11,343 |
| | 5,573 |
| | 4,274 |
| | 20,661 |
|
| Benefits paid | | (57,727 | ) | | (21,699 | ) | | (32,675 | ) | | (16,567 | ) | | (6,252 | ) | | (17,496 | ) | | (9,552 | ) | | (81,331 | ) | | (76,506 | ) | | (22,241 | ) | | (9,054 | ) | | (21,427 | ) | | (15,051 | ) |
| Balance at end of year | |
| $1,192,640 |
| |
| $579,862 |
| |
| $761,350 |
| |
| $345,824 |
| |
| $163,707 |
| |
| $356,080 |
| |
| $270,789 |
| |
| Balance at December 31 | | |
| $1,454,310 |
| |
| $1,624,233 |
| |
| $419,201 |
| |
| $197,464 |
| |
| $386,366 |
| |
| $335,381 |
|
| Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of assets at beginning of year | |
| $785,527 |
| |
| $409,971 |
| |
| $489,027 |
| |
| $248,272 |
| |
| $106,778 |
| |
| $262,110 |
| |
| $168,697 |
| |
| Fair value of assets at January 1 | | |
| $959,618 |
| |
| $1,071,234 |
| |
| $292,297 |
| |
| $129,975 |
| |
| $298,378 |
| |
| $212,006 |
|
| Actual return on plan assets | | 133,113 |
| | 69,473 |
| | 84,388 |
| | 41,980 |
| | 18,259 |
| | 44,257 |
| | 28,878 |
| | 80,306 |
| | 89,998 |
| | 24,325 |
| | 10,858 |
| | 24,705 |
| | 17,692 |
|
| Employer contributions | | 35,382 |
| | 11,550 |
| | 21,152 |
| | 8,152 |
| | 4,175 |
| | 6,880 |
| | 8,305 |
| | 82,999 |
| | 84,421 |
| | 19,968 |
| | 10,709 |
| | 15,920 |
| | 20,497 |
|
| Benefits paid | | (57,727 | ) | | (21,699 | ) | | (32,675 | ) | | (16,567 | ) | | (6,252 | ) | | (17,496 | ) | | (9,552 | ) | | (81,331 | ) | | (76,506 | ) | | (22,241 | ) | | (9,054 | ) | | (21,427 | ) | | (15,051 | ) |
| Fair value of assets at end of year | |
| $896,295 |
| |
| $469,295 |
| |
| $561,892 |
| |
| $281,837 |
| |
| $122,960 |
| |
| $295,751 |
| |
| $196,328 |
| |
| Fair value of assets at December 31 | | |
| $1,041,592 |
| |
| $1,169,147 |
| |
| $314,349 |
| |
| $142,488 |
| |
| $317,576 |
| |
| $235,144 |
|
| Funded status | |
| ($296,345 | ) | |
| ($110,567 | ) | |
| ($199,458 | ) | |
| ($63,987 | ) | |
| ($40,747 | ) | |
| ($60,329 | ) | |
| ($74,461 | ) | |
| ($412,718 | ) | |
| ($455,086 | ) | |
| ($104,852 | ) | |
| ($54,976 | ) | |
| ($68,790 | ) | |
| ($100,237 | ) |
| Amounts recognized in the balance sheet (funded status) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Non-current liabilities | |
| ($296,345 | ) | |
| ($110,567 | ) | |
| ($199,458 | ) | |
| ($63,987 | ) | |
| ($40,747 | ) | |
| ($60,329 | ) | |
| ($74,461 | ) | |
| ($412,718 | ) | |
| ($455,086 | ) | |
| ($104,852 | ) | |
| ($54,976 | ) | |
| ($68,790 | ) | |
| ($100,237 | ) |
Amounts recognized as regulatory asset | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | |
| $— |
| |
| $— |
| |
| ($1 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| ($4 | ) | |
| Net loss | | 457,485 |
| | 178,990 |
| | 299,740 |
| | 120,290 |
| | 69,856 |
| | 120,619 |
| | 121,327 |
| |
| $701,774 |
| |
| $686,337 |
| |
| $189,409 |
| |
| $94,944 |
| |
| $153,544 |
| |
| $169,897 |
|
| | |
| $457,485 |
| |
| $178,990 |
| |
| $299,739 |
| |
| $120,290 |
| |
| $69,856 |
| |
| $120,619 |
| |
| $121,323 |
| |
| Amounts recognized as AOCI (before tax) | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | |
| Net loss | |
| $— |
| |
| $25,437 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $51,660 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
Accumulated Pension Benefit Obligation
The accumulated benefit obligation for Entergy’s qualified pension plans was $7.4 billion and $6.7 billion at December 31, 2017 and 2016, respectively.
The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries for their employees as of December 31, 2017 and 2016 was as follows:
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (In Thousands) |
| Entergy Arkansas |
| $1,492,876 |
| |
| $1,379,265 |
|
| Entergy Louisiana |
| $1,652,939 |
| |
| $1,513,884 |
|
| Entergy Mississippi |
| $430,268 |
| |
| $396,081 |
|
| Entergy New Orleans |
| $205,316 |
| |
| $186,247 |
|
| Entergy Texas |
| $387,083 |
| |
| $365,251 |
|
| System Energy |
| $359,258 |
| |
| $315,131 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Other Postretirement Benefits
Entergy also currently offers retiree medical, dental, vision, and life insurance benefits (other postretirement benefits) for eligible retired employees. Employees who commenced employment before July 1, 2014 and who satisfy certain eligibility requirements (including retiring from Entergy after a certain age and/or years of service with Entergy and immediately commencing their Entergy pension benefit), may become eligible for other postretirement benefits.
In December 2013, Entergy announced changes to its other postretirement benefits which include, among other things, elimination of other postretirement benefits for all non-bargaining employees hired or rehired after June 30, 2014 and for certain bargaining employees hired or rehired after June 30, 2014, or such later date provided for in their applicable collective bargaining agreement, and setting a dollar limit cap on Entergy’s contribution to retiree medical costs, effective 2019 for those non-bargaining employees who commence their Entergy retirement benefits on or after
Entergy Corporation and Subsidiaries
Notes to Financial Statements
January 1, 2015 and for certain bargaining employees who commence their Entergy retirement benefits on or after January 1, 2015 or such later date as provided for in their applicable collective bargaining agreement. In accordance with accounting standards, certain of the other postretirement benefit changes have been reflected in the December 31, 2013 other postretirement obligation. The changes affecting active bargaining unit employees are being negotiated with the unions prior to implementation, where necessary, and to the extent required by law.
Entergy uses a December 31 measurement date for its postretirement benefit plans.
Effective January 1, 1993, Entergy adopted an accounting standard requiring a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. At January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $241.4 million for Entergy (other than the former Entergy Gulf States) and $128 million for the former Entergy Gulf States (now split into Entergy Gulf States Louisiana and Entergy Texas). Such obligations were being amortized over a 20-year period that began in 1993 and ended in 2012. For the most part, the Registrant Subsidiaries recover accrued other postretirement benefit costs from customers and are required to contribute the other postretirement benefits collected in rates to an external trust.
Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Texas have received regulatory approval to recover accrued other postretirement benefit costs through rates. Entergy Arkansas began recovery in 1998, pursuant to an APSC order. This order also allowed Entergy Arkansas to amortize a regulatory asset (representing the difference between other postretirement benefit costs and cash expenditures for other postretirement benefits incurred from 1993 through 1997) over a 15-year period that began in January 1998 and ended in December 2012.
The LPSC ordered Entergy Gulf States Louisiana and Entergy Louisiana to continue the use of the pay-as-you-go method for ratemaking purposes for postretirement benefits other than pensions. However, the LPSC retains the flexibility to examine individual companies’ accounting for other postretirement benefits to determine if special exceptions to this order are warranted.
Pursuant to regulatory directives, Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy contribute the other postretirement benefit costs collected in rates into external trusts. System Energy is funding, on behalf of Entergy Operations, other postretirement benefits associated with Grand Gulf.
Trust assets contributed by participating Registrant Subsidiaries are in bank-administered master trusts, established by Entergy Corporation and maintained by a trustee. Each participating Registrant Subsidiary holds a beneficial interest in the trusts’ assets. The assets in the master trusts are commingled for investment and administrative purposes. Although assets are commingled, supporting records are maintained for the purpose of allocating the beneficial interest in net earnings/(losses) and the administrative expenses of the investment accounts to the various participating plans and participating Registrant Subsidiaries. Beneficial interest in an investment account’s net income/(loss) is comprised of interest and dividends, realized and unrealized gains and losses, and expenses. Beneficial interest from these investments is allocated to the plans and participating Registrant Subsidiary based on their portion of net assets in the pooled accounts.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Components of Net Other Postretirement Benefit Cost and Other Amounts Recognized as a Regulatory Asset and/or AOCI
Entergy Corporation’s and its subsidiaries’ total 2014, 2013,2017, 2016, and 20122015 other postretirement benefit costs, including amounts capitalized and amounts recognized as a regulatory asset and/or other comprehensive income, included the following components:
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| | (In Thousands) | (In Thousands) |
| Other postretirement costs: | | | | | | | | | | |
| Service cost - benefits earned during the period |
| $43,493 |
| |
| $74,654 |
| |
| $68,883 |
|
| $26,915 |
| |
| $32,291 |
| |
| $45,305 |
|
| Interest cost on APBO | 71,841 |
| | 79,453 |
| | 82,561 |
| |
| Interest cost on accumulated postretirement benefit obligation (APBO) | | 55,838 |
| | 56,331 |
| | 71,934 |
|
| Expected return on assets | (44,787 | ) | | (40,323 | ) | | (34,503 | ) | (37,630 | ) | | (41,820 | ) | | (45,375 | ) |
| Amortization of transition obligation | — |
| | — |
| | 3,177 |
| |
| Amortization of prior service credit | (31,590 | ) | | (14,904 | ) | | (18,163 | ) | (41,425 | ) | | (45,490 | ) | | (37,280 | ) |
| Recognized net loss | 11,143 |
| | 44,178 |
| | 36,448 |
| 21,905 |
| | 18,214 |
| | 31,573 |
|
| Curtailment loss | — |
| | 12,729 |
| | — |
| |
| Net other postretirement benefit cost |
| $50,100 |
| |
| $155,787 |
| |
| $138,403 |
|
| $25,603 |
| |
| $19,526 |
| |
| $66,157 |
|
Other changes in plan assets and benefit obligations recognized as a regulatory asset and /or AOCI (before tax) | | | | | | | | | | |
| Arising this period: | | | | | | | | | | |
| Prior service credit for period |
| ($35,864 | ) | |
| ($116,571 | ) | |
| $— |
|
| ($2,564 | ) | |
| ($20,353 | ) | |
| ($48,192 | ) |
| Net loss/(gain) | 287,313 |
| | (405,976 | ) | | 92,584 |
| |
| Net (gain)/loss | | (66,922 | ) | | 49,805 |
| | (154,339 | ) |
| Amounts reclassified from regulatory asset and /or AOCI to net periodic benefit cost in the current year: | | | | | | | | | | |
| Amortization of transition obligation | — |
| | — |
| | (3,177 | ) | |
| Amortization of prior service credit | 31,590 |
| | 14,904 |
| | 18,163 |
| 41,425 |
| | 45,490 |
| | 37,280 |
|
| Acceleration of prior service credit due to curtailment | — |
| | 1,989 |
| | — |
| |
| Amortization of net loss | (11,143 | ) | | (44,178 | ) | | (36,448 | ) | (21,905 | ) | | (18,214 | ) | | (31,573 | ) |
| Total |
| $271,896 |
| |
| ($549,832 | ) | |
| $71,122 |
|
| ($49,966 | ) | |
| $56,728 |
| |
| ($196,824 | ) |
Total recognized as net periodic benefit income/(cost), regulatory asset, and/or AOCI (before tax) |
| $321,996 |
| |
| ($394,045 | ) | |
| $209,525 |
|
| ($24,363 | ) | |
| $76,254 |
| |
| ($130,667 | ) |
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic benefit cost in the following year | | | | | | | | | | |
| Prior service credit |
| ($37,280 | ) | |
| ($31,589 | ) | |
| ($13,336 | ) |
| ($37,002 | ) | |
| ($41,425 | ) | |
| ($45,485 | ) |
| Net loss |
| $31,591 |
| |
| $11,197 |
| |
| $45,217 |
|
| $13,729 |
| |
| $21,905 |
| |
| $18,214 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total 2014, 2013,2017, 2016, and 20122015 other postretirement benefit costs of the Registrant Subsidiaries, including amounts capitalized and deferred, for their employees included the following components:
| | | 2014 | |
Entergy
Arkansas | | Entergy
Gulf States
Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2017 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | |
| Other postretirement costs: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost - benefits earned during the period | |
| $5,957 |
| |
| $4,896 |
| |
| $4,518 |
| |
| $1,900 |
| |
| $868 |
| |
| $2,378 |
| |
| $2,058 |
| |
| $3,451 |
| |
| $6,373 |
| |
| $1,160 |
| |
| $567 |
| |
| $1,488 |
| |
| $1,278 |
|
| Interest cost on APBO | | 12,261 |
| | 8,378 |
| | 8,264 |
| | 3,655 |
| | 2,805 |
| | 5,652 |
| | 2,611 |
| | 9,020 |
| | 12,101 |
| | 2,759 |
| | 1,874 |
| | 4,494 |
| | 2,236 |
|
| Expected return on assets | | (19,135 | ) | | — |
| | — |
| | (5,771 | ) | | (4,475 | ) | | (10,358 | ) | | (3,727 | ) | | (15,836 | ) | | — |
| | (4,801 | ) | | (4,635 | ) | | (8,720 | ) | | (2,869 | ) |
| Amortization of prior credit | | (2,441 | ) | | (2,237 | ) | | (3,377 | ) | | (915 | ) | | (709 | ) | | (1,300 | ) | | (824 | ) | |
| Amortization of prior service credit | | | (5,110 | ) | | (7,735 | ) | | (1,823 | ) | | (745 | ) | | (2,316 | ) | | (1,513 | ) |
| Recognized net loss | | 1,267 |
| | 1,212 |
| | 1,511 |
| | 149 |
| | 56 |
| | 801 |
| | 443 |
| | 4,460 |
| | 1,859 |
| | 1,675 |
| | 418 |
| | 3,303 |
| | 1,560 |
|
| Net other postretirement benefit (income)/cost | |
| ($2,091 | ) | |
| $12,249 |
| |
| $10,916 |
| |
| ($982 | ) | |
| ($1,455 | ) | |
| ($2,827 | ) | |
| $561 |
| |
| ($4,015 | ) | |
| $12,598 |
| |
| ($1,030 | ) | |
| ($2,521 | ) | |
| ($1,751 | ) | |
| $692 |
|
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit for the period | |
| $— |
| |
| ($12,845 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| ($8,536 | ) | |
| ($3,845 | ) | |
| Net loss | |
| $55,642 |
| |
| $36,467 |
| |
| $24,582 |
| |
| $9,525 |
| |
| $6,309 |
| |
| $24,482 |
| |
| $10,596 |
| |
| Net (gain)/loss | | | (29,534 | ) | | (1,256 | ) | | 506 |
| | (7,342 | ) | | (22,255 | ) | | (5,459 | ) |
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | |
| | | | | | | | | | | | | |
| | | | | | | | | | |
| Amortization of prior service credit | | 2,441 |
| | 2,237 |
| | 3,377 |
| | 915 |
| | 709 |
| | 1,300 |
| | 824 |
| | 5,110 |
| | 7,735 |
| | 1,823 |
| | 745 |
| | 2,316 |
| | 1,513 |
|
| Amortization of net loss | | (1,267 | ) | | (1,212 | ) | | (1,511 | ) | | (149 | ) | | (56 | ) | | (801 | ) | | (443 | ) | | (4,460 | ) | | (1,859 | ) | | (1,675 | ) | | (418 | ) | | (3,303 | ) | | (1,560 | ) |
| Total | |
| $56,816 |
| |
| $24,647 |
| |
| $26,448 |
| |
| $10,291 |
| |
| $6,962 |
| |
| $16,445 |
| |
| $7,132 |
| |
| ($28,884 | ) | |
| $4,620 |
| |
| $654 |
| |
| ($7,015 | ) | |
| ($23,242 | ) | |
| ($5,506 | ) |
| Total recognized as net periodic other postretirement income, regulatory asset, and/or AOCI (before tax) | |
| $54,725 |
| |
| $36,896 |
| |
| $37,364 |
| |
| $9,309 |
| |
| $5,507 |
| |
| $13,618 |
| |
| $7,693 |
| |
| Total recognized as net periodic other postretirement income/(cost), regulatory asset, and/or AOCI (before tax) | | |
| ($32,899 | ) | |
| $17,218 |
| |
| ($376 | ) | |
| ($9,536 | ) | |
| ($24,993 | ) | |
| ($4,814 | ) |
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit | |
| ($2,441 | ) | |
| ($4,086 | ) | |
| ($3,381 | ) | |
| ($916 | ) | |
| ($709 | ) | |
| ($2,723 | ) | |
| ($1,465 | ) | |
| ($5,110 | ) | |
| ($7,735 | ) | |
| ($1,823 | ) | |
| ($745 | ) | |
| ($2,316 | ) | |
| ($1,513 | ) |
| Net loss | |
| $5,356 |
| |
| $3,908 |
| |
| $3,210 |
| |
| $860 |
| |
| $470 |
| |
| $2,740 |
| |
| $1,198 |
| |
| $1,154 |
| |
| $1,550 |
| |
| $1,508 |
| |
| $137 |
| |
| $823 |
| |
| $932 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Entergy Arkansas |
| Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2016 | | | Entergy Arkansas |
| Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Other postretirement costs: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost - benefits earned during the period | |
| $9,619 |
| |
| $7,910 |
| |
| $8,541 |
| |
| $3,246 |
| |
| $1,752 |
| |
| $3,760 |
| |
| $3,580 |
| |
| $3,913 |
| |
| $7,476 |
| |
| $1,543 |
| |
| $622 |
| |
| $1,590 |
| |
| $1,337 |
|
| Interest cost on APBO | | 13,545 |
| | 8,964 |
| | 9,410 |
| | 4,289 |
| | 3,135 |
| | 6,076 |
| | 2,945 |
| | 9,297 |
| | 13,041 |
| | 2,835 |
| | 1,791 |
| | 4,154 |
| | 2,117 |
|
| Expected return on assets | | (16,843 | ) | | — |
| | — |
| | (5,335 | ) | | (4,101 | ) | | (9,391 | ) | | (3,350 | ) | | (17,855 | ) | | — |
| | (5,517 | ) | | (4,617 | ) | | (9,575 | ) | | (3,257 | ) |
| Amortization of prior credit | | (689 | ) | | (942 | ) | | (508 | ) | | (204 | ) | | (24 | ) | | (501 | ) | | (126 | ) | |
| Amortization of prior service credit | | | (5,472 | ) | | (7,787 | ) | | (934 | ) | | (745 | ) | | (2,722 | ) | | (1,570 | ) |
| Recognized net loss | | 7,976 |
| | 4,598 |
| | 5,050 |
| | 2,534 |
| | 1,509 |
| | 3,744 |
| | 1,896 |
| | 4,256 |
| | 2,926 |
| | 893 |
| | 146 |
| | 2,148 |
| | 1,149 |
|
| Curtailment loss | | 4,517 |
| | 1,546 |
| | 1,848 |
| | 596 |
| | 354 |
| | 1,436 |
| | 760 |
| |
| Net other postretirement benefit cost | |
| $18,125 |
| |
| $22,076 |
| |
| $24,341 |
| |
| $5,126 |
| |
| $2,625 |
| |
| $5,124 |
| |
| $5,705 |
| |
| Net other postretirement benefit (income)/cost | | |
| ($5,861 | ) | |
| $15,656 |
| |
| ($1,180 | ) | |
| ($2,803 | ) | |
| ($4,405 | ) | |
| ($224 | ) |
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit for the period | |
| ($11,617 | ) | |
| ($8,705 | ) | |
| ($18,844 | ) | |
| ($4,714 | ) | |
| ($4,469 | ) | |
| ($5,359 | ) | |
| ($4,591 | ) | |
| ($1,007 | ) | |
| ($4,647 | ) | |
| ($6,219 | ) | |
| $— |
| |
| $— |
| |
| $— |
|
| Net loss | |
| ($81,236 | ) | |
| ($40,938 | ) | |
| ($43,743 | ) | |
| ($30,018 | ) | |
| ($18,508 | ) | |
| ($34,562 | ) | |
| ($17,579 | ) | |
| Net (gain)/loss | | | 3,331 |
| | (13,117 | ) | | 8,715 |
| | 5,717 |
| | 13,378 |
| | 4,997 |
|
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of prior service credit | | 689 |
| | 942 |
| | 508 |
| | 204 |
| | 24 |
| | 501 |
| | 126 |
| | 5,472 |
| | 7,787 |
| | 934 |
| | 745 |
| | 2,722 |
| | 1,570 |
|
| Acceleration of prior service credit/(cost) due to curtailment | | 78 |
| | 91 |
| | 41 |
| | 20 |
| | (4 | ) | | 62 |
| | 9 |
| |
| Amortization of net loss | | (7,976 | ) | | (4,598 | ) | | (5,050 | ) | | (2,534 | ) | | (1,509 | ) | | (3,744 | ) | | (1,896 | ) | | (4,256 | ) | | (2,926 | ) | | (893 | ) | | (146 | ) | | (2,148 | ) | | (1,149 | ) |
| Total | |
| ($100,062 | ) | |
| ($53,208 | ) | |
| ($67,088 | ) | |
| ($37,042 | ) | |
| ($24,466 | ) | |
| ($43,102 | ) | |
| ($23,931 | ) | |
| $3,540 |
| |
| ($12,903 | ) | |
| $2,537 |
| |
| $6,316 |
| |
| $13,952 |
| |
| $5,418 |
|
| Total recognized as net periodic other postretirement cost, regulatory asset, and/or AOCI (before tax) | |
| ($81,937 | ) | |
| ($31,132 | ) | |
| ($42,747 | ) | |
| ($31,916 | ) | |
| ($21,841 | ) | |
| ($37,978 | ) | |
| ($18,226 | ) | |
| Total recognized as net periodic other postretirement income/(cost), regulatory asset, and/or AOCI (before tax) | | |
| ($2,321 | ) | |
| $2,753 |
| |
| $1,357 |
| |
| $3,513 |
| |
| $9,547 |
| |
| $5,194 |
|
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit | |
| ($2,441 | ) | |
| ($2,236 | ) | |
| ($3,376 | ) | |
| ($918 | ) | |
| ($709 | ) | |
| ($1,301 | ) | |
| ($824 | ) | |
| ($5,110 | ) | |
| ($7,739 | ) | |
| ($1,824 | ) | |
| ($745 | ) | |
| ($2,316 | ) | |
| ($1,513 | ) |
| Net loss | |
| $1,267 |
| |
| $1,212 |
| |
| $1,511 |
| |
| $149 |
| |
| $56 |
| |
| $800 |
| |
| $464 |
| |
| $4,460 |
| |
| $1,859 |
| |
| $1,675 |
| |
| $418 |
| |
| $3,303 |
| |
| $1,560 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2012 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2015 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Other postretirement costs: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost - benefits earned during the period | |
| $9,089 |
| |
| $7,521 |
| |
| $7,796 |
| |
| $3,093 |
| |
| $1,689 |
| |
| $3,651 |
| |
| $3,293 |
| |
| $6,957 |
| |
| $9,893 |
| |
| $2,028 |
| |
| $818 |
| |
| $2,000 |
| |
| $1,881 |
|
| Interest cost on APBO | | 14,452 |
| | 9,590 |
| | 9,781 |
| | 4,716 |
| | 3,422 |
| | 6,650 |
| | 3,028 |
| | 12,518 |
| | 16,311 |
| | 3,436 |
| | 2,608 |
| | 5,366 |
| | 2,511 |
|
| Expected return on assets | | (14,029 | ) | | — |
| | — |
| | (4,521 | ) | | (3,711 | ) | | (8,415 | ) | | (2,601 | ) | | (19,190 | ) | | — |
| | (6,166 | ) | | (4,804 | ) | | (10,351 | ) | | (3,644 | ) |
Amortization of transition obligation | | 820 |
| | 238 |
| | 382 |
| | 351 |
| | 1,189 |
| | 187 |
| | 8 |
| |
| Amortization of prior service cost/(credit) | | (530 | ) | | (824 | ) | | (247 | ) | | (139 | ) | | 38 |
| | (428 | ) | | (63 | ) | |
| Amortization of prior service credit | | | (2,441 | ) | | (7,467 | ) | | (916 | ) | | (709 | ) | | (2,723 | ) | | (1,465 | ) |
| Recognized net loss | | 8,305 |
| | 4,737 |
| | 4,359 |
| | 2,920 |
| | 1,559 |
| | 4,320 |
| | 1,970 |
| | 5,356 |
| | 7,118 |
| | 860 |
| | 470 |
| | 2,740 |
| | 1,198 |
|
| Net other postretirement benefit cost | |
| $18,107 |
| |
| $21,262 |
| |
| $22,071 |
| |
| $6,420 |
| |
| $4,186 |
| |
| $5,965 |
| |
| $5,635 |
| |
| Net other postretirement benefit (income)/cost | | |
| $3,200 |
| |
| $25,855 |
| |
| ($758 | ) | |
| ($1,617 | ) | |
| ($2,968 | ) | |
| $481 |
|
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | |
| $9,066 |
| |
| $5,818 |
| |
| $16,215 |
| |
| $271 |
| |
| $2,260 |
| |
| $191 |
| |
| $2,043 |
| |
| Prior service credit for the period | | |
| ($18,035 | ) | |
| ($1,361 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| ($644 | ) |
| Net (gain)/loss | | | (11,978 | ) | | (47,043 | ) | | 774 |
| | (5,810 | ) | | (4,907 | ) | | 305 |
|
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amortization of transition obligation | | (820 | ) | | (238 | ) | | (382 | ) | | (351 | ) | | (1,189 | ) | | (187 | ) | | (8 | ) | |
| Amortization of prior service (cost)/credit | | 530 |
| | 824 |
| | 247 |
| | 139 |
| | (38 | ) | | 428 |
| | 63 |
| |
| Amortization of prior service credit | | | 2,441 |
| | 7,467 |
| | 916 |
| | 709 |
| | 2,723 |
| | 1,465 |
|
| Amortization of net loss | | (8,305 | ) | | (4,737 | ) | | (4,359 | ) | | (2,920 | ) | | (1,559 | ) | | (4,320 | ) | | (1,970 | ) | | (5,356 | ) | | (7,118 | ) | | (860 | ) | | (470 | ) | | (2,740 | ) | | (1,198 | ) |
| Total | |
| $471 |
| |
| $1,667 |
| |
| $11,721 |
| |
| ($2,861 | ) | |
| ($526 | ) | |
| ($3,888 | ) | |
| $128 |
| |
| ($32,928 | ) | |
| ($48,055 | ) | |
| $830 |
| |
| ($5,571 | ) | |
| ($4,924 | ) | |
| ($72 | ) |
| Total recognized as net periodic other postretirement income, regulatory asset, and/or AOCI (before tax) | |
| $18,578 |
| |
| $22,929 |
| |
| $33,792 |
| |
| $3,559 |
| |
| $3,660 |
| |
| $2,077 |
| |
| $5,763 |
| |
| Total recognized as net periodic other postretirement income/(cost), regulatory asset, and/or AOCI (before tax) | | |
| ($29,728 | ) | |
| ($22,200 | ) | |
| $72 |
| |
| ($7,188 | ) | |
| ($7,892 | ) | |
| $409 |
|
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost/(credit) | |
| ($530 | ) | |
| ($824 | ) | |
| ($247 | ) | |
| ($139 | ) | |
| $38 |
| |
| ($428 | ) | |
| ($62 | ) | |
| Prior service credit | | |
| ($5,472 | ) | |
| ($7,783 | ) | |
| ($933 | ) | |
| ($745 | ) | |
| ($2,722 | ) | |
| ($1,570 | ) |
| Net loss | |
| $8,163 |
| |
| $4,693 |
| |
| $5,149 |
| |
| $2,650 |
| |
| $1,587 |
| |
| $3,905 |
| |
| $1,915 |
| |
| $4,256 |
| |
| $2,926 |
| |
| $893 |
| |
| $146 |
| |
| $2,148 |
| |
| $1,149 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Other Postretirement Benefit Obligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheet
Other postretirement benefit obligations, plan assets, funded status, and amounts not yet recognized and recognized in the Consolidated Balance Sheets of Entergy Corporation and its Subsidiaries as of December 31, 20142017 and 20132016 are as follows:
| | | | December 31, | | | | | |
| | 2014 | | 2013 | 2017 | | 2016 |
| | (In Thousands) | (In Thousands) |
| Change in APBO | |
| | |
| |
| | |
|
| Balance at beginning of year |
| $1,461,910 |
| |
| $1,846,922 |
| |
| Balance at January 1 | |
| $1,568,963 |
| |
| $1,530,829 |
|
| Service cost | 43,493 |
| | 74,654 |
| 26,915 |
| | 32,291 |
|
| Interest cost | 71,841 |
| | 79,453 |
| 55,838 |
| | 56,331 |
|
| Plan amendments | (35,864 | ) | | (116,571 | ) | (2,564 | ) | | (20,353 | ) |
| Curtailment | — |
| | 14,718 |
| |
| Plan participant contributions | 22,160 |
| | 19,141 |
| 35,080 |
| | 27,686 |
|
| Actuarial loss/(gain) | 274,061 |
| | (370,004 | ) | |
| Actuarial (gain)/loss | | (23,409 | ) | | 46,201 |
|
| Benefits paid | (102,439 | ) | | (89,713 | ) | (97,829 | ) | | (104,477 | ) |
| Medicare Part D subsidy received | 4,395 |
| | 3,310 |
| 493 |
| | 455 |
|
| Balance at end of year |
| $1,739,557 |
| |
| $1,461,910 |
| |
| Balance at December 31 | |
| $1,563,487 |
| |
| $1,568,963 |
|
| Change in Plan Assets | |
| | |
| |
| | |
|
| Fair value of assets at beginning of year |
| $569,850 |
| |
| $488,448 |
| |
| Fair value of assets at January 1 | |
| $596,660 |
| |
| $579,069 |
|
| Actual return on plan assets | 31,535 |
| | 76,314 |
| 81,143 |
| | 38,216 |
|
| Employer contributions | 76,521 |
| | 75,660 |
| 44,273 |
| | 56,166 |
|
| Plan participant contributions | 22,160 |
| | 19,141 |
| 35,080 |
| | 27,686 |
|
| Benefits paid | (102,439 | ) | | (89,713 | ) | (97,829 | ) | | (104,477 | ) |
| Fair value of assets at end of year |
| $597,627 |
| |
| $569,850 |
| |
| Fair value of assets at December 31 | |
| $659,327 |
| |
| $596,660 |
|
| Funded status |
| ($1,141,930 | ) | |
| ($892,060 | ) |
| ($904,160 | ) | |
| ($972,303 | ) |
| Amounts recognized in the balance sheet | | | | | | |
| Current liabilities |
| ($41,821 | ) | |
| ($40,602 | ) |
| ($45,237 | ) | |
| ($45,255 | ) |
| Non-current liabilities | (1,100,109 | ) | | (851,458 | ) | (858,923 | ) | | (927,048 | ) |
| Total funded status |
| ($1,141,930 | ) | |
| ($892,060 | ) |
| ($904,160 | ) | |
| ($972,303 | ) |
| Amounts recognized as a regulatory asset | | | | | | |
| Prior service credit |
| ($54,508 | ) | |
| ($93,332 | ) |
| ($40,461 | ) | |
| ($54,896 | ) |
| Net loss | 248,918 |
| | 165,270 |
| 144,966 |
| | 222,540 |
|
| |
| $194,410 |
| |
| $71,938 |
|
| $104,505 |
| |
| $167,644 |
|
| Amounts recognized as AOCI (before tax) | | | | | | |
| Prior service credit |
| ($104,086 | ) | |
| ($60,988 | ) |
| ($65,047 | ) | |
| ($89,474 | ) |
| Net loss | 300,518 |
| | 107,996 |
| 161,322 |
| | 172,575 |
|
| |
| $196,432 |
| |
| $47,008 |
|
| $96,275 |
| |
| $83,101 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Other Postretirement Benefit Obligations, Plan Assets, Funded Status,postretirement benefit obligations, plan assets, funded status, and Amounts Not Yet Recognizedamounts not yet recognized and Recognizedrecognized in the Balance Sheets of the Registrant Subsidiaries as of December 31, 20142017 and 20132016 are as follows:
| | | 2014 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2017 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Change in APBO | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at beginning of year | |
| $250,734 |
| |
| $170,302 |
| |
| $168,764 |
| |
| $74,539 |
| |
| $57,874 |
| |
| $115,418 |
| |
| $53,051 |
| |
| Balance at January 1 | | |
| $258,787 |
| |
| $342,500 |
| |
| $78,485 |
| |
| $55,515 |
| |
| $127,700 |
| |
| $62,498 |
|
| Service cost | | 5,957 |
| | 4,896 |
| | 4,518 |
| | 1,900 |
| | 868 |
| | 2,378 |
| | 2,058 |
| | 3,451 |
| | 6,373 |
| | 1,160 |
| | 567 |
| | 1,488 |
| | 1,278 |
|
| Interest cost | | 12,261 |
| | 8,378 |
| | 8,264 |
| | 3,655 |
| | 2,805 |
| | 5,652 |
| | 2,611 |
| | 9,020 |
| | 12,101 |
| | 2,759 |
| | 1,874 |
| | 4,494 |
| | 2,236 |
|
| Plan amendments | | — |
| | (12,845 | ) | | — |
| | — |
| | — |
| | (8,536 | ) | | (3,845 | ) | |
| Plan participant contributions | | 5,195 |
| | 2,304 |
| | 2,767 |
| | 1,396 |
| | 1,044 |
| | 1,655 |
| | 1,061 |
| | 7,875 |
| | 7,855 |
| | 2,160 |
| | 1,151 |
| | 2,453 |
| | 1,779 |
|
| Actuarial loss | | 49,573 |
| | 36,467 |
| | 24,582 |
| | 7,939 |
| | 5,097 |
| | 21,471 |
| | 9,524 |
| |
| Actuarial (gain)/loss | | | (11,691 | ) | | (1,256 | ) | | 5,858 |
| | (899 | ) | | (12,469 | ) | | (2,233 | ) |
| Benefits paid | | (20,984 | ) | | (10,613 | ) | | (14,012 | ) | | (6,589 | ) | | (4,131 | ) | | (8,333 | ) | | (3,858 | ) | | (18,497 | ) | | (22,273 | ) | | (5,823 | ) | | (4,670 | ) | | (6,980 | ) | | (4,205 | ) |
| Medicare Part D subsidy received | | 980 |
| | 520 |
| | 654 |
| | 322 |
| | 222 |
| | 440 |
| | 152 |
| | 74 |
| | 89 |
| | 22 |
| | 10 |
| | 16 |
| | 28 |
|
| Balance at end of year | |
| $303,716 |
| |
| $199,409 |
| |
| $195,537 |
| |
| $83,162 |
| |
| $63,779 |
| |
| $130,145 |
| |
| $60,754 |
| |
| Balance at December 31 | | |
| $249,019 |
| |
| $345,389 |
| |
| $84,621 |
| |
| $53,548 |
| |
| $116,702 |
| |
| $61,381 |
|
| Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of assets at beginning of year | |
| $231,663 |
| |
| $— |
| |
| $— |
| |
| $73,438 |
| |
| $66,539 |
| |
| $131,618 |
| |
| $48,101 |
| |
| Fair value of assets at January 1 | | |
| $250,926 |
| |
| $— |
| |
| $75,945 |
| |
| $74,236 |
| |
| $137,069 |
| |
| $44,885 |
|
| Actual return on plan assets | | 13,066 |
| | — |
| | — |
| | 4,185 |
| | 3,263 |
| | 7,347 |
| | 2,655 |
| | 33,679 |
| | — |
| | 10,153 |
| | 11,078 |
| | 18,506 |
| | 6,095 |
|
| Employer contributions | | 15,251 |
| | 8,309 |
| | 11,245 |
| | 8,505 |
| | 4,289 |
| | 3,446 |
| | 334 |
| | 695 |
| | 14,418 |
| | (2 | ) | | 3,709 |
| | 3,123 |
| | 570 |
|
| Plan participant contributions | | 5,195 |
| | 2,304 |
| | 2,767 |
| | 1,396 |
| | 1,044 |
| | 1,655 |
| | 1,061 |
| | 7,875 |
| | 7,855 |
| | 2,160 |
| | 1,151 |
| | 2,453 |
| | 1,779 |
|
| Benefits paid | | (20,984 | ) | | (10,613 | ) | | (14,012 | ) | | (6,589 | ) | | (4,131 | ) | | (8,333 | ) | | (3,858 | ) | | (18,497 | ) | | (22,273 | ) | | (5,823 | ) | | (4,670 | ) | | (6,980 | ) | | (4,205 | ) |
| Fair value of assets at end of year | |
| $244,191 |
| |
| $— |
| |
| $— |
| |
| $80,935 |
| |
| $71,004 |
| |
| $135,733 |
| |
| $48,293 |
| |
| Fair value of assets at December 31 | | |
| $274,678 |
| |
| $— |
| |
| $82,433 |
| |
| $85,504 |
| |
| $154,171 |
| |
| $49,124 |
|
| Funded status | |
| ($59,525 | ) | |
| ($199,409 | ) | |
| ($195,537 | ) | |
| ($2,227 | ) | |
| $7,225 |
| |
| $5,588 |
| |
| ($12,461 | ) | |
| $25,659 |
| |
| ($345,389 | ) | |
| ($2,188 | ) | |
| $31,956 |
| |
| $37,469 |
| |
| ($12,257 | ) |
Amounts recognized in the balance sheet | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Current liabilities | |
| $— |
| |
| ($8,884 | ) | |
| ($9,840 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| ($18,794 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
| Non-current liabilities | | (59,525 | ) | | (190,525 | ) | | (185,697 | ) | | (2,227 | ) | | 7,225 |
| | 5,588 |
| | (12,461 | ) | | 25,659 |
| | (326,595 | ) | | (2,188 | ) | | 31,956 |
| | 37,469 |
| | (12,257 | ) |
| Total funded status | |
| ($59,525 | ) | |
| ($199,409 | ) | |
| ($195,537 | ) | |
| ($2,227 | ) | |
| $7,225 |
| |
| $5,588 |
| |
| ($12,461 | ) | |
| $25,659 |
| |
| ($345,389 | ) | |
| ($2,188 | ) | |
| $31,956 |
| |
| $37,469 |
| |
| ($12,257 | ) |
Amounts recognized in regulatory asset | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit | |
| ($10,555 | ) | |
| $— |
| |
| $— |
| |
| ($4,141 | ) | |
| ($3,626 | ) | |
| ($13,741 | ) | |
| ($7,723 | ) | |
| ($16,574 | ) | |
| $— |
| |
| ($6,687 | ) | |
| ($1,427 | ) | |
| ($5,980 | ) | |
| ($3,819 | ) |
| Net loss | | 94,647 |
| | — |
| | — |
| | 18,680 |
| | 12,738 |
| | 46,453 |
| | 20,450 |
| | 42,394 |
| | — |
| | 25,247 |
| | 4,269 |
| | 24,478 |
| | 16,386 |
|
| | |
| $84,092 |
| |
| $— |
| |
| $— |
| |
| $14,539 |
| |
| $9,112 |
| |
| $32,712 |
| |
| $12,727 |
| |
| $25,820 |
| |
| $— |
| |
| $18,560 |
| |
| $2,842 |
| |
| $18,498 |
| |
| $12,567 |
|
| Amounts recognized in AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit | |
| $— |
| |
| ($20,967 | ) | |
| ($16,013 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| ($19,999 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
| Net loss | | — |
| | 66,832 |
| | 58,072 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 51,585 |
| | — |
| | — |
| | — |
| | — |
|
| | |
| $— |
| |
| $45,865 |
| |
| $42,059 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $31,586 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2016 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Change in APBO | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at beginning of year | |
| $315,308 |
| |
| $207,987 |
| |
| $220,017 |
| |
| $100,508 |
| |
| $74,200 |
| |
| $142,114 |
| |
| $67,934 |
| |
| Balance at January 1 | | |
| $258,900 |
| |
| $356,253 |
| |
| $77,382 |
| |
| $51,951 |
| |
| $114,582 |
| |
| $57,645 |
|
| Service cost | | 9,619 |
| | 7,910 |
| | 8,541 |
| | 3,246 |
| | 1,752 |
| | 3,760 |
| | 3,580 |
| | 3,913 |
| | 7,476 |
| | 1,543 |
| | 622 |
| | 1,590 |
| | 1,337 |
|
| Interest cost | | 13,545 |
| | 8,964 |
| | 9,410 |
| | 4,289 |
| | 3,135 |
| | 6,076 |
| | 2,945 |
| | 9,297 |
| | 13,041 |
| | 2,835 |
| | 1,791 |
| | 4,154 |
| | 2,117 |
|
| Plan amendments | | (11,617 | ) | | (8,705 | ) | | (18,844 | ) | | (4,714 | ) | | (4,469 | ) | | (5,359 | ) | | (4,591 | ) | | (1,007 | ) | | (4,647 | ) | | (6,219 | ) | | — |
| | — |
| | — |
|
| Curtailment | | 4,595 |
| | 1,637 |
| | 1,889 |
| | 616 |
| | 350 |
| | 1,498 |
| | 769 |
| |
| Plan participant contributions | | 4,564 |
| | 1,998 |
| | 2,509 |
| | 1,292 |
| | 915 |
| | 1,498 |
| | 860 |
| | 6,330 |
| | 6,273 |
| | 1,721 |
| | 1,213 |
| | 1,927 |
| | 1,390 |
|
| Actuarial gain | | (67,253 | ) | | (40,941 | ) | | (43,747 | ) | | (25,527 | ) | | (13,739 | ) | | (26,048 | ) | | (14,639 | ) | |
| Actuarial (gain)/loss | | | 2,453 |
| | (13,117 | ) | | 8,230 |
| | 4,774 |
| | 12,389 |
| | 4,806 |
|
| Benefits paid | | (18,764 | ) | | (8,958 | ) | | (11,524 | ) | | (5,416 | ) | | (4,464 | ) | | (8,455 | ) | | (3,912 | ) | | (21,178 | ) | | (22,893 | ) | | (7,031 | ) | | (4,852 | ) | | (6,977 | ) | | (4,818 | ) |
| Medicare Part D subsidy received | | 737 |
| | 410 |
| | 513 |
| | 245 |
| | 194 |
| | 334 |
| | 105 |
| | 79 |
| | 114 |
| | 24 |
| | 16 |
| | 35 |
| | 21 |
|
| Balance at end of year | |
| $250,734 |
| |
| $170,302 |
| |
| $168,764 |
| |
| $74,539 |
| |
| $57,874 |
| |
| $115,418 |
| |
| $53,051 |
| |
| Balance at December 31 | | |
| $258,787 |
| |
| $342,500 |
| |
| $78,485 |
| |
| $55,515 |
| |
| $127,700 |
| |
| $62,498 |
|
| Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of assets at beginning of year | |
| $194,018 |
| |
| $— |
| |
| $— |
| |
| $62,951 |
| |
| $58,651 |
| |
| $115,824 |
| |
| $39,474 |
| |
| Fair value of assets at January 1 | | |
| $243,206 |
| |
| $— |
| |
| $75,538 |
| |
| $69,881 |
| |
| $130,374 |
| |
| $44,917 |
|
| Actual return on plan assets | | 30,830 |
| | — |
| | — |
| | 9,826 |
| | 8,870 |
| | 17,905 |
| | 6,292 |
| | 16,977 |
| | — |
| | 5,032 |
| | 3,674 |
| | 8,586 |
| | 3,066 |
|
| Employer contributions | | 21,015 |
| | 6,960 |
| | 9,015 |
| | 4,785 |
| | 2,567 |
| | 4,846 |
| | 5,387 |
| | 5,591 |
| | 16,620 |
| | 685 |
| | 4,320 |
| | 3,159 |
| | 330 |
|
| Plan participant contributions | | 4,564 |
| | 1,998 |
| | 2,509 |
| | 1,292 |
| | 915 |
| | 1,498 |
| | 860 |
| | 6,330 |
| | 6,273 |
| | 1,721 |
| | 1,213 |
| | 1,927 |
| | 1,390 |
|
| Benefits paid | | (18,764 | ) | | (8,958 | ) | | (11,524 | ) | | (5,416 | ) | | (4,464 | ) | | (8,455 | ) | | (3,912 | ) | | (21,178 | ) | | (22,893 | ) | | (7,031 | ) | | (4,852 | ) | | (6,977 | ) | | (4,818 | ) |
| Fair value of assets at end of year | |
| $231,663 |
| |
| $— |
| |
| $— |
| |
| $73,438 |
| |
| $66,539 |
| |
| $131,618 |
| |
| $48,101 |
| |
| Fair value of assets at December 31 | | |
| $250,926 |
| |
| $— |
| |
| $75,945 |
| |
| $74,236 |
| |
| $137,069 |
| |
| $44,885 |
|
| Funded status | |
| ($19,071 | ) | |
| ($170,302 | ) | |
| ($168,764 | ) | |
| ($1,101 | ) | |
| $8,665 |
| |
| $16,200 |
| |
| ($4,950 | ) | |
| ($7,861 | ) | |
| ($342,500 | ) | |
| ($2,540 | ) | |
| $18,721 |
| |
| $9,369 |
| |
| ($17,613 | ) |
Amounts recognized in the balance sheet | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Current liabilities | |
| $— |
| |
| ($8,803 | ) | |
| ($10,249 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| ($19,209 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
| Non-current liabilities | | (19,071 | ) | | (161,499 | ) | | (158,515 | ) | | (1,101 | ) | | 8,665 |
| | 16,200 |
| | (4,950 | ) | | (7,861 | ) | | (323,291 | ) | | (2,540 | ) | | 18,721 |
| | 9,369 |
| | (17,613 | ) |
| Total funded status | |
| ($19,071 | ) | |
| ($170,302 | ) | |
| ($168,764 | ) | |
| ($1,101 | ) | |
| $8,665 |
| |
| $16,200 |
| |
| ($4,950 | ) | |
| ($7,861 | ) | |
| ($342,500 | ) | |
| ($2,540 | ) | |
| $18,721 |
| |
| $9,369 |
| |
| ($17,613 | ) |
Amounts recognized in regulatory asset | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit | |
| ($12,996 | ) | |
| $— |
| |
| $— |
| |
| ($5,056 | ) | |
| ($4,335 | ) | |
| ($6,505 | ) | |
| ($4,702 | ) | |
| ($21,684 | ) | |
| $— |
| |
| ($8,511 | ) | |
| ($2,172 | ) | |
| ($8,296 | ) | |
| ($5,332 | ) |
| Net loss | | 40,272 |
| | — |
| | — |
| | 9,304 |
| | 6,485 |
| | 22,772 |
| | 10,297 |
| | 76,388 |
| | — |
| | 26,416 |
| | 12,029 |
| | 50,036 |
| | 23,405 |
|
| | |
| $27,276 |
| |
| $— |
| |
| $— |
| |
| $4,248 |
| |
| $2,150 |
| |
| $16,267 |
| |
| $5,595 |
| |
| $54,704 |
| |
| $— |
| |
| $17,905 |
| |
| $9,857 |
| |
| $41,740 |
| |
| $18,073 |
|
| Amounts recognized in AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit | |
| $— |
| |
| ($10,359 | ) | |
| ($19,390 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| ($27,735 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
| Net loss | | — |
| | 31,577 |
| | 35,001 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 54,700 |
| | — |
| | — |
| | — |
| | — |
|
| | |
| $— |
| |
| $21,218 |
| |
| $15,611 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $26,965 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Non-Qualified Pension Plans
Entergy also sponsors non-qualified, non-contributory defined benefit pension plans that provide benefits to certain key employees. Entergy recognized net periodic pension cost related to these plans of $32.4$37.6 million in 2014, $54.52017, $24.9 million in 2013,2016, and $26.5$22.8 million in 2012.2015. In 2014, 2013,2017, 2016, and 20122015 Entergy recognized $15.1$20.3 million, $33$8.1 million, and $6.3$5.1 million, respectively in settlement charges related to the payment of lump sum benefits out of the plan that is included in the non-qualified pension plan cost above. The projected benefit obligation was $151.8$162.3 million and $154.3$169.3 million as of December 31, 20142017 and 2013,2016, respectively. The accumulated benefit obligation was $130.6$144.7 million and $131.4$151.0 million as of December 31, 20142017 and 2013,2016, respectively.
Entergy’s non-qualified, non-current pension liability at December 31, 20142017 and 20132016 was $135.6$136 million and $127.5$137.6 million, respectively; and its current liability was $16.2$26.4 million and $26.8$31.7 million, respectively. The unamortized prior service cost and net loss are recognized in regulatory assets ($60.355.2 million at December 31, 20142017 and $59.1$59.8 million at December 31, 2013)2016) and accumulated other comprehensive income before taxes ($23.535.9 million at December 31, 20142017 and $26.1$31.6 million at December 31, 2013)2016).
The following Registrant Subsidiaries (except System Energy) participate in Entergy’s non-qualified, non-contributory defined benefit pension plans that provide benefits to certain key employees. The net periodic pension cost for their employees for the non-qualified plans for 2014, 2013,2017, 2016, and 2012,2015, was as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | (In Thousands) |
| 2014 |
| $754 |
| |
| $130 |
| |
| $5 |
| |
| $190 |
| |
| $95 |
| |
| $491 |
|
| 2013 |
| $448 |
| |
| $151 |
| |
| $12 |
| |
| $192 |
| |
| $92 |
| |
| $1,001 |
|
| 2012 |
| $464 |
| |
| $158 |
| |
| $12 |
| |
| $183 |
| |
| $79 |
| |
| $648 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | (In Thousands) |
| 2017 |
| $679 |
| |
| $185 |
| |
| $251 |
| |
| $73 |
| |
| $499 |
|
| 2016 |
| $1,819 |
| |
| $231 |
| |
| $236 |
| |
| $65 |
| |
| $504 |
|
| 2015 |
| $446 |
| |
| $377 |
| |
| $235 |
| |
| $64 |
| |
| $595 |
|
Included in the 20142017 net periodic pension cost above are settlement charges of $337$269 thousand for Entergy Arkansas related to the lump sum benefits paid out of the plan. Included in the 2016 net periodic pension cost above are settlement charges of $1.4 million and $16$1 thousand for Entergy Arkansas and Entergy Texas,Mississippi, respectively, related to the lump sum benefits paid out of the plan. Included in the 20132015 net periodic pension cost above are settlement charges of $415$108 thousand and $2 thousand for Entergy TexasLouisiana and Entergy Mississippi, respectively, related to the lump sum benefits paid out of the plan. Included in the 2012 net periodic pension cost above are settlement charges of $38 thousand for Entergy Arkansas related to the lump sum benefits paid out of the plan.
The projected benefit obligation for their employees for the non-qualified plans as of December 31, 20142017 and 20132016 was as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | (In Thousands) |
| 2014 |
| $4,495 |
| |
| $2,693 |
| |
| $158 |
| |
| $2,128 |
| |
| $476 |
| |
| $9,567 |
|
| 2013 |
| $4,162 |
| |
| $2,511 |
| |
| $50 |
| |
| $1,752 |
| |
| $434 |
| |
| $7,910 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | (In Thousands) |
| 2017 |
| $4,221 |
| |
| $2,061 |
| |
| $2,737 |
| |
| $583 |
| |
| $8,913 |
|
| 2016 |
| $3,897 |
| |
| $2,134 |
| |
| $2,296 |
| |
| $514 |
| |
| $8,665 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The accumulated benefit obligation for their employees for the non-qualified plans as of December 31, 20142017 and 20132016 was as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | (In Thousands) |
| 2014 |
| $4,086 |
| |
| $2,693 |
| |
| $131 |
| |
| $1,761 |
| |
| $436 |
| |
| $9,215 |
|
| 2013 |
| $3,765 |
| |
| $2,510 |
| |
| $50 |
| |
| $1,528 |
| |
| $387 |
| |
| $7,496 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | (In Thousands) |
| 2017 |
| $3,825 |
| |
| $2,061 |
| |
| $2,250 |
| |
| $519 |
| |
| $8,602 |
|
| 2016 |
| $3,439 |
| |
| $2,134 |
| |
| $1,961 |
| |
| $452 |
| |
| $8,333 |
|
The following amounts were recorded on the balance sheet as of December 31, 20142017 and 2013:2016:
| | | 2014 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | |
| 2017 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) | | (In Thousands) |
| Current liabilities | |
| ($347 | ) | |
| ($241 | ) | |
| ($18 | ) | |
| ($119 | ) | |
| ($23 | ) | |
| ($753 | ) | |
| ($376 | ) | |
| ($231 | ) | |
| ($135 | ) | |
| ($21 | ) | |
| ($788 | ) |
| Non-current liabilities | | (4,148 | ) | | (2,452 | ) | | (140 | ) | | (2,009 | ) | | (453 | ) | | (8,814 | ) | | (3,845 | ) | | (1,830 | ) | | (2,603 | ) | | (562 | ) | | (8,125 | ) |
| Total funded status | |
| ($4,495 | ) | |
| ($2,693 | ) | |
| ($158 | ) | |
| ($2,128 | ) | |
| ($476 | ) | |
| ($9,567 | ) | |
| ($4,221 | ) | |
| ($2,061 | ) | |
| ($2,738 | ) | |
| ($583 | ) | |
| ($8,913 | ) |
| Regulatory asset/(liability) | |
| $2,368 |
| |
| $659 |
| |
| $37 |
| |
| $942 |
| |
| ($65 | ) | |
| $296 |
| |
| $2,995 |
| |
| $166 |
| |
| $1,186 |
| |
| ($140 | ) | |
| $133 |
|
Accumulated other comprehensive income (before taxes) | |
| $— |
| |
| $98 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $11 |
| |
| $— |
| |
| $— |
| |
| $— |
|
| | | 2013 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | |
| 2016 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) | | (In Thousands) |
| Current liabilities | |
| ($367 | ) | |
| ($262 | ) | |
| ($6 | ) | |
| ($118 | ) | |
| ($20 | ) | |
| ($786 | ) | |
| ($242 | ) | |
| ($233 | ) | |
| ($137 | ) | |
| ($20 | ) | |
| ($773 | ) |
| Non-current liabilities | | (3,795 | ) | | (2,249 | ) | | (44 | ) | | (1,634 | ) | | (414 | ) | | (7,124 | ) | | (3,655 | ) | | (1,901 | ) | | (2,159 | ) | | (495 | ) | | (7,892 | ) |
| Total funded status | |
| ($4,162 | ) | |
| ($2,511 | ) | |
| ($50 | ) | |
| ($1,752 | ) | |
| ($434 | ) | |
| ($7,910 | ) | |
| ($3,897 | ) | |
| ($2,134 | ) | |
| ($2,296 | ) | |
| ($515 | ) | |
| ($8,665 | ) |
| Regulatory asset/(liability) | |
| $1,979 |
| |
| $422 |
| |
| ($87 | ) | |
| $637 |
| |
| ($18 | ) | |
| ($1,631 | ) | |
| $2,914 |
| |
| $175 |
| |
| $876 |
| |
| ($148 | ) | |
| ($316 | ) |
Accumulated other comprehensive income (before taxes) | |
| $— |
| |
| $57 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $13 |
| |
| $— |
| |
| $— |
| |
| $— |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Reclassification out of Accumulated Other Comprehensive Income (Loss)
Entergy and the Registrant SubsidiariesEntergy Louisiana reclassified the following costs out of accumulated other comprehensive income (loss) (before taxes and including amounts capitalized) as of December 31, 2014:
2017:
| | | | Qualified
Pension
Costs | | Other
Postretirement
Costs | | Non-Qualified
Pension Costs | | Total | Qualified Pension Costs | | Other Postretirement Costs | | Non-Qualified Pension Costs | | Total |
| | (In Thousands) | (In Thousands) |
| Entergy | | | | | | | | | | | | | | |
| Amortization of prior service cost |
| ($1,559 | ) | |
| $22,280 |
| |
| ($427 | ) | |
| $20,294 |
|
| ($261 | ) | |
| $26,867 |
| |
| ($355 | ) | |
| $26,251 |
|
| Amortization of loss | (26,934 | ) | | (6,689 | ) | | (2,213 | ) | | (35,836 | ) | (73,800 | ) | | (8,805 | ) | | (3,397 | ) | | (86,002 | ) |
| Settlement loss | — |
| | — |
| | (3,643 | ) | | (3,643 | ) | — |
| | — |
| | (7,544 | ) | | (7,544 | ) |
| |
| ($28,493 | ) | |
| $15,591 |
| |
| ($6,283 | ) | |
| ($19,185 | ) |
| ($74,061 | ) | |
| $18,062 |
| |
| ($11,296 | ) | |
| ($67,295 | ) |
| Entergy Gulf States Louisiana | | | | | | | | |
| Amortization of prior service cost |
| $— |
| |
| $2,237 |
| |
| $— |
| |
| $2,237 |
| |
| Amortization of loss | (1,911 | ) | | (1,212 | ) | | (3 | ) | | (3,126 | ) | |
| |
| ($1,911 | ) | |
| $1,025 |
| |
| ($3 | ) | |
| ($889 | ) | |
| Entergy Louisiana | | | | | | | | | | | | | | |
| Amortization of prior service cost |
| $— |
| |
| $3,377 |
| |
| $— |
| |
| $3,377 |
|
| $— |
| |
| $7,735 |
| |
| ($1 | ) | |
| $7,734 |
|
| Amortization of loss | — |
| | (1,511 | ) | | — |
| | (1,511 | ) | (3,459 | ) | | (1,859 | ) | | (9 | ) | | (5,327 | ) |
| |
| $— |
| |
| $1,866 |
| |
| $— |
| |
| $1,866 |
|
| ($3,459 | ) | |
| $5,876 |
| |
| ($10 | ) | |
| $2,407 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy and the Registrant SubsidiariesEntergy Louisiana reclassified the following costs out of accumulated other comprehensive income (loss) (before taxes and including amounts capitalized) as of December 31, 2013:2016:
| | | | Qualified
Pension
Costs | | Other
Postretirement
Costs | | Non-Qualified
Pension Costs | | Total | Qualified Pension Costs | | Other Postretirement Costs | | Non-Qualified Pension Costs | | Total |
| | (In Thousands) | (In Thousands) |
| Entergy | | | | | | | | | | | | | | |
| Amortization of prior service cost |
| ($1,866 | ) |
|
| $12,925 |
| |
| ($503 | ) | |
| $10,556 |
|
| ($1,079 | ) |
|
| $30,949 |
| |
| ($456 | ) | |
| $29,414 |
|
| Acceleration of prior service cost due to curtailment | (1,304 | ) | | 1,797 |
| | (178 | ) | | 315 |
| (1,045 | ) | | — |
| | — |
| | (1,045 | ) |
| Amortization of loss | (43,971 | ) | | (21,590 | ) | | (2,569 | ) | | (68,130 | ) | (49,930 | ) | | (8,248 | ) | | (2,515 | ) | | (60,693 | ) |
| Settlement loss | — |
| | — |
| | (11,612 | ) | | (11,612 | ) | — |
| | — |
| | (2,007 | ) | | (2,007 | ) |
| |
| ($47,141 | ) | |
| ($6,868 | ) | |
| ($14,862 | ) | |
| ($68,871 | ) |
| ($52,054 | ) | |
| $22,701 |
| |
| ($4,978 | ) | |
| ($34,331 | ) |
| Entergy Gulf States Louisiana | | | | | | | | |
| Entergy Louisiana | | | | | | | | |
| Amortization of prior service cost |
| ($1 | ) |
|
| $942 |
| |
| $— |
| |
| $941 |
|
| $— |
|
|
| $7,787 |
| |
| ($1 | ) | |
| $7,786 |
|
| Acceleration of prior service cost due to curtailment | — |
| | 91 |
| | — |
| | 91 |
| |
| Amortization of loss | (3,039 | ) | | (4,598 | ) | | (7 | ) | | (7,644 | ) | (3,345 | ) | | (2,926 | ) | | (10 | ) | | (6,281 | ) |
| |
| ($3,040 | ) | |
| ($3,565 | ) | |
| ($7 | ) | |
| ($6,612 | ) |
| ($3,345 | ) | |
| $4,861 |
| |
| ($11 | ) | |
| $1,505 |
|
| Entergy Louisiana | | | | | | | | |
| Amortization of prior service cost |
| $— |
|
|
| $508 |
| |
| $— |
| |
| $508 |
| |
| Acceleration of prior service cost due to curtailment | — |
| | 41 |
| | — |
| | 41 |
| |
| Amortization of loss | — |
| | (5,050 | ) | | — |
| | (5,050 | ) | |
| |
| $— |
| |
| ($4,501 | ) | |
| $— |
| |
| ($4,501 | ) | |
Accounting for Pension and Other Postretirement Benefits
Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. This is measured as the difference between plan assets at fair value and the benefit obligation. Entergy uses a December 31 measurement date for its pension and other postretirement plans. Employers are to record previously unrecognized gains and losses, prior service costs, and any remaining transition asset or obligation (that resulted from adopting prior pension and other postretirement benefits accounting standards) as comprehensive income and/or as a regulatory asset reflective of the recovery mechanism for pension and other postretirement benefit costs in the Registrant Subsidiaries’ respective regulatory jurisdictions. For the portion of Entergy Gulf States Louisiana that is not regulated, the unrecognized prior service cost, gains and losses, and transition asset/obligation for its pension and other postretirement benefit obligations are recorded as other comprehensive income. Entergy Gulf States Louisiana and Entergy Louisiana recoverrecovers other postretirement benefit costs on a pay-as-you-go basis and recordrecords the unrecognized prior service cost, gains and losses, and transition obligation for its other postretirement benefit obligation as other comprehensive income. Accounting standards also
Entergy Corporation and Subsidiaries
Notes to Financial Statements
require that changes in the funded status be recorded as other comprehensive income and/or a regulatory asset in the period in which the changes occur.
With regard to pension and other postretirement costs, Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For other postretirement benefit plan assets Entergy uses fair value when determining MRV.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Qualified Pension and Other Postretirement Plans’ Assets
The Plan Administrator’s trust asset investment strategy is to invest the assets in a manner whereby long-term earnings on the assets (plus cash contributions) provide adequate funding for retiree benefit payments. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense.
In the optimization studies, the Plan Administrator formulates assumptions about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes. The future market assumptions used in the optimization study are determined by examining historical market characteristics of the various asset classes and making adjustments to reflect future conditions expected to prevail over the study period.
The target asset allocation for pension adjusts dynamically based on the pension plans'plans’ funded status. The current targets are shown below. The expectation is that the allocation to fixed income securities will increase as the pension plans'plans’ funded status increases. The following ranges were established to produce an acceptable, economically efficient plan to manage around the targets.
TheFor postretirement assets the target and range asset allocation for postretirement assets reflects changesallocations (as shown below) reflect recommendations made in 2012 as recommended in the latest optimization study. The target asset allocations for postretirement assets adjust dynamically based on the funded status of each sub-account within each trust. The current weighted average targets shown below represent the aggregate of all targets for all sub-accounts within all trusts.
Entergy’s qualified pension and postretirement weighted-average asset allocations by asset category at December 31, 20142017 and 20132016 and the target asset allocation and ranges for 2017 are as follows:
| | Pension Asset Allocation | | Target | | Range | | Actual 2014 | | Actual 2013 | | Target | | Range | | Actual 2017 | | Actual 2016 |
| Domestic Equity Securities | | 45% | | 34% | to | 53% | | 45% | | 46% | | 45% | | 37% | to | 53% | | 45% | | 46% |
| International Equity Securities | | 20% | | 16% | to | 24% | | 19% | | 20% | | 20% | | 16% | to | 24% | | 20% | | 20% |
| Fixed Income Securities | | 35% | | 31% | to | 41% | | 35% | | 33% | | 35% | | 32% | to | 38% | | 34% | | 33% |
| Other | | 0% | | 0% | to | 10% | | 1% | | 1% | | 0% | | 0% | to | 10% | | 1% | | 1% |
| | Postretirement Asset Allocation | Non-Taxable and Taxable | | Non-Taxable and Taxable |
| |
Target |
Range | Actual 2014 | Actual 2013 | | Target | | Range | | Actual 2017 | | Actual 2016 |
| Domestic Equity Securities | 39% | 34% | to | 44% | 42% | 40% | | 27% | | 22% | to | 32% | | 30% | | 40% |
| International Equity Securities | 26% | 21% | to | 31% | 25% | 26% | | 18% | | 13% | to | 23% | | 20% | | 27% |
| Fixed Income Securities | 35% | 30% | to | 40% | 33% | 34% | | 55% | | 50% | to | 60% | | 50% | | 33% |
| Other | 0% | to | 5% | 0% | | 0% | | 0% | to | 5% | | 0% | | 0% |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and some investment managers.
The expected long-term rate of return for the qualified pension plans’ assets is based primarily on the geometric average of the historical annual performance of a representative portfolio weighted by the target asset allocation defined in the table above, along with other indications of expected return on assets. The time period reflected is a long dated period spanning several decades.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The expected long-term rate of return for the non-taxable postretirement trust assets is determined using the same methodology described above for pension assets, but the aggregate asset allocation specific to the non-taxable postretirement assets is used.
For the taxable postretirement trust assets, the investment allocation includes tax-exempt fixed income securities. This asset allocation, in combination with the same methodology employed to determine the expected return for other trustpostretirement assets (as described above), and with a modification to reflect applicable taxes, is used to produce the expected long-term rate of return for taxable postretirement trust assets.
Concentrations of Credit Risk
Entergy’s investment guidelines mandate the avoidance of risk concentrations. Types of concentrations specified to be avoided include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, geographic area and individual security issuance. As of December 31, 2014,2017, all investment managers and assets were materially in compliance with the approved investment guidelines, therefore there were no significant concentrations (defined as greater than 10 percent of plan assets) of credit risk in Entergy’s pension and other postretirement benefit plan assets.
Fair Value Measurements
Accounting standards provide the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level(Level 1 measurements) and the lowest priority to unobservable inputs (level(Level 3 measurements).
The three levels of the fair value hierarchy are described below:
Level 1 - Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in active markets that the Plan has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Level 2 inputs are inputs other than quoted prices included in Level 1 that are, either directly or indirectly, observable for the asset or liability at the measurement date. Assets are valued based on prices derived by an independent party that uses inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads. Prices are reviewed and can be challenged with the independent parties and/or overridden if it is believed such would be more reflective of fair value. Level 2 inputs include the following:
- quoted prices for similar assets or liabilities in active markets;
- quoted prices for identical assets or liabilities in inactive markets;
- inputs other than quoted prices that are observable for the asset or liability; or
- inputs that are derived principally from or corroborated by observable market data by correlation or other means.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
If an asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.
Level 3 - Level 3 refers to securities valued based on significant unobservable inputs.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following tables set forth by level within the fair value hierarchy, measured at fair value
Entergy Corporation and Subsidiaries
Notes to Financial Statements
on a recurring basis at December 31, 2014,2017, and December 31, 2013,2016, a summary of the investments held in the master trusts for Entergy’s qualified pension and other postretirement plans in which the Registrant Subsidiaries participate.
Qualified Defined Benefit Pension Plan Trusts
Final Average Pay Pension Plans’ Trust
|
| | | | | | | | | | | | | | | | |
| 2014 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Thousands) |
| Equity securities: | | | | | | | | |
| Corporate stocks: | | | | | | | | |
| Preferred | |
| $10,017 |
| (b) |
| $— |
| (a) |
| $— |
| |
| $10,017 |
|
| Common | | 717,685 |
| (b) | 97 |
| | — |
| | 717,782 |
|
| Common collective trusts | | — |
| | 1,886,897 |
| (c) | — |
| | 1,886,897 |
|
| 103-12 investment entities | | — |
| | 259,995 |
| (h) | — |
| | 259,995 |
|
| Fixed income securities: | | | | | | | | |
| U.S. Government securities | | 240 |
| (b) | 400,059 |
| (a) | — |
| | 400,299 |
|
| Corporate debt instruments | | — |
| | 548,788 |
| (a) | — |
| | 548,788 |
|
| Registered investment companies | | 286,534 |
| (d) | 576,641 |
| (e) | — |
| | 863,175 |
|
| Other | | — |
| | 130,295 |
| (f) | — |
| | 130,295 |
|
| Other: | | | | | | | | |
| Insurance company general account (unallocated contracts) | | — |
| | 37,818 |
| (g) | — |
| | 37,818 |
|
| Total investments | |
| $1,014,476 |
| |
| $3,840,590 |
| |
| $— |
| |
| $4,855,066 |
|
| Cash | | | | | | | | 314 |
|
| Other pending transactions | | | | | | | | 7,359 |
|
| Less: Other postretirement assets included in total investments | | | | | | | | (34,954 | ) |
Total fair value of qualified pension assets | | | | | | | |
| $4,827,785 |
|
Cash Balance Pension Plans’ Trust
The Cash Balance pension plans’ trust held $181 thousand of cash as of December 31, 2014. |
| | | | | | | | | | | | | | | | |
| 2017 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Thousands) |
| Equity securities: | | | | | | | | |
| Corporate stocks: | | | | | | | | |
| Preferred | |
| $11,461 |
| (b) |
| $— |
| |
| $— |
| |
| $11,461 |
|
| Common | | 663,923 |
| (b) | 34 |
| (b) | — |
| | 663,957 |
|
| Common collective trusts (c) | |
|
| |
|
| |
|
| | 3,198,799 |
|
| Registered investment companies | | 125,174 |
| (d) | — |
| | — |
| | 125,174 |
|
| Fixed income securities: | | | | | | | | |
| U.S. Government securities | | — |
| (b) | 638,832 |
| (a) | — |
| | 638,832 |
|
| Corporate debt instruments | | — |
| | 619,735 |
| (a) | — |
| | 619,735 |
|
| Registered investment companies (e) | | 45,768 |
| (d) | 2,735 |
| (d) | — |
| | 764,251 |
|
| Other | | 46 |
| (f) | 62,559 |
| (f) | — |
| | 62,605 |
|
| Other: | | | | | | | | |
| Insurance company general account (unallocated contracts) | | — |
| | 37,994 |
| (g) | — |
| | 37,994 |
|
| Total investments | |
| $846,372 |
| |
| $1,361,889 |
| |
| $— |
| |
| $6,122,808 |
|
| Cash | | | | | | | | 1,508 |
|
| Other pending transactions | | | | | | | | 5,179 |
|
| Less: Other postretirement assets included in total investments | | | | | | | | (58,179 | ) |
| Total fair value of qualified pension assets | | | | | | | |
| $6,071,316 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2016 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Thousands) | | (In Thousands) |
| Short-term investments | | |
| $— |
| |
| $3,610 |
| (a) |
| $— |
| |
| $3,610 |
|
| Equity securities: | | | | | | | | | | | | | | | | |
| Corporate stocks: | | | | | | | | | | | | | | | | |
| Preferred | |
| $6,847 |
| (b) |
| $6,038 |
| (a) |
| $— |
| |
| $12,885 |
| | 6,423 |
| (b) | — |
| | — |
| | 6,423 |
|
| Common | | 915,996 |
| (b) | — |
| | — |
| | 915,996 |
| | 745,715 |
| (b) | 39 |
| (b) | — |
| | 745,754 |
|
| Common collective trusts | | — |
| | 1,753,958 |
| (c) | — |
| | 1,753,958 |
| |
| Common collective trusts (c) | | |
|
| |
|
| |
|
| | 2,072,743 |
|
| 103-12 investment entities (h) | | |
| |
| |
| | 335,818 |
|
| Registered investment companies | | | 258,879 |
| (d) | — |
| | — |
| | 258,879 |
|
| Fixed income securities: | | | | | | | | | | | | | | | | |
| U.S. Government securities | | 180,718 |
| (b) | 152,915 |
| (a) | — |
| | 333,633 |
| | 136 |
| (b) | 370,545 |
| (a) | — |
| | 370,681 |
|
| Corporate debt instruments | | — |
| | 464,652 |
| (a) | — |
| | 464,652 |
| | — |
| | 630,726 |
| (a) | — |
| | 630,726 |
|
| Registered investment companies | | 316,863 |
| (d) | 486,748 |
| (e) | — |
| | 803,611 |
| |
| Registered investment companies (e) | | | 35,216 |
| (d) | 2,695 |
| (d) | — |
| | 640,836 |
|
| Other | | — |
| | 129,169 |
| (f) | — |
| | 129,169 |
| | 34 |
| (f) | 105,613 |
| (f) | — |
| | 105,647 |
|
| Other: | | | | | | | | | | | | | | | | |
| Insurance company general account (unallocated contracts) | | — |
| | 36,886 |
| (g) | — |
| | 36,886 |
| | — |
| | 37,111 |
| (g) | — |
| | 37,111 |
|
| Total investments | |
| $1,420,424 |
| |
| $3,030,366 |
| |
| $— |
| |
| $4,450,790 |
| |
| $1,046,403 |
| |
| $1,150,339 |
| |
| $— |
| |
| $5,208,228 |
|
| Cash | | | | | | | | 280 |
| | | | | | | | 929 |
|
| Other pending transactions | | | | | | | | 8,081 |
| | | | | | | | 8,869 |
|
Less: Other postretirement assets included in total investments | | | | | | | | (29,914 | ) | | | | | | | | (46,824 | ) |
Total fair value of qualified pension assets | | | | | | | |
| $4,429,237 |
| | | | | | | |
| $5,171,202 |
|
Other Postretirement Trusts
| | | 2014 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2017 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Thousands) | | (In Thousands) |
| Equity securities: | | | | | | | | | | | | | | | | |
Common collective trust | |
| $— |
| |
| $370,228 |
| (c) |
| $— |
| |
| $370,228 |
| | | | | | | |
| $300,139 |
|
| Fixed income securities: | | | | | | | | |
| | | | | | | | |
|
| U.S. Government securities | | 36,306 |
| (b) | 45,618 |
| (a) | — |
| | 81,924 |
| | 81,602 |
| (b) | 76,790 |
| (a) | — |
| | 158,392 |
|
| Corporate debt instruments | | — |
| | 57,830 |
| (a) | — |
| | 57,830 |
| | — |
| | 92,869 |
| (a) | — |
| | 92,869 |
|
| Registered investment companies | | 5,558 |
| (d) | — |
| | — |
| | 5,558 |
| | 3,127 |
| (d) | — |
| | — |
| | 3,127 |
|
| Other | | — |
| | 46,968 |
| (f) | — |
| | 46,968 |
| | — |
| | 45,627 |
| (f) | — |
| | 45,627 |
|
| Total investments | |
| $41,864 |
| |
| $520,644 |
| |
| $— |
| |
| $562,508 |
| |
| $84,729 |
| |
| $215,286 |
| |
| $— |
| |
| $600,154 |
|
| Other pending transactions | | | | | | | | 165 |
| | | | | | | | 994 |
|
Plus: Other postretirement assets included in the investments of the qualified pension trust | | | | | | | | 34,954 |
| | | | | | | | 58,179 |
|
Total fair value of other postretirement assets | | | | | | | |
| $597,627 |
| | | | | | | |
| $659,327 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2016 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Thousands) | | (In Thousands) |
| Equity securities: | | | | | | | | | | | | | | | | |
Common collective trust | |
| $— |
| |
| $356,700 |
| (c) |
| $— |
| |
| $356,700 |
| | | | | | | |
| $368,704 |
|
| Fixed income securities: | | | | | | | | |
| | | | | | | | |
|
| U.S. Government securities | | 40,808 |
| (b) | 43,471 |
| (a) | — |
| | 84,279 |
| | 30,632 |
| (b) | 43,097 |
| (a) | — |
| | 73,729 |
|
| Corporate debt instruments | | — |
| | 50,563 |
| (a) | — |
| | 50,563 |
| | — |
| | 58,787 |
| (a) | — |
| | 58,787 |
|
Registered investment companies | | 4,163 |
| (d) | — |
| | — |
| | 4,163 |
| | 3,123 |
| (d) | — |
| | — |
| | 3,123 |
|
| Other | | — |
| | 43,458 |
| (f) | — |
| | 43,458 |
| | — |
| | 45,389 |
| (f) | — |
| | 45,389 |
|
| Total investments | |
| $44,971 |
| |
| $494,192 |
| |
| $— |
| |
| $539,163 |
| |
| $33,755 |
| |
| $147,273 |
| |
| $— |
| |
| $549,732 |
|
| Other pending transactions | | | | | | | | 773 |
| | | | | | | | 104 |
|
| Plus: Other postretirement assets included in the investments of the qualified pension trust | | | | | | | | 29,914 |
| | | | | | | | 46,824 |
|
Total fair value of other postretirement assets | | | | | | | |
| $569,850 |
| | | | | | | |
| $596,660 |
|
| |
| (a) | Certain preferred stocks and certain fixed income debt securities (corporate, government, and securitized) are stated at fair value as determined by broker quotes. |
| |
| (b) | Common stocks, certain preferred stocks, and certain fixed income debt securities (government) are stated at fair value determined by quoted market prices. |
| |
| (c) | The common collective trusts hold investments in accordance with stated objectives. The investment strategy of the trusts is to capture the growth potential of equity markets by replicating the performance of a specified index. Net asset value per share of the common collective trusts estimate fair value. Certain of these common collective trusts are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. |
| |
| (d) | The registeredRegistered investment company is acompanies are money market mutual fundfunds with a stable net asset value of one dollar per share. Registered investment companies may hold investments in domestic and international bond markets or domestic equities and estimate fair value using net asset value per share. |
| |
| (e) | TheCertain of these registered investment company holds investments in domesticcompanies are not publicly quoted, and international bond markets and estimates fair valueare valued by the fund administrators using net asset value per share.as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. |
| |
| (f) | The other remaining assets are U.S. municipal and foreign government bonds stated at fair value as determined by broker quotes. |
| |
| (g) | The unallocated insurance contract investments are recorded at contract value, which approximates fair value. The contract value represents contributions made under the contract, plus interest, less funds used to pay benefits and contract expenses, and less distributions to the master trust. |
| |
| (h) | 103-12 investment entities hold investments in accordance with stated objectives. The investment strategy of the investment entities is to capture the growth potential of international equity markets by replicating the performance of a specified index. Net asset value per share of the 103-12 investment entities estimate fair value.value using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. |
Accumulated Pension Benefit Obligation
The accumulated benefit obligation for Entergy’s qualified pension plans was $6.6 billion and $5.2 billion at December 31, 2014 and 2013, respectively.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries for their employees as of December 31, 2014 and 2013 was as follows:
|
| | | | | | | |
| | December 31, |
| | 2014 | | 2013 |
| | (In Thousands) |
| Entergy Arkansas |
| $1,379,108 |
| |
| $1,107,023 |
|
| Entergy Gulf States Louisiana |
| $649,932 |
| |
| $530,974 |
|
| Entergy Louisiana |
| $873,759 |
| |
| $697,945 |
|
| Entergy Mississippi |
| $399,300 |
| |
| $318,941 |
|
| Entergy New Orleans |
| $186,473 |
| |
| $150,239 |
|
| Entergy Texas |
| $391,296 |
| |
| $332,484 |
|
| System Energy |
| $305,556 |
| |
| $247,807 |
|
Estimated Future Benefit Payments
Based upon the assumptions used to measure Entergy’s qualified pension and other postretirement benefit obligations at December 31, 2014,2017, and including pension and other postretirement benefits attributable to estimated future employee service, Entergy expects that benefits to be paid and the Medicare Part D subsidies to be received over the next ten years for Entergy Corporation and its subsidiaries will be as follows:
|
| | | | | | | | | | | | | | | |
| | Estimated Future Benefits Payments | | |
| | Qualified Pension | | Non-Qualified Pension | | Other Postretirement (before Medicare Subsidy) | | Estimated Future Medicare Subsidy Receipts |
| | (In Thousands) |
| Year(s) | | | | | | | |
| 2015 |
| $262,792 |
| |
| $16,173 |
| |
| $78,601 |
| |
| $455 |
|
| 2016 |
| $277,307 |
| |
| $9,976 |
| |
| $80,601 |
| |
| $525 |
|
| 2017 |
| $292,841 |
| |
| $10,774 |
| |
| $83,425 |
| |
| $595 |
|
| 2018 |
| $310,200 |
| |
| $12,598 |
| |
| $88,049 |
| |
| $1,785 |
|
| 2019 |
| $328,533 |
| |
| $11,431 |
| |
| $92,253 |
| |
| $1,984 |
|
| 2020 - 2024 |
| $1,966,776 |
| |
| $70,791 |
| |
| $506,086 |
| |
| $13,539 |
|
|
| | | | | | | | | | | | | | | |
| | Estimated Future Benefits Payments | | |
| | Qualified Pension | | Non-Qualified Pension | | Other Postretirement (before Medicare Subsidy) | | Estimated Future Medicare Subsidy Receipts |
| | (In Thousands) |
| Year(s) | | | | | | | |
| 2018 |
| $412,057 |
| |
| $26,375 |
| |
| $82,087 |
| |
| $745 |
|
| 2019 |
| $435,880 |
| |
| $10,108 |
| |
| $86,685 |
| |
| $842 |
|
| 2020 |
| $447,224 |
| |
| $13,364 |
| |
| $89,508 |
| |
| $956 |
|
| 2021 |
| $462,624 |
| |
| $10,765 |
| |
| $92,087 |
| |
| $1,071 |
|
| 2022 |
| $470,846 |
| |
| $17,425 |
| |
| $94,427 |
| |
| $1,195 |
|
| 2023 - 2027 |
| $2,478,959 |
| |
| $72,181 |
| |
| $475,991 |
| |
| $8,109 |
|
Based upon the same assumptions, Entergy expects that benefits to be paid and the Medicare Part D subsidies to be received over the next ten years for the Registrant Subsidiaries for their employees will be as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Estimated Future Qualified Pension Benefits Payments | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | | | | | |
| 2015 | |
| $66,156 |
| |
| $25,450 |
| |
| $37,892 |
| |
| $18,702 |
| |
| $7,397 |
| |
| $19,078 |
| |
| $11,432 |
|
| 2016 | |
| $67,639 |
| |
| $26,805 |
| |
| $39,070 |
| |
| $19,625 |
| |
| $7,836 |
| |
| $19,697 |
| |
| $11,949 |
|
| 2017 | |
| $69,207 |
| |
| $28,340 |
| |
| $40,675 |
| |
| $20,517 |
| |
| $8,304 |
| |
| $20,558 |
| |
| $12,357 |
|
| 2018 | |
| $71,306 |
| |
| $30,279 |
| |
| $42,336 |
| |
| $21,444 |
| |
| $8,895 |
| |
| $21,448 |
| |
| $12,977 |
|
| 2019 | |
| $73,795 |
| |
| $32,445 |
| |
| $44,058 |
| |
| $22,306 |
| |
| $9,368 |
| |
| $22,291 |
| |
| $13,724 |
|
| 2020 - 2024 | |
| $418,009 |
| |
| $196,323 |
| |
| $256,639 |
| |
| $125,761 |
| |
| $56,659 |
| |
| $125,001 |
| |
| $87,663 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Estimated Future Qualified Pension Benefits Payments | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | | | |
| 2018 | |
| $87,295 |
| |
| $93,155 |
| |
| $25,833 |
| |
| $11,484 |
| |
| $25,333 |
| |
| $17,780 |
|
| 2019 | |
| $87,832 |
| |
| $96,060 |
| |
| $25,977 |
| |
| $12,202 |
| |
| $25,656 |
| |
| $18,566 |
|
| 2020 | |
| $88,905 |
| |
| $100,179 |
| |
| $27,198 |
| |
| $12,463 |
| |
| $26,399 |
| |
| $19,398 |
|
| 2021 | |
| $90,278 |
| |
| $103,810 |
| |
| $27,508 |
| |
| $13,087 |
| |
| $26,756 |
| |
| $20,279 |
|
| 2022 | |
| $92,061 |
| |
| $107,609 |
| |
| $27,389 |
| |
| $13,207 |
| |
| $26,310 |
| |
| $21,714 |
|
| 2023 - 2027 | |
| $479,160 |
| |
| $571,926 |
| |
| $141,912 |
| |
| $69,595 |
| |
| $130,905 |
| |
| $117,835 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| Estimated Future Non-Qualified Pension Benefits Payments | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | |
| 2018 | |
| $376 |
| |
| $231 |
| |
| $135 |
| |
| $21 |
| |
| $788 |
|
| 2019 | |
| $300 |
| |
| $219 |
| |
| $137 |
| |
| $55 |
| |
| $764 |
|
| 2020 | |
| $355 |
| |
| $208 |
| |
| $290 |
| |
| $36 |
| |
| $895 |
|
| 2021 | |
| $310 |
| |
| $196 |
| |
| $192 |
| |
| $39 |
| |
| $723 |
|
| 2022 | |
| $506 |
| |
| $186 |
| |
| $201 |
| |
| $41 |
| |
| $662 |
|
| 2023 - 2027 | |
| $2,196 |
| |
| $749 |
| |
| $1,462 |
| |
| $459 |
| |
| $3,762 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Estimated Future Non-Qualified Pension Benefits Payments | |
Entergy Arkansas | | Entergy Gulf States Louisiana | |
Entergy Louisiana | |
Entergy Mississippi | |
Entergy New Orleans | |
Entergy Texas |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | | | |
| 2015 | |
| $347 |
| |
| $241 |
| |
| $18 |
| |
| $119 |
| |
| $23 |
| |
| $753 |
|
| 2016 | |
| $300 |
| |
| $228 |
| |
| $17 |
| |
| $115 |
| |
| $23 |
| |
| $837 |
|
| 2017 | |
| $291 |
| |
| $241 |
| |
| $16 |
| |
| $124 |
| |
| $23 |
| |
| $784 |
|
| 2018 | |
| $282 |
| |
| $205 |
| |
| $15 |
| |
| $114 |
| |
| $23 |
| |
| $749 |
|
| 2019 | |
| $339 |
| |
| $199 |
| |
| $17 |
| |
| $112 |
| |
| $46 |
| |
| $720 |
|
| 2020 - 2024 | |
| $2,684 |
| |
| $924 |
| |
| $90 |
| |
| $825 |
| |
| $199 |
| |
| $3,442 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Estimated Future Other Postretirement Benefits Payments (before Medicare Part D Subsidy) | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | | | |
| 2018 | |
| $15,282 |
| |
| $18,962 |
| |
| $4,677 |
| |
| $3,954 |
| |
| $6,485 |
| |
| $3,246 |
|
| 2019 | |
| $15,398 |
| |
| $19,767 |
| |
| $4,818 |
| |
| $4,000 |
| |
| $6,842 |
| |
| $3,363 |
|
| 2020 | |
| $15,349 |
| |
| $20,287 |
| |
| $5,043 |
| |
| $3,952 |
| |
| $7,101 |
| |
| $3,381 |
|
| 2021 | |
| $15,483 |
| |
| $20,756 |
| |
| $5,218 |
| |
| $3,899 |
| |
| $7,369 |
| |
| $3,537 |
|
| 2022 | |
| $15,419 |
| |
| $21,250 |
| |
| $5,331 |
| |
| $3,800 |
| |
| $7,519 |
| |
| $3,595 |
|
| 2023 - 2027 | |
| $75,293 |
| |
| $108,290 |
| |
| $26,723 |
| |
| $17,698 |
| |
| $36,897 |
| |
| $17,677 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Estimated Future Other Postretirement Benefits Payments (before Medicare Part D Subsidy) | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | | | | | |
| 2015 | |
| $15,699 |
| |
| $8,921 |
| |
| $9,885 |
| |
| $3,926 |
| |
| $4,261 |
| |
| $6,617 |
| |
| $2,796 |
|
| 2016 | |
| $15,745 |
| |
| $9,219 |
| |
| $10,016 |
| |
| $4,001 |
| |
| $4,253 |
| |
| $6,785 |
| |
| $2,802 |
|
| 2017 | |
| $15,830 |
| |
| $9,580 |
| |
| $10,148 |
| |
| $4,125 |
| |
| $4,280 |
| |
| $7,012 |
| |
| $2,883 |
|
| 2018 | |
| $16,305 |
| |
| $10,110 |
| |
| $10,654 |
| |
| $4,433 |
| |
| $4,373 |
| |
| $7,438 |
| |
| $2,984 |
|
| 2019 | |
| $16,528 |
| |
| $10,706 |
| |
| $11,048 |
| |
| $4,599 |
| |
| $4,412 |
| |
| $7,771 |
| |
| $3,138 |
|
| 2020 - 2024 | |
| $86,854 |
| |
| $59,199 |
| |
| $60,735 |
| |
| $25,341 |
| |
| $21,584 |
| |
| $41,303 |
| |
| $17,664 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Estimated Future Medicare Part D Subsidy | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | | | | | |
| 2015 | |
| $77 |
| |
| $37 |
| |
| $45 |
| |
| $29 |
| |
| $23 |
| |
| $34 |
| |
| $9 |
|
| 2016 | |
| $87 |
| |
| $41 |
| |
| $50 |
| |
| $32 |
| |
| $24 |
| |
| $37 |
| |
| $11 |
|
| 2017 | |
| $96 |
| |
| $46 |
| |
| $56 |
| |
| $34 |
| |
| $25 |
| |
| $40 |
| |
| $1 |
|
| 2018 | |
| $358 |
| |
| $168 |
| |
| $204 |
| |
| $125 |
| |
| $87 |
| |
| $142 |
| |
| $52 |
|
| 2019 | |
| $398 |
| |
| $184 |
| |
| $223 |
| |
| $136 |
| |
| $90 |
| |
| $151 |
| |
| $59 |
|
| 2020 - 2024 | |
| $2,593 |
| |
| $1,243 |
| |
| $1,434 |
| |
| $839 |
| |
| $506 |
| |
| $922 |
| |
| $456 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Estimated Future Medicare Part D Subsidy | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | | | |
| 2018 | |
| $164 |
| |
| $168 |
| |
| $58 |
| |
| $38 |
| |
| $64 |
| |
| $23 |
|
| 2019 | |
| $185 |
| |
| $187 |
| |
| $65 |
| |
| $39 |
| |
| $69 |
| |
| $27 |
|
| 2020 | |
| $209 |
| |
| $210 |
| |
| $70 |
| |
| $41 |
| |
| $75 |
| |
| $33 |
|
| 2021 | |
| $230 |
| |
| $234 |
| |
| $76 |
| |
| $43 |
| |
| $81 |
| |
| $38 |
|
| 2022 | |
| $254 |
| |
| $257 |
| |
| $82 |
| |
| $46 |
| |
| $88 |
| |
| $46 |
|
| 2023 - 2027 | |
| $1,646 |
| |
| $1,720 |
| |
| $514 |
| |
| $259 |
| |
| $552 |
| |
| $346 |
|
Contributions
Entergy currently expects to contribute approximately $396$352.1 million to its qualified pension plans and approximately $66.9$52.3 million to other postretirement plans in 2015.2018. The expected 20152018 pension and other postretirement plan contributions of the Registrant Subsidiaries for their employees are shown below. The 2018 required pension contributions will not be known with more certainty untilwhen the January 1, 20152018 valuations are completed, which is expected by April 1, 2015.2018.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The Registrant Subsidiaries expect to contribute approximately the following to the qualified pension and other postretirement plans for their employees in 2015:2018:
| | | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) | (In Thousands) |
| Pension Contributions |
| $92,523 |
| |
| $32,455 |
| |
| $56,960 |
| |
| $22,472 |
| |
| $10,910 |
| |
| $17,166 |
| |
| $20,778 |
|
| $64,062 |
| |
| $71,917 |
| |
| $14,933 |
| |
| $7,250 |
| |
| $10,883 |
| |
| $13,786 |
|
| Other Postretirement Contributions |
| $16,904 |
| |
| $8,921 |
| |
| $9,885 |
| |
| $535 |
| |
| $3,669 |
| |
| $3,231 |
| |
| $475 |
|
| $472 |
| |
| $18,962 |
| |
| $110 |
| |
| $3,669 |
| |
| $3,231 |
| |
| $16 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Actuarial Assumptions
The significant actuarial assumptions used in determining the pension PBO and the other postretirement benefit APBO as of December 31, 2014,2017 and 20132016 were as follows:
| | | | 2014 | | 2013 | 2017 | | 2016 |
| Weighted-average discount rate: | | | | | | |
| Qualified pension | 4.03% - 4.40% Blended 4.27% | | 5.04% - 5.26% Blended 5.14% | 3.70% - 3.82% Blended 3.78% | | 4.30% - 4.49% Blended 4.39% |
| Other postretirement | 4.23% | | 5.05% | 3.72% | | 4.30% |
| Non-qualified pension | 3.61% | | 4.29% | 3.34% | | 3.63% |
| Weighted-average rate of increase in future compensation levels | 4.23% | | 4.23% | 3.98% | | 3.98% |
| Assumed health care trend rate: | | |
| Pre-65 | 7.10% | | 7.25% | 6.95% | | 6.55% |
| Post-65 | 7.70% | | 7.00% | 7.25% | | 7.25% |
| Ultimate rate | 4.75% | | 4.75% | 4.75% | | 4.75% |
| Year ultimate rate is reached and beyond: |
| |
|
| |
| Pre-65 | 2023 | | 2022 | 2027 | | 2026 |
| Post-65 | 2023 | | 2022 | 2027 | | 2026 |
The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2017, 2016, and 2015 were as follows:
|
| | | | | |
| | 2017 | | 2016 | | 2015 |
| Weighted-average discount rate: | | | | | |
| Qualified pension: | | | | | |
| Service cost | 4.75% | | 5.00% | | 4.27% |
| Interest cost | 3.73% | | 3.90% | | 4.27% |
| Other postretirement: | | | | | |
| Service cost | 4.60% | | 4.92% | | 4.23% |
| Interest cost | 3.61% | | 3.78% | | 4.23% |
| Non-qualified pension: | | | | | |
| Service cost | 3.65% | | 3.65% | | 3.61% |
| Interest cost | 3.10% | | 3.10% | | 3.61% |
| Weighted-average rate of increase in future compensation levels | 3.98% | | 4.23% | | 4.23% |
| Expected long-term rate of return on plan assets: | | | | | |
| Pension assets | 7.50% | | 7.75% | | 8.25% |
| Other postretirement non-taxable assets | 6.50% - 7.50% | | 7.75% | | 8.05% |
| Other postretirement taxable assets | 5.75% | | 6.00% | | 6.25% |
| Assumed health care trend rate: | | | | | |
| Pre-65 | 6.55% | | 6.75% | | 7.10% |
| Post-65 | 7.25% | | 7.55% | | 7.70% |
| Ultimate rate | 4.75% | | 4.75% | | 4.75% |
| Year ultimate rate is reached and beyond: |
| |
| |
|
| Pre-65 | 2026 | | 2024 | | 2023 |
| Post-65 | 2026 | | 2024 | | 2023 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The significant actuarial assumptions used in determiningIn 2016, Entergy refined its approach to estimating the net periodicservice cost and interest cost components of qualified pension, and other postretirement, and non-qualified pension costs. Under the refined approach, instead of using the weighted-average obligation discount rates at the beginning of the year, 2016 service cost and interest costs’ expected cash flows were discounted by the applicable spot rates. The refinement in approach was a change in accounting estimate and, accordingly, the effect was reflected prospectively. The measurement of the benefit costs for 2014, 2013, and 2012 were as follows:obligation was not affected.
|
| | | | | |
| | 2014 | | 2013 | | 2012 |
| Weighted-average discount rate: | | | | | |
| Qualified pension | 5.04%-5.26% Blended 5.14% | | 4.31% - 4.5% Blended 4.36% | | 5.10% - 5.20% Blended 5.11% |
| Other postretirement | 5.05% | | 4.36% | | 5.10% |
| Non-qualified pension | 4.29% | | 3.37% | | 4.40% |
Weighted-average rate of increase in future compensation levels | 4.23% | | 4.23% | | 4.23% |
Expected long-term rate of return on plan assets: | | | | | |
| Pension assets | 8.50% | | 8.50% | | 8.50% |
| Other postretirement tax deferred assets | 8.30% | | 8.50% | | 8.50% |
| Other postretirement taxable assets | 6.50% | | 6.50% | | 6.50% |
| Assumed health care trend rate: | | | | | |
| Pre-65 | 7.25% | | 7.50% | | 7.75% |
| Post-65 | 7.00% | | 7.25% | | 7.50% |
| Ultimate rate | 4.75% | | 4.75% | | 4.75% |
| Year ultimate rate is reached and beyond: |
| |
| |
|
| Pre-65 | 2022 | | 2022 | | 2022 |
| Post-65 | 2022 | | 2022 | | 2022 |
Entergy’s other postretirement benefit transition obligations were amortized over 20 years ending in 2012.
With respect to the mortality assumptions, Entergy used the RP-2014 Employee and HealthHealthy Annuitant Tables (adjusted to base year 2006) with a fully generational MP-2014MP-2017 projection scale, in determining its December 31, 20142017 pension plans’ PBOs and other postretirement benefit APBO. The mortality assumptionsEntergy used the RP-2014 Employee and Healthy Annuitant Tables (adjusted to base year 2006) with a fully generational MP-2016 projection scale, in determining Entergy’sits December 31, 20132016 pension plans’ PBOs were the 1994 Group Annuity Mortality Table and RP 2000 Combined Health Mortality, with generational (using Scale AA) projected mortality improvement. The mortality assumption used in determining the December 31, 2013 other postretirement APBO was the 1994 Group Annuity Mortality Table, with generational (using Scale AA) projected mortality improvement.benefit APBO.
Entergy’s health care cost trend is affected by both medical cost inflation, and with respect to capped costs, the effects of general inflation. A one percentage point change in Entergy’s assumed health care cost trend rate for 2017 would have the following effects:
|
| | | | | | | | | | | | | | | | |
| | | 1 Percentage Point Increase | | 1 Percentage Point Decrease |
| 2017 | | Impact on the APBO | | Impact on the sum of service costs and interest cost | | Impact on the APBO | | Impact on the sum of service costs and interest cost |
| | | Increase /(Decrease) (In Thousands) |
| Entergy Corporation and its subsidiaries | |
| $166,814 |
| |
| $10,221 |
| |
| ($139,648 | ) | |
| ($8,385 | ) |
The Registrant Subsidiaries’ health care cost trend is affected by both medical cost inflation, and with respect to capped costs, the effects of general inflation. A one percentage point change in the assumed health care cost trend rate for 2014 would have the following effects:
|
| | | | | | | | | | | | | | | | |
| | | 1 Percentage Point Increase | | 1 Percentage Point Decrease |
| 2014 | | Impact on the APBO | | Impact on the sum of service costs and interest cost | | Impact on the APBO | | Impact on the sum of service costs and interest cost |
| | | Increase /(Decrease) (In Thousands) |
Entergy Corporation and its subsidiaries | |
| $234,971 |
| |
| $16,769 |
| |
| ($190,996 | ) | |
| ($13,566 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
A one percentage point change in the assumed health care cost trend rate for 20142017 would have the following effects for the Registrant Subsidiaries for their employees:
| | | | | 1 Percentage Point Increase | | 1 Percentage Point Decrease | | 1 Percentage Point Increase | | 1 Percentage Point Decrease |
| 2014 | | Impact on the APBO | | Impact on the sum of service costs and interest cost | | Impact on the APBO | | Impact on the sum of service costs and interest cost | |
| 2017 | | | Impact on the APBO | | Impact on the sum of service costs and interest cost | | Impact on the APBO | | Impact on the sum of service costs and interest cost |
| | | Increase/(Decrease) (In Thousands) | | Increase/(Decrease) (In Thousands) |
| Entergy Arkansas | |
| $39,286 |
| |
| $2,448 |
| |
| ($31,753 | ) | |
| ($1,971 | ) | |
| $23,612 |
| |
| $1,369 |
| |
| ($19,810 | ) | |
| ($1,133 | ) |
| Entergy Gulf States Louisiana | |
| $27,929 |
| |
| $2,092 |
| |
| ($22,591 | ) | |
| ($1,671 | ) | |
| Entergy Louisiana | |
| $23,779 |
| |
| $1,681 |
| |
| ($19,452 | ) | |
| ($1,366 | ) | |
| $37,240 |
| |
| $2,333 |
| |
| ($31,063 | ) | |
| ($1,909 | ) |
| Entergy Mississippi | |
| $10,596 |
| |
| $754 |
| |
| ($8,596 | ) | |
| ($606 | ) | |
| $8,666 |
| |
| $448 |
| |
| ($7,276 | ) | |
| ($370 | ) |
| Entergy New Orleans | |
| $6,373 |
| |
| $386 |
| |
| ($5,317 | ) | |
| ($321 | ) | |
| $4,585 |
| |
| $251 |
| |
| ($3,895 | ) | |
| ($208 | ) |
| Entergy Texas | |
| $16,246 |
| |
| $1,148 |
| |
| ($13,397 | ) | |
| ($927 | ) | |
| $12,444 |
| |
| $751 |
| |
| ($10,452 | ) | |
| ($618 | ) |
| System Energy | |
| $8,716 |
| |
| $734 |
| |
| ($7,044 | ) | |
| ($586 | ) | |
| $7,334 |
| |
| $475 |
| |
| ($6,074 | ) | |
| ($387 | ) |
Defined Contribution Plans
Entergy sponsors the Savings Plan of Entergy Corporation and Subsidiaries (System Savings Plan). The System Savings Plan is a defined contribution plan covering eligible employees of Entergy and certain of its subsidiaries. The participating employing Entergy subsidiary makes matching contributions to the System Savings Plan for all eligible participating employees in an amount equal to either 70% or 100% of the participants’ basic contributions, up to 6% of their eligible earnings per pay period. The matching contribution is allocated to investments as directed by the employee.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy also sponsors the Savings Plan of Entergy Corporation and Subsidiaries IV (established in March 2002), the Savings Plan of Entergy Corporation and Subsidiaries VI (established in April 2007), and the Savings Plan of Entergy Corporation and Subsidiaries VII (established in April 2007) to which matching contributions are also made. The plans are defined contribution plans that cover eligible employees, as defined by each plan, of Entergy and certain of its subsidiaries.
Entergy’s subsidiaries’ contributions to defined contribution plans collectively were $43.3$49.1 million in 2014, $44.52017, $47 million in 2013,2016, and $43.7$44.4 million in 2012.2015. The majority of the contributions were to the System Savings Plan.
The Registrant Subsidiaries’ 2014, 2013,2017, 2016, and 20122015 contributions to defined contribution plans for their employees were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Year | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| 2014 | |
| $3,044 |
| |
| $1,867 |
| |
| $2,266 |
| |
| $1,855 |
| |
| $710 |
| |
| $1,563 |
|
| 2013 | |
| $3,351 |
| |
| $1,906 |
| |
| $2,393 |
| |
| $1,954 |
| |
| $769 |
| |
| $1,616 |
|
| 2012 | |
| $3,223 |
| |
| $1,842 |
| |
| $2,327 |
| |
| $1,875 |
| |
| $740 |
| |
| $1,601 |
|
|
| | | | | | | | | | | | | | | | | | | | |
Year | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| 2017 | |
| $3,741 |
| |
| $5,079 |
| |
| $2,133 |
| |
| $731 |
| |
| $1,865 |
|
| 2016 | |
| $3,528 |
| |
| $4,746 |
| |
| $1,997 |
| |
| $708 |
| |
| $1,778 |
|
| 2015 | |
| $3,242 |
| |
| $4,324 |
| |
| $1,920 |
| |
| $721 |
| |
| $1,620 |
|
NOTE 12. STOCK-BASED COMPENSATION (Entergy Corporation)
Entergy grants stock options, restricted stock, performance units, and restricted stock unit awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans which are shareholder-approved stock-based compensation
Entergy Corporation and Subsidiaries
Notes to Financial Statements
plans. The Equity Ownership Plan, as restated in February 2003 (2003 Plan), had 885,200 authorized shares remaining for long-term incentive and restricted unit awards as of December 31, 2014. Effective January 1, 2007,May 8, 2015, Entergy’s shareholders approved the 20072015 Equity Ownership and Long-Term Cash Incentive Plan (2007 Plan). The maximum aggregate number of common shares that can be issued from the 2007 Plan for stock-based awards is 7,000,000 with no more than 2,000,000 available for non-option grants. The 2007 Plan, which only applies to awards made on or after January 1, 2007, will expire after 10 years. As of December 31, 2014, there were 1,104,547 authorized shares remaining for stock-based awards, all of which are available for non-option grants. Effective May 6, 2011, Entergy’s shareholders approved the 2011 Equity Ownership and Long-Term Cash Incentive Plan (2011(2015 Plan). The maximum number of common shares that can be issued from the 20112015 Plan for stock-based awards is 5,500,0006,900,000 with no more than 2,000,0001,500,000 available for incentive stock option grants. The 20112015 Plan which only applies to awards madegranted on or after May 6, 2011,8, 2015 and awards will expire after 10 years.ten years from the date of grant. As of December 31, 2014,2017, there were 1,579,5633,498,788 authorized shares remaining for stock-based awards, including 2,000,0001,500,000 for incentive stock option grants.
Stock Options
Stock options are granted at exercise prices that equal the closing market price of Entergy Corporation common stock on the date of grant. Generally, stock options granted will become exercisable in equal amounts on each of the first three anniversaries of the date of grant. Unless they are forfeited previously under the terms of the grant, options expire ten10 years after the date of the grant if they are not exercised.
The following table includes financial information for stock options for each of the years presented:
|
| | | | | |
| | 2014 | | 2013 | | 2012 |
| | (In Millions) |
| Compensation expense included in Entergy’s Consolidated Net Income | $4.1 | | $4.1 | | $7.7 |
| Tax benefit recognized in Entergy’s Consolidated Net Income | $1.6 | | $1.6 | | $3.0 |
| Compensation cost capitalized as part of fixed assets and inventory | $0.7 | | $0.7 | | $1.5 |
|
| | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In Millions) |
| Compensation expense included in Entergy’s consolidated net income | $4.4 | | $4.4 | | $4.3 |
| Tax benefit recognized in Entergy’s consolidated net income | $1.7 | | $1.7 | | $1.6 |
| Compensation cost capitalized as part of fixed assets and inventory | $0.7 | | $0.7 | | $0.7 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy determines the fair value of the stock option grants by considering factors such as lack of marketability, stock retention requirements, and regulatory restrictions on exercisability in accordance with accounting standards. The stock option weighted-average assumptions used in determining the fair values are as follows:
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| Stock price volatility | 24.67% | | 24.61% | | 25.11% | 18.39% | | 20.38% | | 23.62% |
| Expected term in years | 6.95 | | 6.69 | | 6.55 | 7.35 | | 7.25 | | 7.06 |
| Risk-free interest rate | 2.16% | | 1.31% | | 1.22% | 2.31% | | 1.77% | | 1.59% |
| Dividend yield | 4.75% | | 4.75% | | 4.50% | 4.75% | | 4.50% | | 4.50% |
| Dividend payment per share | $3.32 | | $3.32 | | $3.32 | $3.50 | | $3.42 | | $3.34 |
Stock price volatility is calculated based upon the daily public stock price volatility of Entergy Corporation common stock over a period equal to the expected term of the award. The expected term of the options is based upon historical option exercises and the weighted average life of options when exercised and the estimated weighted average life of all vested but unexercised options. In 2008, Entergy implemented stock ownership guidelines for its senior executive officers. These guidelines require an executive officer to own shares of Entergy Corporation common stock equal to a specified multiple of his or her salary. Until an executive officer achieves this ownership position the executive officer is required to retain 75% of the after-taxnet-of-tax net profit upon exercise of the option to be held in Entergy Corporation common stock. The reduction in fair value of the stock options due to this restriction is based upon an estimate of the call option value of the reinvested gain discounted to present value over the applicable reinvestment period.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
A summary of stock option activity for the year ended December 31, 20142017 and changes during the year are presented below:
|
| | | | | | | | |
| | Number of Options | | Weighted- Average Exercise Price | | Aggregate Intrinsic Value | | Weighted- Average Contractual Life |
| Options outstanding as of January 1, 2014 | 9,639,849 |
| | $80.06 | | | | |
| Options granted | 611,700 |
| | $63.17 | | | | |
| Options exercised | (2,852,350 | ) | | $68.19 | | | | |
| Options forfeited/expired | (117,803 | ) | | $82.48 | | | | |
| Options outstanding as of December 31, 2014 | 7,281,396 |
| | $83.25 | | $30,830,809 | | 4.3 years |
| Options exercisable as of December 31, 2014 | 6,232,998 |
| | $86.41 | | $6,657,504 | | 3.6 years |
Weighted-average grant-date fair value of options granted during 2014 | $8.71 | | | | | | |
|
| | | | | | | | |
| | Number of Options | | Weighted- Average Exercise Price | | Aggregate Intrinsic Value | | Weighted- Average Contractual Life |
| Options outstanding as of January 1, 2017 | 7,137,210 |
| | $84.91 | | | | |
| Options granted | 791,900 |
| | $70.53 | | | | |
| Options exercised | (1,109,306 | ) | | $72.74 | | | | |
| Options forfeited/expired | (1,654,950 | ) | | $91.36 | | | | |
| Options outstanding as of December 31, 2017 | 5,164,854 |
| | $83.26 | | $— | | 4.18 years |
| Options exercisable as of December 31, 2017 | 4,027,902 |
| | $86.37 | | $— | | 2.94 years |
| Weighted-average grant-date fair value of options granted during 2017 | $6.54 | | | | | | |
The weighted-average grant-date fair value of options granted during the year was $8.00$7.40 for 20132016 and $9.42$11.41 for 2012.2015. The total intrinsic value of stock options exercised was $25.5$11 million during 2014, $5.72017, $5 million during 2013,2016, and $39.8$5 million during 2012.2015. The intrinsic value, which has no effect on net income, of the outstanding stock options exercised is calculated by the positive difference in Entergy Corporation’s common stock price onbetween the date of exercise and theweighted average exercise price of the stock options granted. Thegranted and Entergy Corporation’s common stock price as of December 31, 2017. Because Entergy’s year-end common stock price was less than the weighted average exercise price, the aggregate intrinsic value of the stock options outstanding as of December 31, 20142017 was $30.8 million.zero. The intrinsic value of “in the money” stock options is $32 million as of December 31, 2017. Entergy recognizes compensation cost over the vesting period of the options based on their grant-date fair value. The total fair value of options that vested was approximately $6 million during 2017, $5 million during 2016, and $4 million during 2014, $112015. Cash received from option exercises was $81 million during 2013,for the year ended December 31, 2017. The tax benefits realized from options exercised was $4 million for the year ended December 31, 2017.
Entergy Corporation and $11 million during 2012.Subsidiaries
Notes to Financial Statements
The following table summarizes information about stock options outstanding as of December 31, 2014:2017:
| | | | | | Options Outstanding | | Options Exercisable | | | Options Outstanding | | Options Exercisable |
| Range of | Range of | | As of | | Weighted-Avg. Remaining Contractual Life-Yrs. | | Weighted Avg. Exercise Price | | Number Exercisable as of | | Weighted Avg. Exercise Price | Range of | | As of | | Weighted-Average Remaining Contractual Life-Yrs. | | Weighted Average Exercise Price | | Number Exercisable as of | | Weighted Average Exercise Price |
| Exercise Prices | Exercise Prices | | 12/31/2014 | | 12/31/2014 | | Exercise Prices | | 12/31/2017 | | 12/31/2017 | |
| $51 | - | $64.99 | | 1,138,602 |
| | 8.6 | | $63.84 | | 192,152 |
| | $64.60 | $51 | - | $64.99 | | 502,709 |
| | 5.73 | | $63.68 | | 502,709 |
| | $63.68 |
| $65 | - | $78.99 | | 3,095,377 |
| | 4.4 | | $74.31 | | 2,993,429 |
| | $74.41 | $65 | - | $78.99 | | 2,790,045 |
| | 5.56 | | $72.94 | | 1,751,402 |
| | $74.36 |
| $79 | - | $91.99 | | 1,604,717 |
| | 2.1 | | $91.82 | | 1,604,717 |
| | $91.82 | $79 | - | $91.99 | | 441,000 |
| | 7.08 | | $89.90 | | 342,691 |
| | $89.90 |
| $92 | - | $108.20 | | 1,442,700 |
| | 3.1 | | $108.20 | | 1,442,700 |
| | $108.20 | $92 | - | $108.20 | | 1,431,100 |
| | 0.06 | | $108.20 | | 1,431,100 |
| | $108.20 |
| $51 | - | $108.20 | | 7,281,396 |
| | 4.3 | | $83.25 | | 6,232,998 |
| | $86.41 | $51 | - | $108.20 | | 5,164,854 |
| | 4.18 | | $83.26 | | 4,027,902 |
| | $86.37 |
Stock-based compensation cost related to non-vested stock options outstanding as of December 31, 20142017 not yet recognized is approximately $5.4$6 million and is expected to be recognized over a weighted-average period of 1.71.70 years.
Restricted Stock Awards
In January 2014 the Board approved and Entergy granted 352,600grants restricted stock awards earned under its stock benefit plans in the 2011 Equity Ownership and Long-term Cash Incentive Plan. The restrictedform of stock awards were made effective as of January 30, 2014 and were valued at $63.17 per share, which was the closing price of Entergy Corporation’s common stock on that date.units. One-third of the restricted stock awards will vest upon each anniversary of the grant date and are expensed
Entergy Corporation and Subsidiaries
Notes to Financial Statements
ratably over the three year vesting period. Shares of restricted stock have the same dividend and voting rights as other common stock and are considered issued and outstanding shares of Entergy upon vesting. In January 2017 the Board approved and Entergy granted 379,850 restricted stock awards under the 2015 Equity Ownership and Long-term Cash Incentive Plan. The restricted stock awards were made effective as of January 26, 2017 and were valued at $70.53 per share, which was the closing price of Entergy Corporation’s common stock on that date.
The following table includes information about the restricted stock awards outstanding as of December 31, 2017:
|
| | | | |
| | Shares | | Weighted-Average Grant Date Fair Value Per Share |
| Outstanding shares at January 1, 2017 | 683,474 |
| | $74.80 |
| Granted | 410,787 |
| | $70.71 |
| Vested | (330,816 | ) | | $73.61 |
| Forfeited | (53,834 | ) | | $75.63 |
| Outstanding shares at December 31, 2017 | 709,611 |
| | $72.92 |
The following table includes financial information for restricted stock for each of the years presented:
|
| | | | | |
| | 2014 | | 2013 | | 2012 |
| | (In Millions) |
| Compensation expense included in Entergy’s Consolidated Net Income | $19.3 | | $16.4 | | $11.4 |
| Tax benefit recognized in Entergy’s Consolidated Net Income | $7.5 | | $6.3 | | $4.4 |
| Compensation cost capitalized as part of fixed assets and inventory | $3.1 | | $2.6 | | $2.0 |
|
| | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In Millions) |
| Compensation expense included in Entergy’s consolidated net income | $19.7 | | $19.8 | | $19.5 |
| Tax benefit recognized in Entergy’s consolidated net income | $7.6 | | $7.6 | | $7.5 |
| Compensation cost capitalized as part of fixed assets and inventory | $5.2 | | $4.5 | | $3.9 |
The total fair value of the restricted stock awards granted was $29 million for each of the years ended December 31, 2017, 2016, and 2015.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The total fair value of the restricted stock awards vested was $24 million, $23 million, and $29 million for the years ended December 31, 2017, 2016, and 2015, respectively.
Long-Term Performance Unit Program
Entergy grants long-term incentive awards earned under its stock benefit plans in the form of performance units, which are equal torepresents the cash value of sharesone share of Entergy Corporation common stock at the end of the three-year performance period, plus dividends accrued during the performance period. The Long-Term Performance Unit Program specifies a minimum, target, and maximum achievement level, the achievement of which iswill determine the last trading daynumber of performance units that may be earned. Entergy measures performance by assessing Entergy’s total shareholder return relative to the total shareholder return of the year. Performance units will pay out tocompanies in the extentPhiladelphia Utility Index. There is no payout for performance that falls within the lowest quartile of performance conditions are satisfied. In addition to the potential for equivalent share appreciation or depreciation, performance units will earn the cash equivalent of the dividends paid during the 3-yearpeer companies. For top quartile performance, period applicable to each plan. a maximum payout of 200% of target is earned.
The costs of incentive awards are charged to income over the 3-year period. Beginning with the 2012-2014 performance period, upon vesting, the performance units granted under the Long-Term Performance Unit Program will be settled in shares of Entergy common stock rather than cash. In January 20142017 the Board approved and Entergy granted 226,792220,450 performance units under the 20112015 Equity Ownership and Long-Term Cash Incentive Plan. The performance units were made effective as of January 30, 2014,26, 2017, and were valued at $67.16$71.40 per share. Entergy considers factors, primarily market conditions, in determining the value of the performance units. Shares of the performance units have the same dividend and voting rights as other common stock, are considered issued and outstanding shares of Entergy upon vesting, and are expensed ratably over the 3-year vesting period.
The following table includes information about the long-term performance units outstanding at the target level as of December 31, 2017:
|
| | | | |
| | Shares | | Weighted-Average Grant Date Fair Value Per Share |
| Outstanding shares at January 1, 2017 | 571,551 |
| | $82.02 |
| Granted | 258,808 |
| | $72.28 |
| Vested | (86,964 | ) | | $67.16 |
| Forfeited | (209,244 | ) | | $72.12 |
| Outstanding shares at December 31, 2017 | 534,151 |
| | $83.60 |
The following table includes financial information for the long-term performance units for each of the years presented:
|
| | | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| | (In Millions) |
| Fair value of long-term performance units as of December 31, | $23.4 | |
| $11.1 |
| |
| $4.3 |
|
| Compensation expense included in Entergy’s Consolidated Net Income | $10.7 | |
| $6.0 |
| |
| ($5.0 | ) |
| Tax benefit (expense) recognized in Entergy’s Consolidated Net Income | $4.1 | |
| $2.3 |
| |
| ($1.9 | ) |
| Compensation cost capitalized as part of fixed assets and inventory | $1.5 | |
| $0.9 |
| |
| ($0.9 | ) |
|
| | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In Millions) |
| Compensation expense included in Entergy’s consolidated net income | $10.8 | |
| $12.3 |
| |
| $11.8 |
|
| Tax benefit recognized in Entergy’s consolidated net income | $4.2 | |
| $4.8 |
| |
| $4.5 |
|
| Compensation cost capitalized as part of fixed assets and inventory | $3.0 | |
| $2.9 |
| |
| $2.3 |
|
There was no payout in 2014 forThe total fair value of the long-term performance units granted in 2011 applicablewas $19 million, $21 million, and $16 million for the years ended December 31, 2017, 2016, and 2015, respectively.
In January 2017, Entergy issued 86,964 shares of Entergy Corporation common stock at a share price of $71.89 for awards earned and dividends accrued under the 2014-2016 Long-Term Performance Unit Program. In January 2016, Entergy issued 54,103 shares of Entergy Corporation common stock at a share price of $68.09 for awards earned and dividends accrued under the 2013-2015 Long-Term Performance Unit Program. In January 2015, Entergy issued 105,503 shares of Entergy Corporation common stock at a share price of $88.67 for awards earned and dividends accrued under the 2012-2014 Long-Term Performance Unit Program.
Entergy Corporation and Subsidiaries
Notes to the 2011 – 2013 performance period.Financial Statements
Restricted Stock Unit Awards
Entergy grants restricted stock unit awards earned under its stock benefit plans in the form of stock units that are subject to time-based restrictions. The restricted stock units are equal tomay be settled in shares of Entergy Corporation common stock or the cash value of shares of Entergy Corporation common stock at the time of vesting. The costs of restricted stock unit awards are charged to income over the restricted period, which varies from grant to grant. The average vesting period for restricted stock unit awards granted is 3641 months. As of December 31, 2014,2017, there were 98,334201,570 unvested restricted stock units that are expected to vest over an average period of 2124 months.
The following table includes information about the restricted stock unit awards outstanding as of December 31, 2017:
Entergy Corporation and Subsidiaries
Notes to Financial Statements |
| | | | |
| | Shares | | Weighted-Average Grant Date Fair Value Per Share |
| Outstanding shares at January 1, 2017 | 181,650 |
| | $74.94 |
| Granted | 40,170 |
| | $79.10 |
| Vested | (5,800 | ) | | $73.22 |
| Forfeited | (14,450 | ) | | $79.69 |
| Outstanding shares at December 31, 2017 | 201,570 |
| | $75.48 |
The following table includes financial information for restricted stock unit awards for each of the years presented:
|
| | | | | |
| | 2014 | | 2013 | | 2012 |
| | (In Millions) |
| Fair value of restricted awards as of December 31, | $3.3 | | $2.5 | | $3.0 |
| Compensation expense included in Entergy’s Consolidated Net Income | $2.2 | | $1.4 | | $1.3 |
| Tax benefit recognized in Entergy’s Consolidated Net Income | $0.9 | | $0.6 | | $0.5 |
| Compensation cost capitalized as part of fixed assets and inventory | $0.3 | | $0.2 | | $0.2 |
|
| | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In Millions) |
| Compensation expense included in Entergy’s consolidated net income | $2.5 | | $2.2 | | $0.9 |
| Tax benefit recognized in Entergy’s consolidated net income | $1.0 | | $0.8 | | $0.4 |
| Compensation cost capitalized as part of fixed assets and inventory | $0.6 | | $0.4 | | $0.3 |
Entergy paid $1.7The total fair value of the restricted stock unit awards granted was $3 million, in 2014$5 million, and $4 million for the years ended December 31, 2017, 2016, and 2015, respectively.
The total fair value of the restricted stock unit awards undervested was $0.4 million, $2 million, and $1 million for the Restricted Units Awards Plan.years ended December 31, 2017, 2016, and 2015, respectively.
NOTE 13. BUSINESS SEGMENT INFORMATION (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy’s reportable segments as of December 31, 20142017 are Utility and Entergy Wholesale Commodities. Utility includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Louisiana, Mississippi, and Texas, and natural gas utility service in portions of Louisiana. Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities also includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. “All Other” includes the parent company, Entergy Corporation, and other business activity.
Entergy’s segment financial information is as follows:
|
| | | | | | | | | | | | | | | | | | | | |
| 2014 | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated |
| | | (In Thousands) |
| Operating revenues | |
| $9,773,822 |
| |
| $2,719,404 |
| |
| $1,821 |
| |
| ($126 | ) | |
| $12,494,921 |
|
| Depreciation, amortization, & decommissioning | |
| $1,170,122 |
| |
| $417,435 |
| |
| $3,702 |
| |
| $— |
| |
| $1,591,259 |
|
| Interest and investment income | |
| $171,217 |
| |
| $113,959 |
| |
| $22,159 |
| |
| ($159,649 | ) | |
| $147,686 |
|
| Interest expense | |
| $531,729 |
| |
| $16,646 |
| |
| $120,908 |
| |
| ($41,776 | ) | |
| $627,507 |
|
| Income taxes | |
| $472,148 |
| |
| $176,988 |
| |
| ($59,539 | ) | |
| $— |
| |
| $589,597 |
|
| Consolidated net income (loss) | |
| $846,496 |
| |
| $294,521 |
| |
| ($62,887 | ) | |
| ($117,873 | ) | |
| $960,257 |
|
| Total assets | |
| $38,295,309 |
| |
| $10,279,500 |
| |
| ($654,831 | ) | |
| ($1,392,124 | ) | |
| $46,527,854 |
|
| Investment in affiliates - at equity | |
| $199 |
| |
| $36,035 |
| |
| $— |
| |
| $— |
| |
| $36,234 |
|
Cash paid for long-lived asset additions | |
| $2,113,631 |
| |
| $615,021 |
| |
| $87 |
| |
| $— |
| |
| $2,728,739 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy’s segment financial information is as follows:
| | | 2013 | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated | |
| 2017 | | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated |
| | | (In Thousands) | | (In Thousands) |
| Operating revenues | |
| $9,101,786 |
| |
| $2,312,758 |
| |
| $3,558 |
| |
| ($27,155 | ) | |
| $11,390,947 |
| |
| $9,417,866 |
| |
| $1,656,730 |
| |
| $— |
| |
| ($115 | ) | |
| $11,074,481 |
|
| Asset write-offs, impairments, and related charges | | |
| $— |
| |
| $538,372 |
| |
| $— |
| |
| $— |
| |
| $538,372 |
|
| Depreciation, amortization, & decommissioning | |
| $1,157,843 |
| |
| $341,163 |
| |
| $4,142 |
| |
| $— |
| |
| $1,503,148 |
| |
| $1,345,906 |
| |
| $448,079 |
| |
| $1,678 |
| |
| $— |
| |
| $1,795,663 |
|
| Interest and investment income | |
| $186,724 |
| |
| $137,727 |
| |
| $24,179 |
| |
| ($149,330 | ) | |
| $199,300 |
| |
| $218,317 |
| |
| $224,121 |
| |
| $21,669 |
| |
| ($175,910 | ) | |
| $288,197 |
|
| Interest expense | |
| $509,173 |
| |
| $16,323 |
| |
| $122,291 |
| |
| ($43,750 | ) | |
| $604,037 |
| |
| $547,301 |
| |
| $23,714 |
| |
| $139,619 |
| |
| ($48,291 | ) | |
| $662,343 |
|
| Income taxes | |
| $365,917 |
| |
| ($77,471 | ) | |
| ($62,465 | ) | |
| $— |
| |
| $225,981 |
| |
| $794,616 |
| |
| ($146,480 | ) | |
| ($105,566 | ) | |
| $— |
| |
| $542,570 |
|
| Consolidated net income (loss) | |
| $846,215 |
| |
| $42,976 |
| |
| ($53,039 | ) | |
| ($105,580 | ) | |
| $730,572 |
| |
| $773,148 |
| |
| ($172,335 | ) | |
| ($47,840 | ) | |
| ($127,620 | ) | |
| $425,353 |
|
| Total assets | |
| $35,539,585 |
| |
| $9,696,705 |
| |
| ($486,438 | ) | |
| ($1,343,406 | ) | |
| $43,406,446 |
| |
| $42,978,669 |
| |
| $5,638,009 |
| |
| $1,011,612 |
| |
| ($2,921,141 | ) | |
| $46,707,149 |
|
| Investment in affiliates - at equity | |
| $199 |
| |
| $40,151 |
| |
| $— |
| |
| $— |
| |
| $40,350 |
| |
| $198 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $198 |
|
Cash paid for long-lived asset additions | |
| $2,268,083 |
| |
| $626,322 |
| |
| $49 |
| |
| $— |
| |
| $2,894,454 |
| |
| $3,680,513 |
| |
| $320,667 |
| |
| $438 |
| |
| $— |
| |
| $4,001,618 |
|
| | | 2012 | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated | |
| 2016 | | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated |
| | | (In Thousands) | | (In Thousands) |
| Operating revenues | |
| $8,005,091 |
| |
| $2,326,309 |
| |
| $4,048 |
| |
| ($33,369 | ) | |
| $10,302,079 |
| |
| $8,996,106 |
| |
| $1,849,638 |
| |
| $— |
| |
| ($99 | ) | |
| $10,845,645 |
|
| Asset write-offs, impairments, and related charges | | |
| $— |
| |
| $2,835,637 |
| |
| $— |
| |
| $— |
| |
| $2,835,637 |
|
| Depreciation, amortization, & decommissioning | |
| $1,076,845 |
| |
| $248,143 |
| |
| $4,357 |
| |
| $— |
| |
| $1,329,345 |
| |
| $1,298,043 |
| |
| $374,922 |
| |
| $1,647 |
| |
| $— |
| |
| $1,674,612 |
|
| Interest and investment income | |
| $150,292 |
| |
| $105,062 |
| |
| $30,656 |
| |
| ($158,234 | ) | |
| $127,776 |
| |
| $189,994 |
| |
| $108,466 |
| |
| $27,385 |
| |
| ($180,718 | ) | |
| $145,127 |
|
| Interest expense | |
| $476,485 |
| |
| $17,900 |
| |
| $126,913 |
| |
| ($52,014 | ) | |
| $569,284 |
| |
| $557,546 |
| |
| $22,858 |
| |
| $139,090 |
| |
| ($53,124 | ) | |
| $666,370 |
|
| Income taxes | |
| $49,340 |
| |
| $61,329 |
| |
| ($79,814 | ) | |
| $— |
| |
| $30,855 |
| |
| $424,388 |
| |
| ($1,192,263 | ) | |
| ($49,384 | ) | |
| $— |
| |
| ($817,259 | ) |
| Consolidated net income (loss) | |
| $960,322 |
| |
| $40,427 |
| |
| ($26,167 | ) | |
| ($106,219 | ) | |
| $868,363 |
| |
| $1,151,133 |
| |
| ($1,493,124 | ) | |
| ($94,917 | ) | |
| ($127,595 | ) | |
| ($564,503 | ) |
| Total assets | |
| $35,438,130 |
| |
| $9,623,345 |
| |
| ($509,985 | ) | |
| ($1,348,988 | ) | |
| $43,202,502 |
| |
| $41,098,751 |
| |
| $6,696,038 |
| |
| $1,283,816 |
| |
| ($3,174,171 | ) | |
| $45,904,434 |
|
| Investment in affiliates - at equity | |
| $199 |
| |
| $46,539 |
| |
| $— |
| |
| $— |
| |
| $46,738 |
| |
| $198 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $198 |
|
Cash paid for long-lived asset additions | |
| $3,182,695 |
| |
| $577,652 |
| |
| $619 |
| |
| $— |
| |
| $3,760,966 |
| |
| $3,754,225 |
| |
| $289,639 |
| |
| $393 |
| |
| $— |
| |
| $4,044,257 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | | | | | |
| 2015 | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated |
| | | (In Thousands) |
| Operating revenues | |
| $9,451,486 |
| |
| $2,061,827 |
| |
| $— |
| |
| ($62 | ) | |
| $11,513,251 |
|
| Asset write-offs, impairments, and related charges | |
| $68,672 |
| |
| $2,036,234 |
| |
| $— |
| |
| $— |
| |
| $2,104,906 |
|
| Depreciation, amortization, & decommissioning | |
| $1,238,832 |
| |
| $376,560 |
| |
| $2,156 |
| |
| $— |
| |
| $1,617,548 |
|
| Interest and investment income | |
| $191,546 |
| |
| $148,654 |
| |
| $34,303 |
| |
| ($187,441 | ) | |
| $187,062 |
|
| Interest expense | |
| $543,132 |
| |
| $26,788 |
| |
| $129,750 |
| |
| ($56,201 | ) | |
| $643,469 |
|
| Income taxes | |
| $16,761 |
| |
| ($610,339 | ) | |
| ($49,349 | ) | |
| $— |
| |
| ($642,927 | ) |
| Consolidated net income (loss) | |
| $1,114,516 |
| |
| ($1,065,657 | ) | |
| ($74,353 | ) | |
| ($131,240 | ) | |
| ($156,734 | ) |
| Total assets | |
| $38,356,906 |
| |
| $8,210,183 |
| |
| ($461,505 | ) | |
| ($1,457,903 | ) | |
| $44,647,681 |
|
| Investment in affiliates - at equity | |
| $199 |
| |
| $4,142 |
| |
| $— |
| |
| $— |
| |
| $4,341 |
|
| Cash paid for long-lived asset additions | |
| $2,495,194 |
| |
| $569,824 |
| |
| $236 |
| |
| $— |
| |
| $3,065,254 |
|
Businesses marked with * are sometimes referred to as the “competitive businesses.” Eliminations are primarily intersegment activity. Almost all of Entergy’s goodwill is related to the Utility segment.
Earnings were negatively affected by expensesOn December 29, 2014, the Vermont Yankee plant ceased power production and entered its decommissioning phase. In December 2015, Rhode Island State Energy Center, a natural gas-fired combined cycle generating plant, was sold. In October 2015 management announced the intention to shutdown the FitzPatrick plant in 20132017 and the Pilgrim plant in 2019, earlier than previously expected. In 2016 management announced the planned sale of approximately $110 million ($70 million after-tax), including approximately $85 million ($55 million after-tax) for UtilityVermont Yankee in 2018, the planned sale of FitzPatrick in 2017, and $25 million ($15 million after-tax) forthe planned amendment of the Consumers Energy PPA to terminate early, in May 2018, and the subsequent plan to shut down the Palisades plant in 2018, earlier than expected. In January 2017 management announced a settlement with New York State to shut down Indian Point 2 in 2020 and Indian Point 3 in 2021, both earlier than expected. In March 2017 the FitzPatrick plant was sold to Exelon. In September 2017 management announced the termination of the PPA amendment agreement with Consumers Energy and the revised plan to continue to operate Palisades under the current PPA and to shut down Palisades permanently on May 31, 2022.
Management expects these transactions to result in the cessation of merchant power generation at all Entergy Wholesale Commodities nuclear power plants owned and expenses in 2014 of approximately $20 million ($12 million after-tax), including approximately $15 million ($9 million after-tax) for Utilityoperated by Entergy by 2022. Entergy will continue to have the obligation to decommission the nuclear plants owned by Entergy.
These decisions and $5 million ($3 million after-tax) for Entergy Wholesale Commodities, recorded in connection with a strategic imperative intended to optimize the organization through a process known as human capital management. In July 2013 management completed a comprehensive review of Entergy’s organization design and processes. This efforttransactions resulted in a new internal organization structure, which resulted in the elimination of approximately 800asset impairments; employee positions. The restructuring costs associated with this phase of human capital management included implementation costs,retention and severance expenses and other benefits-related costs; and contracted economic development contributions. The employee retention and severance expenses and other benefits-related costs, including pension curtailment losses and special termination benefits, and impairments of corporate property, plant, and equipment. The implementation costs, severance costs, and benefits-related costscontracted economic development contributions are included in “Other"Other operation and maintenance”maintenance" in the consolidated income statements. The property, plant, and equipment impairments are included in “Asset write-offs, impairments, and related charges” in the consolidated income statements. Total restructuring charges were comprisedstatement of the following:operations.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total restructuring charges in 2017 were comprised of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2013 | | 2014 | | Remaining Accrual as of December 31, 2014 |
| | Restructuring Costs | | Paid In Cash | | Non-Cash Portion | | Restructuring Costs | | Paid In Cash | | Non-Cash Portion | |
| | (In Millions) |
| Implementation costs |
| $19 |
| |
| $19 |
| |
| $— |
| |
| $9 |
| |
| $9 |
| |
| $— |
| |
| $— |
|
| Severance costs | 45 |
| | 6 |
| | — |
| | 11 |
| | 44 |
| | — |
| | 6 |
|
| Benefits-related costs | 26 |
| | — |
| | 26 |
| | — |
| | — |
| | — |
| | — |
|
| Property, plant, and equipment impairments | 20 |
| | — |
| | 20 |
| | — |
| | — |
| | — |
| | — |
|
| Total |
| $110 |
| |
| $25 |
| |
| $46 |
| |
| $20 |
| |
| $53 |
| |
| $— |
| |
| $6 |
|
|
| | | | | | | | | | | | |
| | | Employee retention and severance expenses and other benefits-related costs
| | Contracted economic development costs | | Total |
| | | (In Millions) |
| Balance as of January 1, 2017 | |
| $70 |
| |
| $21 |
| |
| $91 |
|
| Restructuring costs accrued | | 113 |
| | — |
| | 113 |
|
| Non-cash portion | | — |
| | (7 | ) | | (7 | ) |
| Cash paid out | | 100 |
| | — |
| | 100 |
|
| Balance as of December 31, 2017 | |
| $83 |
| |
| $14 |
| |
| $97 |
|
Total restructuring charges in 2016 were comprised of the following:
|
| | | | | | | | | | | | |
| | | Employee retention and severance expenses and other benefits-related costs
| | Contracted economic development costs | | Total |
| | | (In Millions) |
| Balance as of January 1, 2016 | |
| $— |
| |
| $— |
| |
| $— |
|
| Restructuring costs accrued | | 74 |
| | 21 |
| | 95 |
|
| Non-cash portion | | (3 | ) | | — |
| | (3 | ) |
| Cash paid out | | 1 |
| | — |
| | 1 |
|
| Balance as of December 31, 2016 | |
| $70 |
| |
| $21 |
| |
| $91 |
|
In addition, Entergy Wholesale Commodities incurred $0.5 billion in 2017 and $2.8 billion in 2016 of impairment and other related charges associated with these strategic decisions and transactions. See Note 14 to the financial statements for further discussion of these impairment charges.
Going forward, Entergy Wholesale Commodities expects to incur employee retention and severance expenses of approximately $165 million in 2018 and approximately $205 million from 2019 through mid-2022 associated with these strategic transactions.
Geographic Areas
For the years ended December 31, 2014, 2013,2017, 2016, and 2012,2015, the amount of revenue Entergy derived from outside of the United States was insignificant. As of December 31, 20142017 and 2013,2016, Entergy had no long-lived assets located outside of the United States.
Registrant Subsidiaries
Each of the Registrant Subsidiaries has one reportable segment, which is an integrated utility business, except for System Energy, which is an electricity generation business. Each of the Registrant Subsidiaries’ operations is managed on an integrated basis by that company because of the substantial effect of cost-based rates and regulatory oversight on the business process, cost structures, and operating results.
NOTE 14. EQUITY METHOD INVESTMENTS (Entergy Corporation)
As of December 31, 2014, Entergy owns investments in the following companies that it accounts for under the equity method of accounting:
|
| | | | | | |
Investment | | Ownership | | Description |
| | | | | |
RS Cogen LLC | | 50 | % | member interest | | Co-generation project that produces power and steam on an industrial and merchant basis in the Lake Charles, Louisiana area. |
| | | | | |
Top Deer | | 50 | % | member interest | | Wind-powered electric generation joint venture. |
Following is a reconciliation of Entergy’s investments in equity affiliates:
|
| | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| | (In Thousands) |
| Beginning of year |
| $40,350 |
| |
| $46,738 |
| |
| $44,876 |
|
| Income (loss) from the investments | (5,169 | ) | | (1,702 | ) | | 1,162 |
|
| Dispositions and other adjustments | 1,053 |
| | (4,686 | ) | | 700 |
|
| End of year |
| $36,234 |
| |
| $40,350 |
| |
| $46,738 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Transactions with equity method investees
Entergy Gulf States Louisiana purchased approximately $3.2 million in 2013 and $2.8 million in 2012 of electricity generated from Entergy’s share of RS Cogen. Entergy Gulf States Louisiana made no purchases in 2014 of electricity generated from Entergy’s share of RS Cogen. Entergy’s operating transactions with its other equity method investees were not significant in 2014, 2013, or 2012.
NOTE 15.14. ACQUISITIONS, DISPOSITIONS, AND DISPOSITIONSIMPAIRMENT OF LONG-LIVED ASSETS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and Entergy Mississippi)New Orleans)
Acquisitions
Hot Spring Energy FacilityUnion Power Station
In November 2012,March 2016, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans purchased the Hot Spring Energy Facility,Union Power Station, a 6201,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas-fired, combined-cycle natural gas turbine unit locatedpower blocks, each rated at 495 MW (summer rating). Entergy Louisiana purchased two of the power blocks and a 50% undivided ownership interest in Malvern,certain assets related to the facility, and Entergy Arkansas from KGen Hot Spring LLCand Entergy New Orleans each purchased one power block and a 25% undivided ownership interest in such related assets. The aggregate purchase price for the Union Power Station was approximately $253 million. The FERC$949 million (approximately $237 million for each power block and the APSC approved the transaction.associated assets).
Hinds Energy Facility
In November 2012, Entergy Mississippi purchased the Hinds Energy Facility, a 450 MW combined-cycle natural gas turbine unit located in Jackson, Mississippi, from KGen Hinds LLC for approximately $206 million. The FERC and the MPSC approved the transaction.
Palisades Purchased Power Agreement
Entergy’s purchase of the Palisades plant in 2007 included a unit-contingent, 15-year purchased power agreement (PPA) with Consumers Energy for 100% of the plant’s output, excluding any future uprates. Prices under the PPA range from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA is $51/MWh. For the PPA, which was at below-market prices at the time of the acquisition, Entergy will amortize a liability to revenue over the life of the agreement. The amount that will be amortized each period is based upon the difference between the present value, calculated at the date of acquisition, of each year’s difference between revenue under the agreement and revenue based on estimated market prices. Amounts amortized to revenue were $16$28 million in 2014, $182017, $13 million in 2013,2016, and $17$15 million in 2012.2015.
In December 2016, Entergy reached an agreement with Consumers Energy to amend the existing PPA to terminate early, on May 31, 2018. Pursuant to the agreement to amend the PPA, Consumers Energy would pay Entergy $172 million for the early termination of the PPA. The PPA amendment agreement was subject to regulatory approvals, including approval by the Michigan Public Service Commission. Separately, Entergy intended to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. Entergy updated the liability amortization calculation to reflect the expected early termination of the PPA.
In September 2017 the Michigan Public Service Commission issued an order conditionally approving the PPA amendment transaction, but only granting Consumers Energy recovery of $136.6 million of the $172 million requested early termination payment. As a result, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy will continue to operate Palisades under the current PPA with Consumers Energy, instead of shutting down in the fall of 2018 as previously planned. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022. Based on that decision, the amounts to be amortized to revenue for the next five years will be $15approximately $6 million in 2015, $132018, $10 million for 2016,in 2019, $11 million in 2020, $12 million for 2017, $8in 2021, and $5 million for 2018, and $13 million for 2019.in 2022.
NYPA Value Sharing Agreements
Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, Entergy subsidiaries and NYPA amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements, Entergy subsidiaries made annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014. Entergy subsidiaries paid NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual
Entergy Corporation and Subsidiaries
Notes to Financial Statements
cap of $24 million. The annual payment for each year’s output was due by January 15 of the following year.year, and the final payment to NYPA was made in January 2015. Entergy recorded the liability for payments to NYPA as power iswas generated and sold by Indian Point 3 and FitzPatrick. An amount equal to the liability was recorded to the plant asset account as contingent purchase price consideration for the plants.
Dispositions
Vermont Yankee
In 2014, 2013,November 2016, Entergy entered into an agreement to sell 100% of the membership interests in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant and 2012,is in the Entergy Wholesale Commodities recorded approximately $72segment. The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of the nuclear decommissioning trust fund and the asset retirement obligation for the spent fuel management and decommissioning of the plant.
Entergy Nuclear Vermont Yankee has an outstanding credit facility with borrowing capacity of $145 million to pay for dry fuel storage costs. This credit facility is guaranteed by Entergy Corporation. At or before closing, a subsidiary of Entergy will assume the obligations under the existing credit facility or enter into a new credit facility and Entergy will guarantee the credit facility. At the closing of the sale transaction, NorthStar will pay $1,000 for the membership interests in Entergy Nuclear Vermont Yankee, and NorthStar will cause Entergy Nuclear Vermont Yankee to issue a promissory note to an Entergy subsidiary. The amount of the promissory note issued will be equal to the amount drawn under the credit facility or the amount drawn under the new credit facility, plus borrowing fees and costs incurred by Entergy in connection with such facility. The principal amount drawn under the outstanding credit facility was $104 million as plant for generation during each of those years. This amountDecember 31, 2017, and the net book value of Entergy Nuclear Vermont Yankee, including unrealized gains on the decommissioning trust fund, as of December 31, 2017, was depreciated overapproximately $123 million.
Entergy plans to transfer all spent nuclear fuel to dry cask storage by the expected remaining useful lifeend of 2018 in advance of the plants.planned transaction close. Under the sale agreement and related agreements to be entered into at the closing, NorthStar will commit to initiate decommissioning and site restoration by 2021 and complete those activities by 2030. The original planned completion date, as outlined in Entergy’s Post Shutdown Decommissioning Activities Report filed with the NRC, was 2075. Entergy Nuclear Vermont Yankee, under NorthStar ownership, will be required to repay the promissory note issued to Entergy with certain of the proceeds from the recovery of damages under its claims against the DOE related to spent nuclear fuel disposal, with any balance remaining due at partial site release, subject to extension not to exceed two years from partial site release.
The transaction is subject to certain closing conditions, including approval by the NRC; approval by the State of Vermont Public Utility Commission, including approval of revised site restoration standards that have been proposed as part of the transaction; the transfer of all spent nuclear fuel to dry fuel storage on the independent spent fuel storage installation; and that the market value of the fund assets held in the decommissioning trust fund for the Vermont Yankee Nuclear Power Station, less the hypothetical income tax on the aggregate unrealized net gain of such fund assets at closing, is equal to or exceeds $451.95 million, subject to adjustments. Entergy has the option to contribute to the decommissioning trust fund if the value is less than $451.95 million, subject to adjustments. The transaction is planned to close by the end of 2018.
FitzPatrick
In August 2016, Entergy entered into an agreement to sell the FitzPatrick plant, an 838 MW nuclear power plant owned by Entergy in the Entergy Wholesale Commodities segment. As a result of the sales agreement and the status of the necessary regulatory approvals, the assets and liabilities associated with the sale of FitzPatrick to Exelon were classified as held for sale on Entergy Corporation and Subsidiaries’ Consolidated Balance Sheet as of December 31, 2016. At December 31, 2016, the receivable for the beneficial interest in the decommissioning trust fund was $785 million, classified within other deferred debits, and the asset retirement obligation was $714 million, classified within
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Dispositionsother non-current liabilities. See Note 9 to the financial statements for further discussion of FitzPatrick’s decommissioning liability and see Note 16 to the financial statements for further discussion of the receivables for the beneficial interest in FitzPatrick’s decommissioning trust fund.
In March 2017 the NRC approved the sale of the plant to Exelon. The transaction closed in March 2017 for a purchase price of $110 million, which included a $10 million non-refundable signing fee paid in August 2016, in addition to the assumption by Exelon of certain liabilities related to the FitzPatrick plant, resulting in a pre-tax gain on the sale of $16 million. At the transaction close, Exelon paid an additional $8 million for the proration of certain expenses prepaid by Entergy. The disposition-date fair value of the decommissioning trust fund was $805 million, classified within other deferred debits, and the disposition-date fair value of the asset retirement obligation was $727 million, classified within other non-current liabilities. The transaction also included property, plant, and equipment with a net book value of zero, materials and supplies, and prepaid assets.
As part of the transaction, Entergy entered into a reimbursement agreement with Exelon pursuant to which Exelon reimbursed Entergy for specified out-of-pocket costs associated with Entergy’s operation of FitzPatrick prior to closing of the sale. In the first quarter 2017, Entergy billed Exelon for reimbursement of $98 million of other operation and maintenance expenses, $7 million in lost operating revenues, and $3 million in taxes other than income taxes, partially offset by a $10 million defueling credit to Exelon.
As discussed in Note 3 to the financial statements, as a result of the sale of FitzPatrick on March 31, 2017, Entergy redetermined the plant’s tax basis, resulting in a $44 million income tax benefit in the first quarter 2017.
Top Deer
In November 2013,2016, Entergy sold Entergy Solutions District Energy,its 50% membership interest in Top Deer Wind Ventures, LLC, a business wholly-ownedwind-powered electric generation joint venture owned by Entergy in the Entergy Wholesale Commodities segment that owns and operates district energy assets serving the business districts in Houston and New Orleans.accounted for as an equity method investment. Entergy sold its 50% membership interest in Top Deer for approximately $0.5 million and realized a pre-tax loss of $0.2 million on the sale.
Rhode Island State Energy Center
In December 2015, Entergy Solutions Districtsold the Rhode Island State Energy Center, a 583 MW natural gas-fired combined-cycle generating plant owned by Entergy in the Entergy Wholesale Commodities segment. Entergy sold the Rhode Island State Energy Center for $140approximately $490 million and realized a pre-tax gain of $44$154 million on the sale.
Impairment of Long-lived Assets
2015 Impairment Conclusions
Entergy determined in October 2015 that it would close FitzPatrick at the end of its fuel cycle, which was planned for January 27, 2017, because of poor market conditions that led to reduced revenues, a poor market design that failed to properly compensate nuclear generators for the benefits they provide, and increased operational costs. This decision came after management’s extensive analysis of whether it was advisable economically to refuel the plant, as scheduled, in the fall of 2016. Entergy also had discussions with the State of New York regarding the future of FitzPatrick. Because of the uncertainty regarding the refueling decision and its implications to the plant’s expected operating life, Entergy tested the recoverability of the plant and related assets as of September 30, 2015. See above in the Dispositions section for further information on the subsequent decision to sell the FitzPatrick plant.
Entergy determined in October 2015 that it would close Pilgrim no later than June 1, 2019 because of poor market conditions that led to reduced revenues, a poor market design that failed to properly compensate nuclear generators for the benefits they provide, and increased operational costs. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision in September 2015
Entergy Corporation and Subsidiaries
Notes to Financial Statements
to place the plant in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix. Because of the uncertainty regarding the plant’s operating life created by the NRC’s decision and management’s analysis of the plant, Entergy tested the recoverability of the plant and related assets as of September 30, 2015.
Due to the announced plant closures in October 2015, as well as the continued challenging market price trend, the high level of investment required to continue to operate the Entergy Wholesale Commodities plants, and the inadequate compensation provided to nuclear generators for their capacity benefits under the current market design, in the fourth quarter 2015, Entergy tested the recoverability of the plant and related assets of the two remaining operating nuclear power generating facilities in the Entergy Wholesale Commodities business, Palisades and Indian Point. For purposes of that evaluation, Entergy considered a number of factors associated with the facilities’ continued operation, including the status of the associated NRC licenses, the status of state regulatory issues, existing power purchase agreements, and the supply region in which the nuclear facilities sell energy and capacity.
Under generally accepted accounting principles the determination of an asset’s recoverability is based on the probability-weighted undiscounted net cash flows expected to be generated by the plant and related assets. Projected net cash flows primarily depend on the status of the operations of the plant and pending legal and state regulatory matters, as well as projections of future revenues and costs over the estimated remaining life of the plant.
The tests for FitzPatrick and Pilgrim indicated that the probability-weighted undiscounted net cash flows did not exceed the carrying values of the plants and related assets as of September 30, 2015.
The test for Palisades indicated that the probability-weighted undiscounted net cash flows did not exceed the carrying value of the plant and related assets as of December 31, 2015.
The test for Indian Point indicated that the probability-weighted undiscounted net cash flows exceeded the carrying value of the plant and related assets as of December 31, 2015. As such, the carrying value of Indian Point was not impaired as of December 31, 2015.
As of September 30, 2015, the estimated fair value of the FitzPatrick plant and related long-lived assets was $29 million, while the carrying value was $742 million, resulting in an impairment charge of $713 million. Materials and supplies were evaluated and written down by $48 million. In addition, FitzPatrick had a contract asset recorded for an agreement between Entergy subsidiaries and NYPA entered when Entergy subsidiaries purchased FitzPatrick from NYPA in 2000 and NYPA retained the decommissioning trusts and the decommissioning liabilities. The agreement gave NYPA the right to require the Entergy subsidiaries to assume the decommissioning liability provided that it assigns the decommissioning trust, up to a specified level, to Entergy. If NYPA retained the decommissioning liabilities, the Entergy subsidiaries would perform the decommissioning of the plant at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. The contract asset represented an estimate of the present value of the difference between the Entergy subsidiaries’ stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies. See Note 9 for further discussion of the contract asset. Due to a change in expectation regarding the timing of decommissioning cash flows, the result was a write down of the contract asset from $335 million to $131 million, for a charge of $204 million. In summary, as of September 30, 2015, the impairment and related charges for FitzPatrick was $965 million ($624 million net-of-tax).
As of September 30, 2015, the estimated fair value of the Pilgrim plant and related long-lived assets is $65 million, while the carrying value was $718 million, resulting in an impairment charge of $653 million. Materials and supplies were evaluated and written down by $24 million. In summary, as of September 30, 2015, the total impairment loss and related charges for Pilgrim was $677 million ($438 million net-of-tax). The pre-impairment carrying value of $718 million includes the effect of a $134 million increase in Pilgrim’s estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the change in expectation regarding the timing of decommissioning cash flows.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
As of December 31, 2015, the estimated fair value of the Palisades plant and related long-lived assets was $463 million, while the carrying value was $859 million, resulting in an impairment charge of $396 million ($256 million net-of-tax). The pre-impairment carrying value of $859 million includes the effect of a $42 million increase in Palisades’ estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the assessment of the estimated decommissioning cash flows that occurred in conjunction with the impairment analysis.
2016 Impairment Conclusions
As discussed in more detail above in the Acquisitionssection, in December 2016, Entergy reached an agreement with Consumers Energy to amend the existing PPA to terminate early, on May 31, 2018. The PPA amendment agreement was subject to regulatory approvals, including approval by the Michigan Public Service Commission. Separately, Entergy intended to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. As a result of the planned PPA termination and its intention to shut down the plant, Entergy tested the recoverability of the plant and related assets as of December 31, 2016. Entergy and Consumers Energy subsequently agreed to terminate the PPA amendment agreement and Entergy now intends to shut down the Palisades plant permanently on May 31, 2022.
Indian Point 2 and Indian Point 3 have an application pending for renewed NRC licenses. Various parties, including the State of New York, expressed opposition to renewal of the licenses. Under federal law, nuclear power plants may continue to operate beyond their original license expiration dates while their timely filed renewal applications are pending NRC approval. Indian Point 2 reached the expiration date of its original NRC operating license on September 28, 2013, and Indian Point 3 reached the expiration date of its original NRC operating license on December 12, 2015. Upon expiration of their operating licenses, each plant entered into a period of extended operation under the timely renewal rule.
In January 2017, Entergy announced that it reached a settlement with New York State to shut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021, and resolve all New York State-initiated legal challenges to Indian Point’s operating license renewal. As part of the settlement, New York State agreed to issue Indian Point’s water quality certification and Coastal Zone Management Act consistency certification and to withdraw its objection to license renewal before the NRC. New York State also agreed to issue a water discharge permit, which is required regardless of whether the plant is seeking a renewed NRC license. The shutdowns are conditioned, among other things, upon such actions being taken by New York State. As a result of its evaluation of alternatives to the continued operation of the Indian Point plants, and taking into consideration the status of negotiations with the State of New York, Entergy tested the recoverability of the plants and related assets as of December 31, 2016.
The tests for Palisades and Indian Point indicated that the probability-weighted undiscounted net cash flows did not exceed the carrying values of the plants and related assets as of December 31, 2016.
As of December 31, 2016 the estimated fair value of the Palisades plant and related long-lived assets was $206 million, while the carrying value was $558 million, resulting in an impairment charge of $352 million. Materials and supplies were evaluated and written down by $48 million. In summary, as of December 31, 2016, the total impairment loss and related charges for Palisades was $400 million ($258 million net-of-tax). The pre-impairment carrying value of $558 million included the effect of a $129 million increase in Palisades’ estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the change in expectation regarding the timing of decommissioning cash flows. See Note 9 to the financial statements for further discussion regarding the Palisades decommissioning cost revision.
As of December 31, 2016 the estimated fair value of the Indian Point plants and related long-lived assets was $433 million, while the carrying value was $2,619 million, resulting in an impairment charge of $2,186 million. Materials and supplies were evaluated and written down by $157 million. In summary, as of December 31, 2016, the total impairment loss and related charges for Indian Point was $2,343 million ($1,511 million net-of-tax). The pre-
Entergy Corporation and Subsidiaries
Notes to Financial Statements
impairment carrying value of $2,619 million included the effect of a $392 million increase in Indian Point’s estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the change in expectation regarding the timing of decommissioning cash flows. See Note 9 to the financial statements for further discussion regarding the Indian Point decommissioning cost revision.
2017 Impairment Conclusions
In 2017 Entergy management continued to execute the strategy to reduce the size of Entergy Wholesale Commodities’ merchant fleet, with the planned shutdowns of Pilgrim by May 31, 2019, Indian Point 2 by April 30, 2020, Indian Point 3 by April 30, 2021, and, as discussed in further detail above in the Acquisitions section, Palisades on May 31, 2022. The FitzPatrick plant was classified as held-for-sale at December 31, 2016, and subsequently sold to Exelon in March 2017.
In 2017 Entergy Wholesale Commodities incurred $538 million of impairment charges related to nuclear fuel spending, nuclear refueling outage spending, and expenditures for capital assets. These costs were charged to expense as incurred as a result of the impaired fair value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet.
As discussed above in the Acquisitions section, as a result of the Michigan Public Service Commission only granting Consumers Energy partial recovery of the requested early termination payment, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement in September 2017. Entergy will continue to operate Palisades under the current PPA with Consumers Energy, instead of shutting down in the fall of 2018 as previously planned. Entergy intends to shut down the Palisades plant permanently on May 31, 2022. As a result of the change in expected operating life of the Palisades plant, the expected probability-weighted undiscounted net cash flows as of September 30, 2017 exceeded the carrying value of the plant and related assets. Accordingly, nuclear fuel spending, nuclear refueling outage spending, and expenditures for capital assets incurred at Palisades after September 30, 2017 are no longer charged to expense as incurred, but recorded as assets and depreciated or amortized, subject to the typical periodic impairment reviews prescribed in the accounting rules.
Overall Regarding All Impairments
The impairments and other related charges are recorded as a separate line item in Entergy’s consolidated statements of operations and are included within the results of the Entergy Wholesale Commodities segment. In addition to the impairments and other related charges, Entergy expects to incur additional charges through mid-2022 associated with these strategic transactions. See Note 13 to the financial statements for further discussion of these additional charges.
The fair value analyses for FitzPatrick, Pilgrim, and Palisades in 2015, and Palisades and Indian Point in 2016, were performed based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimates of fair value were based on the prices that Entergy would expect to receive in hypothetical sales of the FitzPatrick, Pilgrim, Palisades, and Indian Point plants and related assets to a market participant. In order to determine these prices, Entergy used significant observable inputs, including quoted forward power and gas prices, where available. Significant unobservable inputs, such as projected long-term pre-tax operating margins (cash basis) and estimated weighted-average costs of capital, were also used in the estimation of fair value. In addition, Entergy made certain assumptions regarding future tax deductions associated with the plants and related assets, the amount and timing of recoveries from future litigation with the DOE related to spent fuel storage costs, and the expected operating life of the plant. Based on the use of significant unobservable inputs, the fair value measurement for the entirety of the asset group, and for each type of asset within the asset group, are classified as Level 3 in the fair value hierarchy discussed in Note 15 to the financial statements.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The following table sets forth a description of significant unobservable inputs used in the valuation of the FitzPatrick, Pilgrim, Palisades, and Indian Point plants and related assets:
|
| | | | |
| Significant Unobservable Inputs | | Amount | | Weighted-Average |
| 2015 | | | | |
| Weighted-average cost of capital | | | | |
| FitzPatrick | | 7.5% | | 7.5% |
| Pilgrim (a) | | 7.5%-8.0% | | 7.9% |
| Palisades | | 7.5% | | 7.5% |
| | | | | |
| Long-term pre-tax operating margin (cash basis) | | | | |
| FitzPatrick | | 10.2% | | 10.2% |
| Pilgrim (a) | | 2.4%-10.6% | | 8.1% |
| Palisades (b) | | 30.8% | | 30.8% |
| | | | | |
| 2016 | | | | |
| Weighted-average cost of capital | | | | |
| Indian Point (c) | | 7.0%-7.5%
| | 7.2% |
| Palisades | | 6.5% | | 6.5% |
| | | | | |
| Long-term pre-tax operating margin (cash basis) | | | | |
| Indian Point | | 19.7% | | 19.7% |
| Palisades (b) (d) | | 17.8%-38.8%
| | 34.6% |
| |
| (a) | The fair value of Pilgrim was based on the probability weighting of two potential scenarios. |
| |
| (b) | Most of the Palisades output is sold under a 15-year power purchase agreement, entered at the plant’s acquisition in 2007, that is scheduled to expire in 2022. The power purchase agreement prices currently exceed market prices and escalate each year, up to $61.50/MWh in 2022. |
| |
| (c) | The cash flows extending through the 2021 shutdown at Indian Point 3 were assigned a higher discount factor to incorporate the increased risk associated with longer operations. |
| |
| (d) | The fair value of Palisades at December 31, 2016 is based on the probability weighting of whether the PPA will terminate before the originally scheduled termination in 2022. |
Entergy’s Accounting Policy and Entergy Wholesale Commodities Accounting group, which reports to the Chief Accounting Officer, was primarily responsible for determining the valuation of the FitzPatrick, Pilgrim, Palisades and Indian Point plants and related assets, in consultation with external advisors. Entergy’s Accounting Policy group obtained and reviewed information from other Entergy departments with expertise on the various inputs and assumptions that were necessary to calculate the fair values of the asset groups.
NOTE 16.15. RISK MANAGEMENT AND FAIR VALUES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Market Risk
In the normal course of business, Entergy is exposed to a number of market risks. Market risk is the potential loss that Entergy may incur as a result of changes in the market or fair value of a particular commodity or instrument. All financial and commodity-related instruments, including derivatives, are subject to market risk including commodity
Entergy Corporation and Subsidiaries
Notes to Financial Statements
price risk, equity price, and interest rate risk. Entergy uses derivatives primarily to mitigate commodity price risk, particularly power price and fuel price risk.
The Utility has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail regulators, the Utility operating companies use derivative instruments to hedge the exposure to price volatility inherent in their purchased power, fuel, and gas purchased for resale costs that are recovered from customers.
As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy and capacity in the day ahead or spot markets. In addition to its forward physical power and gas contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, and options, to mitigate commodity price risk. When the market price falls, the combination of instruments is expected to settle in gains that offset lower revenue from generation, which results in a more predictable cash flow.
Entergy’s exposure to market risk is determined by a number of factors, including the size, term, composition, and diversification of positions held, as well as market volatility and liquidity. For instruments such as options, the time period during which the option may be exercised and the relationship between the current market price of the underlying instrument and the option’s contractual strike or exercise price also affects the level of market risk. A significant factor influencing the overall level of market risk to which Entergy is exposed is its use of hedging techniques to mitigate such risk. Hedging instruments and volumes are chosen based on ability to mitigate risk associated with future energy and capacity prices; however, other considerations are factored into hedge product and volume decisions including corporate liquidity, corporate credit ratings, counterparty credit risk, hedging costs, firm settlement risk, and product availability in the marketplace. Entergy manages market risk by actively monitoring compliance with stated risk management policies as well as monitoring the effectiveness of its hedging policies and strategies. Entergy’s risk management policies limit the amount of total net exposure and rolling net exposure during the stated periods. These policies, including related risk limits, are regularly assessed to ensure their appropriateness given Entergy’s objectives.
Derivatives
Some derivative instruments are classified as cash flow hedges due to their financial settlement provisions while others are classified as normal purchase/normal sale transactions due to their physical settlement provisions. Normal purchase/normal sale risk management tools include power purchase and sales agreements, fuel purchase agreements, capacity contracts, and tolling agreements. Financially-settled cash flow hedges can include
Entergy Corporation and Subsidiaries
Notes to Financial Statements
natural gas and electricity swaps and options and interest rate swaps. Entergy may enter into financially-settled swap and option contracts to manage market risk that may or may not be designated as hedging instruments.
Entergy enters into derivatives to manage natural risks inherent in its physical or financial assets or liabilities. Electricity over-the-counter instruments and futures contracts that financially settle against day-ahead power pool prices are used to manage price exposure for Entergy Wholesale Commodities generation. The maximum length of time over which Entergy Wholesale Commodities is currently hedging the variability in future cash flows with derivatives for forecasted power transactions at December 31, 20142017 is approximately 33.25 years. Planned generation currently under contract from Entergy Wholesale Commodities nuclear power plants is 86%98% for 2015,2018, of which approximately 62%79% is sold under financial derivatives and the remainder under normal purchase/normal sale contracts. Total planned generation for 20152018 is 3527.9 TWh.
Entergy may use standardized master netting agreements to help mitigate the credit risk of derivative instruments. These master agreements facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Cash, letters of credit, and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds an established threshold. The threshold represents an unsecured credit limit, which may be supported by a parental/affiliate guaranty, as determined in accordance with Entergy’s credit policy.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
Certain of the agreements to sell the power produced by Entergy Wholesale Commodities power plants contain provisions that require an Entergy subsidiary to provide collateralcredit support to secure its obligations whendepending on the current market prices exceedmark-to-market values of the contracted power prices.contracts. The primary form of collateralcredit support to satisfy these requirements is an Entergy Corporation guarantee. As of December 31, 2014,2017, derivative contracts with 1 counterparty were in a liability position (approximately $1 million total). As of December 31, 2013, derivative contracts with 9eight counterparties were in a liability position (approximately $187$65 million total). In addition to the corporate guarantee, $47$1 million in cash collateral was required to be posted.posted by the Entergy subsidiary to its counterparties and $4 million in cash collateral and $34 million in letters of credit were required to be posted by its counterparties to the Entergy subsidiary. As of December 31, 2016, derivative contracts with three counterparties were in a liability position (approximately $8 million total). In addition to the corporate guarantee, $2 million in cash collateral was required to be posted by the Entergy subsidiary to its counterparties. If the Entergy Corporation credit rating falls below investment grade, the effect of the corporate guarantee is typically ignored and Entergy would have to post collateral equal to the estimated outstanding liability under the contract at the applicable date.
Entergy manages fuel price volatility for its Louisiana jurisdictions (Entergy Gulf States Louisiana, Entergy Louisiana and Entergy New Orleans) and Entergy Mississippi through the purchase of short-term natural gas swaps that financially settle against NYMEX futures. These swaps are marked-to-market through fuel expense with offsetting regulatory assets or liabilities. All benefits or costs of the program are recorded in fuel costs. The notional volumes of these swaps are based on a portion of projected annual exposure to gas for electric generation at Entergy Louisiana and Entergy Mississippi and projected winter purchases for gas distribution at Entergy Gulf States Louisiana and Entergy New Orleans. The total volume of natural gas swaps outstanding as of December 31, 20142017 is 21,475,00038,540,750 MMBtu for Entergy, including 8,740,000 MMBtu for Entergy Gulf States Louisiana, 8,810,00031,361,500 MMBtu for Entergy Louisiana, 3,230,0006,714,250 MMBtu for Entergy Mississippi, and 695,000465,000 MMBtu for Entergy New Orleans. Credit support for these natural gas swaps is covered by master agreements that do not require collateralizationcollateral based on mark-to-market value, but do carry adequate assurance language that may lead to collateralization requests.requests for collateral.
During the second quarter 2014,2017, Entergy participated in the annual FTRfinancial transmission rights auction process for the MISO planning year of June 1, 20142017 through May 31, 2015. FTRs2018. Financial transmission rights are derivative instruments which represent economic hedges of future congestion charges that will be incurred in serving Entergy’s customer load. They are not designated as hedging instruments. Entergy initially records FTRsfinancial transmission rights at their estimated fair value and subsequently adjusts the carrying value to their estimated fair value at the end of each accounting period prior to settlement. Unrealized gains or losses on FTRsfinancial transmission rights held by Entergy Wholesale Commodities are included in operating revenues. The Utility operating companies recognize regulatory liabilities or assets for unrealized gains or losses on FTRs.financial transmission rights. The total volume of FTRsfinancial transmission rights outstanding as of December 31, 20142017 is 45,19646,474 GWh for Entergy, including 9,84410,479 GWh for Entergy Arkansas, 9,881 GWh for Entergy Gulf States Louisiana, 10,69120,590 GWh for Entergy Louisiana, 5,4036,391 GWh for Entergy Mississippi, 3,6332,366 GWh for Entergy New Orleans, and 5,6696,322 GWh for Entergy Texas. Credit support for FTRsfinancial transmission rights held by the Utility operating companies is covered by cash and/or letters of credit issued by each Utility operating company as required by MISO. Credit support for financial transmission rights held by Entergy Wholesale Commodities is covered by cash. No cash or letters of credit were required to be posted for financial transmission rights exposure for Entergy Wholesale Commodities as of December 31, 2017 and December 31, 2016. Letters of credit posted with MISO covered the financial transmission rights exposure for Entergy Arkansas, Entergy Mississippi, and Entergy Texas as of December 31 2017 and for Entergy Arkansas and Entergy Mississippi as of December 31, 2016.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
companies is covered by cash or letters of credit issued by each Utility operating company as required by MISO. Credit support for FTRs held by Entergy Wholesale Commodities is covered by cash. As of December 31, 2014, letters of credit posted with MISO covered the FTR exposure for Entergy Arkansas and Entergy Mississippi. No cash collateral was required to be posted for FTR exposure for the Utility operating companies or Entergy Wholesale Commodities.
The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 20142017 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.
| | | Instrument | | Balance Sheet Location | | Fair Value (a) | | Offset (b) | | Net (c) (d) | | Business | | Balance Sheet Location | | Fair Value (a) | | Offset (b) | | Net (c) (d) | | Business |
| | | (In Millions) | | |
| | | | | | | | | | | (In Millions) | |
| Derivatives designated as hedging instruments | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | |
| Electricity swaps and options | | Prepayments and other (current portion) | | $149 | | ($53) | | $96 | | Entergy Wholesale Commodities | | Prepayments and other (current portion) | | $19 | | ($19) | | $— | | Entergy Wholesale Commodities |
| Electricity swaps and options |
| Other deferred debits and other assets (non-current portion) | | $48 | | $— | | $48 | | Entergy Wholesale Commodities |
| Other deferred debits and other assets (non-current portion) | | $19 | | ($14) | | $5 | | Entergy Wholesale Commodities |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | | | |
| Electricity swaps and options | | Other current liabilities (current portion) | | $24 | | ($24) | | $— | | Entergy Wholesale Commodities | | Other current liabilities (current portion) | | $86 | | ($20) | | $66 | | Entergy Wholesale Commodities |
| Electricity swaps and options | | | Other non-current liabilities (non-current portion) | | $17 | | ($14) | | $3 | | Entergy Wholesale Commodities |
| | | Derivatives not designated as hedging instruments | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | |
| Electricity swaps and options | | Prepayments and other (current portion) | | $97 | | ($25) | | $72 | | Entergy Wholesale Commodities | | Prepayments and other (current portion) | | $9 | | ($9) | | $— | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other deferred debits and other assets (non-current portion) | | $9 | | ($8) | | $1 | | Entergy Wholesale Commodities | |
| FTRs | | Prepayments and other | | $50 | | ($3) | | $47 | | Utility and Entergy Wholesale Commodities | |
| Financial transmission rights | | | Prepayments and other | | $22 | | ($1) | | $21 | | Utility and Entergy Wholesale Commodities |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | | | |
| Electricity swaps and options | | Other current liabilities (current portion) | | $57 | | ($55) | | $2 | | Entergy Wholesale Commodities | | Other current liabilities (current portion) | | $9 | | ($8) | | $1 | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other non-current liabilities (non-current portion) | | $8 | | ($8) | | $— | | Entergy Wholesale Commodities | |
| Natural gas swaps | | Other current liabilities | | $20 | | $— | | $20 | | Utility | | Other current liabilities | | $6 | | $— | | $6 | | Utility |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 20132016 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.
| | | Instrument | | Balance Sheet Location | | Fair Value (a) | | Offset (b) | | Net (c) (d) | | Business | | Balance Sheet Location | | Fair Value (a) | | Offset (b) | | Net (c) (d) | | Business |
| | | (In Millions) | | |
| | | | | | | | | | | (In Millions) | |
| Derivatives designated as hedging instruments | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | |
| Electricity swaps and options | | Prepayments and other (current portion) | | $118 | | ($99) | | $19 | | Entergy Wholesale Commodities | | Prepayments and other (current portion) | | $25 | | ($14) | | $11 | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other deferred debits and other assets (non-current portion) | | $17 | | ($17) | | $— | | Entergy Wholesale Commodities | | Other deferred debits and other assets (non-current portion) | | $6 | | ($6) | | $— | | Entergy Wholesale Commodities |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | | | |
| Electricity swaps and options | | Other current liabilities (current portion) | | $197 | | ($131) | | $66 | | Entergy Wholesale Commodities | | Other current liabilities (current portion) | | $11 | | ($10) | | $1 | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other non-current liabilities (non-current portion) | | $46 | | ($17) | | $29 | | Entergy Wholesale Commodities | | Other non-current liabilities (non-current portion) | | $16 | | ($7) | | $9 | | Entergy Wholesale Commodities |
| | | Derivatives not designated as hedging instruments | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | |
| Electricity swaps and options | | Prepayments and other (current portion) | | $177 | | ($122) | | $55 | | Entergy Wholesale Commodities | | Prepayments and other (current portion) | | $18 | | ($13) | | $5 | | Entergy Wholesale Commodities |
| Electricity swaps and options | | | Other deferred debits and other assets (non-current portion) | | $5 | | ($5) | | $— | | Entergy Wholesale Commodities |
| Natural gas swaps | | Prepayments and other | | $6 | | $— | | $6 | | Utility | | Prepayments and other | | $13 | | $— | | $13 | | Utility |
| FTRs | | Prepayments and other | | $36 | | ($2) | | $34 | | Utility and Entergy Wholesale Commodities | |
| Financial transmission rights | | | Prepayments and other | | $22 | | ($1) | | $21 | | Utility and Entergy Wholesale Commodities |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | | | |
| Electricity swaps and options | | Other current liabilities (current portion) | | $201 | | ($89) | | $112 | | Entergy Wholesale Commodities | | Other current liabilities (current portion) | | $18 | | ($17) | | $1 | | Entergy Wholesale Commodities |
| Electricity swaps and options | | | Other non-current liabilities (non-current portion) | | $4 | | ($4) | | $— | | Entergy Wholesale Commodities |
| |
| (a) | Represents the gross amounts of recognized assets/liabilities |
| |
| (b) | Represents the netting of fair value balances with the same counterparty |
| |
| (c) | Represents the net amounts of assets/liabilities presented on the Entergy Corporation and Subsidiaries’ Consolidated Balance SheetsSheet |
| |
| (d) | Excludes cash collateral in the amountsamount of $25 million held as of December 31, 2014 and $47$1 million posted and $4 million held as of December 31, 2013, respectively2017 and $2 million posted as of December 31, 2016. Also excludes $34 million in letters of credit held as of December 31, 2017. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The effecteffects of Entergy’s derivative instruments designated as cash flow hedges on the consolidated income statements for the years ended December 31, 2014, 2013,2017, 2016, and 20122015 are as follows:
| | Instrument | | Amount of gain (loss) recognized in other comprehensive income | | Income Statement location | | Amount of gain (loss) reclassified from AOCI into income (a) | | Amount of gain recognized in other comprehensive income | | Income Statement location | | Amount of gain (loss) reclassified from accumulated other comprehensive income into income (a) |
| | | (In Millions) | | | | (In Millions) | | (In Millions) | | | | (In Millions) |
| 2014 | | | | | | | |
| 2017 | | | | | | | |
| Electricity swaps and options | | $81 | | Competitive business operating revenues | | ($193) | | $44 | | Competitive business operating revenues | | $109 |
| | | | | | | | | | | | | |
| 2013 | | | | | | | |
| 2016 | | | | | | | |
| Electricity swaps and options | | ($190) | | Competitive business operating revenues | | $47 | | $135 | | Competitive business operating revenues | | $293 |
| | | | | | | | | | | | | |
| 2012 | | | | | | | |
| 2015 | | | | | | | |
| Electricity swaps and options | | $111 | | Competitive business operating revenues | | $268 | | $254 | | Competitive business operating revenues | | ($244) |
| |
| (a) | Before taxes of ($68)$38 million, $18$103 million, and $94($85) million, for the years ended December 31, 2014, 2013,2017, 2016, and 2012,2015, respectively |
At each reporting period, Entergy measures its hedges for ineffectiveness. Any ineffectiveness is recognized in earnings during the period. The ineffective portion of cash flow hedges is recorded in competitive businesses operating revenues. The change in fair value of Entergy’s cash flow hedges due to ineffectiveness was $7($3) million, ($6) million,356) thousand, and ($14) million$150 thousand for the years ended December 31, 2014, 2013,2017, 2016, and 2012,2015, respectively.
Based on market prices as of December 31, 2014,2017, unrealized gains recorded in AOCIaccumulated other comprehensive income on cash flow hedges relating to power sales totaled $156$55 million of net unrealized gains.losses. Approximately $109($59) million is expected to be reclassified from AOCIaccumulated other comprehensive income to operating revenues in the next twelve months. The actual amount reclassified from AOCI,accumulated other comprehensive income, however, could vary due to future changes in market prices.
Entergy may effectively liquidate a cash flow hedge instrument by entering into a contract offsetting the original hedge, and then de-designating the original hedge in this situation. Gains or losses accumulated in other comprehensive income prior to de-designation continue to be deferred in other comprehensive income until they are included in income as the original hedged transaction occurs. From the point of de-designation, the gains or losses on the original hedge and the offsetting contract are recorded as assets or liabilities on the balance sheet and offset as they flow through to earnings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The effecteffects of Entergy’s derivative instruments not designated as hedging instruments on the consolidated income statements for the years ended December 31, 2014, 2013,2017, 2016, and 2012 is2015 are as follows:
| | Instrument | | Amount of gain (loss) recognized in AOCI | | Income Statement location | | Amount of gain (loss) recorded in the income statement | | Amount of gain recognized in accumulated other comprehensive income | | Income Statement location | | Amount of gain (loss) recorded in the income statement |
| | | (In Millions) | | | | (In Millions) | | (In Millions) | | | | (In Millions) |
| 2014 | | | | | | | |
| 2017 | | | | | | | |
| Natural gas swaps | | — | | Fuel, fuel-related expenses, and gas purchased for resale | (a) | ($8) | | $— | | Fuel, fuel-related expenses, and gas purchased for resale | (a) | ($31) |
| FTRs | | — | | Purchased power expense | (b) | $229 | |
| Financial transmission rights | | | $— | | Purchased power expense | (b) | $139 |
| Electricity swaps and options | | ($13) | | Competitive business operating revenues | | $56 | | $— | (c) | Competitive business operating revenues | | $— |
| | | | | | | | | | | | | |
| 2013 | | | | | | | |
| 2016 | | | | | | | |
| Natural gas swaps | | — | | Fuel, fuel-related expenses, and gas purchased for resale | (a) | $13 | | $— | | Fuel, fuel-related expenses, and gas purchased for resale | (a) | $11 |
| FTRs | | — | | Purchased power | (b) | $3 | |
| Financial transmission rights | | | $— | | Purchased power expense | (b) | $125 |
| Electricity swaps and options | | $1 | | Competitive business operating revenues | | ($50) | | $— | (c) | Competitive business operating revenues | | ($11) |
| | | | | | | | | | | | | |
| 2012 | | | | | | | |
| 2015 | | | | | | | |
| Natural gas swaps | | — | | Fuel, fuel-related expenses, and gas purchased for resale | (a) | ($42) | | $— | | Fuel, fuel-related expenses, and gas purchased for resale | (a) | ($41) |
| Financial transmission rights | | | $— | | Purchased power expense | (b) | $166 |
| Electricity swaps and options | | $1 | | Competitive business operating revenues | | $1 | | $12 | (c) | Competitive business operating revenues | | ($19) |
| |
| (a) | Due to regulatory treatment, the natural gas swaps are marked-to-market through fuel, fuel-related expenses, and gas purchased for resale and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability. The gains or losses recorded as fuel expenses when the swaps are settled are recovered or refunded through fuel cost recovery mechanisms. |
| |
| (b) | Due to regulatory treatment, the changes in the estimated fair value of FTRsfinancial transmission rights for the Utility operating companies are recorded through purchased power expense and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability. The gains or losses recorded as purchased power expense when the FTRsfinancial transmission rights for the Utility operating companies are settled are recovered or refunded through fuel cost recovery mechanisms. |
| |
| (c) | Amount of gain (loss) recognized in accumulated other comprehensive income from electricity swaps and options de-designated as hedged items. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair values of the Registrant Subsidiaries’ derivative instruments not designated as hedging instruments on their balance sheets as of December 31, 20142017 and 20132016 are as follows:
|
| | | | | | |
| Instrument | | Balance Sheet Location | | Fair Value (a) | | Registrant |
| | | | | (In Millions) | | |
20142017 | | | | | | |
| Assets: | | | | | | |
FTRsFinancial transmission rights | | Prepayments and other | | $0.73.0 | | Entergy Arkansas |
FTRsFinancial transmission rights | | Prepayments and other | | $14.410.2 | | Entergy Gulf States Louisiana |
FTRsFinancial transmission rights | | Prepayments and other | | $11.12.1 | | Entergy LouisianaMississippi |
FTRsFinancial transmission rights | | Prepayments and other | | $2.2 | | Entergy New Orleans |
| Financial transmission rights | | Prepayments and other | | $3.4 | | Entergy Mississippi |
FTRs | | Prepayments and other | | $4.1 | | Entergy New Orleans |
FTRs | | Prepayments and other | | $12.3 | | Entergy Texas |
| | | | | | | |
| Liabilities: | | | | | | |
| Natural gas swaps | | Other current liabilities | | $8.2 | | Entergy Gulf States Louisiana |
Natural gas swaps | | Other current liabilities | | $7.65.0 | | Entergy Louisiana |
| Natural gas swaps | | Other current liabilities | | $2.81.2 | | Entergy Mississippi |
| Natural gas swaps | | Other current liabilities | | $0.90.2 | | Entergy New Orleans |
| | | | | | | |
20132016 | | | | | | |
| Assets: | | | | | | |
| Natural gas swaps | | Gas hedge contractsPrepayments and other | | $2.2 | | Entergy Gulf States Louisiana |
Natural gas swaps | | Gas hedge contracts | | $2.910.9 | | Entergy Louisiana |
| Natural gas swaps | | Prepayments and other | | $0.72.3 | | Entergy Mississippi |
| Natural gas swaps | | Prepayments and other | | $0.10.2 | | Entergy New Orleans |
| | | | | | | |
FTRsFinancial transmission rights | | Prepayments and other | | $6.75.4 | | Entergy Gulf States LouisianaArkansas |
FTRsFinancial transmission rights | | Prepayments and other | | $5.78.5 | | Entergy Louisiana |
FTRsFinancial transmission rights | | Prepayments and other | | $1.03.2 | | Entergy Mississippi |
FTRsFinancial transmission rights | | Prepayments and other | | $2.01.1 | | Entergy New Orleans |
FTRsFinancial transmission rights | | Prepayments and other | | $18.43.1 | | Entergy Texas |
| |
| (a) | No cash collateral was required to be posted asAs of December 31, 20142017, letters of credit posted with MISO covered financial transmission rights exposure of $0.2 million for Entergy Arkansas, $0.1 million for Entergy Mississippi, and 2013, respectively.$0.05 million for Entergy Texas. As of December 31, 2016, letters of credit posted with MISO covered financial transmission rights exposure of $0.3 million for Entergy Arkansas and $0.1 million for Entergy Mississippi. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The effects of the Registrant Subsidiaries’ derivative instruments not designated as hedging instruments on their income statements for the years ended December 31, 2014, 2013,2017, 2016, and 20122015 are as follows:
|
| | | | | | |
Instrument | | Income Statement Location | | Amount of gain (loss) recorded in the income statement | | Registrant |
| | | | | (In Millions) | | |
20142017 | | | | | | |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($3.9)25.4) | | Entergy Gulf States Louisiana |
Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($1.6) | (a) | Entergy Louisiana |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($2.5)5.2) | (a) | Entergy Mississippi |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($0.2)0.3) | (a) | Entergy New Orleans |
| | | | | | | |
FTRsFinancial transmission rights | | Purchased power | | $21.641.7 | (b) | Entergy Arkansas |
FTRsFinancial transmission rights | | Purchased power | | $56.345.8 | (b) | Entergy Gulf States Louisiana |
FTRsFinancial transmission rights | | Purchased power | | $47.218.9 | (b) | Entergy LouisianaMississippi |
FTRsFinancial transmission rights | | Purchased power | | $19.09.1 | (b) | Entergy MississippiNew Orleans |
FTRsFinancial transmission rights | | Purchased power | | $16.522.3 | | Entergy New Orleans |
FTRs | | Purchased power | | $65.8 | (b) | Entergy Texas |
| | | | | | | |
20132016 | | | | | | |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | $4.58.4 | | Entergy Gulf States Louisiana |
Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | $6.0 | (a) | Entergy Louisiana |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | $2.53.1 | (a) | Entergy Mississippi |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | $0.1($0.4) | (a) | Entergy New Orleans |
| | | | | | | |
FTRs | | Purchased power | | ($0.1) | | Entergy Arkansas |
FTRsFinancial transmission rights | | Purchased power | | $0.323.2 | (b) | Entergy Gulf States LouisianaArkansas |
FTRsFinancial transmission rights | | Purchased power | | $0.269.7 | (b) | Entergy Louisiana |
FTRsFinancial transmission rights | | Purchased power | | $1.016.6 | (b) | Entergy Mississippi |
FTRsFinancial transmission rights | | Purchased power | | $1.24.1 | (b) | Entergy New Orleans |
FTRsFinancial transmission rights | | Purchased power | | $0.810.2 | (b) | Entergy Texas |
| | | | | | | |
20122015 | | | | | | |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | �� | ($12.9)33.2) | | Entergy Gulf States Louisiana |
Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($16.2) | (a) | Entergy Louisiana |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($11.2)6.1) | (a) | Entergy Mississippi |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($1.5)1.4) | (a) | Entergy New Orleans |
| | | | | | |
| Financial transmission rights | | Purchased power | | $68.7 | (b) | Entergy Arkansas |
| Financial transmission rights | | Purchased power | | $55.4 | (b) | Entergy Louisiana |
| Financial transmission rights | | Purchased power | | $16.5 | (b) | Entergy Mississippi |
| Financial transmission rights | | Purchased power | | $8.5 | (b) | Entergy New Orleans |
| Financial transmission rights | | Purchased power | | $16.8 | (b) | Entergy Texas |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
| (a) | Due to regulatory treatment, the natural gas swaps are marked-to-market through fuel, fuel-related expenses, and gas purchased for resale and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability. The gains or losses recorded as fuel expenses when the swaps are settled are recovered or refunded through fuel cost recovery mechanisms. |
| |
| (b) | Due to regulatory treatment, the changes in the estimated fair value of financial transmission rights for the Utility operating companies are recorded through purchased power expense and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability. The gains or losses recorded as purchased power expense when the financial transmission rights for the Utility operating companies are settled are recovered or refunded through fuel cost recovery mechanisms. |
Fair Values
The estimated fair values of Entergy’s financial instruments and derivatives are determined using historical prices, bid prices, market quotes, and financial modeling. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments other than those instruments held by the Entergy Wholesale Commodities business are reflected in future rates and therefore do not affect net income. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments.
Accounting standards define fair value as an exit price, or the price that would be received to sell an asset or the amount that would be paid to transfer a liability in an orderly transaction between knowledgeable market participants at the date of measurement. Entergy and the Registrant Subsidiaries use assumptions or market input data that market participants would use in pricing assets or liabilities at fair value. The inputs can be readily observable, corroborated by market data, or generally unobservable. Entergy and the Registrant Subsidiaries endeavor to use the best available information to determine fair value.
Accounting standards establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy establishes the highest priority for unadjusted market quotes in an active market for the identical asset or liability and the lowest priority for unobservable inputs.
The three levels of the fair value hierarchy are:
Level 1 - Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the entity has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of individually owned common stocks, cash equivalents (temporary cash investments, securitization recovery trust account, and escrow accounts), debt instruments, and gas hedge contracts. Cash equivalents includes all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at the date of purchase.
Level 2 - Level 2 inputs are inputs other than quoted prices included in Level 1 that are, either directly or indirectly, observable for the asset or liability at the measurement date. Assets are valued based on prices derived by independent third parties that use inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads. Prices are reviewed and can be challenged with the independent parties and/or overridden by Entergy if it is believed such would be more reflective of fair value. Level 2 inputs include the following:
- quoted prices for similar assets or liabilities in active markets;
- quoted prices for identical assets or liabilities in inactive markets;
- | |
| – | quoted prices for similar assets or liabilities in active markets; |
| |
| – | quoted prices for identical assets or liabilities in inactive markets; |
| |
| – | inputs other than quoted prices that are observable for the asset or liability; or |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
-– | inputs that are derived principally from or corroborated by observable market data by correlation or other means. |
Level 2 consists primarily of individually-owned debt instruments or shares in common trusts. Common trust funds are stated at estimated fair value based on the fair market value of the underlying investments.instruments.
Level 3 - Level 3 inputs are pricing inputs that are generally less observable or unobservable from objective sources. These inputs are used with internally developed methodologies to produce management’s best estimate of fair value for the asset or liability. Level 3 consists primarily of FTRsfinancial transmission rights and derivative power contracts used as cash flow hedges of power sales at merchant power plants.
The values for power contract assets or liabilities are based on both observable inputs including public market prices and interest rates, and unobservable inputs such as implied volatilities, unit contingent discounts, expected basis differences, and credit adjusted counterparty interest rates. They are classified as Level 3 assets and liabilities. The
Entergy Corporation and Subsidiaries
Notes to Financial Statements
valuations of these assets and liabilities are performed by the Entergy Wholesale CommoditiesBusiness Unit Risk Control group and the Accounting Policy and Entergy Wholesale Commodities Accounting Policy and External Reporting group. The primary functions of the Entergy Wholesale CommoditiesBusiness Unit Risk Control group include: gathering, validating and reporting market data, providing market risk analyses and valuations in support of Entergy Wholesale Commodities’ commercial transactions, developing and administering protocols for the management of market risks, and implementing and maintaining controls around changes to market data in the energy trading and risk management system. The Business Unit Risk Control group is also responsible for managing the energy trading and risk management system, forecasting revenues, forward positions and analysis. The Accounting Policy and Entergy Wholesale Commodities Accounting Policy and External Reporting group performs functions related to market and counterparty settlements, revenue reporting and analysis and financial accounting. The Entergy Wholesale CommoditiesBusiness Unit Risk Control group reports to the Vice President and Treasurer while the Accounting Policy and Entergy Wholesale Commodities Accounting Policy and External Reporting group reports to the Vice President,Chief Accounting Policy and External Reporting.Officer.
The amounts reflected as the fair value of electricity swaps are based on the estimated amount that the contracts are in-the-money at the balance sheet date (treated as an asset) or out-of-the-money at the balance sheet date (treated as a liability) and would equal the estimated amount receivable to or payable by Entergy if the contracts were settled at that date. These derivative contracts include cash flow hedges that swap fixed for floating cash flows for sales of the output from the Entergy Wholesale Commodities business. The fair values are based on the mark-to-market comparison between the fixed contract prices and the floating prices determined each period from quoted forward power market prices. The differences between the fixed price in the swap contract and these market-related prices multiplied by the volume specified in the contract and discounted at the counterparties’ credit adjusted risk free rate are recorded as derivative contract assets or liabilities. For contracts that have unit contingent terms, a further discount is applied based on the historical relationship between contract and market prices for similar contract terms.
The amounts reflected as the fair values of electricity options are valued based on a Black Scholes model, and are calculated at the end of each month for accounting purposes. Inputs to the valuation include end of day forward market prices for the period when the transactions will settle, implied volatilities based on market volatilities provided by a third party data aggregator, and USU.S. Treasury rates for a risk-free return rate. As described further below, prices and implied volatilities are reviewed and can be adjusted if it is determined that there is a better representation of fair value.
On a daily basis, Entergy Wholesale Commoditiesthe Business Unit Risk Control group calculates the mark-to-market for electricity swaps and options. Entergy Wholesale CommoditiesThe Business Unit Risk Control group also validates forward market prices by comparing them to other sources of forward market prices or to settlement prices of actual market transactions. Significant differences are analyzed and potentially adjusted based on these other sources of forward market prices or settlement prices of actual market transactions. Implied volatilities used to value options are also validated using actual counterparty quotes for Entergy Wholesale Commodities transactions when available and uses multiplecompared with other sources of market implied volatilities. Moreover, on at least a monthly basis, the Office of Corporate Risk Oversight confirms the mark-to-market calculations and prepares price scenarios and credit downgrade scenario analysis. The scenario analysis is communicated to senior management within Entergy and within Entergy Wholesale Commodities. Finally, for all
Entergy Corporation and Subsidiaries
Notes to Financial Statements
proposed derivative transactions, an analysis is completed to assess the risk of adding the proposed derivative to Entergy Wholesale Commodities’ portfolio. In particular, the credit and liquidity effects are calculated for this analysis. This analysis is communicated to senior management within Entergy and Entergy Wholesale Commodities.
The values of FTRsfinancial transmission rights are based on unobservable inputs, including estimates of future congestion costs in MISO between applicable generation and load pricing nodes based on prices published by MISO.the 50th percentile of historical prices. They are classified as Level 3 assets and liabilities. The valuations of these assets and liabilities are performed by the Business Unit Risk Control group. The values are calculated internally and verified against the data published by MISO. Entergy’s Accounting Policy and Entergy Wholesale Commodities Risk Control group for the unregulated business and by the System Planning and Operations Risk Control group for the Utility operating companies. Entergy’s Accounting Policy group reviews these valuations for reasonableness, with the assistance of others within the organization with knowledge of the various inputs and
Entergy Corporation and Subsidiaries
Notes to Financial Statements
assumptions used in the valuation. The System Planning and OperationsBusiness Unit Risk Control group reportsgroups report to the Vice President and Treasurer. The Accounting Policy and Entergy Wholesale Commodities Accounting group reports to the Vice President,Chief Accounting Policy and External Reporting.Officer.
The following tables set forth, by level within the fair value hierarchy, Entergy’s assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 20142017 and December 31, 2013.2016. The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.
| | | 2014 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2017 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | |
| $1,291 |
| |
| $— |
| |
| $— |
| |
| $1,291 |
| |
| $725 |
| |
| $— |
| |
| $— |
| |
| $725 |
|
| Decommissioning trust funds (a): | | | | | | | | | | | | | | | | |
| Equity securities | | 452 |
| | 2,834 |
| (b) | — |
| | 3,286 |
| | 526 |
| | — |
| | — |
| | 526 |
|
| Debt securities | | 880 |
| | 1,205 |
| | — |
| | 2,085 |
| | 1,125 |
| | 1,425 |
| | — |
| | 2,550 |
|
| Common trusts (b) | | | | | | | | | 4,136 |
|
| Power contracts | | — |
| | — |
| | 217 |
| | 217 |
| | — |
| | — |
| | 5 |
| | 5 |
|
| Securitization recovery trust account | | 44 |
| | — |
| | — |
| | 44 |
| | 45 |
| | — |
| | — |
| | 45 |
|
| Escrow accounts | | 362 |
| | — |
| | — |
| | 362 |
| | 406 |
| | — |
| | — |
| | 406 |
|
| FTRs | | — |
| | — |
| | 47 |
| | 47 |
| |
| Financial transmission rights | | | — |
| | — |
| | 21 |
| | 21 |
|
| | |
| $3,029 |
| |
| $4,039 |
| |
| $264 |
| |
| $7,332 |
| |
| $2,827 |
| |
| $1,425 |
| |
| $26 |
| |
| $8,414 |
|
| Liabilities: | | | | | | | | | | | | | | | | |
| Power contracts | |
| $— |
| |
| $— |
| |
| $2 |
| |
| $2 |
| |
| $— |
| |
| $— |
| |
| $70 |
| |
| $70 |
|
| Gas hedge contracts | | 20 |
| | — |
| | — |
| | 20 |
| | 6 |
| | — |
| | — |
| | 6 |
|
| | |
| $20 |
| |
| $— |
| |
| $2 |
| |
| $22 |
| |
| $6 |
| |
| $— |
| |
| $70 |
| |
| $76 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2016 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | |
| $609 |
| |
| $— |
| |
| $— |
| |
| $609 |
| |
| $1,058 |
| |
| $— |
| |
| $— |
| |
| $1,058 |
|
| Decommissioning trust funds (a): | | | | | | | | | | | | | | | | |
| Equity securities | | 472 |
| | 2,601 |
| (b) | — |
| | 3,073 |
| | 480 |
| | — |
| | — |
| | 480 |
|
| Debt securities | | 783 |
| | 1,047 |
| | — |
| | 1,830 |
| | 985 |
| | 1,228 |
| | — |
| | 2,213 |
|
| Common trusts (b) | | | | | | | | | 3,031 |
|
| Power contracts | | — |
| | — |
| | 74 |
| | 74 |
| | — |
| | — |
| | 16 |
| | 16 |
|
| Securitization recovery trust account | | 46 |
| | — |
| | — |
| | 46 |
| | 46 |
| | — |
| | — |
| | 46 |
|
| Escrow accounts | | 115 |
| | — |
| | — |
| | 115 |
| | 433 |
| | — |
| | — |
| | 433 |
|
| Gas hedge contracts | | 6 |
| | — |
| | — |
| | 6 |
| | 13 |
| | — |
| | — |
| | 13 |
|
| FTRs | | — |
| | — |
| | 34 |
| | 34 |
| |
| Financial transmission rights | | | — |
| | — |
| | 21 |
| | 21 |
|
| | |
| $2,031 |
| |
| $3,648 |
| |
| $108 |
| |
| $5,787 |
| |
| $3,015 |
| |
| $1,228 |
| |
| $37 |
| |
| $7,311 |
|
| Liabilities: | | | | | | | | | | | | | | | | |
| Power contracts | |
| $— |
| |
| $— |
| |
| $207 |
| |
| $207 |
| |
| $— |
| |
| $— |
| |
| $11 |
| |
| $11 |
|
| |
| (a) | The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices. Fixed income securities are held in various governmental and corporate securities. See Note 179 to the financial statements for additional information on the investment portfolios. |
| |
| (b) | Commingled equityCommon trust funds may be redeemed semi-monthly.are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the years ended December 31, 2014, 2013,2017, 2016, and 2012:2015:
|
| | | | | | | | | | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| | Power Contracts | | FTRs | | Power Contracts | | FTRs | | Power Contracts |
| | (In Millions) |
| Balance as of January 1, |
| ($133 | ) | |
| $34 |
| |
| $178 |
| |
| $— |
| |
| $312 |
|
| Realized losses included in earnings | (65 | ) | | — |
| | (38 | ) | | — |
| | (11 | ) |
| Unrealized gains (losses) included in earnings | 120 |
| | 2 |
| | (35 | ) | | — |
| | (4 | ) |
| Unrealized gains (losses) included in OCI | 131 |
| | — |
| | (204 | ) | | — |
| | 140 |
|
| Unrealized gains included as a regulatory liability / asset | — |
| | 119 |
| | — |
| | — |
| | — |
|
| Issuances of FTRs | — |
| | 121 |
| | — |
| | 37 |
| | — |
|
| Purchases | 17 |
| | — |
| | 14 |
| | — |
| | 9 |
|
| Settlements | 145 |
| | (229 | ) | | (48 | ) | | (3 | ) | | (268 | ) |
| Balance as of December 31, |
| $215 |
| |
| $47 |
| |
| ($133 | ) | |
| $34 |
| |
| $178 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | Power Contracts | Financial transmission rights | | Power Contracts | Financial transmission rights | | Power Contracts | Financial transmission rights |
| | (In Millions) |
| Balance as of January 1, |
| $5 |
|
| $21 |
| |
| $189 |
|
| $23 |
| |
| $215 |
|
| $47 |
|
| Total gains (losses) for the period (a) | | | | | | | | |
| Included in earnings | (3 | ) | 1 |
| | (10 | ) | — |
| | (20 | ) | (1 | ) |
| Included in other comprehensive income | 44 |
| — |
| | 135 |
| — |
| | 254 |
| — |
|
| Included as a regulatory liability/asset | — |
| 76 |
| | — |
| 68 |
| | — |
| 63 |
|
| Issuances of financial transmission rights | — |
| 62 |
| | — |
| 55 |
| | — |
| 80 |
|
| Purchases | — |
| — |
| | — |
| — |
| | 15 |
| — |
|
| Settlements | (111 | ) | (139 | ) | | (309 | ) | (125 | ) | | (275 | ) | (166 | ) |
| Balance as of December 31, |
| ($65 | ) |
| $21 |
| |
| $5 |
|
| $21 |
| |
| $189 |
|
| $23 |
|
| |
| (a) | Change in unrealized gains or losses for the period included in earnings for derivatives held at the end of the reporting period is $0.9 million, $0.2 million, and $3 million for the years ended December 31, 2017, 2016, and 2015, respectively. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The following table sets forth a description of the types of transactions classified as Level 3 in the fair value hierarchy and significant unobservable inputs to each which cause that classification, as of December 31, 2014:2017:
|
| | | | | | | | |
| Transaction Type | | Fair Value as of December 31, 2014 | | Significant Unobservable Inputs | | Range from Average % | | Effect on Fair Value |
| | | (In Millions) | | | | | | (In Millions) |
| Electricity swaps | | $165 | | Unit contingent discount | | +/-3% | | $10 |
| Electricity options | | $50 | | Implied volatility | | +/-130% | | $43 |
|
| | | | | | | | |
| Transaction Type | | Fair Value as of December 31, 2017 | | Significant Unobservable Inputs | | Range from Average % | | Effect on Fair Value |
| | (In Millions) | | | | | | (In Millions) |
| Power contracts - electricity swaps | | ($65) | | Unit contingent discount | | +/- 4% - 4.75% | | $6 - $7 |
The following table sets forth an analysis of each of the types of unobservable inputs impacting the fair value of items classified as Level 3 within the fair value hierarchy, and the sensitivity to changes to those inputs:
|
| | | | | | | | |
Significant Unobservable Input | | Transaction Type | | Position | | Change to Input | | Effect on Fair Value |
| | | | | | | | | |
| Unit contingent discount | | Electricity swaps | | Sell | | Increase (Decrease) | | Decrease (Increase) |
Implied volatility | | Electricity options | | Sell | | Increase (Decrease) | | Increase (Decrease) |
Implied volatility | | Electricity options | | Buy | | Increase (Decrease) | | Increase (Decrease) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The following table sets forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ assets that are accounted for at fair value on a recurring basis as of December 31, 20142017 and December 31, 2013.2016. The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect its placement within the fair value hierarchy levels.
Entergy Arkansas
| | | 2014 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2017 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | |
| $208.0 |
| |
| $— |
| |
| $— |
| |
| $208.0 |
| |
| Decommissioning trust funds (a): | | | | | | | | | | | | | | | | |
| Equity securities | | 7.2 |
| | 480.1 |
| (b) | — |
| | 487.3 |
| |
| $11.7 |
| |
| $— |
| |
| $— |
| |
| $11.7 |
|
| Debt securities | | 72.2 |
| | 210.4 |
| | — |
| | 282.6 |
| | 115.8 |
| | 232.4 |
| | — |
| | 348.2 |
|
| Common trusts (b) | | | | | | | | | 585.0 |
|
| Securitization recovery trust account | | 4.1 |
| | — |
| | — |
| | 4.1 |
| | 3.7 |
| | — |
| | — |
| | 3.7 |
|
| Escrow accounts | | 12.2 |
| | — |
| | — |
| | 12.2 |
| | 2.4 |
| | — |
| | — |
| | 2.4 |
|
| FTRs | | — |
| | — |
| | 0.7 |
| | 0.7 |
| |
| Financial transmission rights | | | — |
| | — |
| | 3.0 |
| | 3.0 |
|
| | |
| $303.7 |
| |
| $690.5 |
| |
| $0.7 |
| |
| $994.9 |
| |
| $133.6 |
| |
| $232.4 |
| |
| $3.0 |
| |
| $954.0 |
|
| | | 2013 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2016 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | |
| $122.8 |
| |
| $— |
| |
| $— |
| |
| $122.8 |
| |
| Decommissioning trust funds (a): | | | | | | | | | | | | | | | | |
| Equity securities | | 13.6 |
| | 449.7 |
| (b) | — |
| | 463.3 |
| |
| $3.6 |
| |
| $— |
| |
| $— |
| |
| $3.6 |
|
| Debt securities | | 58.6 |
| | 189.0 |
| | — |
| | 247.6 |
| | 112.5 |
| | 196.8 |
| | — |
| | 309.3 |
|
| Common trusts (b) | | | | | | | | | 521.8 |
|
| Securitization recovery trust account | | 3.8 |
| | — |
| | — |
| | 3.8 |
| | 4.1 |
| | — |
| | — |
| | 4.1 |
|
| Escrow accounts | | 26.0 |
| | — |
| | — |
| | 26.0 |
| | 7.1 |
| | — |
| | — |
| | 7.1 |
|
| Financial transmission rights | | | — |
| | — |
| | 5.4 |
| | 5.4 |
|
| | |
| $224.8 |
| |
| $638.7 |
| |
| $— |
| |
| $863.5 |
| |
| $127.3 |
| |
| $196.8 |
| |
| $5.4 |
| |
| $851.3 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Gulf States Louisiana
| | | 2014 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2017 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | |
| $109.6 |
| |
| $— |
| |
| $— |
| |
| $109.6 |
| |
| $30.1 |
| |
| $— |
| |
| $— |
| |
| $30.1 |
|
| Decommissioning trust funds (a): | | | | | | | | | | | | | | | | |
| Equity securities | | 10.5 |
| | 385.4 |
| (b) | — |
| | 395.9 |
| | 15.2 |
| | — |
| | — |
| | 15.2 |
|
| Debt securities | | 81.9 |
| | 159.9 |
| | — |
| | 241.8 |
| | 143.3 |
| | 350.5 |
| | — |
| | 493.8 |
|
| Common trusts (b) | | | | | | | | | 803.1 |
|
| Escrow accounts | | 90.1 |
| | — |
| | — |
| | 90.1 |
| | 289.5 |
| | — |
| | — |
| | 289.5 |
|
| FTRs | | — |
| | — |
| | 14.4 |
| | 14.4 |
| |
| | |
| $292.1 |
| |
| $545.3 |
| |
| $14.4 |
| |
| $851.8 |
| |
| Securitization recovery trust account | | | 2.0 |
| | — |
| | — |
| | 2.0 |
|
| Financial transmission rights | | | — |
| | — |
| | 10.2 |
| | 10.2 |
|
| | | | | | | | | | |
| $480.1 |
| |
| $350.5 |
| |
| $10.2 |
| |
| $1,643.9 |
|
| Liabilities: | | | | | | | | | | | | | | | | |
| Gas hedge contracts | |
| $8.2 |
| |
| $— |
| |
| $— |
| |
| $8.2 |
| |
| $5.0 |
| |
| $— |
| |
| $— |
| |
| $5.0 |
|
|
| | | | | | | | | | | | | | | | |
| 2016 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $163.9 |
| |
| $— |
| |
| $— |
| |
| $163.9 |
|
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | | 13.9 |
| | — |
| | — |
| | 13.9 |
|
| Debt securities | | 132.3 |
| | 292.5 |
| | — |
| | 424.8 |
|
| Common trusts (b) | | | | | | | | 702.0 |
|
| Escrow accounts | | 305.7 |
| | — |
| | — |
| | 305.7 |
|
| Securitization recovery trust account | | 2.8 |
| | — |
| | — |
| | 2.8 |
|
| Gas hedge contracts | | 10.9 |
| | — |
| | — |
| | 10.9 |
|
| Financial transmission rights | | — |
| | — |
| | 8.5 |
| | 8.5 |
|
| | |
| $629.5 |
| |
| $292.5 |
| |
| $8.5 |
| |
| $1,632.5 |
|
Entergy Mississippi
|
| | | | | | | | | | | | | | | | |
| 2017 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $4.5 |
| |
| $— |
| |
| $— |
| |
| $4.5 |
|
| Escrow accounts | | 32.0 |
| | — |
| | — |
| | 32.0 |
|
| Financial transmission rights | | — |
| | — |
| | 2.1 |
| | 2.1 |
|
| | |
| $36.5 |
| |
| $— |
| |
| $2.1 |
| |
| $38.6 |
|
| Liabilities: | | | | | | | | |
| Gas hedge contracts | |
| $1.2 |
| |
| $— |
| |
| $— |
| |
| $1.2 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | |
| 2016 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $76.8 |
| |
| $— |
| |
| $— |
| |
| $76.8 |
|
| Escrow accounts | | 31.8 |
| | — |
| | — |
| | 31.8 |
|
| Gas hedge contracts | | 2.3 |
| | — |
| | — |
| | 2.3 |
|
| Financial transmission rights | | — |
| | — |
| | 3.2 |
| | 3.2 |
|
| | |
| $110.9 |
| |
| $— |
| |
| $3.2 |
| |
| $114.1 |
|
Entergy New Orleans
|
| | | | | | | | | | | | | | | | |
| 2017 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $32.7 |
| |
| $— |
| |
| $— |
| |
| $32.7 |
|
| Securitization recovery trust account | | 1.5 |
| | — |
| | — |
| | 1.5 |
|
| Escrow accounts | | 81.9 |
| | — |
| | — |
| | 81.9 |
|
| Financial transmission rights | | — |
| | — |
| | 2.2 |
| | 2.2 |
|
| | |
| $116.1 |
| |
| $— |
| |
| $2.2 |
| |
| $118.3 |
|
| Liabilities: | | | | | | | | |
| Gas hedge contracts | |
| $0.2 |
| |
| $— |
| |
| $— |
| |
| $0.2 |
|
|
| | | | | | | | | | | | | | | | |
| 2016 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $103.0 |
| |
| $— |
| |
| $— |
| |
| $103.0 |
|
| Securitization recovery trust account | | 1.7 |
| | — |
| | — |
| | 1.7 |
|
| Escrow accounts | | 88.6 |
| | — |
| | — |
| | 88.6 |
|
| Gas hedge contracts | | 0.2 |
| | — |
| | — |
| | 0.2 |
|
| Financial transmission rights | | — |
| | — |
| | 1.1 |
| | 1.1 |
|
| | |
| $193.5 |
| |
| $— |
| |
| $1.1 |
| |
| $194.6 |
|
Entergy Texas
|
| | | | | | | | | | | | | | | | |
| 2017 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
Assets: | | | | | | | | |
| Temporary cash investments | |
| $115.5 |
| |
| $— |
| |
| $— |
| |
| $115.5 |
|
| Securitization recovery trust account | | 37.7 |
| | — |
| | — |
| | 37.7 |
|
| Financial transmission rights | | — |
| | — |
| | 3.4 |
| | 3.4 |
|
| | |
| $153.2 |
| |
| $— |
| |
| $3.4 |
| |
| $156.6 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | |
| 2013 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $13.8 |
| |
| $— |
| |
| $— |
| |
| $13.8 |
|
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | | 27.6 |
| | 343.2 |
| (b) | — |
| | 370.8 |
|
| Debt securities | | 71.7 |
| | 131.2 |
| | — |
| | 202.9 |
|
| Escrow accounts | | 21.5 |
| | — |
| | — |
| | 21.5 |
|
| Gas hedge contracts | | 2.2 |
| | — |
| | — |
| | 2.2 |
|
| FTRs | | — |
| | — |
| | 6.7 |
| | 6.7 |
|
| | |
| $136.8 |
| |
| $474.4 |
| |
| $6.7 |
| |
| $617.9 |
|
Entergy Louisiana
|
| | | | | | | | | | | | | | | | |
| 2014 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $157.1 |
| |
| $— |
| |
| $— |
| |
| $157.1 |
|
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | | 4.8 |
| | 234.8 |
| (b) | — |
| | 239.6 |
|
| Debt securities | | 68.7 |
| | 75.3 |
| | — |
| | 144.0 |
|
| Securitization recovery trust account | | 3.1 |
| | — |
| | — |
| | 3.1 |
|
| Escrow accounts | | 200.1 |
| | — |
| | — |
| | 200.1 |
|
| FTRs | | — |
| | — |
| | 11.1 |
| | 11.1 |
|
| | |
| $433.8 |
| |
| $310.1 |
| |
| $11.1 |
| |
| $755.0 |
|
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | |
| $7.6 |
| |
| $— |
| |
| $— |
| |
| $7.6 |
|
|
| | | | | | | | | | | | | | | | |
| 2013 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $123.6 |
| |
| $— |
| |
| $— |
| |
| $123.6 |
|
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | | 13.5 |
| | 210.7 |
| (b) | — |
| | 224.2 |
|
| Debt securities | | 61.7 |
| | 61.4 |
| | — |
| | 123.1 |
|
| Securitization recovery trust account | | 4.5 |
| | — |
| | — |
| | 4.5 |
|
| Gas hedge contracts | | 2.9 |
| | — |
| | — |
| | 2.9 |
|
| FTRs | | — |
| | — |
| | 5.7 |
| | 5.7 |
|
| | |
| $206.2 |
| |
| $272.1 |
| |
| $5.7 |
| |
| $484.0 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Mississippi
|
| | | | | | | | | | | | | | | | |
| 2014 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $60.4 |
| |
| $— |
| |
| $— |
| |
| $60.4 |
|
| Escrow accounts | | 41.8 |
| | — |
| | — |
| | 41.8 |
|
| FTRs | | — |
| | — |
| | 3.4 |
| | 3.4 |
|
| | |
| $102.2 |
| |
| $— |
| |
| $3.4 |
| |
| $105.6 |
|
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | |
| $2.8 |
| |
| $— |
| |
| $— |
| |
| $2.8 |
|
|
| | | | | | | | | | | | | | | | |
| 2013 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Escrow accounts | |
| $51.8 |
| |
| $— |
| |
| $— |
| |
| $51.8 |
|
| Gas hedge contracts | | 0.7 |
| | — |
| | — |
| | 0.7 |
|
| FTRs | | — |
| | — |
| | 1.0 |
| | 1.0 |
|
| | |
| $52.5 |
| |
| $— |
| |
| $1.0 |
| |
| $53.5 |
|
Entergy New Orleans
|
| | | | | | | | | | | | | | | | |
| 2014 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $41.4 |
| |
| $— |
| |
| $— |
| |
| $41.4 |
|
| Escrow accounts | | 18.0 |
| | — |
| | — |
| | 18.0 |
|
| FTRs | | — |
| | — |
| | 4.1 |
| | 4.1 |
|
| | |
| $59.4 |
| |
| $— |
| |
| $4.1 |
| |
| $63.5 |
|
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | |
| $0.9 |
| |
| $— |
| |
| $— |
| |
| $0.9 |
|
|
| | | | | | | | | | | | | | | | |
| 2013 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $33.2 |
| |
| $— |
| |
| $— |
| |
| $33.2 |
|
| Escrow accounts | | 10.5 |
| | — |
| | — |
| | 10.5 |
|
| Gas hedge contracts | | 0.1 |
| | — |
| | — |
| | 0.1 |
|
| FTRs | | — |
| | — |
| | 2.0 |
| | 2.0 |
|
| | |
| $43.8 |
| |
| $— |
| |
| $2.0 |
| |
| $45.8 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Texas
|
| | | | | | | | | | | | | | | | |
| 2014 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
Assets: | | | | | | | | |
| Temporary cash investments | |
| $28.7 |
| |
| $— |
| |
| $— |
| |
| $28.7 |
|
| Securitization recovery trust account | | 37.2 |
| | — |
| | — |
| | 37.2 |
|
| FTRs | | — |
| | — |
| | 12.3 |
| | 12.3 |
|
| | |
| $65.9 |
| |
| $— |
| |
| $12.3 |
| |
| $78.2 |
|
| | | 2013 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2016 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) | | (In Millions) |
Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | |
| $44.1 |
| |
| $— |
| |
| $— |
| |
| $44.1 |
| |
| $5.0 |
| |
| $— |
| |
| $— |
| |
| $5.0 |
|
| Securitization recovery trust account | | 37.5 |
| | — |
| | — |
| | 37.5 |
| | 37.5 |
| | — |
| | — |
| | 37.5 |
|
| FTRs | | — |
| | — |
| | 18.4 |
| | 18.4 |
| |
| Financial transmission rights | | | — |
| | — |
| | 3.1 |
| | 3.1 |
|
| | |
| $81.6 |
| |
| $— |
| |
| $18.4 |
| |
| $100.0 |
| |
| $42.5 |
| |
| $— |
| |
| $3.1 |
| |
| $45.6 |
|
System Energy
| | | 2014 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2017 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | |
| $222.4 |
| |
| $— |
| |
| $— |
| |
| $222.4 |
| |
| $287.1 |
| |
| $— |
| |
| $— |
| |
| $287.1 |
|
| Decommissioning trust funds (a): | | | | | | | | | | | | | | | | |
| Equity securities | | 2.0 |
| | 422.5 |
| (b) | — |
| | 424.5 |
| | 3.1 |
| | — |
| | — |
| | 3.1 |
|
| Debt securities | | 194.2 |
| | 61.1 |
| | — |
| | 255.3 |
| | 187.2 |
| | 143.3 |
| | — |
| | 330.5 |
|
| Common trusts (b) | | | | | | | | | 572.1 |
|
| | |
| $418.6 |
| |
| $483.6 |
| |
| $— |
| |
| $902.2 |
| |
| $477.4 |
| |
| $143.3 |
| |
| $— |
| |
| $1,192.8 |
|
| | | 2013 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2016 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | |
| $64.6 |
| |
| $— |
| |
| $— |
| |
| $64.6 |
| |
| $245.1 |
| |
| $— |
| |
| $— |
| |
| $245.1 |
|
| Decommissioning trust funds (a): | | | | | | | | | | | | | | | | |
| Equity securities | | 2.2 |
| | 377.8 |
| (b) | — |
| | 380.0 |
| | 0.3 |
| | — |
| | — |
| | 0.3 |
|
| Debt securities | | 152.9 |
| | 71.0 |
| | — |
| | 223.9 |
| | 248.3 |
| | 58.3 |
| | — |
| | 306.6 |
|
| Common trusts (b) | | | | | | | | | 473.6 |
|
| | |
| $219.7 |
| |
| $448.8 |
| |
| $— |
| |
| $668.5 |
| |
| $493.7 |
| |
| $58.3 |
| |
| $— |
| |
| $1,025.6 |
|
| |
| (a) | The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices. Fixed income securities are held in various governmental and corporate securities. See Note 179 to the financial statements for additional information on the investment portfolios. |
| |
| (b) | Commingled equityCommon trust funds may be redeemed semi-monthly.are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the year ended December 31, 2014.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Gulf States Louisiana |
| Entergy Louisiana |
| Entergy Mississippi |
| Entergy New Orleans |
| Entergy Texas |
| | (In Millions) |
| | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance as of January 1, |
| $— |
| |
| $6.7 |
| |
| $5.7 |
| |
| $1.0 |
| |
| $2.0 |
| |
| $18.4 |
|
| Issuances of FTRs | 4.2 |
| | 37.3 |
| | 21.5 |
| | 15.2 |
| | 8.3 |
| | 33.2 |
|
| Unrealized gains (losses) included as a regulatory liability / asset | 18.1 |
| | 26.7 |
| | 31.1 |
| | 6.2 |
| | 10.3 |
| | 26.5 |
|
| Settlements | (21.6 | ) | | (56.3 | ) | | (47.2 | ) | | (19.0 | ) | | (16.5 | ) | | (65.8 | ) |
| Balance as of December 31, |
| $0.7 |
| |
| $14.4 |
| |
| $11.1 |
| |
| $3.4 |
| |
| $4.1 |
| |
| $12.3 |
|
The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the year ended December 31, 2013.2017.
| | | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | Entergy Arkansas | | Entergy Louisiana |
| Entergy Mississippi |
| Entergy New Orleans |
| Entergy Texas |
| | (In Millions) | (In Millions) |
| | | | | | | | | | | | | | |
|
|
|
|
|
|
|
|
|
|
|
| Balance as of January 1, |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
| $5.4 |
| |
| $8.5 |
| |
| $3.2 |
| |
| $1.1 |
| |
| $3.1 |
|
| Issuances of FTRs | — |
| | 7.2 |
| | 6.2 |
| | 1.1 |
| | 2.2 |
| | 20.0 |
| |
| Unrealized gains (losses) included as a regulatory liability / asset | (0.1 | ) | | (0.2 | ) | | (0.3 | ) | | 0.9 |
| | 1.0 |
| | (0.8 | ) | |
| Issuances of financial transmission rights | | 8.9 |
| | 31.0 |
| | 9.6 |
| | 5.0 |
| | 7.1 |
|
| Gains (losses) included as a regulatory liability/asset | | 30.4 |
| | 16.5 |
| | 8.2 |
| | 5.2 |
| | 15.5 |
|
| Settlements | 0.1 |
| | (0.3 | ) | | (0.2 | ) | | (1.0 | ) | | (1.2 | ) | | (0.8 | ) | (41.7 | ) | | (45.8 | ) | | (18.9 | ) | | (9.1 | ) | | (22.3 | ) |
| Balance as of December 31, |
| $— |
| |
| $6.7 |
| |
| $5.7 |
| |
| $1.0 |
| |
| $2.0 |
| |
| $18.4 |
|
| $3.0 |
| |
| $10.2 |
| |
| $2.1 |
| |
| $2.2 |
| |
| $3.4 |
|
The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the year ended December 31, 2016.
|
| | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | (In Millions) |
| | | | | | | | | | |
| Balance as of January 1, |
| $7.9 |
| |
| $8.5 |
| |
| $2.4 |
| |
| $1.5 |
| |
| $2.2 |
|
| Issuances of financial transmission rights | 18.8 |
| | 18.1 |
| | 5.9 |
| | 2.8 |
| | 9.3 |
|
| Gains included as a regulatory liability/asset | 1.9 |
| | 51.6 |
| | 11.5 |
| | 0.9 |
| | 1.8 |
|
| Settlements | (23.2 | ) | | (69.7 | ) | | (16.6 | ) | | (4.1 | ) | | (10.2 | ) |
| Balance as of December 31, |
| $5.4 |
| |
| $8.5 |
| |
| $3.2 |
| |
| $1.1 |
| |
| $3.1 |
|
NOTE 17.16. DECOMMISSIONING TRUST FUNDS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy)
Entergy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The NRC requires Entergy subsidiaries to maintain trusts to fund the costs of decommissioning ANO 1, ANO 2, River Bend, Waterford 3, Grand Gulf, Pilgrim, Indian Point 1, andIndian Point 2, Indian Point 3, Vermont Yankee, and Palisades (NYPA currently retains the decommissioning trusts and liabilities for Indian Point 3 and FitzPatrick).Palisades. The funds are invested primarily in equity securities, fixed-rate debt securities, and cash and cash equivalents.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specified their decommissioning obligations. At the time of the acquisition of the plants Entergy recorded a contract asset that represented an estimate of the present value of the difference between the stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies.
In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy. The transaction
Entergy Corporation and Subsidiaries
Notes to Financial Statements
was contingent upon receiving approval from the NRC, which was received in January 2017. As a result of the agreement with NYPA, in the third quarter 2016, Entergy removed the contract asset from its balance sheet, and recorded receivables for the beneficial interests in the decommissioning trust funds and recorded asset retirement obligations for the decommissioning liabilities. At December 31, 2016, the fair values of the decommissioning trust funds held by NYPA were $719 million for the Indian Point 3 plant and $785 million for the FitzPatrick plant. The fair values were based on the trust statements received from NYPA and were valued by the fund administrator using net asset value as a practical expedient. Accordingly, these funds were not assigned a level in the fair value hierarchy. For Indian Point 3, the receivable for the beneficial interest in the decommissioning trust fund was recorded in other deferred debits on the consolidated balance sheet as of December 31, 2016. For FitzPatrick, the receivable for the beneficial interest in the decommissioning trust fund was classified as held for sale within other deferred debits on the consolidated balance sheet as of December 31, 2016. In January 2017, NYPA transferred to Entergy the Indian Point 3 decommissioning trust funds with a fair value of $726 million and the FitzPatrick decommissioning trust fund with a fair value of $793 million. In March 2017, Entergy closed on the sale of the FitzPatrick plant to Exelon. As part of the transaction, Entergy transferred the FitzPatrick decommissioning trust fund to Exelon. The FitzPatrick decommissioning trust fund had a disposition-date fair value of $805 million. See Note 9 to the financial statements for further discussion of the decommissioning agreements with NYPA and see Note 14 to the financial statements for further discussion of the sale of FitzPatrick.
Entergy records decommissioning trust funds on the balance sheet at their fair value. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the 30% interest in River Bend formerly owned by Cajun, Entergy Gulf States Louisiana has recordedrecords an offsetting amount of unrealized gains/(losses) in other deferred credits.credits for the excess trust earnings not currently expected to be needed to decommission the plant. Decommissioning trust funds for Pilgrim, Indian Point 1, andIndian Point 2, Indian Point 3, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of shareholders’ equity because these assets are classified as available for sale. Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of shareholders’ equity unless the unrealized loss is other than temporary and therefore recorded in earnings. Generally, Entergy records
Entergy Corporation and Subsidiaries
Notes to Financial Statements
realized gains and losses on its debt and equity securities using the specific identification method to determine the cost basis of its securities.
The securities held as of December 31, 20142017 and 20132016 are summarized as follows:
| | | | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | 2017 | | 2016 |
| | | (In Millions) | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| 2014 | | |
| | |
| | |
| |
| | | | (In Millions) |
| Equity Securities | |
| $3,286 |
| |
| $1,513 |
| |
| $1 |
| |
| $4,662 |
| |
| $2,131 |
| |
| $1 |
| |
| $3,511 |
| |
| $1,673 |
| |
| $1 |
|
| Debt Securities | | 2,085 |
| | 76 |
| | 6 |
| | 2,550 |
| | 44 |
| | 16 |
| | 2,213 |
| | 34 |
| | 27 |
|
| Total | |
| $5,371 |
| |
| $1,589 |
| |
| $7 |
| |
| $7,212 |
| |
| $2,175 |
| |
| $17 |
| |
| $5,724 |
| |
| $1,707 |
| |
| $28 |
|
The fair values of the decommissioning trust funds related to the Entergy Wholesale Commodities nuclear plants as of December 31, 2017 are $491 million for Indian Point 1, $621 million for Indian Point 2, $798 million for Indian Point 3, $458 million for Palisades, $1,068 million for Pilgrim, and $613 million for Vermont Yankee. The fair values of the decommissioning trust funds related to the Entergy Wholesale Commodities nuclear plants as of December 31, 2016 are $443 million for Indian Point 1, $564 million for Indian Point 2, $412 million for Palisades, $960 million for Pilgrim, and $584 million for Vermont Yankee. The fair values of the decommissioning trust funds for the Registrant Subsidiaries’ nuclear plants are detailed below.
|
| | | | | | | | | | | | |
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| 2013 | | |
| | |
| | |
|
| Equity Securities | |
| $3,073 |
| |
| $1,260 |
| |
| $— |
|
| Debt Securities | | 1,830 |
| | 47 |
| | 29 |
|
| Total | |
| $4,903 |
| |
| $1,307 |
| |
| $29 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Deferred taxes on unrealized gains/(losses) are recorded in other comprehensive income (loss) for the decommissioning trusts which do not meet the criteria for regulatory accounting treatment as described above. Unrealized gains/(losses) above are reported before deferred taxes of $396$479 million and $329$399 million as of December 31, 20142017 and 2013,2016, respectively. The amortized cost of debt securities was $2,019$2,539 million as of December 31, 20142017 and $1,843$2,212 million as of December 31, 2013.2016. As of December 31, 2014,2017, the debt securities have an average coupon rate of approximately 3.31%3.24%, an average duration of approximately 5.656.33 years, and an average maturity of approximately 8.459.99 years. The equity securities are generally held in funds that are designed to approximate or somewhat exceed the return of the Standard & Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index or the Russell 3000 Index.
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2014:2017 and 2016:
| | | | | | | | | | | | 2017 | | 2016 |
| | Equity Securities | | Debt Securities | Equity Securities | | Debt Securities | | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) | (In Millions) |
| Less than 12 months |
| $9 |
| |
| $1 |
| |
| $277 |
| |
| $2 |
|
| $8 |
| |
| $1 |
| |
| $1,099 |
| |
| $7 |
| |
| $23 |
| |
| $1 |
| |
| $1,169 |
| |
| $26 |
|
| More than 12 months | — |
| | — |
| | 163 |
| | 4 |
| — |
| | — |
| | 265 |
| | 9 |
| | 1 |
| | — |
| | 20 |
| | 1 |
|
| Total |
| $9 |
| |
| $1 |
| |
| $440 |
| |
| $6 |
|
| $8 |
| |
| $1 |
| |
| $1,364 |
| |
| $16 |
| |
| $24 |
| |
| $1 |
| |
| $1,189 |
| |
| $27 |
|
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2017 and 2016 are as follows:
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
| less than 1 year |
| $74 |
| |
| $125 |
|
| 1 year - 5 years | 902 |
| | 763 |
|
| 5 years - 10 years | 812 |
| | 719 |
|
| 10 years - 15 years | 147 |
| | 109 |
|
| 15 years - 20 years | 100 |
| | 73 |
|
| 20 years+ | 515 |
| | 424 |
|
| Total |
| $2,550 |
| |
| $2,213 |
|
During the years ended December 31, 2017, 2016, and 2015, proceeds from the dispositions of securities amounted to $3,163 million, $2,409 million, and $2,492 million, respectively. During the years ended December 31, 2017, 2016, and 2015, gross gains of $149 million, $32 million, and $72 million, respectively, and gross losses of $13 million, $13 million, and $13 million, respectively, were reclassified out of other comprehensive income into earnings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2013:
|
| | | | | | | | | | | | | | | |
| | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) |
| Less than 12 months |
| $— |
| |
| $— |
| |
| $892 |
| |
| $24 |
|
| More than 12 months | — |
| | — |
| | 60 |
| | 5 |
|
| Total |
| $— |
| |
| $— |
| |
| $952 |
| |
| $29 |
|
The unrealized losses in excess of twelve months on equity securities above relate to Entergy’s Utility operating companies and System Energy.
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2014 and 2013 are as follows:
|
| | | | | | | |
| | 2014 | | 2013 |
| | (In Millions) |
| less than 1 year |
| $94 |
| |
| $83 |
|
| 1 year - 5 years | 783 |
| | 752 |
|
| 5 years - 10 years | 681 |
| | 620 |
|
| 10 years - 15 years | 173 |
| | 169 |
|
| 15 years - 20 years | 79 |
| | 52 |
|
| 20 years+ | 275 |
| | 154 |
|
| Total |
| $2,085 |
| |
| $1,830 |
|
During the years ended December 31, 2014, 2013, and 2012, proceeds from the dispositions of securities amounted to $1,872 million, $2,032 million, and $2,074 million, respectively. During the years ended December 31, 2014, 2013, and 2012, gross gains of $39 million, $91 million, and $39 million, respectively, and gross losses of $8 million, $11 million, and $7 million, respectively, were reclassified out of other comprehensive income into earnings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas
Entergy Arkansas holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 20142017 and 20132016 are summarized as follows:
| | | | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | 2017 | | 2016 |
| | | (In Millions) | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| 2014 | | | | | | | |
| | | | (In Millions) |
| Equity Securities | |
| $487.3 |
| |
| $248.9 |
| |
| $— |
| |
| $596.7 |
| |
| $354.9 |
| |
| $— |
| |
| $525.4 |
| |
| $281.5 |
| |
| $— |
|
| Debt Securities | | 282.6 |
| | 6.2 |
| | 1.1 |
| | 348.2 |
| | 2.1 |
| | 3.0 |
| | 309.3 |
| | 3.4 |
| | 4.2 |
|
| Total | |
| $769.9 |
| |
| $255.1 |
| |
| $1.1 |
| |
| $944.9 |
| |
| $357.0 |
| |
| $3.0 |
| |
| $834.7 |
| |
| $284.9 |
| |
| $4.2 |
|
| 2013 | | | | | | | |
| Equity Securities | |
| $463.3 |
| |
| $214.0 |
| |
| $— |
| |
| Debt Securities | | 247.6 |
| | 5.3 |
| | 5.2 |
| |
| Total | |
| $710.9 |
| |
| $219.3 |
| |
| $5.2 |
| |
The amortized cost of debt securities was $277.4$349.1 million as of December 31, 20142017 and $248.9$310.1 million as of December 31, 2013.2016. As of December 31, 2014,2017, the debt securities have an average coupon rate of approximately 2.55%2.64%, an average duration of approximately 4.685.61 years, and an average maturity of approximately 5.327.00 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2014:2017 and 2016:
| | | | | | | | | | | | 2017 | | 2016 |
| | Equity Securities | | Debt Securities | Equity Securities | | Debt Securities | | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) | (In Millions) |
| Less than 12 months |
| $0.1 |
| |
| $— |
| |
| $56.5 |
| |
| $0.3 |
|
| $— |
| |
| $— |
| |
| $168.0 |
| |
| $1.2 |
| |
| $— |
| |
| $— |
| |
| $146.7 |
| |
| $4.2 |
|
| More than 12 months | — |
| | — |
| | 34.8 |
| | 0.8 |
| — |
| | — |
| | 41.4 |
| | 1.8 |
| | — |
| | — |
| | — |
| | — |
|
| Total |
| $0.1 |
| |
| $— |
| |
| $91.3 |
| |
| $1.1 |
|
| $— |
| |
| $— |
| |
| $209.4 |
| |
| $3.0 |
| |
| $— |
| |
| $— |
| |
| $146.7 |
| |
| $4.2 |
|
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as followscontractual maturities, as of December 31, 2013:2017 and 2016 are as follows:
|
| | | | | | | | | | | | | | | |
| | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) |
| Less than 12 months |
| $— |
| |
| $— |
| |
| $153.2 |
| |
| $4.8 |
|
| More than 12 months | — |
| | — |
| | 6.9 |
| | 0.4 |
|
| Total |
| $— |
| |
| $— |
| |
| $160.1 |
| |
| $5.2 |
|
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
| less than 1 year |
| $13.0 |
| |
| $16.7 |
|
| 1 year - 5 years | 123.4 |
| | 106.2 |
|
| 5 years - 10 years | 180.6 |
| | 161.2 |
|
| 10 years - 15 years | 4.8 |
| | 7.7 |
|
| 15 years - 20 years | 3.4 |
| | 1.0 |
|
| 20 years+ | 23.0 |
| | 16.5 |
|
| Total |
| $348.2 |
| |
| $309.3 |
|
During the years ended December 31, 2017, 2016, and 2015, proceeds from the dispositions of securities amounted to $339.4 million, $197.4 million, and $213 million, respectively. During the years ended December 31,
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2014 and 2013 are as follows:
|
| | | | | | | |
| | 2014 | | 2013 |
| | (In Millions) |
| less than 1 year |
| $14.9 |
| |
| $8.1 |
|
| 1 year - 5 years | 127.3 |
| | 110.9 |
|
| 5 years - 10 years | 128.2 |
| | 118.0 |
|
| 10 years - 15 years | 1.7 |
| | 3.9 |
|
| 15 years - 20 years | 1.0 |
| | 0.9 |
|
| 20 years+ | 9.5 |
| | 5.8 |
|
| Total |
| $282.6 |
| |
| $247.6 |
|
During the years ended December 31, 2014, 2013,2017, 2016, and 2012, proceeds from the dispositions of securities amounted to $181.5 million, $266.4 million, and $144.3 million, respectively. During the years ended December 31, 2014, 2013, and 2012,2015, gross gains of $8.7$17.7 million, $16.8$1.8 million, and $3.4$5.9 million, respectively, and gross losses of $0.3 million, $0.6 million, $0.8 million, and $0.1$0.3 million, respectively, were recorded in earnings.
Entergy Gulf States Louisiana
Entergy Gulf States Louisiana holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 2014 and 2013 are summarized as follows:
|
| | | | | | | | | | | | |
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| 2014 | | | | | | |
| Equity Securities | |
| $395.9 |
| |
| $177.6 |
| |
| $— |
|
| Debt Securities | | 241.8 |
| | 11.9 |
| | 0.3 |
|
| Total | |
| $637.7 |
| |
| $189.5 |
| |
| $0.3 |
|
| 2013 | | | | | | |
| Equity Securities | |
| $370.8 |
| |
| $141.8 |
| |
| $— |
|
| Debt Securities | | 202.9 |
| | 7.4 |
| | 3.5 |
|
| Total | |
| $573.7 |
| |
| $149.2 |
| |
| $3.5 |
|
The amortized cost of debt securities was $231.5 million as of December 31, 2014 and $199.1 million as of December 31, 2013. As of December 31, 2014, the debt securities have an average coupon rate of approximately 4.40%, an average duration of approximately 5.87 years, and an average maturity of approximately 11.13 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2014:
|
| | | | | | | | | | | | | | | |
| | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) |
| Less than 12 months |
| $0.1 |
| |
| $— |
| |
| $14.0 |
| |
| $0.1 |
|
| More than 12 months | — |
| | — |
| | 15.0 |
| | 0.2 |
|
| Total |
| $0.1 |
| |
| $— |
| |
| $29.0 |
| |
| $0.3 |
|
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2013:
|
| | | | | | | | | | | | | | | |
| | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) |
| Less than 12 months |
| $— |
| |
| $— |
| |
| $91.9 |
| |
| $3.1 |
|
| More than 12 months | — |
| | — |
| | 4.6 |
| | 0.4 |
|
| Total |
| $— |
| |
| $— |
| |
| $96.5 |
| |
| $3.5 |
|
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2014 and 2013 are as follows:
|
| | | | | | | |
| | 2014 | | 2013 |
| | (In Millions) |
| less than 1 year |
| $6.4 |
| |
| $7.9 |
|
| 1 year - 5 years | 59.8 |
| | 51.2 |
|
| 5 years - 10 years | 68.3 |
| | 75.5 |
|
| 10 years - 15 years | 43.6 |
| | 55.8 |
|
| 15 years - 20 years | 14.8 |
| | 4.6 |
|
| 20 years+ | 48.9 |
| | 7.9 |
|
| Total |
| $241.8 |
| |
| $202.9 |
|
During the years ended December 31, 2014, 2013, and 2012, proceeds from the dispositions of securities amounted to $173.5 million, $193.8 million, and $131.0 million, respectively. During the years ended December 31, 2014, 2013, and 2012, gross gains of $1.9 million, $16.0 million, and $6.7 million, respectively, and gross losses of $0.3 million, $0.1 million, and $0.04 million, respectively, were recorded in earnings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Louisiana
Entergy Louisiana holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 20142017 and 20132016 are summarized as follows:
| | | | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | 2017 | | 2016 |
| | | (In Millions) | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| 2014 | | | | | | | |
| | | | (In Millions) |
| Equity Securities | |
| $239.6 |
| |
| $116.7 |
| |
| $— |
| |
| $818.3 |
| |
| $461.2 |
| |
| $— |
| |
| $715.9 |
| |
| $346.6 |
| |
| $— |
|
| Debt Securities | | 144.0 |
| | 6.9 |
| | 0.4 |
| | 493.8 |
| | 10.9 |
| | 3.6 |
| | 424.8 |
| | 8.0 |
| | 5.0 |
|
| Total | |
| $383.6 |
| |
| $123.6 |
| |
| $0.4 |
| |
| $1,312.1 |
| |
| $472.1 |
| |
| $3.6 |
| |
| $1,140.7 |
| |
| $354.6 |
| |
| $5.0 |
|
| 2013 | | | | | | | |
| Equity Securities | |
| $224.2 |
| |
| $96.1 |
| |
| $— |
| |
| Debt Securities | | 123.1 |
| | 4.7 |
| | 1.9 |
| |
| Total | |
| $347.3 |
| |
| $100.8 |
| |
| $1.9 |
| |
The amortized cost of debt securities was $137.9$490 million as of December 31, 20142017 and $120.6$421.9 million as of December 31, 2013.2016. As of December 31, 2014,2017, the debt securities have an average coupon rate of approximately 3.05%3.88%, an average duration of approximately 5.396.17 years, and an average maturity of approximately 8.3912.06 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2014:2017 and 2016:
| | | | | | | | | | | | 2017 | | 2016 |
| | Equity Securities | | Debt Securities | Equity Securities | | Debt Securities | | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) | (In Millions) |
| Less than 12 months |
| $0.1 |
| |
| $— |
| |
| $19.1 |
| |
| $0.1 |
|
| $— |
| |
| $— |
| |
| $135.3 |
| |
| $1.1 |
| |
| $— |
| |
| $— |
| |
| $198.8 |
| |
| $4.8 |
|
| More than 12 months | — |
| | — |
| | 12.1 |
| | 0.3 |
| — |
| | — |
| | 84.4 |
| | 2.5 |
| | — |
| | — |
| | 4.8 |
| | 0.2 |
|
| Total |
| $0.1 |
| |
| $— |
| |
| $31.2 |
| |
| $0.4 |
|
| $— |
| |
| $— |
| |
| $219.7 |
| |
| $3.6 |
| |
| $— |
| |
| $— |
| |
| $203.6 |
| |
| $5.0 |
|
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as followscontractual maturities, as of December 31, 2013:2017 and 2016 are as follows:
|
| | | | | | | | | | | | | | | |
| | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) |
| Less than 12 months |
| $— |
| |
| $— |
| |
| $38.3 |
| |
| $1.7 |
|
| More than 12 months | — |
| | — |
| | 1.7 |
| | 0.2 |
|
| Total |
| $— |
| |
| $— |
| |
| $40.0 |
| |
| $1.9 |
|
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In Millions) |
| less than 1 year |
| $23.2 |
| |
| $31.4 |
|
| 1 year - 5 years | 122.8 |
| | 99.1 |
|
| 5 years - 10 years | 109.3 |
| | 122.8 |
|
| 10 years - 15 years | 52.7 |
| | 41.4 |
|
| 15 years - 20 years | 50.7 |
| | 30.9 |
|
| 20 years+ | 135.1 |
| | 99.2 |
|
| Total |
| $493.8 |
| |
| $424.8 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2014 and 2013 are as follows:
|
| | | | | | | |
| | 2014 | | 2013 |
| | (In Millions) |
| less than 1 year |
| $5.6 |
| |
| $14.8 |
|
| 1 year - 5 years | 58.2 |
| | 41.9 |
|
| 5 years - 10 years | 44.2 |
| | 37.0 |
|
| 10 years - 15 years | 7.3 |
| | 6.6 |
|
| 15 years - 20 years | 9.4 |
| | 6.2 |
|
| 20 years+ | 19.3 |
| | 16.6 |
|
| Total |
| $144.0 |
| |
| $123.1 |
|
During the years ended December 31, 2014, 2013,2017, 2016, and 2012,2015, proceeds from the dispositions of securities amounted to $43.2$231.3 million, $109.9$219.2 million, and $27.6$123.5 million, respectively. During the years ended December 31, 2014, 2013,2017, 2016, and 2012,2015, gross gains of $0.3$12 million, $6.0$3.9 million, and $0.2$1.9 million, respectively, and gross losses of $0.02$0.4 million, $0.1$0.4 million, and $0.04$0.3 million, respectively, were recorded in earnings.
System Energy
System Energy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 20142017 and 20132016 are summarized as follows:
| | | | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | 2017 | | 2016 |
| | | (In Millions) | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| 2014 | | | | | | | |
| | | | (In Millions) |
| Equity Securities | |
| $424.5 |
| |
| $188.0 |
| |
| $— |
| |
| $575.2 |
| |
| $308.6 |
| |
| $— |
| |
| $473.9 |
| |
| $221.9 |
| |
| $0.1 |
|
| Debt Securities | | 255.3 |
| | 5.9 |
| | 0.3 |
| | 330.5 |
| | 4.2 |
| | 1.2 |
| | 306.6 |
| | 2.0 |
| | 4.5 |
|
| Total | |
| $679.8 |
| |
| $193.9 |
| |
| $0.3 |
| |
| $905.7 |
| |
| $312.8 |
| |
| $1.2 |
| |
| $780.5 |
| |
| $223.9 |
| |
| $4.6 |
|
| 2013 | | | | | | | |
| Equity Securities | |
| $380.0 |
| |
| $150.8 |
| |
| $— |
| |
| Debt Securities | | 223.9 |
| | 3.5 |
| | 1.8 |
| |
| Total | |
| $603.9 |
| |
| $154.3 |
| |
| $1.8 |
| |
The amortized cost of debt securities was $251$327.5 million as of December 31, 20142017 and $223.4$309.1 million as of December 31, 2013.2016. As of December 31, 2014,2017, the debt securities have an average coupon rate of approximately 2.23%2.67%, an average duration of approximately 4.486.48 years, and an average maturity of approximately 5.959.22 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2014:2017 and 2016:
| | | | | | | | | | | | 2017 | | 2016 |
| | Equity Securities | | Debt Securities | Equity Securities | | Debt Securities | | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) | (In Millions) |
| Less than 12 months |
| $0.1 |
| |
| $— |
| |
| $51.6 |
| |
| $0.2 |
|
| $— |
| |
| $— |
| |
| $196.9 |
| |
| $1.0 |
| |
| $— |
| |
| $— |
| |
| $220.9 |
| |
| $4.4 |
|
| More than 12 months | — |
| | — |
| | 6.5 |
| | 0.1 |
| — |
| | — |
| | 10.4 |
| | 0.2 |
| | — |
| | 0.1 |
| | 0.8 |
| | 0.1 |
|
| Total |
| $0.1 |
| |
| $— |
| |
| $58.1 |
| |
| $0.3 |
|
| $— |
| |
| $— |
| |
| $207.3 |
| |
| $1.2 |
| |
| $— |
| |
| $0.1 |
| |
| $221.7 |
| |
| $4.5 |
|
The fair value
Entergy Corporation and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2013:Subsidiaries
Notes to Financial Statements |
| | | | | | | | | | | | | | | |
| | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) |
| Less than 12 months |
| $— |
| |
| $— |
| |
| $121.7 |
| |
| $1.7 |
|
| More than 12 months | — |
| | — |
| | 0.9 |
| | 0.1 |
|
| Total |
| $— |
| |
| $— |
| |
| $122.6 |
| |
| $1.8 |
|
The fair value of debt securities, summarized by contractual maturities, as of December 31, 20142017 and 20132016 are as follows:
| | | | 2014 | | 2013 | 2017 | | 2016 |
| | (In Millions) | (In Millions) |
| less than 1 year |
| $33.5 |
| |
| $5.5 |
|
| $4.1 |
| |
| $6.6 |
|
| 1 year - 5 years | 139.7 |
| | 144.9 |
| 173.0 |
| | 188.2 |
|
| 5 years - 10 years | 53.5 |
| | 44.3 |
| 78.5 |
| | 78.5 |
|
| 10 years - 15 years | 3.4 |
| | 9.3 |
| 1.0 |
| | 1.3 |
|
| 15 years - 20 years | 3.2 |
| | 1.6 |
| 6.9 |
| | 7.8 |
|
| 20 years+ | 22.0 |
| | 18.3 |
| 67.0 |
| | 24.2 |
|
| Total |
| $255.3 |
| |
| $223.9 |
|
| $330.5 |
| |
| $306.6 |
|
During the years ended December 31, 2014, 2013,2017, 2016, and 2012,2015, proceeds from the dispositions of securities amounted to $392.9$565.4 million, $215.5$499.3 million, and $349.4$390.4 million, respectively. During the years ended December 31, 2014, 2013,2017, 2016, and 2012,2015, gross gains of $1.8$1.4 million, $1.5$3.5 million, and $3.6$3.3 million, respectively, and gross losses of $0.9$3.3 million, $1.3$1.7 million, and $0.3$0.5 million, respectively, were recorded in earnings.
Other-than-temporary impairments and unrealized gains and losses
Entergy evaluates investment securities in the Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy evaluateWholesale Commodities’ nuclear decommissioning trust funds with unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery
Entergy Corporation and Subsidiaries
Notes to Financial Statements
of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). Entergy did not have any material other-than-temporary impairments relating to credit losses on debt securities for the years ended December 31, 2014, 2013,2017, 2016, and 2012.2015. The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment continues to beis based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. Entergy did not record material charges to other income in 2014, 2013, and 2012, respectively,2017, 2016, or 2015 resulting from the recognition of the other-than-temporary impairment of certain equity securities held in its decommissioning trust funds.
NOTE 18.17. VARIABLE INTEREST ENTITIES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Under applicable authoritative accounting guidance, a variable interest entity (VIE) is an entity that conducts a business or holds property that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity holders do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations, and is required to consolidate a VIE if it is the VIE’s primary beneficiary. The primary beneficiary of a VIE is the entity that has the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance, and has the obligation to absorb losses or has the right to residual returns that would potentially be significant to the entity.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy consolidate the respective companies from which they lease nuclear fuel, usually in a sale and leaseback transaction. This is because Entergy directs the nuclear fuel companies with respect to nuclear fuel purchases, assists the nuclear fuel companies in obtaining financing, and, if financing cannot be arranged, the lessee (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, or System Energy) is responsible to repurchase nuclear fuel to allow the nuclear fuel company (the VIE) to meet its obligations. During the term of the arrangements, none of the Entergy operating companies have been required to provide financial support apart from their scheduled lease payments. See Note 4 to the financial statements for details of the nuclear fuel companies’ credit facility and commercial paper borrowings and long-term debt that are reported by Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy. These amounts also represent Entergy’s and the respective Registrant Subsidiary’s maximum exposure to losses associated with their respective interests in the nuclear fuel companies.
Entergy Gulf States Reconstruction Funding I, LLC, and Entergy Texas Restoration Funding, LLC, companies wholly-owned and consolidated by Entergy Texas, are variable interest entities and Entergy Texas is the primary beneficiary. In June 2007, Entergy Gulf States Reconstruction Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas’s Hurricane Rita reconstruction costs. In November 2009, Entergy Texas Restoration Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas’s Hurricane Ike and Hurricane Gustav restoration costs. With the proceeds, the variable interest entities purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of the variable interest entities, including the transition property, and the creditors of the variable interest entities do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to the variable interest entities except to remit transition charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, is a variable interest entity and Entergy Arkansas is the primary beneficiary. In August 2010, Entergy Arkansas Restoration Funding issued storm cost recovery bonds to finance Entergy Arkansas’s January 2009 ice storm damage restoration costs. With the proceeds, Entergy Arkansas Restoration Funding purchased from Entergy Arkansas the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy Arkansas balance sheet. The creditors of Entergy Arkansas do not have recourse to the assets or revenues of Entergy Arkansas Restoration Funding, including the storm recovery property, and the creditors of Entergy Arkansas Restoration Funding do not have recourse to the assets or revenues of Entergy Arkansas. Entergy Arkansas has no payment obligations to Entergy Arkansas Restoration Funding except to remit storm recovery charge collections. See Note 5 to the financial statements for additional details regarding the storm cost recovery bonds.
Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, is a variable interest entity and Entergy Louisiana is the primary beneficiary. In September 2011, Entergy Louisiana Investment Recovery Funding issued investment recovery bonds to recover Entergy Louisiana’s investment recovery costs associated with the canceled Little Gypsy repowering project. With the proceeds, Entergy Louisiana Investment Recovery Funding purchased from Entergy Louisiana the investment recovery property, which is the right to recover from customers through an investment recovery charge amounts sufficient to service the bonds. The investment recovery property is reflected as a regulatory asset on the consolidated Entergy Louisiana balance sheet. The creditors of Entergy Louisiana do not have recourse to the assets or revenues of Entergy Louisiana Investment Recovery Funding, including the investment recovery property, and the creditors of Entergy Louisiana Investment Recovery Funding do not have recourse to the assets or revenues of Entergy Louisiana. Entergy Louisiana has no payment obligations to Entergy Louisiana Investment Recovery Funding except to remit investment recovery charge collections. See Note 5 to the financial statements for additional details regarding the investment recovery bonds.
Entergy New Orleans Storm Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy New Orleans, is a variable interest entity, and Entergy New Orleans is the primary beneficiary. In July 2015,
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy New Orleans Storm Recovery Funding issued storm cost recovery bonds to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs, including carrying costs, the costs of funding and replenishing the storm recovery reserve, and up-front financing costs associated with the securitization. With the proceeds, Entergy New Orleans Storm Recovery Funding purchased from Entergy New Orleans the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy New Orleans balance sheet. The creditors of Entergy New Orleans do not have recourse to the assets or revenues of Entergy New Orleans Storm Recovery Funding, including the storm recovery property, and the creditors of Entergy New Orleans Storm Recovery Funding do not have recourse to the assets or revenues of Entergy New Orleans. Entergy New Orleans has no payment obligations to Entergy New Orleans Storm Recovery Funding except to remit storm recovery charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.
Entergy Louisiana and System Energy are alsowas considered to each hold a variable interest in the lessorslessor from which they leaseit leased an undivided interestsinterest in the Waterford 3 nuclear plant. After Entergy Louisiana acquired a beneficial interest in the leased assets in March 2016, however, the lessor was no longer considered a variable interest entity. Entergy Louisiana made payments on its lease, including interest, of $9.2 million through March 2016 and $28.8 million in 2015. See Note 10 to the financial statements for a discussion of Entergy Louisiana’s purchase of the Waterford 3 leased assets.
System Energy is considered to hold a variable interest in the lessor from which it leases an undivided interest in the Grand Gulf nuclear plants, respectively. Entergy Louisiana andplant. System Energy areis the lesseeslessee under these arrangements,this arrangement, which areis described in more detail in Note 10 to the financial statements. Entergy Louisiana made payments on its lease, including interest, of $31.0 million in 2014, $26.3 million in 2013, and $39.1 million in 2012. System Energy made payments on its lease, including interest, of $51.6$17.2 million in 2014, $50.52017, $17.2 million in 2013,2016, and $50.0$52.3 million in 2012.2015. The lessors are bankslessor is a bank acting in the capacity of owner trustee for the benefit of equity investors in the transactionstransaction pursuant to trust agreementsagreement entered solely for the purpose of facilitating the lease transactions.transaction. It is possible that Entergy Louisiana and System Energy may be considered as the primary beneficiary of the lessors,lessor, but Entergy is unable to apply the authoritative accounting guidance with respect to these VIEsthis VIE because the lessors arelessor is not required to, and could not, provide the necessary financial information to consolidate the lessors.lessor. Because Entergy accounts for thesethis leasing arrangementsarrangement as a capital financings,financing, however, Entergy believes that consolidating the lessorslessor would not materially affect the financial statements. In the unlikely event of default under a lease, remedies available to the lessor include payment by the lessee of the fair value of the undivided interest in the plant, payment of the present value of the basic rent payments, or payment of a predetermined casualty value. Entergy believes, however, that the obligations recorded on the balance sheetssheet materially represent eachthe company’s potential exposure to loss.
Entergy has also reviewed various lease arrangements, power purchase agreements, including agreements for renewable power, and other agreements that represent variable interests in other legal entities which it holds ahave been determined to be variable interest.interest entities. In these cases, Entergy has determined that it is not the primary beneficiary of the related VIE because it does not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance, or it does not have the obligation to absorb losses or the right to residual returns that would potentially be significant to the entity, or both.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 19.18. TRANSACTIONS WITH AFFILIATES (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Each Registrant Subsidiary purchases electricity from or sells electricity to the other Registrant Subsidiaries, or both, under rate schedules filed with the FERC. The Registrant Subsidiaries receive management, technical, advisory, operating, and administrative services from Entergy Services; and receive management, technical, and operating services from Entergy Operations. These transactions are on an “at cost” basis. In addition, Entergy Power sold electricity to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans prior to the expiration of the contract in 2013. RS Cogen sells electricity to Entergy Gulf States Louisiana.
As described in Note 1 to the financial statements, all of System Energy’s operating revenues consist of billings to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
As described in Note 4 to the financial statements, the Registrant Subsidiaries participate in Entergy’s money pool and earn interest income from the money pool. As described in Note 2 to the financial statements, Entergy Gulf States Louisiana and Entergy Louisiana receivereceives preferred membership interest distributions from Entergy Holdings Company.
The tables below contain the various affiliate transactions of the Utility operating companies, System Energy, and other Entergy affiliates.
Intercompany Revenues
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Millions) |
| 2014 |
| $131.2 |
| |
| $418.0 |
| |
| $258.5 |
| |
| $169.8 |
| |
| $76.8 |
| |
| $316.1 |
| |
| $664.4 |
|
| 2013 |
| $349.9 |
| |
| $383.1 |
| |
| $114.9 |
| |
| $107.3 |
| |
| $27.0 |
| |
| $369.4 |
| |
| $735.1 |
|
| 2012 |
| $324.0 |
| |
| $380.6 |
| |
| $138.2 |
| |
| $36.1 |
| |
| $43.9 |
| |
| $313.2 |
| |
| $622.1 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Millions) |
| 2017 |
| $127.8 |
| |
| $282.4 |
| |
| $1.7 |
| |
| $— |
| |
| $57.9 |
| |
| $633.5 |
|
| 2016 |
| $49.4 |
| |
| $376.6 |
| |
| $2.9 |
| |
| $30.3 |
| |
| $180.2 |
| |
| $548.3 |
|
| 2015 |
| $127.9 |
| |
| $420.2 |
| |
| $86.0 |
| |
| $66.1 |
| |
| $259.1 |
| |
| $632.4 |
|
Intercompany Operating Expenses
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy
Gulf States
Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Millions) |
| | (a) | | (b) | | (c) | | | | (d) | | | | |
| 2014 |
| $596.6 |
| |
| $773.1 |
| |
| $490.9 |
| |
| $367.6 |
| |
| $241.5 |
| |
| $445.3 |
| |
| $156.7 |
|
| 2013 |
| $656.1 |
| |
| $672.8 |
| |
| $667.6 |
| |
| $399.0 |
| |
| $279.6 |
| |
| $418.1 |
| |
| $175.2 |
|
| 2012 |
| $580.7 |
| |
| $532.3 |
| |
| $597.4 |
| |
| $352.7 |
| |
| $247.2 |
| |
| $386.1 |
| |
| $147.4 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Millions) |
| 2017 |
| $510.2 |
| |
| $619.5 |
| |
| $310.5 |
| |
| $286.1 |
| |
| $234.6 |
| |
| $197.0 |
|
| 2016 |
| $467.4 |
| |
| $670.8 |
| |
| $256.5 |
| |
| $276.7 |
| |
| $343.7 |
| |
| $146.0 |
|
| 2015 |
| $508.5 |
| |
| $929.4 |
| |
| $331.8 |
| |
| $278.4 |
| |
| $413.7 |
| |
| $155.1 |
|
| |
(a) | Includes power purchased from Entergy Power of $3.3 million in 2013 and $1.4 million in 2012. The contract with Entergy Power expired in May 2013. |
| |
(b) | Includes power purchased from RS Cogen of $3.2 million in 2013 and $2.8 million in 2012. |
| |
(c) | Includes power purchased from Entergy Power of $8.1 million in 2013 and $14.3 million in 2012. The contract with Entergy Power expired in May 2013. |
| |
(d) | Includes power purchased from Entergy Power of $8 million in 2013 and $14.1 million in 2012. The contract with Entergy Power expired in May 2013. |
Intercompany Interest and Investment Income
|
| | | | | | | | | | | | | | | | |
| | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | System Energy |
| | | (In Millions) |
| | | | | | | | | |
| 2017 | |
| $128.0 |
| |
| $— |
| |
| $0.2 |
| |
| $0.9 |
|
| 2016 | |
| $127.7 |
| |
| $0.1 |
| |
| $— |
| |
| $0.1 |
|
| 2015 | |
| $133.6 |
| |
| $— |
| |
| $— |
| |
| $— |
|
Transactions with Equity Method Investees
EWO Marketing, LLC, an indirect wholly-owned subsidiary of Entergy, paid capacity charges and gas transportation to RS Cogen in the amounts of $24.6 million in 2017, $24.7 million in 2016, and $24.5 million in 2015.
Entergy’s operating transactions with its other equity method investees were not significant in 2017, 2016, or 2015.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Intercompany Interest and Investment Income
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Millions) |
| 2014 |
| $— |
| |
| $30.3 |
| |
| $87.6 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
| 2013 |
| $— |
| |
| $27.5 |
| |
| $78.2 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
| 2012 |
| $— |
| |
| $28.2 |
| |
| $78.2 |
| |
| $— |
| |
| $— |
| |
| $0.1 |
| |
| $— |
|
NOTE 20.19. QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Operating results for the four quarters of 20142017 and 20132016 for Entergy Corporation and subsidiaries were:
| | | | Operating Revenues | | Operating Income | | Consolidated Net Income | | Net Income Attributable to Entergy Corporation | Operating Revenues | | Operating Income (Loss) | | Consolidated Net Income (Loss) | | Net Income (Loss) Attributable to Entergy Corporation |
| | (In Thousands) | (In Thousands) |
| 2014: | | | | |
| 2017: | | | | |
| First Quarter |
| $3,208,843 |
| |
| $739,877 |
| |
| $406,053 |
| |
| $401,174 |
|
| $2,588,458 |
| |
| $174,803 |
| |
| $86,051 |
| |
| $82,605 |
|
| Second Quarter |
| $2,996,650 |
| |
| $454,477 |
| |
| $194,281 |
| |
| $189,383 |
|
| $2,618,550 |
| |
| $143,509 |
| |
| $413,368 |
| |
| $409,922 |
|
| Third Quarter |
| $3,458,110 |
| |
| $492,859 |
| |
| $234,916 |
| |
| $230,037 |
|
| $3,243,628 |
| |
| $729,469 |
| |
| $401,644 |
| |
| $398,198 |
|
| Fourth Quarter |
| $2,831,318 |
| |
| $319,674 |
| |
| $125,006 |
| |
| $120,127 |
|
| $2,623,845 |
| |
| $211,901 |
| |
| ($475,710 | ) | |
| ($479,113 | ) |
| 2013: | | | | |
| 2016: | | | | |
| First Quarter |
| $2,608,874 |
| |
| $394,045 |
| |
| $166,982 |
| |
| $161,400 |
|
| $2,609,852 |
| |
| $498,218 |
| |
| $235,242 |
| |
| $229,966 |
|
| Second Quarter |
| $2,738,208 |
| |
| $346,512 |
| |
| $168,055 |
| |
| $163,723 |
|
| $2,462,562 |
| |
| $442,258 |
| |
| $572,590 |
| |
| $567,314 |
|
| Third Quarter |
| $3,351,959 |
| |
| $388,894 |
| |
| $244,182 |
| |
| $239,850 |
|
| $3,124,703 |
| |
| $772,060 |
| |
| $393,204 |
| |
| $388,170 |
|
| Fourth Quarter |
| $2,691,906 |
| |
| $225,548 |
| |
| $151,353 |
| |
| $146,929 |
|
| $2,648,528 |
| |
| ($2,599,001 | ) | |
| ($1,765,539 | ) | |
| ($1,769,068 | ) |
Earnings (loss) per Average Common Shareaverage common share
| | | | 2014 | | 2013 | 2017 | | 2016 |
| | Basic | | Diluted | | Basic | | Diluted | Basic | | Diluted | | Basic | | Diluted |
| First Quarter |
| $2.24 |
| |
| $2.24 |
| |
| $0.91 |
| |
| $0.90 |
|
| $0.46 |
| |
| $0.46 |
| |
| $1.29 |
| |
| $1.28 |
|
| Second Quarter |
| $1.06 |
| |
| $1.05 |
| |
| $0.92 |
| |
| $0.92 |
|
| $2.28 |
| |
| $2.27 |
| |
| $3.17 |
| |
| $3.16 |
|
| Third Quarter |
| $1.28 |
| |
| $1.27 |
| |
| $1.35 |
| |
| $1.34 |
|
| $2.22 |
| |
| $2.21 |
| |
| $2.17 |
| |
| $2.16 |
|
| Fourth Quarter |
| $0.67 |
| |
| $0.66 |
| |
| $0.82 |
| |
| $0.82 |
|
| ($2.67 | ) | |
| ($2.66 | ) | |
| ($9.89 | ) | |
| ($9.86 | ) |
As discussed in more detail in Note 1 to the financial statements, operating results for 2014 include $154 million ($100 million after-tax) of charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completed in the third quarter 2014 along with reassessment of assumptions regarding the timing of decommissioning cash flows and severance and employee retention costs. Results of operations for 2014 also include2017 include: 1) $538 million ($350 million net-of-tax) of impairment charges due to costs being charged to expense as incurred as a result of the $56.2 million ($36.7 million after-tax) write-offimpaired value of the Entergy Mississippi’s regulatory assetWholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with new nuclear generation development costsmanagement’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet; 2) a reduction in income of $181 million, including a $34 million net-of-tax reduction of regulatory liabilities, at Utility and $397 million at Entergy Wholesale Commodities and an increase in income of $52 million at Parent and Other as a result of Entergy’s re-measurement of its deferred tax assets and liabilities not subject to the ratemaking process due to the enactment of the Tax Cuts and Jobs Act, in December 2017, which lowered the federal corporate income tax rate from 35% to 21%; and 3) a reduction in income tax expense, net of unrecognized tax benefits, of $373 million as a result of a joint stipulation entered into withchange in the Mississippi Public Utilities Staff, subsequently approvedtax classification of legal entities that own Entergy Wholesale Commodities nuclear power plants. See Note 14 to the financial statements for further discussion of the impairment and related charges. See Note 3 to the financial statements for further discussion of the effects of the Tax Cuts and Jobs Act and the change in the tax classification.
Results of operations for 2016 include: 1) $2,836 million ($1,829 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values; 2) a reduction of income tax expense, net of unrecognized tax benefits, of $238 million as a result of a change in the tax classification of a legal entity that owned one of the Entergy Wholesale Commodities nuclear power plants; income tax benefits as a result of the settlement of the 2010-2011 IRS audit, including a $75 million tax benefit recognized by Entergy Louisiana related to the MPSC, in which Entergy Mississippi agreed not to pursue recovery oftreatment
Entergy Corporation and Subsidiaries
Notes to Financial Statements
of the Vidalia purchased power agreement and a $54 million net benefit recognized by Entergy Louisiana related to the treatment of proceeds received in 2010 for the financing of Hurricane Gustav and Hurricane Ike storm costs deferred by an MPSC orderpursuant to Louisiana Act 55; and 3) a reduction in expenses of $100 million ($64 million net-of-tax) due to the neweffects of recording in 2016 the final court decisions in several lawsuits against the DOE related to spent nuclear generation docket.fuel storage costs. See Note 214 to the financial statements for further discussion of the new nuclear generation development costs and the joint stipulation.
Results of operations for 2013 include $322 million ($202 million after-tax) of impairment and other related charges, primarily to write down the carrying value of Vermont Yankee and related assets to their fair values. Seesee Note 13 to the financial statements for furtheradditional discussion of the charges. Also, as discussed in more detail inincome tax items, and see Note 138 to the financial statements operating results include approximately $110 million ($70 million after-tax) in costs in 2013 associated withfor discussion of the human capital management strategic imperative, primarily implementation costs, severance expenses, pension curtailment losses, and special termination benefits expense. In December 2013, Entergy deferred for future recovery approximately $45 million ($30 million after-tax) of these costs in the Arkansas and Louisiana jurisdictions, as approved by the APSC and the LPSC, respectively.spent nuclear fuel litigation.
The business of the Utility operating companies is subject to seasonal fluctuations with the peak periods occurring during the third quarter. Operating results for the Registrant Subsidiaries for the four quarters of 20142017 and 20132016 were:
Operating Revenues
| | | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) | (In Thousands) |
| 2014: | | | | | | | | | | | | | | |
| 2017: | | | | | | | | | | | | |
| First Quarter |
| $514,981 |
| |
| $513,295 |
| |
| $623,494 |
| |
| $348,196 |
| |
| $186,567 |
| |
| $440,256 |
| |
| $157,667 |
|
| $474,351 |
| |
| $880,783 |
| |
| $258,443 |
| |
| $168,989 |
| |
| $363,927 |
| |
| $154,787 |
|
| Second Quarter |
| $511,522 |
| |
| $554,034 |
| |
| $736,408 |
| |
| $370,638 |
| |
| $169,989 |
| |
| $482,932 |
| |
| $163,830 |
|
| $496,662 |
| |
| $1,083,434 |
| |
| $291,212 |
| |
| $176,222 |
| |
| $378,488 |
| |
| $164,956 |
|
| Third Quarter |
| $627,153 |
| |
| $610,493 |
| |
| $870,181 |
| |
| $425,341 |
| |
| $182,971 |
| |
| $528,508 |
| |
| $172,151 |
|
| $673,226 |
| |
| $1,290,494 |
| |
| $349,197 |
| |
| $199,017 |
| |
| $432,909 |
| |
| $156,106 |
|
| Fourth Quarter |
| $518,735 |
| |
| $473,104 |
| |
| $595,798 |
| |
| $380,018 |
| |
| $150,558 |
| |
| $400,286 |
| |
| $170,716 |
|
| $495,680 |
| |
| $1,045,839 |
| |
| $299,377 |
| |
| $171,842 |
| |
| $369,569 |
| |
| $157,609 |
|
| 2013: | | | | | | | | | | | | | | |
| 2016: | | | | | | | | | | | | |
| First Quarter |
| $542,392 |
| |
| $419,955 |
| |
| $606,085 |
| |
| $291,641 |
| |
| $146,466 |
| |
| $306,173 |
| |
| $168,578 |
|
| $465,373 |
| |
| $955,145 |
| |
| $263,046 |
| |
| $149,340 |
| |
| $378,304 |
| |
| $137,693 |
|
| Second Quarter |
| $508,653 |
| |
| $492,361 |
| |
| $635,805 |
| |
| $326,039 |
| |
| $142,841 |
| |
| $455,100 |
| |
| $172,177 |
|
| $504,252 |
| |
| $999,034 |
| |
| $248,138 |
| |
| $164,920 |
| |
| $412,922 |
| |
| $151,323 |
|
| Third Quarter |
| $647,671 |
| |
| $558,331 |
| |
| $782,789 |
| |
| $397,833 |
| |
| $178,641 |
| |
| $526,978 |
| |
| $192,679 |
|
| $654,599 |
| |
| $1,249,452 |
| |
| $309,739 |
| |
| $201,336 |
| |
| $442,085 |
| |
| $114,039 |
|
| Fourth Quarter |
| $491,443 |
| |
| $470,486 |
| |
| $602,256 |
| |
| $319,027 |
| |
| $152,208 |
| |
| $440,548 |
| |
| $201,655 |
|
| $462,384 |
| |
| $973,417 |
| |
| $273,726 |
| |
| $149,867 |
| |
| $382,308 |
| |
| $145,236 |
|
Operating Income (Loss)
| | | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) | (In Thousands) |
| 2014: | | | | | | | | | | | | | | |
| 2017: | | | | | | | | | | | | |
| First Quarter |
| $66,360 |
| |
| $82,576 |
| |
| $85,057 |
| |
| $57,132 |
| |
| $15,281 |
| |
| $43,056 |
| |
| $52,029 |
|
| $39,847 |
| |
| $152,648 |
| |
| $39,608 |
| |
| $21,762 |
| |
| $38,842 |
| |
| $41,544 |
|
| Second Quarter |
| $68,970 |
| |
| $70,350 |
| |
| $100,176 |
| |
| $59,063 |
| |
| $12,862 |
| |
| $53,158 |
| |
| $56,547 |
|
| $68,994 |
| |
| $193,779 |
| |
| $55,262 |
| |
| $27,606 |
| |
| $47,787 |
| |
| $40,717 |
|
| Third Quarter |
| $115,357 |
| |
| $96,698 |
| |
| $160,595 |
| |
| $9,403 |
| |
| $24,866 |
| |
| $82,911 |
| |
| $58,484 |
|
| $169,755 |
| |
| $290,089 |
| |
| $84,035 |
| |
| $33,415 |
| |
| $78,950 |
| |
| $37,459 |
|
| Fourth Quarter |
| $19,317 |
| |
| $43,766 |
| |
| $38,615 |
| |
| $61,162 |
| |
| ($539 | ) | |
| $29,590 |
| |
| $54,056 |
|
| $14,507 |
| |
| $210,325 |
| |
| $42,169 |
| |
| $12,333 |
| |
| $33,800 |
| |
| $41,073 |
|
| 2013: | | | | | | | | | | | | | | |
| 2016: | | | | | | | | | | | | |
| First Quarter |
| $43,314 |
| |
| $52,083 |
| |
| $64,728 |
| |
| $37,123 |
| |
| $4,272 |
| |
| $26,277 |
| |
| $52,052 |
|
| $54,378 |
| |
| $181,618 |
| |
| $41,573 |
| |
| $21,880 |
| |
| $41,269 |
| |
| $47,466 |
|
| Second Quarter |
| $80,942 |
| |
| $53,856 |
| |
| $88,691 |
| |
| $46,809 |
| |
| $3,627 |
| |
| $38,355 |
| |
| $51,632 |
|
| $73,447 |
| |
| $193,752 |
| |
| $61,890 |
| |
| $26,913 |
| |
| $58,039 |
| |
| $45,020 |
|
| Third Quarter |
| $157,681 |
| |
| $85,284 |
| |
| $145,847 |
| |
| $70,186 |
| |
| $15,895 |
| |
| $79,430 |
| |
| $52,029 |
|
| $188,660 |
| |
| $312,951 |
| |
| $88,312 |
| |
| $42,279 |
| |
| $107,964 |
| |
| $43,886 |
|
| Fourth Quarter |
| $23,123 |
| |
| $56,114 |
| |
| $56,128 |
| |
| $36,112 |
| |
| $3,070 |
| |
| $30,071 |
| |
| $47,367 |
|
| $29,843 |
| |
| $111,066 |
| |
| $32,464 |
| |
| $8,807 |
| |
| $38,338 |
| |
| $44,781 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Net Income (Loss)
| | | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) | (In Thousands) |
| 2014: | | | | | | | | | | | | | | |
| 2017: | | | | | | | | | | | | |
| First Quarter |
| $28,370 |
| |
| $46,472 |
| |
| $58,378 |
| |
| $25,839 |
| |
| $8,294 |
| |
| $13,165 |
| |
| $24,619 |
|
| $14,304 |
| |
| $94,378 |
| |
| $17,158 |
| |
| $10,978 |
| |
| $10,854 |
| |
| $20,347 |
|
| Second Quarter |
| $29,005 |
| |
| $36,171 |
| |
| $69,667 |
| |
| $26,564 |
| |
| $6,374 |
| |
| $18,585 |
| |
| $25,931 |
|
| $38,550 |
| |
| $124,479 |
| |
| $28,303 |
| |
| $14,882 |
| |
| $21,101 |
| |
| $19,350 |
|
| Third Quarter |
| $62,980 |
| |
| $55,535 |
| |
| $123,821 |
| |
| ($6,464 | ) | |
| $13,932 |
| |
| $39,559 |
| |
| $26,730 |
|
| $92,638 |
| |
| $186,284 |
| |
| $46,545 |
| |
| $18,529 |
| |
| $39,588 |
| |
| $20,583 |
|
| Fourth Quarter |
| $1,037 |
| |
| $24,313 |
| |
| $31,665 |
| |
| $28,882 |
| |
| $107 |
| |
| $3,495 |
| |
| $19,054 |
|
| ($5,648 | ) | |
| ($88,794 | ) | |
| $18,026 |
| |
| $164 |
| |
| $4,630 |
| |
| $18,316 |
|
| 2013: | | | | | | | | | | | | | | |
| 2016: | | | | | | | | | | | | |
| First Quarter |
| $14,719 |
| |
| $27,165 |
| |
| $45,376 |
| |
| $13,934 |
| |
| $1,307 |
| |
| $922 |
| |
| $28,006 |
|
| $19,294 |
| |
| $111,606 |
| |
| $17,118 |
| |
| $11,167 |
| |
| $14,562 |
| |
| $25,958 |
|
| Second Quarter |
| $40,483 |
| |
| $29,720 |
| |
| $61,377 |
| |
| $18,954 |
| |
| $598 |
| |
| $10,953 |
| |
| $27,734 |
|
| $33,891 |
| |
| $253,325 |
| |
| $32,194 |
| |
| $11,843 |
| |
| $24,058 |
| |
| $25,090 |
|
| Third Quarter |
| $82,577 |
| |
| $62,642 |
| |
| $100,597 |
| |
| $33,813 |
| |
| $8,086 |
| |
| $35,801 |
| |
| $35,105 |
|
| $110,148 |
| |
| $189,506 |
| |
| $46,612 |
| |
| $23,701 |
| |
| $56,133 |
| |
| $22,370 |
|
| Fourth Quarter |
| $24,169 |
| |
| $42,135 |
| |
| $45,114 |
| |
| $15,458 |
| |
| $1,692 |
| |
| $10,205 |
| |
| $22,819 |
|
| $3,879 |
| |
| $67,610 |
| |
| $13,260 |
| |
| $2,138 |
| |
| $12,785 |
| |
| $23,326 |
|
Earnings (Loss) Applicable to Common Equity
| | | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | Entergy Arkansas | | Entergy Mississippi | | Entergy New Orleans |
| | (In Thousands) | (In Thousands) |
| 2014: | | | | | | | | | | |
| 2017: | | | | | | |
| First Quarter |
| $26,652 |
| |
| $46,266 |
| |
| $56,640 |
| |
| $25,132 |
| |
| $8,053 |
|
| $13,947 |
| |
| $16,920 |
| |
| $10,737 |
|
| Second Quarter |
| $27,287 |
| |
| $35,962 |
| |
| $67,910 |
| |
| $25,857 |
| |
| $6,133 |
|
| $38,193 |
| |
| $28,064 |
| |
| $14,641 |
|
| Third Quarter |
| $61,262 |
| |
| $55,329 |
| |
| $122,083 |
| |
| ($7,171 | ) | |
| $13,691 |
|
| $92,281 |
| |
| $46,307 |
| |
| $18,288 |
|
| Fourth Quarter |
| ($682 | ) | |
| $24,107 |
| |
| $29,929 |
| |
| $28,175 |
| |
| ($135 | ) |
| ($6,005 | ) | |
| $17,788 |
| |
| $46 |
|
| 2013: | | | | | | | | | | |
| 2016: | | | | | | |
| First Quarter |
| $13,001 |
| |
| $26,959 |
| |
| $43,638 |
| |
| $13,227 |
| |
| $1,066 |
|
| $17,576 |
| |
| $16,411 |
| |
| $10,926 |
|
| Second Quarter |
| $38,765 |
| |
| $29,514 |
| |
| $59,639 |
| |
| $18,247 |
| |
| $357 |
|
| $32,173 |
| |
| $31,487 |
| |
| $11,602 |
|
| Third Quarter |
| $80,859 |
| |
| $62,436 |
| |
| $98,859 |
| |
| $33,106 |
| |
| $7,845 |
|
| $108,672 |
| |
| $45,905 |
| |
| $23,460 |
|
| Fourth Quarter |
| $22,450 |
| |
| $41,928 |
| |
| $43,378 |
| |
| $14,751 |
| |
| $1,450 |
|
| $3,521 |
| |
| $12,938 |
| |
| $1,896 |
|
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
ENTERGY’S BUSINESS
Entergy is an integrated energy company engaged primarily in electric power production and retail electric distribution operations. Entergy owns and operates power plants with approximately 30,000 MW of aggregate electric generating capacity, including nearly 10,0009,000 MW of nuclear-fueled capacity. Entergy’s Utility businessnuclear power. Entergy delivers electricity to 2.82.9 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy generatedhad annual revenues of $12.5$11.1 billion in 20142017 and had approximatelymore than 13,000 employees as of December 31, 2014.2017.
Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.
The Utility business segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operatesoperation of a small natural gas distribution business.
The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. In August 2013, Entergy announced plans to close and decommission Vermont Yankee. On December 29, 2014 the Vermont Yankee plant ceased power production and has entered its decommissioning phase. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” for discussion of the operation and planned shutdown or sale of each of the Entergy Wholesale Commodities nuclear power plants.
See Note 13 to the financial statements for financial information regarding Entergy’s business segments.
Strategy
Entergy’s mission is to operate a world-class energy business that creates sustainable value for its owners, customers, employees, and communities. Entergy aspires to achieve top quartile total shareholder returns in a socially and environmentally responsible fashion by leveraging the scale and expertise inherent in its core utility and nuclear operations. Entergy’s current scope includes electricity generation, transmission, and distribution as well as natural gas distribution. Entergy focuses on operational excellence with an emphasis on safety, reliability, customer service, sustainability, cost efficiency, risk management, and engaged employees. Entergy also continually seeks opportunities to grow its utility business to benefit all stakeholders and to optimize its portfolio of assets in an ever-dynamic market through periodic buy, build, hold, or disposal decisions. To accomplish this, Entergy has established strategic imperatives for each business segment. For the Utility, the strategic imperative is to growmodernize its operations, maintain reliability, and better serve its customers while growing the business by leveraging the industrial expansion underway in the Gulf region of the United States, and forbusiness. For Entergy Wholesale Commodities, the strategic imperative is to continue to manage the risk and preserve value inof its operating portfolio as Entergy completes its exit from the merchant power business.
Utility
The Utility business segment includes sixfive wholly-owned retail electric utility subsidiaries: Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. These companies generate, transmit, distribute and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy Gulf States Louisiana and Entergy New Orleans also provide natural gas utility services to customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Also included in the Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf. System Energy sells its power and capacity from Grand Gulf at wholesale to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The sixfive retail utility subsidiaries are each regulated by the FERC and by state utility commissions, or, in the case of Entergy New Orleans, the City Council. System Energy is regulated by the FERC because all of its transactions are at wholesale. The overall generation portfolio of the Utility, which relies heavily on natural gas and nuclear generation, is consistent with Entergy’s strong support for the environment.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Customers
As of December 31, 2014,2017, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
| | | | | | Electric Customers | | Gas Customers | | | Electric Customers | | Gas Customers |
| | Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) | Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) |
| Entergy Arkansas | Portions of Arkansas | | 702 |
| | 25 | % | | | | | Portions of Arkansas | | 709 |
| | 25 | % | | | | |
Entergy Gulf States Louisiana | Portions of Louisiana | | 396 |
| | 14 | % | | 93 |
| | 47 | % | |
| Entergy Louisiana | Portions of Louisiana | | 680 |
| | 24 | % | | | | | Portions of Louisiana | | 1,078 |
| | 37 | % | | 93 |
| | 47 | % |
| Entergy Mississippi | Portions of Mississippi | | 442 |
| | 16 | % | | | | | Portions of Mississippi | | 449 |
| | 16 | % | | | | |
| Entergy New Orleans | City of New Orleans (a) | | 171 |
| | 6 | % | | 105 |
| | 53 | % | City of New Orleans | | 200 |
| | 7 | % | | 106 |
| | 53 | % |
| Entergy Texas | Portions of Texas | | 427 |
| | 15 | % | | | | | Portions of Texas | | 448 |
| | 15 | % | | | | |
| Total customers | | | 2,818 |
| | 100 | % | | 198 |
| | 100 | % | | | 2,884 |
| | 100 | % | | 199 |
| | 100 | % |
| |
(a) | Excludes the Algiers area of the city, where Entergy Louisiana provides electric service. |
Electric Energy Sales
The electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On August 22, 2014,July 20, 2017, Entergy reached a 20142017 peak demand of 20,47221,671 MWh, compared to the 20132016 peak of 21,58121,387 MWh recorded on August 8, 2013.July 21, 2016. Selected electric energy sales data is shown in the table below:
Selected 20142017 Electric Energy Sales Data
| | | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| | (In GWh) | (In GWh) |
Sales to retail customers | 21,050 |
| | 20,823 |
| | 32,904 |
| | 13,204 |
| | 5,229 |
| | 17,698 |
| | — |
| | 110,910 |
| 20,888 |
| | 55,243 |
| | 13,048 |
| | 5,622 |
| | 18,058 |
| | — |
| | 112,859 |
|
| Sales for resale: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Affiliates | 2,299 |
| | 6,966 |
| | 4,450 |
| | 2,657 |
| | 1,322 |
| | 4,763 |
| | 9,219 |
| | — |
| 1,782 |
| | 4,793 |
| | — |
| | — |
| | 1,534 |
| | 6,675 |
| | — |
|
| Others | 8,003 |
| | 925 |
| | 126 |
| | 193 |
| | 16 |
| | 200 |
| | — |
| | 9,462 |
| 6,549 |
| | 1,711 |
| | 857 |
| | 1,703 |
| | 729 |
| | — |
| | 11,550 |
|
| Total | 31,352 |
| | 28,714 |
| | 37,480 |
| | 16,054 |
| | 6,567 |
| | 22,661 |
| | 9,219 |
| | 120,372 |
| 29,219 |
| | 61,747 |
| | 13,905 |
| | 7,325 |
| | 20,321 |
| | 6,675 |
| | 124,409 |
|
Average use per residential customer (kWh) | 13,774 |
| | 15,865 |
| | 15,355 |
| | 15,319 |
| | 12,870 |
| | 15,560 |
| | — |
| | 14,911 |
| 12,349 |
| | 14,377 |
| | 14,142 |
| | 11,986 |
| | 14,597 |
| | — |
| | 13,716 |
|
| |
| (a) | Includes the effect of intercompany eliminations. |
The following table illustrates the Utility operating companies’ 2017 combined electric sales volume as a percentage of total electric sales volume, and 2017 combined electric revenues as a percentage of total 2017 electric revenue, each by customer class.
|
| | | | |
| Customer Class | | % of Sales Volume | | % of Revenue |
| Residential | | 27.2 | | 36.2 |
| Commercial | | 23.1 | | 26.7 |
| Industrial (a) | | 38.4 | | 27.8 |
| Governmental | | 2.0 | | 2.5 |
| Wholesale/Other | | 9.3 | | 6.8 |
| |
| (a) | Major industrial customers are primarily in the petroleum refining and chemical industries. |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
The following table illustrates the Utility operating companies’ 2014 combined electric sales volume as a percentage of total electric sales volume, and 2014 combined electric revenues as a percentage of total 2014 electric revenue, each by customer class.
|
| | | | |
| Customer Class | | % of Sales Volume | | % of Revenue |
| Residential | | 29.9 | | 37.1 |
| Commercial | | 23.9 | | 26.6 |
| Industrial (a) | | 36.3 | | 27.3 |
| Governmental | | 2.0 | | 2.4 |
| Wholesale/Other | | 7.9 | | 6.6 |
| |
(a) | Major industrial customers are in the chemical, petroleum refining, and pulp and paper industries. |
See “Selected Financial Data” for each of the Utility operating companies for the detail of their sales by customer class for 2010-2014.2013-2017.
Selected 20142017 Natural Gas Sales Data
Entergy New Orleans and Entergy Gulf States Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Gulf States Louisiana sold 11,296,1799,745,874 and 7,933,9686,017,174 Mcf, respectively, of natural gas to retail customers in 2014.2017. In 2014, 97%2017, 99% of Entergy Gulf States Louisiana’s operating revenue was derived from the electric utility business, and only 3%1% from the natural gas distribution business. For Entergy New Orleans, 84%88% of operating revenue was derived from the electric utility business and 16%12% from the natural gas distribution business in 2014.2017.
Following is data concerning Entergy New Orleans’s 20142017 retail operating revenue sources.
| | Customer Class | | Electric Operating Revenue | | Natural Gas Revenue | | Electric Operating Revenue | | Natural Gas Operating Revenue |
| Residential | | 42% | | 51% | | 42% | | 46% |
| Commercial | | 38% | | 26% | | 39% | | 28% |
| Industrial | | 7% | | 8% | | 6% | | 7% |
| Governmental/Municipal | | 13% | | 15% | | 13% | | 19% |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Retail Rate Regulation
General (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Each Utility operating company regularly participates in retail rate proceedings. The status of material retail rate proceedings is described in Note 2 to the financial statements. Certain aspects of the Utility operating companies’ retail rate mechanisms are discussed below.
|
| | | | | | | | | | | |
| | | Rate base (in billions) | | Current authorized return on common equity | | Weighted average cost of capital (after-tax) | | Equity ratio | | Regulatory construct | |
| | | | | | | | | | | | |
| Entergy Arkansas | | $7.095 (a) | | 9.25% -10.25% | | 4.67% | | 31.69% | | - forward test year formula rate plan
- riders: MISO, capacity, Grand
Gulf, energy efficiency, fuel and
purchased power | |
| | | | | | | | | | | | |
| Entergy Louisiana (electric) | | $8.303 (b) | | 9.15% - 10.75% | | 7.35% | | 49.64% | | - formula rate plan through 2016 test
year
- riders/specific recovery: MISO,
capacity, fuel | |
| | | | | | | | | | | | |
| Entergy Louisiana (gas) | | $0.059 (c) | | 9.45% - 10.45% | | 7.54% | | 51.63% | | - gas rate stabilization plan
- rider: gas infrastructure | |
| | | | | | | | | | | | |
| Entergy Mississippi | | $2.131 (d) | | 9.47% - 11.49% | | 7.35% | | 49.37% | | - formula rate plan with
forward-looking features
- riders: power management, Grand
Gulf, fuel, MISO, unit power cost,
storm damage, energy efficiency, ad
valorem tax adjustment
| |
| | | | | | | | | | | | |
| Entergy New Orleans (electric) | | $0.299 (e) | | 10.7% - 11.5% | | 8.58% | | 50.08% | | - rate case
- riders/specific recovery: fuel, capacity | |
| | | | | | | | | | | | |
| Entergy New Orleans (gas) | | $0.089 (f) | | 10.25% - 11.25% | | 8.40% | | 50.08% | | - rate case
- rider: purchased gas | |
| | | | | | | | | | | | |
| Entergy Texas | | $1.634 (g) | | 9.8% | | 8.22% | | 48.6% | | - rate case
- riders: fuel, distribution and transmission, RPCE payments and rate case expenses, among others | |
| | | | | | | | | | | | |
| System Energy | | $1.201 (h) | | 10.94% | | 8.90% | | 65% | | - monthly cost of service | |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
| |
| (a) | Based on 2018 forward test year. |
| |
| (b) | Based on December 31, 2016 test year. |
| |
| (c) | Based on September 30, 2016 test year. |
| |
| (d) | Based on 2017 forward test year. |
| |
| (e) | Based on December 31, 2011 test year and excludes approximately $228 million first-year average rate base for Union. |
| |
| (f) | Based on December 31, 2011 test year. |
| |
| (g) | Based on March 31, 2013 adjusted test year and excludes approximately $331 million for rate base being recovered through the distribution cost recovery rider and the transmission cost recovery rider |
| |
| (h) | Based on calculation as of December 31, 2017. |
Entergy Arkansas
Fuel and Purchased Power Cost Recovery
Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased energypower costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
upon the level of over- or under-recovery of fuel and purchased energy costs. In December 2007 the APSC issued an order stating that Entergy Arkansas’s energy cost recovery rider will remain in effect, and any future termination of the rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Arkansas’s storm restoration costs.
Entergy Gulf States Louisiana
Fuel Recovery
Entergy Gulf States Louisiana’s electric rates include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Gulf States Louisiana’s fuel adjustment clause filings.
To help stabilize electricity costs, Entergy Gulf States Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Gulf States Louisiana hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Entergy Gulf States Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
To help stabilize retail gas costs, Entergy Gulf States Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility for its gas purchased for resale through the use of financial instruments. Entergy Gulf States Louisiana hedges approximately one-half of the projected natural gas volumes used to serve its natural gas customers for November through March. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Gulf States Louisiana’s filings to recover storm-related costs.
Entergy Louisiana
Fuel Recovery
Entergy Louisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Louisiana’s fuel adjustment clause filings.
To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana hedges approximately one-
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
thirdone-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis. In January 2018, Entergy Louisiana filed an application with the LPSC to suspend these seasonal hedging programs and implement financial hedges with terms up to five years for a portion of its natural gas exposure. A decision is expected in 2018.
Entergy Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
To help stabilize retail gas costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility for its gas purchased for resale through the use of financial instruments. Entergy Louisiana hedges approximately one-half of the projected natural gas volumes used to serve its natural gas customers for November through March. The hedge quantity is reviewed on an annual basis.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs, Entergy Louisiana plans to cap the average fuel adjustment charge to be billed in March 2018 at $0.03060 per kWh and to defer billing of all fuel costs in excess of the capped amounts by including such costs in the over- or under-recovery account.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the recently-approved Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased energypower costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
Power Management Rider
In November 2005 the MPSC approved the purchase of the Attala power plant and recovery of the investment cost through Entergy Mississippi’s power management rider. Entergy Mississippi recovered the annual ownership costs of the Attala plant through the power management rider until resolution of its general rate case. In 2012 the MPSC approved the purchase of the Hinds power plant recovery of the investment cost through Entergy Mississippi’s power management rider. Entergy Mississippi recovered the annual ownership costs of the Hinds plant through the power management rider until resolution of its general rate case. See Note 2 to the financial statements for a discussion of Entergy Mississippi’s 2014 general rate case. Included in the rate changes and revenue adjustments effective with February 2015 bills was the realignment of the annual ownership costs associated with the Attala plant and the Hinds plant from the power management rider to base rates.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
Entergy Mississippi maintainsSee Note 2 to the financial statements for a storm damage provision pursuant to ordersdiscussion of the MPSC and consistent with regulatory accounting requirements.proceedings regarding recovery of Entergy Mississippi’s storm damage provision is funded through its storm damage rider schedule. storm-related costs.
Formula Rate Plan
In two orders issued in JulyAugust 2012 the MPSC temporarily increasedopened inquiries to review whether the current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s storm damage provision monthly accrual from $750,000formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to $2 millionbetter serve the public interest. The intent of this inquiry and review was for bills rendered duringinformational purposes only; the billing monthsevaluation of August 2012 through December 2012, and approved recovery of $14.9 million in prudently incurred storm costs to be amortized over five months, beginning with August 2012 bills. Beginning with January 2013 bills, the monthly accrualany recommendations for changes to the storm damage provision reverted back to $750,000. On July 1,existing methodology would take place in a general rate case or in the existing formula rate plan docket. In March 2013 Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, infiled its consultant’s report which both parties agreed that approximately $32 million in storm restoration costs incurred in 2011 and 2012 were prudently incurred and chargeable to storm damages, while approximately $700,000 in prudently incurred costs were more properly recoverable throughnoted the formula rate plan.return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi Public Utilities Staff also agreed that the storm damage accrual shouldand Mississippi Power Company might be increased from $750,000 per month to $1.75 million per month. In September 2013 the MPSC approved the joint stipulation with the increaseimproved, but did not recommend specific changes in the storm damage accrual effective with October 2013 bills. In February 2015, Entergy Mississippi provided notice to the Mississippi Public Utilities Staff that the storm damage accrual would be set to zero effective with the March 2015 billing cycle as a result of Entergy Mississippi's storm damage accrual balance exceedingreturn on common equity formulas
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
$15 million as of January 31, 2015, but will return to its current level when the storm damage accrual balance becomes less than $10 million.
or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has also ordered that Entergybeen set. In October 2014 the Mississippi will annually submitPublic Utilities Staff conducted a public technical conference to discuss performance benchmarking and its storm costs for audit.potential application to the electric utilities’ formula rate plans. The docket remains open.
Entergy New Orleans
Fuel Recovery
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges. In October 2005 the City Council approved modification of the current gas cost collection mechanism effective November 2005 in order to address concerns regarding its fluctuations, particularly during the winter heating season. The modifications are intended to minimize fluctuations in gas rates during the winter months.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Due to higher fuel costs associated in part with the extended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans to cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs associated in part with certain plant outages, Entergy New Orleans has proposed to cap the fuel adjustment charge to be billed in March 2018 to non-transmission Entergy New Orleans legacy customers and Entergy New Orleans Algiers customers at $0.035323 per kWh and $0.025446 per kWh, respectively. Entergy New Orleans has also proposed to cap the fuel adjustment charge to be billed in March 2018 for Entergy New Orleans legacy transmission customers at $0.034609 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.
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Entergy Texas
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.
Electric Industry Restructuring
In June 2009, a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of Entergy Texas’s power region.
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The law also contains provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
In September 2011 the PUCT adopted a proposed rule implementing a Distribution Cost Recovery Factor to recover capital and capital-related costs related to distribution infrastructure. The Distribution Cost Recovery Factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect depreciation expense, federal income tax and other taxes, and return on investment. The Distribution Cost Recovery Factor rider may be changed a maximum of four times between base rate cases, and expires in January 2017, unless otherwise extended by the Texas Legislature.
The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer”; and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction.
Entergy Texas and the other parties to the PUCT proceeding to determine the design of the competitive generation tariff were involved in negotiations throughout 2011 and 2012 with the objective of resolving as many disputed issues as possible regarding the tariff. The PUCT determined that unrecovered costs that could be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The PUCT also ruled that the amount of customer load that may be included in the competitive generation service program is limited to 115 MW. After additional negotiations, and ultimately the scheduling of a hearing to resolve remaining contested issues, the PUCT issued the order approving the competitive generation service rider in July 2013. Entergy Texas filed for rehearing of the PUCT’s July 2013 order, which the PUCT denied. Entergy Texas has since filed its appeal of that PUCT order to the Travis County District Court, which found in favor of the PUCT in an order issued in October 2014. In November 2014, Entergy Texas appealed the District Court’s order which moves the appeal to the Third Court of Appeals. Entergy
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Texas and opposing parties filed briefs and responses in the first quarter 2015. Oral argument was held in May 2015. In March 2016 the Court of Appeals upheld the District Court’s ruling favoring the PUCT. In May 2016, Entergy Texas filed with the Texas Supreme Court a petition for review of the Court of Appeals ruling. In January 2017, Entergy Texas filed its petitioner’s brief on the merits with the Texas Supreme Court. In June 2017 the Texas Supreme Court denied Entergy Texas’s petition in this matter.
In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The appeal remains pending.distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect depreciation expense, federal income tax and other taxes, and return on investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas franchises are considered to be contracts and, therefore, are terminable pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Gulf States Louisiana holds non-exclusive franchises to provide electric service in approximately 59175 incorporated municipalities and in the unincorporated areas of approximately 2259 parishes andof Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and the unincorporated areas of two parishes. Most of Entergy Gulf States Louisiana’s franchises have a term ofin East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years. Entergy Gulf States Louisiana’s current electric and gas franchises expire during 2015-2055.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 117 incorporated Louisiana municipalities. Most of these franchises have 25-year terms. Entergy Louisiana also supplies electric service in approximately 52 Louisiana parishes in which it holds non-exclusive franchises. Entergy Louisiana’s electric franchises expire during 2015-2039.
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Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances (except electric service in Algiers, which is provided by Entergy Louisiana).ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 68 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire during 2016-2058.2018-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2014,2017, is indicated below:
| | | | | Owned and Leased Capability MW(a) | | Owned and Leased Capability MW(a) |
| Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 4,721 |
| | 1,630 |
| | 1,820 |
| | 1,198 |
| | 73 |
| | 5,217 |
| | 2,136 |
| | 1,821 |
| | 1,189 |
| | 71 |
| | — |
|
| Entergy Gulf States Louisiana | | 2,963 |
| | 1,630 |
| | 973 |
| | 360 |
| | — |
| |
| Entergy Louisiana | | 6,321 |
| | 5,157 |
| | 1,164 |
| | — |
| | — |
| | 9,099 |
| | 6,603 |
| | 2,136 |
| | 360 |
| | — |
| | — |
|
| Entergy Mississippi | | 3,495 |
| | 3,075 |
| | — |
| | 420 |
| | — |
| | 3,359 |
| | 2,944 |
| | — |
| | 414 |
| | — |
| | 1 |
|
| Entergy New Orleans | | 782 |
| | 782 |
| | — |
| | — |
| | — |
| | 492 |
| | 491 |
| | — |
| | — |
| | — |
| | 1 |
|
| Entergy Texas | | 2,553 |
| | 2,287 |
| | — |
| | 266 |
| | — |
| | 2,331 |
| | 2,065 |
| | — |
| | 266 |
| | — |
| | — |
|
| System Energy | | 1,268 |
| | — |
| | 1,268 |
| | — |
| | — |
| | 1,271 |
| | — |
| | 1,271 |
| | — |
| | — |
| | — |
|
| Total | | 22,103 |
| | 14,561 |
| | 5,225 |
| | 2,244 |
| | 73 |
| | 21,769 |
| | 14,239 |
| | 5,228 |
| | 2,229 |
| | 71 |
| | 2 |
|
| |
| (a) | “Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. |
Summer peak load for the Utility has averaged 23,26921,533 MW over the previous decade. The Utility operating companies, in aggregate, are projected to have approximately 224 MW more than their minimum capacity requirements needed to meet MISO Resource Adequacy for 2015.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, and the availability and price of power, the location of new load, the economy, environmental regulations, public policy goals, and the age and condition of Entergy’s existing infrastructure. The resource planning processes also consider the Entergy Arkansas exit from the System Agreement on December 18, 2013, and Entergy Mississippi’s (in November 2015), Entergy Texas’s, Entergy Louisiana’s, and Entergy Gulf States Louisiana’s notices of their future withdrawal from the System Agreement.
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The Utility operating companies’ long-term resource strategy the “Portfolio(Portfolio Transformation Strategy,”Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 6,5006,800 MW of new long-term resources.resources and the deactivation of over 5,200 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term summerMISO reliability requirements as well as longer-term requirements through a broad range of wholesale power products, including limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things, in:things:
Entergy Louisiana’s June 2005 purchase of the 718 MW, gas-fired Perryville plant, of which a total of 75%35% of the output is sold to Entergy Gulf States Louisiana and Entergy Texas;
Entergy Arkansas’s September 2008 purchase of the 789 MW, combined-cycle, gas-fired Ouachita Generating Facility. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, purchasedowns one-third of the facility from facility;
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Entergy Arkansas’s November 2012 purchase of the 620 MW, combined-cycle, gas-fired Hot Spring Energy facility;
Entergy Mississippi’s November 2012 purchase of the 450 MW, combined-cycle, gas-fired Hinds Energy facility; and
Entergy Louisiana’s construction of the 560 MW, combined-cycle, gas turbine Ninemile 6 generating facility at its existing Ninemile Point electric generating station. The facility reached commercial operation in December 2014. For additional discussion2014;
Entergy Louisiana’s construction of the Ninemile 6 project see “Capital Expenditure Plans980 MW, combined-cycle, gas turbine St. Charles generating facility at its existing Little Gypsy electric generating station. Entergy Louisiana received regulatory approval from the LPSC in December 2016 and Other Usesthe facility is scheduled to be in service by mid-2019;
Entergy Texas’s construction of Capital” the 993 MW, combined-cycle, gas turbine Montgomery County generating facility at its existing Lewis Creek electric generating station. Entergy Texas received regulatory approval from the PUCT in July 2017 and the facility is scheduled to be in service by mid-2021; and
Entergy CorporationLouisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station. Entergy Louisiana received regulatory approval from the LPSC in July 2017 and Subsidiaries Management’s Financial Discussion and Analysis.
the facility is scheduled to be in service by mid-2020.
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
River Bend 30% life-of-unit PPAs totaling approximately 300 MWPPA between Entergy Gulf States Louisiana and Entergy Louisiana (200 MW), and between Entergy Gulf States Louisiana and Entergy New Orleans (100 MW)for 100 MW related to Entergy Gulf States Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
Entergy Arkansas wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
12-month agreements originally executed in 2005 and which are renewed annually between Entergy Arkansas and Entergy Gulf States Louisiana and Entergy Texas, and between Entergy Arkansas and Entergy Mississippi, relating to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
In December 2009, Entergy Texas and Exelon Generation Company, LLC executed a 10-year agreement for 150-300 MW from the Frontier Generating Station located in Grimes County, Texas;
In May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Gulf States Louisiana purchases 50% of the facility'sfacility’s capacity and energy from Entergy Texas;
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Entergy Corporation, Utility operating companies,Texas. In July 2014, LS Power purchased the Carville Energy Center and Systemreplaced Calpine Energy Services as the counterparty to the agreement;
In OctoberSeptember 2012, Entergy Arkansas and UnionGulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from Rain CII Carbon LLC’s pet coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility;
In March 2013, Entergy Gulf States Louisiana executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, L.P.LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric;
In September 2013, Entergy Louisiana executed a 3 ½-year10-year agreement for 495with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from the Union Power Stationits landfill gas-fueled power generation facility located in El Dorado, Arkansas. Cost recovery for this agreement was approved within Entergy Arkansas’s general rate case filed in March 2013; andCleveland, Texas;
Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013.2013;
In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC has approved the project, and the expected commercial operation date is in June 2019;
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In December 2010November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. The transaction has received regulatory approval and will begin in June 2022;
In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction has received regulatory approval and will begin in June 2018; and
In June 2017, Entergy Arkansas and Chicot Solar, LLC executed 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. Entergy Arkansas filed for regulatory approval in October 2017.
In June 2016, Entergy Services, on behalf of Entergy Gulf States Louisiana, and Entergy Louisiana, Entergy Services issued the 2010an RFP for Long-Term Renewable Energy Resourceslong-term renewable generation resources. The RFP was seeking up to 233200 MW of renewable generation resources that could provide energy, fuel diversity, and other benefits to meetcustomers. Two proposals were placed in the requirements of an LPSC general order issued on December 9, 2010. In September 2012, Entergy Gulf States Louisiana executed a 20-year contract for 28 MW, withprimary selection list and the potential to purchase an additional 9 megawatts when available, from Rain CII Carbon LLC’s pet coke calcining facilitytransactions are currently in Sulphur, Louisiana. The facility began commercial operation in May 2013. In March 2013, Entergy Gulf States Louisiana executed a 20-year contract for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. In September 2013, Entergy Louisiana executed a 10-year contract with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas. LPSC certification of these three contracts has been received.negotiations.
In May 2014,July 2016, Entergy Arkansas issued the 2014 Entergy Arkansas RFP for Long-Term, Supply-Side and Renewable Generation Resources. This RFP is seeking between 200 to 600 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes from traditional resources (CT, CCTG or solid fuel) for deliveries beginning in 2017 and approximately 200 MW of the same products from renewable resources (wind, solar, biomass and hydro) for deliveries starting as early as 2015.
In September 2014,Services, on behalf of one or more of Entergy Gulf States Louisiana, Entergy Louisiana, and Entergy New Orleans, Entergy Services issued the 2014 Amite Southan RFP for Long-Term Supply Side Developmental Resourceslong-term renewable generation resources. The RFP was seeking up to be constructed in the Amite South planning region. This RFP is seeking between 650 and 100020 MW of capacity, energy,renewable resources that could provide increased depth and related products and environmental attributes from a new, single integrateddiversity to Entergy New Orleans’s generation resource portfolio. In May 2017, Entergy New Orleans selected three proposals, including a 5 MW self-build option for an aggregated solar photovoltaic resource located in Amite South, preferably in close proximitywithin Orleans Parish, Louisiana. In October 2017, Entergy New Orleans filed an application seeking City Council approval for the self-build option, which is pending before the City Council. Following unsuccessful negotiations related to the Downstreamother proposals selected in May 2017, Entergy New Orleans suspended negotiations in November 2017 and invited bidders to re-submit proposals with current information. From these submissions, in January 2018, Entergy New Orleans selected three proposals with an anticipated total capacity of Gypsy region. This RFP includes a90 MW. The updated proposals selected are in addition to the self-build option at Entergy Louisiana’s Little Gypsy site.option.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Mississippi’s January 2006 acquisition of the 480 MW, combined-cycle, gas-fired Attala power plant; Entergy Gulf States Louisiana’s March 2008 acquisition of the 322 MW, simple-cycle, gas-fired Calcasieu Generating Facility; and Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2.2; and Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating). The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire the Union Power Station,The Washington Parish Energy Center is a 1,980361 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas-fired combined-cycle gas turbinepeaking power blocks, each rated at 495 MW (summer rating). Pursuantplant under advanced development approximately 60 miles north of New Orleans on a partially developed site Calpine has owned since 2001. This simple-cycle power plant is proposed to thebe developed pursuant to an agreement with Entergy Gulf States Louisiana, which will acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas will each acquire one power block and a 25% undivided ownership interest in the related assets. If Entergy Arkansas or Entergy Texas do not obtain approval for the purchase of their power blocks, Entergy Gulf States Louisiana will seek to purchase the power blocks not approved. The base purchase price is expectedplant upon completion in 2021 for a fixed payment to be approximately $948 million (approximately $237 million for each power block) subject to adjustments.reimburse construction costs plus an associated premium. In addition,May 2017, Entergy Gulf States Louisiana anticipates selling 20% of the capacity and energy associated with its two power blocks to Entergy New Orleans through a cost-based, life-of-unit power purchase
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agreement. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. These include regulatory approvals from the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino anti-trust law. In December 2014, Entergy Texas filed its application with the PUCT for approval of the acquisition. The PUCT has indicated that it will convene the hearing on the merits of this case in June 2015. Entergy Texas intends to file a rate application to seek cost recovery later in 2015. In January 2015, Entergy Gulf States Louisiana filed itsan application with the LPSC and Entergy Arkansas filed its application with the APSC, each for approvalseeking certification of the acquisition and cost recovery. Closingplant. The application is targeted to occur in late-2015.pending.
Interconnections
The Utility operating companies’ generating units are interconnected by a transmission system operating at various voltages up to 500 kV. These generating units consist primarily of steam-electric production facilities and are provided dispatch instructions by MISO. Entergy’s Utility operating companies are MISO market participants and are interconnected with many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. As a Regional Transmission Organization, MISO assures consumers of unbiased regional grid management and open access to the transmission
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facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of the SERC Reliability Corporation (SERC). SERC is a nonprofit corporation responsible for promoting and improving the reliability, adequacy, and critical infrastructure of the bulk power supply systems in all or portions of 16 central and southeastern states. SERC serves as a regional entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing reliability standards within the SERC Region.
Gas Property
As of December 31, 2014,2017, Entergy New Orleans distributed and transported natural gas for distribution within Algiers and New Orleans, Louisiana, through approximately 2,500 miles of gas pipeline. As of December 31, 2014,2017, the gas properties of Entergy Gulf States Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Gulf States Louisiana’s financial position.
Title
The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.
Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station is owned by GSG&T, Inc., a subsidiary of Entergy Texas, and is not subject to its mortgage lien. Lewis Creek is leased to and operated by Entergy Texas.
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Fuel Supply
The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years 2012-20142015-2017 were:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Natural Gas | | Nuclear | | Coal | | Purchased Power |
Year | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh |
| 2014 | | 28 | | 4.36 |
| | 33 | | 0.89 |
| | 11 | | 2.63 |
| | 28 | | 5.14 |
|
| 2013 | | 26 | | 4.12 |
| | 39 | | 0.92 |
| | 10 | | 2.70 |
| | 25 | | 4.32 |
|
| 2012 | | 27 | | 3.15 |
| | 33 | | 0.85 |
| | 11 | | 2.60 |
| | 29 | | 3.58 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Natural Gas | | Nuclear | | Coal | | Purchased Power | | MISO Purchases |
| Year | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh |
| 2017 | | 38 | | 2.60 |
| | 26 | | 0.86 |
| | 8 | | 2.35 |
| | 8 | | 4.02 |
| | 20 | | 3.09 |
|
| 2016 | | 41 | | 2.44 |
| | 28 | | 0.63 |
| | 7 | | 2.65 |
| | 9 | | 3.71 |
| | 15 | | 3.13 |
|
| 2015 | | 35 | | 2.65 |
| | 31 | | 0.85 |
| | 7 | | 2.85 |
| | 11 | | 3.63 |
| | 16 | | 3.24 |
|
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Actual 20142017 and projected 20152018 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Natural Gas | | Nuclear | | Coal | | Purchased Power |
| | 2014 | | 2015 | | 2014 | | 2015 | | 2014 | | 2015 | | 2014 | | 2015 |
| Entergy Arkansas (a) | 12 | % | | 13 | % | | 53 | % | | 58 | % | | 24 | % | | 23 | % | | 11 | % | | 5 | % |
| Entergy Gulf States Louisiana | 43 | % | | 30 | % | | 15 | % | | 15 | % | | 9 | % | | 12 | % | | 33 | % | | 43 | % |
| Entergy Louisiana | 26 | % | | 25 | % | | 36 | % | | 35 | % | | 1 | % | | 1 | % | | 37 | % | | 39 | % |
| Entergy Mississippi | 37 | % | | 32 | % | | 22 | % | | 25 | % | | 16 | % | | 16 | % | | 25 | % | | 27 | % |
| Entergy New Orleans | 30 | % | | 31 | % | | 45 | % | | 43 | % | | 3 | % | | 3 | % | | 22 | % | | 23 | % |
| Entergy Texas | 19 | % | | 14 | % | | 13 | % | | 13 | % | | 8 | % | | 10 | % | | 60 | % | | 63 | % |
| System Energy (b) | — |
| | — |
| | 100 | % | | 100 | % | | — |
| | — |
| | — |
| | — |
|
| Utility (a) | 28 | % | | 23 | % | | 33 | % | | 33 | % | | 11 | % | | 11 | % | | 28 | % | | 33 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Natural Gas | | Nuclear | | Coal | | Purchased Power (d) | | MISO Purchases (e) |
| | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 |
| Entergy Arkansas (a) | 28 | % | | 33 | % | | 49 | % | | 51 | % | | 18 | % | | 15 | % | | — | % | | 1 | % | | 5 | % | | — |
| Entergy Louisiana | 38 | % | | 49 | % | | 26 | % | | 33 | % | | 3 | % | | 4 | % | | 9 | % | | 14 | % | | 24 | % | | — |
| Entergy Mississippi (b) | 47 | % | | 55 | % | | 18 | % | | 30 | % | | 13 | % | | 15 | % | | — | % | | — |
| | 22 | % | | — |
| Entergy New Orleans (b) | 53 | % | | 57 | % | | 33 | % | | 41 | % | | 2 | % | | 1 | % | | — | % | | 1 | % | | 12 | % | | — |
| Entergy Texas | 30 | % | | 33 | % | | 10 | % | | 17 | % | | 7 | % | | 9 | % | | 28 | % | | 41 | % | | 25 | % | | — |
| System Energy (c) | — |
| | — |
| | 100 | % | | 100 | % | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Utility (a) (b) | 38 | % | | 44 | % | | 26 | % | | 36 | % | | 8 | % | | 9 | % | | 8 | % | | 11 | % | | 20 | % | | — |
| |
| (a) | Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 20142017 and is expected to provide about less than1% of its generation in 2018. |
| |
| (b) | Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2017 and is expected to provide less than 1% of itseach of Entergy Mississippi’s and Entergy New Orleans's generation in 2015.2018. |
| |
(b)(c) | Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. |
| |
| (d) | Excludes MISO purchases |
| |
| (e) | In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. MISO purchases cannot be projected for 2018. |
Some of the Utility’s gas-fired plants are also capable of also using fuel oil, if necessary. In addition, two small peaking units burn only oil. AnyAlthough based on current economics the Utility does not expect fuel oil use in 2018, it is included inpossible that various operational events including weather or pipeline maintenance may require the total for gas.use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Long-term firm contracts for power plants comprise less than 25%Over 50% of the Utility operating companies’ total requirements.power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements. Entergy Texas owns a gas storage facility that provides reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies
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to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies will use alternate fuels, such as oil, or rely to a larger extent on coal, nuclear generation, and purchased power.
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Coal
Entergy Arkansas has committed to eight one- to three-year and two spot contracts that will supply approximately 87%85% of the total coal supply needs in 2015.2018. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 13%15% of total coal requirements will be satisfied by contracts with a term of less than one year. Based on continued improved Powder River Basin (PRB) coal deliveries by rail and the high cost of alternate sources and modes of transportation, no alternative coal consumption is expected at Entergy Arkansas during 2015. Entergy2018. Coal will be transported to Arkansas is currently negotiating a new railvia an existing transportation agreement that willis expected to provide all of Entergy Arkansas’s coalrail transportation requirements through 2015. The current agreement is set to expire June 30, 2015.for 2018.
Entergy Gulf States Louisiana has committed to fourfive one- to three-year contracts that will supply approximately 79%90% of Nelson Unit 6 coal needs in 2015. Additional2018. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as for Entergy Arkansas’s plants, no alternative coal consumption is expected at Nelson Unit 6 during 2015.2018. Coal will be transported to Nelson primarily via an existing transportation agreement that is expected to provide all of Entergy Gulf States Louisiana’s rail transportation requirements for 2015.2018.
For the year 2014,2017, coal transportation delivery to Entergy Arkansas- andArkansas-and Entergy Gulf States Louisiana-operated coal-fired units met coal demand atwas adequate for the plants and itmajority of the year but experienced some delays in the fourth quarter of 2017. It is expected that delivery times experiencedwill improve in 2014 will continue to improve through 2015.2018. Both Entergy Arkansas and Entergy Gulf States Louisiana control a sufficient number of railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Gulf States Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2015.2018. Entergy Gulf States Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
mining and milling of uranium ore to produce a concentrate;
conversion of the concentrate to uranium hexafluoride gas;
enrichment of the uranium hexafluoride gas;
fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, (EntergyEntergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy)Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
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Based upon currently planned fuel cycles, the nuclear units in both the Utility and Entergy Wholesale Commodities segments have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2015.2018 or beyond. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment is being adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the
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Palisades, Pilgrim, Indian Point 2, and Indian Point 3 plants. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and tenseven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with three interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with AtmosCenterpoint Energy Services which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The AtmosCenterpoint Energy Service gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases. In recent years, natural gas deliveries to Entergy New Orleans have been subject primarily to weather-related curtailments.
Entergy Gulf States Louisiana purchasespurchased natural gas for resale in 2017 under a firm contract from Enbridge Marketing (U.S.) Inc.Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Gulf States Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates (including intrasystem sales pursuant to the System Agreement) and
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interstate transmission of electricity, as well as rates forincluding System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
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System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
ThePrior to each operating company’s termination of participation in the System Agreement (Entergy Arkansas in December 2013, Entergy Mississippi in November 2015, and Entergy Louisiana, Entergy New Orleans, and Entergy Texas each in August 2016), the Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which iswas a rate schedule that has been approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources arewere jointly operated by the Utility operating companies that arewere participating in the System Agreement. The System Agreement provides,provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) shallwould receive payments from those parties having generating reserves that arewere less than their allocated share of reserves (short companies). Such payments arewere at amounts sufficient to cover certain of the long companies’ costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred equity, and a fair rate of return on common equity investment. Under the System Agreement, the rates used to compensate long companies arewere based on costs associated with the long companies’ steam electric generating units fueled by oil or gas and having an annual average heat rate above 10,000 Btu/kWh. In addition, for all energy exchanged among the Utility operating companies under the System Agreement, the companies purchasing exchange energy arewere required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs. Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi will terminateterminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.
See “System Agreement” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional discussion ofAlthough the System Agreement including otherhas terminated, certain of the Utility operating companies’ noticesand their retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. The proceedings include challenges to terminate participation in the future.allocation of costs as defined by the System Agreement and other matters. See Note 2 to the financial statements for discussion of legal proceedings at the FERC and in federal courts involving the System Agreement.
Transmission and MISO Markets
See “Entergy’s IntegrationOn December 19, 2013, the Utility operating companies integrated into the MISO Regional Transmission Organization”RTO. Although becoming a member of MISO does not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the “Rate, Cost-recovery,MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and Other Regulation - Federal Regulation” sectioncongestion management and provides schedules and pricing for the commitment and dispatch of Entergy Corporationgeneration that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and Subsidiaries Management’s Financial Discussionancillary services on a bilateral basis to certain wholesale customers and Analysis.offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In December 1995, System Energy commenced a rate proceeding at the FERC. In July 2001 the rate proceeding became final, with the FERC approving a prospective 10.94% return on equity. The FERC’s decision also affected other aspects of System Energy’s charges to the Utility operating companies that it supplies with power. In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased
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power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of a complaint filed with the FERC in January 2017 regarding System Energy’s return on equity.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy
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delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted rate relief for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges. The September 1989 write-off of System Energy’s investment in Grand Gulf 2, amounting to approximately $900 million, is being amortized for Availability Agreement purposes over 27 years.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in
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the event of a shortfall of funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its one outstanding series of first mortgage bonds and reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 10 to the financial statements under “Sale and Leaseback Transactions - Grand Gulf Lease Obligations.”bonds. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making
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payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.
Capital Funds Agreement
System Energy and Entergy Corporation have entered into the Capital Funds Agreement, whereby Entergy Corporation has agreed to supply System Energy with sufficient capital to (i) maintain System Energy’s equity capital at an amount equal to a minimum of 35% of its total capitalization (excluding short-term debt) and (ii) permit the continued commercial operation of Grand Gulf and pay in full all indebtedness for borrowed money of System Energy when due.
Entergy Corporation has entered into various supplements to the Capital Funds Agreement. System Energy has assigned its rights under such supplementsa supplement as security for its one outstanding series of first mortgage bonds and for reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 10 to the financial statements under “Sale and Leaseback Transactions - Grand Gulf Lease Obligations.” Each suchbonds. The supplement provides that permitted indebtedness for borrowed money incurred by System Energy in connection with the financing of Grand Gulf may be secured by System Energy’s rights under the Capital Funds Agreement on a pro rata basis (except for the Specific Payments, as defined below). In addition, in the supplements to the Capital Funds Agreement relating to the specific indebtedness being secured, Entergy Corporation has agreed to make cash capital
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contributions directly to System Energy sufficient to enable System Energy to make payments when due on such indebtedness (Specific Payments). However, if there is an event of default, Entergy Corporation must make those payments directly to the holders of indebtedness benefiting from the supplemental agreements. The payments (other than the Specific Payments) must be made pro rata according to the amount of the respective obligations benefiting from the supplemental agreements.
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The Capital Funds Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, upon obtaining the consent, if required, of those holders of System Energy’s indebtedness then outstanding who have received the assignments of the Capital Funds Agreement. No such consent would be required to terminate the Capital Funds Agreement or the supplement thereto at this time.
Service Companies
Entergy Services, a corporation wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas now owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Entergy Texas purchases from Entergy Gulf States Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. Entergy Gulf States Louisiana purchases a 57.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Texas, and Entergy Texas purchases a 42.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Gulf States Louisiana. The purchased power agreements associatedIn connection with the gas-fired generating plants will terminate when the unit(s) is/are removed from Entergy System dispatch. The dispatch and operationtermination of the generating plants did not change as a result of the jurisdictional separation. The LPSC staff has asserted thatSystem Agreement effective August 31, 2016, the purchased power agreements would terminate if Entergy Texas and Entergy Gulf States Louisiana join MISO. Entergy Gulf States Louisiana filed testimony opposing that position. The LPSC stayed considerationwere put in place for certain legacy units at the time of this issue until December 31, 2013. No further action has been taken regarding this matter.the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements in the “Federal Regulation - Entergy’s Integration Into the MISO Regional Transmission Organization” section in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
See Note 2 toOn October 1, 2015, the financial statements for a discussion of the plannedbusinesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination.combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States
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Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana. See Note 2 to the financial statements for additional discussion of the business combination.
Entergy New Orleans Internal Restructuring
In November 2017, pursuant to the agreement in principle, Entergy New Orleans, Inc. undertook a multi-step restructuring, including the following:
Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.
Earnings Ratios of Registrant Subsidiaries
The Registrant Subsidiaries’ ratios of earnings to fixed charges and ratios of earnings to combined fixed charges and preferred dividends or distributions pursuant to Item 503 of SEC Regulation S-K are as follows:
| | | | Ratios of Earnings to Fixed Charges Years Ended December 31, | Ratios of Earnings to Fixed Charges Years Ended December 31, |
| | 2014 | | 2013 | | 2012 | | 2011 | | 2010 | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| Entergy Arkansas | 3.08 | | 3.62 | | 3.79 | | 4.31 | | 3.91 | 2.87 | | 3.32 | | 2.04 | | 3.08 | | 3.62 |
| Entergy Gulf States Louisiana | 3.84 | | 3.63 | | 3.48 | | 4.36 | | 3.58 | |
| Entergy Louisiana | 3.23 | | 3.13 | | 2.08 | | 1.86 | | 3.41 | 3.85 | | 3.57 | | 3.36 | | 3.44 | | 3.30 |
| Entergy Mississippi | 3.23 | | 3.19 | | 2.79 | | 3.55 | | 3.35 | 4.49 | | 3.96 | | 3.59 | | 3.23 | | 3.19 |
| Entergy New Orleans | 3.96 | | 1.93 | | 3.02 | | 5.37 | | 4.43 | 4.50 | | 4.61 | | 4.90 | | 3.55 | | 1.85 |
| Entergy Texas | 2.39 | | 1.94 | | 1.76 | | 2.34 | | 2.10 | 2.41 | | 2.92 | | 2.22 | | 2.39 | | 1.94 |
| System Energy | 4.04 | | 5.66 | | 5.12 | | 3.85 | | 3.64 | 4.91 | | 5.39 | | 4.53 | | 4.04 | | 5.66 |
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| | | | Ratios of Earnings to Combined Fixed Charges and Preferred Dividends or Distributions Years Ended December 31, | Ratios of Earnings to Combined Fixed Charges and Preferred Dividends or Distributions Years Ended December 31, |
| | 2014 | | 2013 | | 2012 | | 2011 | | 2010 | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| Entergy Arkansas | 2.76 | | 3.25 | | 3.36 | | 3.83 | | 3.60 | 2.81 | | 3.09 | | 1.85 | | 2.76 | | 3.25 |
| Entergy Gulf States Louisiana | 3.78 | | 3.57 | | 3.43 | | 4.30 | | 3.54 | |
| Entergy Louisiana | 3.03 | | 2.92 | | 1.93 | | 1.70 | | 3.19 | 3.85 | | 3.57 | | 3.24 | | 3.28 | | 3.14 |
| Entergy Mississippi | 3.00 | | 2.97 | | 2.59 | | 3.27 | | 3.16 | 4.36 | | 3.71 | | 3.34 | | 3.00 | | 2.97 |
| Entergy New Orleans | 3.56 | | 1.74 | | 2.67 | | 4.74 | | 4.08 | 4.24 | | 4.30 | | 4.50 | | 3.26 | | 1.70 |
The Registrant Subsidiaries accrue interest expense related to unrecognized tax benefits in income tax expense and do not include it in fixed charges.
Entergy Wholesale Commodities
Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants, located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities revenues are primarily derived from sales of energy and generation capacity from these plants. Entergy Wholesale Commodities also provides operations and management services, including decommissioning services, to nuclear power plants owned by other utilities in the United States. Entergy Wholesale Commodities also includes the ownership of or participationinterests in joint ventures that own, non-nuclear power plants and the sale to wholesale customers ofthat sell the electric power produced by these plants.those plants to wholesale customers.
On December 29, 2014, Entergy Wholesale CommoditiesCommodities’ Vermont Yankee plant was removed from the grid, after 42 years of operations. The decision to close and decommission Vermont Yankee, which was announced in August 2013, as a result ofwas due to numerous issues including sustained low natural gas and wholesale energy prices, the high cost structure of the plant, and lack of a market structure that adequately compensates merchant nuclear plants for their environmental and fuel diversity benefits in the Northeast region. In November 2016, Entergy entered into an agreement to sell 100% of its membership interest in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant. The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of Entergy Nuclear Vermont Yankee’s nuclear decommissioning trust fund and the asset retirement obligation for spent fuel management and decommissioning of the plant. Entergy plans to transfer all spent nuclear fuel to dry cask storage by the end of 2018 in advance of the planned transaction close. Under the sale and related agreements to be entered into at the closing, NorthStar will commit to initiate decommissioning and site restoration by 2021 and complete those activities, along with partial restoration of the Vermont Yankee site, with the exception of the independent spent fuel storage installation and switchyard, by 2030. The original completion date, as outlined in Entergy’s Post Shutdown Decommissioning Activities Report filed with the NRC, was 2075. The transaction is contingent upon certain closing conditions, including approval by the NRC; approval by the State of Vermont Public Utility Commission, including approval of site restoration standards that will be proposed as part of the transaction; the transfer of all spent nuclear fuel to dry fuel storage on the independent spent fuel storage installation; and that the market value of the assets held in the decommissioning trust fund for the Vermont Yankee Nuclear Power Station, less the hypothetical income tax on the aggregate unrealized net gain of such assets at closing, is equal to or exceeds $451.95 million, subject to adjustments.
In October 2015, Entergy determined that it would close the FitzPatrick plant at the end of its fuel cycle in January 2017. In August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon. The transaction was contingent upon, among other things, the expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, the receipt of necessary regulatory approvals from the FERC, the NRC, and the Public Service Commission of the State of New York (NYPSC), and the receipt of a private letter ruling from the IRS. Because certain specified conditions were satisfied in November 2016, including the continued effectiveness of the Clean Energy Standards/Zero Emissions Credit program (CES/ZEC), the establishment of certain long-term agreements on acceptable terms with the Energy Research and Development Authority of the State of New York in connection with the CES/ZEC program, and NYPSC approval of the transaction on acceptable terms, Entergy
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refueled the FitzPatrick plant in January and February 2017. The sale closed in March 2017 after obtaining all the necessary approvals.
In October 2015, Entergy determined that it would close the Pilgrim plant. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision in September 2015 to place the plant in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix. The Pilgrim plant is expected to cease operations on May 31, 2019, after refueling in the spring of 2017 and operating through the end of that fuel cycle.
In December 2015, Entergy Wholesale Commodities closed on the sale of its 583 MW Rhode Island State Energy Center, in Johnston, Rhode Island. The base sales price, excluding adjustments, was approximately $490 million. Entergy Wholesale Commodities purchased the Rhode Island State Energy Center for $346 million in December 2011.
In December 2016, Entergy announced that it had reached an agreement with Consumers Energy to terminate the existing PPA for the Palisades plant on May 31, 2018. Pursuant to the agreement, Consumers Energy would pay Entergy $172 million for the early termination of the PPA. The PPA amendment agreement was subject to regulatory approvals, including approval by the Michigan Public Service Commission. Separately, Entergy intended to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. In September 2017 the Michigan Public Service Commission issued an order conditionally approving the PPA amendment transaction, but granting Consumers Energy recovery of only $136.6 million of the $172 million requested early termination payment. As a result, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy will continue to operate Palisades under the current PPA with Consumers Energy, instead of shutting down in the fall of 2018 as previously planned. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022.
In January 2017, Entergy reached a settlement with New York State, several State agencies, and Riverkeeper, Inc., under which Indian Point 2 and Indian Point 3 will cease commercial operation by April 30, 2020 and April 30, 2021, respectively, subject to certain conditions, including New York State’s withdrawal of opposition to Indian Point’s license renewals and issuance of contested permits and similar authorizations. See Note 14 to the financial statements for a discussion of the impairment and related charges associated with the settlement with New York State.
The Indian Point settlement required New York State agencies to issue environmental certifications needed for license renewal and a renewed water discharge permit based on current plant configuration. It also required the New York State Attorney General and Riverkeeper to withdraw their contentions pending before the Atomic Safety and Licensing Board (ASLB). In exchange, Entergy commits to cease commercial operation of Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021. These actions have been completed, all New York State approvals required for the NRC to issue renewed licenses have been granted, and the ASLB has terminated proceedings before it following the withdrawal of pending contentions. The NRC is not expected to issue renewed licenses earlier than third quarter 2018, as its staff must complete updates to the record on environmental and safety matters (a supplement to the final supplemental environmental impact statement and a supplement to the final safety evaluation report).
With the settlement concerning Indian Point, Entergy has announced plans for the disposition of all of the Entergy Wholesale Commodities nuclear power plants, including the sales of Vermont Yankee and FitzPatrick, and the earlier than previously expected shutdowns of Pilgrim, Palisades, Indian Point 2, and Indian Point 3. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” for further discussion.
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Property
Nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:
|
| | | | | | | | | | | | |
Power Plant | | Market | | In Service Year | | Acquired | | Location | | Capacity- Reactor Type | | License Expiration Date |
| Pilgrim | | IS0-NE | | 1972 | | July 1999 | | Plymouth, MA | | 688 MW - Boiling Water | | 2032 |
| FitzPatrick | | NYISO | | 1975 | | Nov. 2000 | | Oswego, NY | | 838 MW - Boiling Water | | 2034 |
| Indian Point 3 | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2015 |
| Indian Point 2 | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2013 (b) |
| Vermont Yankee (a) | | IS0-NE | | 1972 | | July 2002 | | Vernon, VT | | 605 MW - Boiling Water | | 2032 |
| Palisades | | MISO | | 1971 | | Apr. 2007 | | Covert, MI | | 811 MW - Pressurized Water | | 2031 |
|
| | | | | | | | | | | | |
| Power Plant | | Market | | In Service Year | | Acquired | | Location | | Capacity - Reactor Type | | License Expiration Date |
| Pilgrim (a) | | ISO-NE | | 1972 | | July 1999 | | Plymouth, MA | | 688 MW - Boiling Water | | 2032 (a) |
| Indian Point 3 (b) | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2015 (b) |
| Indian Point 2 (b) | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2013 (b) |
| Vermont Yankee (c) | | IS0-NE | | 1972 | | July 2002 | | Vernon, VT | | 605 MW - Boiling Water | | 2032 (c) |
| Palisades (d) | | MISO | | 1971 | | Apr. 2007 | | Covert, MI | | 811 MW - Pressurized Water | | 2031 (d) |
| |
| (a) | In October 2015, Entergy determined that it would close the Pilgrim plant no later than June 1, 2019, as discussed above. |
| |
| (b) | In January 2017, Entergy announced that it reached a settlement with New York State to shut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021, and resolve all New York State-initiated legal challenges to Indian Point’s operating license renewal. See below for discussion of Indian Point 2 and Indian Point 3 entering their “period of extended operation” after expiration of the plants’ initial license terms under “timely renewal.” |
| |
| (c) | On December 29, 2014, the Vermont Yankee plant ceased power production. In November 2016, Entergy entered into an agreement to sell 100% of the membership interest in Entergy Nuclear Vermont Yankee, to NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant. |
| |
(b)(d) | The original expiration dateIn December 2016, Entergy announced that it had reached an agreement with Consumers Energy to terminate the existing PPA for the Palisades plant in 2018. Separately, and assuming regulatory approvals are obtained for the PPA termination agreement, Entergy intended to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. In September 2017, as a result of the NRC operating license for Indian Point 2 was September 28, 2013. Indian Point 2 has now entered its “period of extended operation” after expiration ofMichigan Public Service Commission’s order, Entergy and Consumers Energy agreed to terminate the plant’s initial license term under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed withPPA amendment agreement. Entergy intends to shut down the licensing agency. The Indian Point license renewal application qualifies for timely renewal protection because it met NRC regulatory standards for timely filing.Palisades nuclear power plant permanently on May 31, 2022. |
In October 2015, Entergy determined that it would close the FitzPatrick plant at the end of the fuel cycle, in January 2017, but in August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon, and the sale closed in March 2017.
Entergy Wholesale Commodities also includes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and Indian Point 1 in New York that were acquired when Entergy purchased the Palisades and Indian Point 2 nuclear plants, respectively. These facilities are in various stages of the decommissioning process.
In April 2007, Entergy submitted to the NRC a joint application to renew the operating licenses for Indian Point 2 and Indian Point 3 for an additional 20 years. The original expiration datedates of the NRC operating licenselicenses for Indian Point 2 was in September 2013 and the original expiration date of the NRC operating license for Indian Point 3 is inwere September 28, 2013 and December 2015.12, 2015, respectively. Authorization to operate Indian Point 2 rests, and for Indian Point 3 will likely rest,rests on Entergy’s having timely filed a license renewal application that remains pending before the NRC. Indian Point 2 hasand Indian Point 3 have now entered itstheir “period of extended operation” after expiration of the plant’splants’ initial license term under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed with the licensing agency. Indian Point 3 is expected to reachagency until the same milestone, and to become subject to the same statutorily prescribed extension of its license expiration date, in December 2015.renewal process has been completed. The license renewal application for Indian Point 2 and Indian Point 3 qualifies for timely renewal protection because it met NRC regulatory standards for timely filing. The NRC is not expected to issue renewed licenses earlier than third quarter 2018. For additional discussion of the license renewal applications and the settlement with New York State, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
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Authorizations to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
Non-nuclear Generating Stations
In November 2016, Entergy sold its 50% membership interest in Top Deer Wind Ventures, LLC, a wind-powered electric generation joint venture owned in the Entergy Wholesale Commodities segment and accounted for as an equity method investment. Entergy sold its 50% membership interest in Top Deer for $0.5 million and realized a pre-tax loss of $0.2 million.
Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, the following non-nuclear power plants:
|
| | | | | | | | |
Plant | | Location | | Ownership | | Net Owned Capacity(a)
Capacity (a) | | Type |
Rhode Island State Energy Center; 583 MW | | Johnston, RI | | 100% | | 583 MW | | Gas |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
Top of Iowa; 80 MW (c) | | Worth County, IA | | 50% | | 40 MW | | Wind |
White Deer; 80 MW (c) | | Amarillo, TX | | 50% | | 40 MW | | Wind |
| RS Cogen; 425 MW (c) | | Lake Charles, LA | | 50% | | 213 MW | | Gas/Steam |
| Nelson 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
| |
| (a) | “Net Owned Capacity” refers to the nameplate rating on the generating unit. |
| |
| (b) | The owned MW capacity is the portion of the plant capacity owned by Entergy Wholesale Commodities. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements. |
| |
| (c) | Indirectly owned through interests in unconsolidated joint ventures. |
Independent System Operators
The Pilgrim and Vermont Yankee and Rhode Island plants fallplant falls under the authority of the Independent System Operator (ISO) New England (ISO-NE) and the FitzPatrick and Indian Point plants fall under the authority of the New York Independent System Operator (NYISO). The Palisades plant falls under the authority of the MISO. The primary purpose of ISO New England,ISO-NE, NYISO, and MISO is to direct the operations of the major generation and transmission facilities in their respective regions; ensure grid reliability; administer and monitor wholesale electricity markets; and plan for their respective region’s energy needs.
Energy and Capacity Sales
As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy in the day ahead or spot markets. In addition to selling the energy produced by its plants, Entergy Wholesale Commodities also sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward fixed pricephysical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both. See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.
As part of the purchase of the Palisades plant in 2007, Entergy executed a 15-year PPA with the seller, Consumers Energy, for 100% of the plant’s output, excluding any future uprates. Under the purchased power agreement, Consumers Energy will receivereceives the value of any new environmental credits for the first ten years of the agreement. Palisades and Consumers Energy will share on a 50/50 basis the value of any new environmental credits for years 11 through 15 of the agreement. The environmental credits are defined as benefits from a change in law that causes capability of the plant as of the purchase date to become a tradable attribute (e.g., emission credit, renewable energy credit, environmental credit, “green” credit, etc.) or otherwise to have a market value.
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credit, “green” credit, etc.) or otherwise to have a market value. In December 2016, Entergy announced that it reached an agreement with Consumers Energy to terminate the existing PPA for the Palisades plant in 2018. Entergy intended to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. In September 2017, as a result of the Michigan Public Service Commission’s order, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022. See discussion above for additional details regarding the agreement.
Customers
Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its nuclear plants include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. These customers include Consolidated Edison and Consumers Energy, companies from which Entergy purchased plants, and ISO New England,ISO-NE, NYISO, and MISO. Substantially all of the counterparties or their guarantors forcredit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants is with counterparties or their guarantors that have public investment grade credit ratings.
Competition
The ISO New EnglandISO-NE and NYISO markets are highly competitive. Entergy Wholesale Commodities has numerous competitors in New England and New York, including generation companies affiliated with regulated utilities, other independent power producers, municipal and co-operative generators, owners of co-generation plants and wholesale power marketers. Entergy Wholesale Commodities is an independent power producer, which means it generates power for sale to third parties at day ahead or spot market prices to the extent that the power is not sold under a fixed price contract. Municipal and co-operative generators also generate power but use most of it to deliver power to their municipal or co-operative power customers. Owners of co-generation plants produce power primarily for their own consumption. Wholesale power marketers do not own generation; rather they buy power from generators or other market participants and resell it to retail providers or other market participants. Competition in the New England and New York power markets is affected by, among other factors, the amount of generation and transmission capacity in these markets. MISO does not have a centralized clearing capacity market, but load serving entities do meet the majority of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. The majority of Palisades’sPalisades’ current output is contracted to Consumers Energy through 2022 and, therefore,2022. Entergy Wholesale Commodities does not expect to be materially affected by competition in the MISO market in the near term.
Seasonality
Entergy Wholesale Commodities’ revenues and operating income are subject to fluctuations during the year due to seasonal factors, weather conditions, and contract pricing. Refueling outages are generally scheduled forin the spring and the fall, and cause volumetric decreases during those seasons. When outdoor and cooling water temperatures are lower,low, generally during colder months, Entergy Wholesale Commodities nuclear power plants operate more efficiently, and consequently, generate more electricity. Many of Entergy Wholesale Commodities’ contracts provide for shaped pricing over the course of the year. As a result of these factors, Entergy Wholesale Commodities’ revenues are typically higher in the first and third quarters than in the second and fourth quarters.
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Fuel Supply
Nuclear Fuel
See “Fuel Supply - Nuclear Fuel” in the Utility portion of Part I, Item 1 for a discussion of the nuclear fuel cycle and markets. Entergy Nuclear Fuels Company, a wholly-owned subsidiary, is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for Entergy Wholesale Commodities nuclear power plants, while Entergy Nuclear Operations, Inc. acts as the agent for the purchase of nuclear fuel assembly fabrication services. All contracts for the disposal of spent nuclear fuel are between the DOE and each of the nuclear power plants.plant owners.
Other Business Activities
Entergy Nuclear Power Marketing, LLC (ENPM) was formed in 2005 to centralize the power marketing function for Entergy Wholesale Commodities nuclear plants. Upon its formation, ENPM entered into long-term power purchase agreements with the Entergy Wholesale Commodities subsidiaries that own nuclear power plants (generating
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subsidiaries). As part of a series of agreements, ENPM agreed to assume and/or otherwise service the existing power purchase agreements that were in effect between the generating subsidiaries and their customers. ENPMENPM’s functions include origination of new energy and capacity transactions and generation scheduling.
Entergy Nuclear, Inc. pursuescan pursue service agreements with other nuclear power plant owners who seek the advantages of Entergy’s scale and expertise but do not necessarily want to sell their assets. Services provided by either Entergy Nuclear, Inc. or other Entergy Wholesale Commodities subsidiaries include engineering, operations and maintenance, fuel procurement, management and supervision, technical support and training, administrative support, and other managerial or technical services required to operate, maintain, and decommission nuclear electric power facilities. Entergy Nuclear, Inc. provided decommissioning services for the Maine Yankee nuclear power plant and continues to pursue opportunities for Entergy Wholesale Commodities with other nuclear plant owners through operating agreements.plant.
Entergy Nuclear, Inc. also offers operating license renewal and life extension services to nuclear power plant owners. TLG Services, a subsidiary of Entergy Nuclear, Inc., offers decommissioning, engineering, and related services to nuclear power plant owners. In April 2009, Entergy announced that it will team with energy firm ENERCON to offer nuclear development services ranging from plant relicensing to full-service, new plant deployment. ENERCON has experience in engineering, environmental, technical and management services.
In September 2003, Entergy agreed to provide plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. The original contract was to expire in 2014 corresponding to the original operating license life of the plant. In 2006 an Entergy subsidiary signed an agreement to provide license renewal services for the Cooper Nuclear Station. The Cooper Nuclear Station received its license renewal from the NRC in November 2010. Entergy continues to provide implementation services for the renewed license. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029. In 2017 the contract was amended so that it could not be terminated prior to December 21, 2022.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
the transmission and wholesale sale of electric energy in interstate commerce;
the reliability of the high voltage interstate transmission system through reliability standards;
sale or acquisition of certain assets;
securities issuances;
the licensing of certain hydroelectric projects;
certain other activities, including accounting policies and practices of electric and gas utilities; and
changes in control of FERC jurisdictional entities or rate schedules.
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The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over some of the rates charged by Entergy Arkansas and Entergy Gulf States Louisiana. The FERC also regulates the provisions of the System Agreement, including the rates, and the provision of transmission service to wholesale market participants. The FERC also regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.
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Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC, which includes the authority to:
oversee utility service;
set retail rates;
determine reasonable and adequate service;
control leasing;
control the acquisition or sale of any public utility plant or property constituting an operating unit or system;
set rates of depreciation;
issue certificates of convenience and necessity and certificates of environmental compatibility and public need; and
regulate the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to recent legislation enacted in Tennessee, and as a result, may be requiredEntergy Arkansas is subject to submit certain matters approved by the APSC for consideration bycomplaints before the Tennessee Regulatory Authority.Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to the retail rate or regulatory scheme in Missouri.
Entergy Gulf States Louisiana’s electric and gas business and Entergy Louisiana areis subject to regulation by the LPSC as to:
utility service;
retail rates and charges;
certification of generating facilities;facilities and certain transmission projects;
certification of power or capacity purchase contracts;
audit of the fuel adjustment charge, environmental adjustment charge, and avoided cost payment to Qualifying Facilities;
integrated resource planning;
utility mergers and acquisitions and other changes of control; and
depreciation and other matters.
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Entergy Louisiana is also subject to the jurisdiction of the City Council with respect to such matters within Algiers in Orleans Parish, although the precise scope of that jurisdiction differs from that of the LPSC.Corporation, Utility operating companies, and System Energy
Entergy Mississippi is subject to regulation by the MPSC as to the following:
utility service;
service areas;
facilities;
certification of generating facilities and certain transmission projects;
retail rates;
fuel cost recovery;
depreciation rates; and
mergers and changes of control.
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Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
utility service;
retail rates and charges;
standards of service;
depreciation;depreciation and other matters;
issuance and sale of certain securities; and
other matters.mergers and changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to:
retail rates and service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
customer service standards;
certification of certain transmission and generation projects; and
extensions of service into new areas.
Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy subsidiaries in the Entergy Wholesale Commodities segment are subject to the NRC’s jurisdiction as the owners and operatoroperators of Pilgrim, Indian Point Energy Center, FitzPatrick, Vermont Yankee, and Palisades. Substantial capital expenditures, increased operating expenses, and/or higher decommissioning costs at Entergy’s nuclear plants because of revised safety requirements of the NRC could be required in the future.
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Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 20142017 of $181.3$183.3 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick and Indian Point 3, Indian Point 1 and Indian Point 2, Vermont Yankee, Palisades, and Big Rock Point spent fuel disposal contracts with the DOE held by their previous owners. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the sale of the plant, completed in March 2017. The previous owners have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the
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DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.6 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts. The DOE continues to delay meeting its obligation. Moreover, the current Presidential administration hasSpecific steps were taken specific steps to discontinue the Yucca Mountain project, and study a new spent fuel strategy. Such actions includedincluding a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. This amount of money isAlthough the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not expected to be sufficient to complete the review.review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.
Following the current Presidential administration’s defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014. Management cannot predict the potential timing or magnitude of future spent fuel fee revisions that may occur.
As a result of the DOE’s failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy’s nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. In November 2003 theseThese subsidiaries except for the owner of Palisades, beganhave been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. Through 2014,2017, Entergy’s subsidiaries have won and collected on judgments against the government totaling over $500 million.
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In April 2015 the U.S. Court of Federal Claims issued a judgment in excessthe amount of $200$29 million , including approximately $48 million collected byin favor of Entergy Arkansas in 2013,and against the U.S. for damages caused byDOE in the DOE’s breach of the contract. First round or second round ANO damages cases arecase. Also in progress covering eachApril 2015 the U.S. Court of Federal Claims issued a judgment in the nuclear plants owned by Entergy subsidiaries. In 2014 trials were heldamount of $44 million in three additional cases (second round ANO case,favor of System Energy and against the DOE in the second round Grand Gulf damages case. In June 2015, Entergy Arkansas and System Energy appealed to the U.S. Court of Appeals for the Federal Circuit portions of those decisions relating to cask loading costs. In April 2016 the Federal Circuit issued a decision in both appeals in favor of Entergy Arkansas and System Energy, and remanded the cases back to the U.S. Court of Federal Claims. In June 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $49 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case, and Entergy received the payment from the U.S. Treasury in August 2016. In July 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $31 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case, and Entergy received payment from the U.S. Treasury in October 2016.
In May 2015 the U.S. Court of Federal Claims issued a final partial summary judgment on a portion, $21 million, of the claims in the Palisades case. The DOE did not appeal that decision, and Entergy received the payment from the U.S. Treasury in October 2015.
In December 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $81 million in favor of Entergy Nuclear Indian Point 3 and Entergy Nuclear FitzPatrick in the first round Indian Point 3/FitzPatrick damages case, and Entergy received the payment from the U.S. Treasury in June 2016.
In January 2016 the U.S. Court of Federal Claims issued a judgment in the amount of $49 million in favor of Entergy Louisiana and against the DOE in the first round Waterford 3 case) but judgments havedamages case. In April 2016, Entergy Louisiana appealed to the U.S. Court of Appeals for the Federal Circuit the portion of that decision relating to cask loading costs. After the ANO and Grand Gulf appeal was rendered, the U.S. Court of Appeals for the Federal Circuit remanded the Waterford 3 case back to the U.S. Court of Federal Claims for decision in accordance with the U.S. Court of Appeals ruling on cask loading costs. In August 2016 the U.S. Court of Federal Claims issued a final judgment in the Waterford 3 case in the amount of $53 million, and Entergy Louisiana received the payment from the U.S. Treasury in November 2016.
In April 2016 the U.S. Court of Federal Claims issued a partial judgment in the amount of $42 million in favor of Entergy Louisiana and against the DOE in the first round River Bend damages case, reserving the issue of cask loading costs pending resolution of the appeal on the same issues in the Entergy Arkansas and System Energy cases. Entergy Louisiana received payment from the U.S. Treasury in August 2016. In September 2016 the U.S. Court of Federal Claims issued a further judgment in the River Bend case in the amount of $5 million. Entergy Louisiana received the payment from the U.S. Treasury in January 2017. In May 2017 the U.S. Court of Federal Claims issued a final judgment in the first round River Bend damages case for $0.6 million, awarding certain cask loading costs that had not yetpreviously been adjudicated by the court.
In May 2016, Entergy Nuclear Vermont Yankee and the DOE entered into a stipulated agreement and the U.S. Court of Federal Claims issued a judgment in anythe amount of those cases. A$19 million in favor of Entergy Nuclear Vermont Yankee and against the DOE in the second round case was filed for the Vermont Yankee plantdamages case. Entergy received payment from the U.S. Treasury in April 2014 andJune 2016.
In September 2016 the U.S. Court of Federal Claims issued a final judgment in the Entergy Nuclear Palisades case in the amount of $14 million. Entergy Nuclear Palisades received payment from the U.S. Treasury in January 2017.
In October 2016 the U.S. Supreme Court of Federal Claims issued a judgment in the second round Entergy Nuclear Indian Point 2 case was filed forin the Pilgrim plantamount of $34 million. Entergy Nuclear Indian Point 2 received payment from the U.S. Treasury in December 2014. January 2017.
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Management cannot predict the timing or amount of any potential recoveries on other claims filed by Entergy subsidiaries, and cannot predict the timing of any eventual receipt from the DOE of the U.S. Court of Federal Claims damage awards.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at Palisades in 1993, at ANO in 1996, at FitzPatrick in 2002, at River Bend in 2005, at Grand Gulf in 2006, at Indian Point and Vermont Yankee in 2008, at Waterford 3 in 2011, and at Pilgrim in 2015. These facilities will be expanded as needed.
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Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Texas, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation, Waterford 3, and Grand Gulf, respectively.regulation. The collections are deposited in trust funds that can only be used for future decommissioning costs. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
Following a review in 2009, Entergy concluded that there was a funding shortfall for Vermont Yankee of approximately $40 million, which it satisfied with a $40 million guarantee from Entergy Corporation that is still in place subject to a 120-day notice of cancellation sent to the NRC in December 2014. In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend and in December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2016 the APSC ordered continued collections for decommissioning for ANO 2, while finding that ANO 1’s decommissioning was adequately funded without continued collections. In December 2017 the APSC ordered continued collections for decommissioning for ANO 2, and again found that ANO 1’s decommissioning was adequately funded without continued collections. In September 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed (among other things) to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted the proposal subject to refund, and appointed a settlement judge to oversee settlement negotiations in the case. Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
In November 2016, Entergy entered into an agreement to sell 100% of the membership interest in Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar. Upon closing of the sale, NorthStar will assume ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. The sale is subject to certain closing conditions, including approval from the NRC and the State of Vermont Public Utility Commission. See Note 19 to the financial statements for further discussion of Vermont Yankee decommissioning costs.costs and see “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the NorthStar transaction.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning truststrust funds and the decommissioning liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specify their decommissioning obligations. NYPA hasliabilities with the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigns the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. IfIn August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities are retained by NYPA,for the responsibleIndian Point 3 and FitzPatrick plants to Entergy, subsidiary will performwhich was completed in January 2017. In March 2017, Entergy sold the FitzPatrick plant to Exelon, and as part of the transaction, the FitzPatrick decommissioning trust fund, along with the decommissioning obligation for that plant, was transferred to Exelon. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the plants at a price equaltransaction. See Note 14 to the lesserfinancial statements for discussion of a pre-specified level or the amount in the decommissioning trusts.FitzPatrick sale.
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In March 2014, Entergy Nuclear Operations made2017 filings with the NRC were made for certain Entergy subsidiaries’ nuclear plants reporting on decommissioning funding for certain of Entergy’s nuclear plants.funding. Those reports all showed that decommissioning funding for each of those nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 1716 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $127.318$127.3 million per reactor (with 104102 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, System Energy, or an Entergy Wholesale Commodities company is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.
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The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. Waterford 3, River Bend, Indian Point 2, Indian Point 3, and Palisades are in Column 1. Grand Gulf is in Column 2. ANO 1 and 2 are in Column 4, and are subject to an extensive set of required NRC inspections. Pilgrim is also in Column 4 and is subject to an extensive, but limited, set of required NRC inspections. See Note 8 to the financial statements for further discussion of the placement of ANO 1 and 2, and Pilgrim in Column 4 of the NRC’s matrix.
Environmental Regulation
Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations.operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.
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Clean Air Act and Subsequent Amendments
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
New source review and preconstruction permits for new sources of criteria air pollutants, new and existing sources of greenhouse gases, and significant modifications to existing facilities;
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| • | Acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx); |
Nonattainment area programs for control of criteria air pollutants, which could include fee assessments for air pollutant emission sources under Section 185 of the Clean Air Act if attainment is not reached in a timely manner;
Hazardous air pollutant emissions reduction programs;
Interstate Air Transport;
Operating permits program for administrationpermit programs and enforcement of these and other Clean Air Act programs;
Regional Haze and Best Available Retrofit Technology programs; and
New and existing source standards for greenhouse gas emissions.
New Source Review (NSR)
Preconstruction permits are required for new facilities and for existing facilities that undergo a modification that results in a significant net emissions increase and is not classified as routine repair, maintenance, or replacement. Units that undergo certain non-routine modifications must obtain a permit modification and may be required to install additional air pollution control technologies. Entergy has an established process for identifying modifications requiring additional permitting approval and has followedfollows the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. In recent years, however, the EPA has begun an enforcement initiative, aimed primarily at coal plants, to identify modifications that it does not consider routine for which the unit did not obtain a modified permit. Various courts and the EPA have been inconsistent in their judgments regarding modifications that are considered routine.routine and on other legal issues that affect this program.
In February 2011, Entergy received a request from the EPA for several categories of information concerning capital and maintenance projects at the White Bluff and Independence facilities, both located in Arkansas, in order to determine compliance with the Clean Air Act.Act, including NSR requirements and air permits issued by the Arkansas Department of Environmental Quality. In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 a subsequent request for similar information was received for the White Bluff facility. Entergy responded to bothall requests. NeitherNone of these EPA requestrequests for information alleged that the facilities arewere in violation of law.
In January 2018 and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. Entergy is reviewing these claims and will respond accordingly.
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Acid Rain Program
The Clean Air Act provides SO2 allowances to most of the affected Entergy generating units for emissions based upon past emission levels and operating characteristics. Each allowance is an entitlement to emit one ton of SO2 per year. Plant owners are required to possess allowances for SO2 emissions from affected generating units. Virtually all Entergy fossil-fueled generating units are subject to SO2 allowance requirements. Entergy could be required to purchase additional allowances when it generates power using fuel oil. Fuel oil usage is determined by economic dispatch and influenced by the price and availability of natural gas, incremental emission allowance costs, and the availability and cost of purchased power.
Ozone Nonattainment
Entergy Texas operates one fossil-fueled generating unitfacility (Lewis Creek) and is in the process of permitting and constructing one fossil-fueled facility (Montgomery Count Power Station) in a geographic area that is not in attainment ofwith the currently-enforced national ambient air quality standards (NAAQS) for ozone. The nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Areas in nonattainment are classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
The Houston-Galveston-Brazoria area was originally classified as “moderate” nonattainment under the 1997 8-hour ozone standard with an attainment date of June 15, 2010. In June 2007 the Texas governor petitioned the EPA to reclassify Houston-Galveston-Brazoria from “moderate” to “severe” and the EPA granted the request in October 2008. In February 2015 the Texas Commission on Environmental Quality (TCEQ) submitted a request to the EPA for a finding that the Houston-Galveston-Brazoria area is in attainment with the 1997 8-hour ozone standard. The area’s new attainment dateEPA issued this finding in December 2015. In April 2015 the EPA revoked the 1997 ozone NAAQS and in May 2016, the EPA issued a proposed rule approving a substitute for the Houston-Galveston-Brazoria area. This redesignation indicates that the area has attained the revoked 1997 8-hour ozone standard is as expeditiously as practicable, butNAAQS due to permanent and enforceable emission reductions and that it will maintain that NAAQS for 10 years from the date of the approval. Final approval, which was effective in December 2016, resulted in the area no later than June 15, 2019.longer being subject to any remaining anti-backsliding or non-attainment new source review requirements associated with the revoked 1997 NAAQS.
In March 2008 the EPA revised the NAAQS for ozone, creating the potential for additional counties and parishes in which Entergy operates to be placed in nonattainment status. In April 2012 the EPA released its final non-attainment designations for the 2008 ozone NAAQS. In Entergy’s utility service area, the Houston-Galveston-Brazoria, Texas; Baton Rouge, Louisiana; and Memphis, Tennessee/Mississippi/Arkansas areas were designated as in “marginal” nonattainment.
For these marginal In August 2015 and January 2016, the EPA proposed determinations that the Baton Rouge and Memphis areas had attained the 2008 standard. In May 2016 the EPA finalized those determinations and extended the Houston-Galveston-Brazoria area’s attainment must be demonstrated no later thandate for the 2008 Ozone standard to July 20, 2015 (with2016 and reclassified the Baton Rouge area as attainment for ozone under the 2008 8-hour ozone standard. In December 2016 the EPA evaluating whetherdetermined that the Houston-Galveston-Brazoria area attained the standard based on monitored ozone data from 2013-2015). In the final designation rule, EPA states that it anticipates the marginal areas will be ablehad failed to attain the 2008 ozone standard by that date based upon reductions attendant with other rules and programs such as the interstate transport rules. Entergy facilities in these areas may be subject2016 attainment date. This finding reclassifies the Houston-Galveston-Brazoria area from marginal to installation of NOx controls, but the degree of control will remain unknown until the states are further along in implementation in the marginal areas. Entergy will continue to monitor and engage in the state’s implementation process in Entergy states.“moderate.”
In December 2014October 2015 the EPA publishedissued a proposedfinal rule to lowerlowering the primary and secondary NAAQS for ozone to a level within a range of 65 to 7570 parts per billion (ppb).billion. States were required to assess their attainment status and recommend designations to the EPA. In January 2018 the EPA proposed that the following counties and parishes in Entergy’s service territory be listed as in non-attainment: in Louisiana, Ascension Parish, East Baton Rouge Parish, West Baton Rouge Parish, Iberville Parish, and Livingston Parish; in Texas, Montgomery County. In addition to Lewis Creek in Montgomery County, Texas, Entergy owns or operates fossil-fueled generating units in East Baton Rouge Parish (Louisiana Station) and in Iberville Parish (Willow Glen), Louisiana. The agency also is askingEPA’s final designations are pending. Entergy will continue to work with state environmental agencies on appropriate methods for commentassessing attainment and non-attainment with the new standard and, where necessary, in planning for compliance. Following designations by the EPA, states will be required to develop plans intended to return non-attainment areas to a condition of attainment. The timing for that action depends largely on the potential for leaving the standard at its current levelseverity of 75 ppb, or lowering the standard to 60 ppb. Entergy is analyzing the proposal and is engaged with industry groups, regulators, and lawmakers. If the standard is lowered, this may resultnon-attainment in additional counties/parishes in which Entergy operates being designated as nonattainment and potentially requiring further emission reductions. Comments are due in March 2015, and a final rule is anticipated in late-2015 according to the EPA’s regulatory agenda.given area.
Potential SO2 Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. The EPA designations for counties in attainment and nonattainment were originally due in June 2012, but the EPA has indicated that it willwould delay designations except for those areas with existing monitoring data from 2009
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to 2011 indicating violations of the new standard. In JulyAugust 2013 the EPA issued final designations for these areas. In Entergy’s utility service territory, only St. Bernard Parish in Louisiana is designated as non-attainment for the SO2
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1-hour national ambient air quality standard of 75 parts per billion. Entergy does not have a generation asset in that parish. In all otherJuly 2016 the EPA finalized another round of designations for areas analysis is required oncewith newly monitored violations of the 2010 standard and those with stationary sources that emit over a threshold amount of SO2. Counties and parishes in which Entergy owns and operates fossil generating facilities that were included in this round of designations include Independence County and Jefferson County, Arkansas and Calcasieu Parish, Louisiana. Independence County and Calcasieu Parish were designated “unclassifiable,” and Jefferson County was designated “unclassifiable/attainment.” In August 2015 the EPA issues additionalissued a final regulationsdata requirement rule for the SO2 1-hour standard. This rule will guide the process to be followed by the states and guidance.the EPA to determine the appropriate designation for the remaining unclassified areas in the country. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020 as monitors were installed to determine compliance. In January 2018 the EPA published a final rule designating a third round of attainment and non-attainment areas. Evangeline Parish, Louisiana, was designated non-attainment. Entergy does not have a generation asset in that parish. Additional capital projects or operational changes may be required forto continue operating Entergy facilities in theseareas eventually designated as in non-attainment of the standard or designated as contributing to non-attainment areas.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, and the rule became effective inwhich had a compliance date, with a widely granted one-year extension, of April 2012. Entergy currently is on schedule to have the2016. The required controls in place for compliancehave been installed and are operational at Entergy’s coal-firedall affected Entergy units. Compliance with MATS is required by the Clean Air Act within three years, or by 2015, although certain extensions of this deadline are available from state permit authorities and the EPA. Entergy has applied for and received a one-year extension, as allowed by the Clean Air Act, for its affected facilities in Arkansas and Louisiana.
Cross-State Air Pollution
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy.
Based on several court challenges, CAIR and its subsequent versions, now known as the CAIR was vacatedCross State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions. In July 2015 the D.C. Circuit invalidated the allowance budgets created by the EPA for several states, including Texas, and remanded that portion of the rule to the EPA by the D.C. Circuit in 2008.for further action. The court alloweddid not stay or vacate the CAIR to become effectiverule in January 2009, while the EPA revised the rule. In July 2011 the EPA released its final Cross-State Air Pollution Rule (CSAPR, which previously was referred to as the Transport Rule). The rule was directed at limiting the interstate transport of emissions of NOx and SO2 as precursors to ozone and fine particulate matter. The final rule provided a significantly lower number of allowances to Entergy’s Utility states than did the draft rule. Entergy’s capital investment and annual allowance purchase costs under theinterim. CSAPR would depend on the economic assessment of NOx and SO2 allowance markets, the cost of control technologies, generation unit utilization, and the availability and cost of purchased power.remains in effect.
Entergy filed a petition for review with the United States Court of Appeals for the D.C. Circuit and a petition with the EPA for reconsideration of the rule and stay of its effectiveness. Several other parties filed similar petitions. In December 2011 the Court of Appeals for the D.C. Circuit Court stayed CSAPR and instructed the EPA to continue administering CAIR, pending further judicial review. In August 2012 the court issued a decision vacating CSAPR and leaving CAIR in place pending the promulgation of a lawful replacement for both rules. In January 2013 the court denied petitions for reconsideration filed by the EPA and certain states and intervenors. In March 2013 the EPA and other parties filed petitions for certiorari with the U.S. Supreme Court. The U.S. Supreme Court issued an order in June 2013 granting the EPA’s and environmental groups’ petitions for review of the D.C. Circuit’s decision vacating CSAPR. In April 2014 the U.S. Supreme Court reversed the D.C. Circuit and remanded the case to the D.C. Circuit for further proceedings. In June 2014 the EPA filed a motion with the D.C. Circuit Court requesting that the court lift the stay and extend CSAPR’s deadlines by three years so that the Phase 1 emissions budgets apply in 2015 and 2016 and the Phase 2 emissions budgets apply in 2017 and beyond. In October 2014 the D.C. Circuit granted EPA’s motion to lift the stay. Accordingly, CSAPR Phase 1 implementation became effective January 1, 2015. Entergy is developinghas developed a compliance plan that could, over time, include both installation of controls at certain facilities and an emission allowance procurement strategy. Litigation concerning several issues not determined by
In September 2016 the U.S. Supreme Court continuesEPA finalized the CSAPR Update Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 the D.C. Circuit.final rule will require reductions in summer nitrogen oxides (NOx) emissions. Several states, including Arkansas and Texas, filed a challenge to the Update Rule, which remains pending.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could potentially result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology (BART) to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states.
In Arkansas, the Arkansas Department of Environmental Quality prepared a state implementation plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. In April 2012 the EPA finalized a decision
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(BART) on certain of Entergy’s coal and oil generation units. The rule leaves certain CAVR determinations to the states. The Arkansas Department of Environmental Quality (ADEQ) prepared a State Implementation Plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. The ADEQ determined that Entergy Arkansas’s White Bluff power plant affects a Class I Area’s visibility and will be subject to the EPA’s presumptive BART limits, which likely would require the installation of scrubbers and low NOx burners. Under then-current state regulations, the scrubbers would have had to be operational by October 2013. Entergy Arkansas filed a petition in December 2009 with the Arkansas Pollution Control and Ecology Commission requesting a variance from this deadline because the EPA had expressed concerns about Arkansas’s Regional Haze SIP and questioned the appropriateness of issuing an air permit prior to that approval. Entergy Arkansas’s petition requested that, consistent with federal law, the compliance deadline be changed to as expeditiously as practicable, but in no event later than five years after EPA approval of the Arkansas Regional Haze SIP. The Arkansas Pollution Control and Ecology Commission approved the variance in March 2010. In October 2011 the EPA released a proposed rule addressing the Arkansas Regional Haze SIP. In the proposal the EPASIP, in which it disapproved a large portion of the Arkansas Regional Haze SIP,plan, including the emission limits for NOx and SO2 at White Bluff. In April 2015 the EPA published a proposed federal implementation plan (FIP) for Arkansas, taking comment on requiring installation of scrubbers and low NOx burners to continue operating both units at the White Bluff plant and both units at the Independence plant and NOx controls to continue operating the Lake Catherine plant. Entergy filed comments by the deadline in August 2015. Among other comments, including opposition to the EPA’s proposed controls on the Independence units, Entergy proposed to meet more stringent SO2 and NOx limits at both White Bluff and Independence within three years of the effective date of the final FIP and to cease the use of coal at the White Bluff units at a later date.
In September 2016 the EPA published the final Arkansas Regional Haze FIP. In most respects, the EPA finalized its original proposal but shortened the time for compliance for installation of the NOx controls. The FIP required an emission limitation consistent with SO2 scrubbers at both White Bluff and Independence by October 2021 and NOx controls by April 2018. The EPA declined to adopt Entergy’s proposals related to ceasing coal use as an alternative to SO2 scrubbers for White Bluff SO2 BART. In November 2016, Entergy and other interested parties, including the State of Arkansas, filed petitions for administrative reconsideration and stay at the EPA as well as petitions for judicial review in the U.S. Court of Appeals for the Eighth Circuit. The Eighth Circuit continues to review its prior grant of the government’s motion to hold the appeal litigation in abeyance pending settlement discussions and pending the State’s development of a SIP that, if approved by the EPA, would replace the FIP. The state has proposed its replacement SIP in two parts: Part I considers NOx requirements, and Part II considers SO2 requirements. The EPA approved the Part I NOx SIP in January 2018. Arkansas has proposed a Part II SIP which is still under consideration at the state level. The public comment period on Part II ended on February 2, 2018.
In Louisiana, Entergy worked with the Louisiana Department of Environmental Quality (LDEQ) and the EPA to revise the Louisiana SIP for regional haze, which was disapproved in part in 2012. The LDEQ submitted a revised SIP in February 2017. In May 2017 the EPA proposed to approve a majority of the revisions. In September 2017 the EPA issued a proposed SIP approval for the Nelson plant, requiring an emission limitation consistent with the use of low-sulfur coal, with a compliance date three years from the effective date of the final ruleEPA approval. The EPA’s final approval decision was published, mostly unchanged,issued in March 2012December 2017 and became finalis on appeal to the U.S. Court of Appeals for the Fifth Circuit.
New and Existing Source Performance Standards for Greenhouse Gas Emissions
As a part of a climate plan announced in April 2012. This triggered a two-year timeframe in whichJune 2013, the EPA was requireddirected to either approve(i) reissue proposed carbon pollution standards for new power plants by September 20, 2013, with finalization of the rules to occur in a revised SIP issued by Arkansastimely manner; (ii) issue proposed carbon pollution standards, regulations, or issue a Federal Implementation Plan (FIP). This two-year time frame expired in April 2014. In December 2014 a draft consent decree between the Sierra Clubguidelines, as appropriate, for modified, reconstructed, and the EPA was filed with the U.S. District Court for the Eastern District of Arkansas. This consent decree states that the EPA is to issue a draft FIP addressing Regional Haze requirements in Arkansasexisting power plants no later than June 1, 2014; (iii) finalize those rules by no later than March 6, 2015June 1, 2015; and (iv) include in the guidelines addressing existing power plants a final FIP for these same requirementsrequirement that states submit to the EPA the implementation plans required under Section 111(d) of the Clean Air Act and its implementing regulations by no later than December 15, 2015. The consent decree has not been finalized. These decisions could impact the timing and level of control installation at Entergy's units in Arkansas.
Fine Particle (PM2.5) National Ambient Air Quality Standard
June 30, 2016. In December 2012 the EPA released regulations that lowered the NAAQS for fine particle pollution or PM2.5. In DecemberJanuary 2014 the EPA issued the proposed New Source Performance Standards rule for new sources. In June 2014 the EPA issued proposed standards for existing power plants. Entergy was actively engaged in the rulemaking process, and submitted comments to the EPA in December 2014. The EPA issued the final area designationsrules for this standard. All areasboth new and existing sources in Entergy’s service territoryAugust 2015, and they were designated as “Unclassifiable/Attainment”published in the Federal Register in October 2015. The existing source rule, also called the Clean Power Plan, requires states to develop plans for this standard.compliance with the EPA’s emission standards. In February 2016 the U.S. Supreme Court issued a stay halting the effectiveness of the rule until the rule is reviewed by the D.C. Circuit and by the U.S. Supreme Court, if further review is granted. In March 2017 the current administration issued an executive order entitled “Promoting Energy Independence and Economic Growth” instructing the EPA to review and then to suspend, revise, or rescind the Clean Power Plan, if appropriate. The EPA subsequently asked the D.C. Circuit to hold the challenges to the Clean Power Plan and the greenhouse gas new source performance standards in abeyance and signed a notice of withdrawal of the proposed federal plan, model trading rules, and the Clean Energy Incentive Program. The court placed the litigation in abeyance in April 2017. The EPA Administrator also sent a letter to the affected governors explaining that states are not currently required to meet Clean Power Plan deadlines, some of which have passed. In October 2017 the EPA proposed a new rule that would repeal the Clean Power Plan on the grounds that it exceeds the EPA’s statutory authority under the Clean Air Act. In December
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2017 the EPA issued an advanced notice of proposed rulemaking regarding section 111(d), seeking comment on the form and content of a replacement for the Clean Power Plan, if one is promulgated. Entergy will continue to monitor and engagebe engaged in the state’s implementation process in Entergy states.this rulemaking process.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives concerning air emissions, as well as other media, that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
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| • | introduction of bills in Congress and development of regulations by the EPA proposing further limits on NOx, SO2, mercury, and carbon dioxide and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs; |
efforts in Congress or at the EPA to establish a mandatory federal carbon dioxide emission control structure or unit performance standards;
revisions to the estimates of the Social Cost of Carbon usedand its use for regulatory impact analysis of Federal laws and regulations;
implementation of the Regional Greenhouse Gas Initiative by several states in the northeastern United States and similar actions in other regions of the United States;
efforts on the state and federal level to codify renewable portfolio standards, a clean energy standard, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;
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efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;
efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of PCBs; and
efforts by certain external groups to encourage reporting and disclosure of carbon dioxide emissions and risk. Entergy has prepared responsesrisk;
the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the Carbon Disclosure Project’s (CDP) annual questionnaire for legal protection of eagles and migratory birds; and
the past several yearsregulation of the management, disposal, and has given permission for those responses to be posted to CDP’s website.beneficial reuse of coal combustion residuals.
Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in a responsible and flexible manner. By virtue of its proportionally large investment in low-emitting gas-fired and nuclear generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per kilowatt-hourmegawatt-hour of electricity generated. In anticipation of the potential imposition of carbon dioxide emission limits on the electric industry in the future, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included establishment of a formal program to stabilize power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in actually reducing emissions below 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants in the United States were approximately 53.2 million tons in 2000 and 35.6 million tons in 2005. In 2006, Entergy changed its method of calculating emissions and now includesto include emissions from controllable power purchases as well as its ownership share of generation. Entergy established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 46.1 million tons in 2011, approximately 45.5 million tons in 2012, approximately 46.2 million tons in 2013, and approximately 41.842.4 million tons in 2014.2014, 39.5 million tons in 2015, 42.5 million tons in 2016, and 39.9 million tons in 2017. The decrease
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in this number infrom 2014 isto 2015 was largely attributable to the impact on the calculation methodology of the Utility operating companies’ transition into the MISO system. Participation in this system resulted in fewer power purchases being classified as "controllable"“controllable” and thus included in the calculation of the emissions total.
Greenhouse Gas Reporting
In September 2009,Entergy participates in the EPA finalized a rule to require reporting of several greenhouse gases. This rule requires Entergy to report annually greenhouse gas emissions from operating power plants, various combustion sources, certain transmission and distribution equipment, and natural gas distribution operations.
New and Existing Source Performance Standards for Greenhouse GasM.J. Bradley & Associates’ Annual Benchmarking Air Emissions
As a part of a climate plan announced in June 2013, President Obama directed the EPA to (i) reissue proposed carbon pollution standards for new power plants by September 20, 2013, with finalization Report, an annual analysis of the rules to occur in a timely manner; (ii) issue proposed carbon pollution standards, regulations, or guidelines, as appropriate, for modified, reconstructed,100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s annual CO2 emissions audit is also third-party verified, and existing power plants no later than June 1, 2014; (iii) finalize those rules by no later than June 1, 2015; and (iv) includethat certification is made available on the American Carbon Registry website. Entergy participates annually in the guidelines addressing existing power plants a requirement that states submit toDow Jones Sustainability Index and in 2017 was listed on the EPA the implementation plans required under Section 111(d) of the Clean Air Act and its implementing regulations by no later than June 30, 2016. In September 2013 the EPA issued the proposed New Source Performance Standards rule for new sources. The rule was published in the Federal Register in January 2014. In June 2014 the EPA issued proposed standards for existing power plants. Entergy is actively engaged in the rulemaking process, having submitted comments to the EPA in December 2014. Cost and methods of compliance remain unknown at this time.North American Index.
Nelson Unit 6 (Entergy Gulf States Louisiana)
Entergy Gulf States Louisiana has self-reported to the LDEQ an annual carbon monoxide (CO) emission limit deviation at the Nelson Unit 6 coal-fired facility for the years 2006-2010 and the failure to report these deviations in semi-annual reporting and in annual Title V compliance certifications. Entergy Gulf States Louisiana is not required
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to monitor carbon monoxide emissions from Nelson Unit 6 using a continuous emissions monitoring system (CEMS). Stack tests performed in 2010 appear to indicate CO emissions in excess of the maximum hourly limit for three - 1 hour test runs; however, comparison of the 2010 stack tests with the most recent previous tests, from 2006, appear to indicate that the permit limits were calculated incorrectly in the Title V Permit application and should have been higher using the 2006 stack test as the basis. The 2010 test emission levels did not cause a violation of NAAQS. Additionally, the 2010 stack testing, which was performed in compliance with an EPA data request connected to the agency’s development of a new air emissions rule, was not taken during a period of normal and representative operations for Nelson 6. Settlement negotiations continue with the LDEQ.
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System (NPDES) permit program and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
NPDES Permits and Section 401 Water Quality Certifications
NPDES permits are subject to renewal every five years. Consequently, Entergy is currently in various stages of the data evaluation and discharge permitting process for its power plants. Additionally, the State of New York has taken the position that a new state-issued water quality certification is required as part of the NRC license renewal process. Entergy Wholesale Commodities’ Indian Point nuclear facility in New York is seeking a new Section 401 certification prior to license renewal under full reservation of rights.
Indian Point
For thirteen years, Entergy is involvedparticipated in an administrative permitting process with the New York State Department of Environmental Conservation (NYSDEC) for renewal of the Indian Point 2 and Indian Point 3 discharge permit. In November 2003That proceeding recently was settled along with other ongoing proceedings. For a discussion of the NYSDEC issued a draft permit indicating that closed cycle cooling would be considered the “best technology available” for minimizing alleged adverse environmental effects attributable to the intake of cooling water atrecent Indian Point subject to a feasibility determination and alternatives analysis for that technology, if Entergy applied for and received NRC license renewal for Indian Point 2 and Indian Point 3. Upon becoming effective, the draft permit also would have required payment of approximately $24 million annually, and an annual 42 unit-day outage period, until closed cycle cooling is implemented. Entergy is participating in the administrative process to request that the draft permit be modified prior to final issuance, and opposes any requirement to install cooling towers at Indian Point.
An August 2008 ruling by the NYSDEC’s Assistant Commissioner restructured the permitting and administrative process, including the application of a new economic test designed to implement the U.S. Second Circuit Court of Appeals standard in that court’s review of the EPA’s cooling water intake structure rules, which is discussed in the 316(b) Cooling Water Intake Structures section below. The NYSDEC has directed Entergy to develop detailed feasibility information regarding the construction and operation of cooling towers, and alternatives to closed cycle cooling, prior to the issuance of a new draft permit by the NYSDEC staff and commencement of the adjudicatory proceeding. The reports include a visual impact and aesthetics report filed in June 2009, a plume and emissions report filed in September 2009, a technical feasibility report and alternatives analysis filed in February 2010, and an economic report to establish whether the technology, if feasible, satisfies the economic test that is part of the New York standard. Entergy requested that the NYSDEC Assistant Commissioner reconsider the New York standard in light of the U.S. Supreme Court decision reversing the Second Circuit’s alternative economic test adopted in the August 2008 ruling. In November 2012 the NYSDEC Assistant Commissioner’s delegate issued a decision overturning the alternative economic test adopted in the August 2008 ruling and reestablishing the “wholly disproportionate” test
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derived from previous New York precedent. The wholly disproportionate test considers whether the costs of a technology are wholly disproportionate to the environmental benefits gained from the technology.
In February 2010, Entergy provided to the NYSDEC an updated estimate of the capital cost to retrofit Indian Point 2 and Indian Point 3 with cooling towers. Construction costs for retrofitting with cooling towers are estimated to be at least $1.19 billion, in addition to lost generation of approximately 14.5 terawatt-hours (TWh) during the forced outage of both units that is estimated to take at least 42 weeks. Entergy also proposed an alternative to the cooling towers, the use of cylindrical wedgewire screens, the construction costs of which are now expected to be approximately $250 million to $300 million. Because a cooling tower retrofitting of this size and complexity has never been undertaken at an operating nuclear facility, significant uncertainties exist in the capital cost estimates and, therefore, the actual capital costs could be materially higher than estimated. Moreover, construction outage-related costs to Entergy have not been calculated because of the significant variability in power pricing at any given time, but they are expected to be significant and may exceed the capital costs. The capital cost estimate for the wedgewire screen construction is also subject to uncertainty. Hearings on certain issues began in 2011 in consolidation with certain issues in the water quality certification matter.
Hearings were held in July 2013 before NYSDEC ALJs on environmental issues related to Indian Point’s wedgewire screen proposal for “best technology available.” In 2014, hearings were held on NYSDEC’s proposed best technology available, closed cycle cooling. NYSDEC also has proposed annual fish protection outages of 42, 62, or 92 days at both units or at one unit with closed cycle cooling at the other. The ALJs held a further legislative hearing and issues conference on this NYSDEC staff proposal in July 2014. In January 2015, Entergy wrote NYSDEC leadership requesting an explanation of the delay in release of the ruling following an ALJ's on-record statement that the ALJ's draft ruling was under "executive review." In February 2015 the ALJs issued a ruling scheduling hearings on the outage proposals and other pending issues in September and October 2015, with post-hearing briefing to follow in December 2015. For additional discussion of this and other proceedings related to Indian Point,settlement, see “Entergy Wholesale Commodities AuthorizationsAuthorization to Operate Its Nuclear PlantsIndian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
Pilgrim Nuclear Power Station
In October 2012, EcoLaw, a coalition of several environmental groups, served Entergy Nuclear Generating Company and Entergy Nuclear Operations, Inc. with a notice of intent (NOI) to sue under the Clean Water Act for alleged violations at the Pilgrim Nuclear Power Station. The NOI alleges 33,253 discharge permit violations since 1994 (including alleged violations prior to Entergy’s ownership; Entergy purchased the plant in 1999) and seeks $25,000 per violation for a total of $831,325,000. The Clean Water Act states that an alleged violator must be given 60 days notice prior to a citizen’s suit being filed. Review of the NOI indicates that many of the alleged violations were discharges in compliance with the current EPA facility discharge permit, which the putative plaintiff alleges was improperly issued or modified. An additional NOI was served by EcoLaw to the same Entergy parties and the Massachusetts Department of Environmental Protection alleging violations of state water quality standards and requesting revocation of the state-issued Section 401 Water Quality Certification associated with the plant’s water discharge permit. In November and December 2012, Entergy filed responses to the state and federal notices of intent to sue. To date, Pilgrim has not received notice that EcoLaw has initiated any lawsuits against Pilgrim.
316(b) Cooling Water Intake Structures
The EPA finalized regulations in July 2004 governing the intake of water at large existing power plants employing cooling water intake structures. The rule sought to reduce perceived impacts on aquatic resources by requiring covered facilities to implement technology or other measures to meet EPA-targeted reductions in water use and corresponding perceived aquatic impacts. Entergy, other industry members and industry groups, environmental groups, and a coalition of northeastern and mid-Atlantic states challenged various aspects of the rule. In January 2007 the U.S. Second Circuit Court of Appeals remanded the rule to the EPA for reconsideration. The court instructed the EPA to reconsider several aspects of the rule that were beneficial to businesses affected by the rule after finding that these provisions of the rule were contrary to the language of the Clean Water Act or were not sufficiently explained in
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the rule. In April 2008 the U.S. Supreme Court agreed to review the Second Circuit decision on the question of whether the EPA may take into consideration a cost-benefit analysis in developing these regulations, a consideration of potential benefit to businesses affected by the rule that the Second Circuit disallowed. In March 2009 the Supreme Court ruled in favor of the petitioners that cost-benefit analysis may be taken into consideration. The EPA reissued the proposed rule in April 2011. Entergy filed comments with the EPA on the proposed rule. The EPA further extended the finalization deadline to November 2013, then to January 2014, and then to April 2014. In May 2014After litigation, the EPA issued thea new final 316(b) rule followed by publication in the Federal Register in August 2014, with the final rule effective in October 2014. Entergy is developing a compliance plan for each affected facility in accordance with the requirements of the final rule.
Entergy filed a petition for review of the final rule as a co-petitioner with the Utility Water Act Group a petitionGroup. The U.S. Court of Appeals for review of the final rule. The case will be heard in the U.S. Second Circuit Court of Appeals. Entergy expects briefing on the case to occurheard oral argument in 2015.September 2017. A decision is expected in 2018.
Coastal Zone Management Act
Before a federal licensing agency (such as the NRC) may issue a major license or permit for an activity within the federally designated coastal zone, the agency must be satisfied that the requirements of the Coastal Zone Management Act (CZMA), as applicable, have been met. In many cases, CZMA requirements are satisfied by the state’s written concurrence with a “consistency determination” filed by the federal license applicant explaining why the activity proposed to be federally licensed is consistent with the state’s coastal management program. The CZMA givesFor a discussion of the state six months to act once the consistency determination is deemed complete; failure to act is treated as a deemed concurrence. Entergy is pursuing three independent paths to ensure that CZMA requirements forrecent Indian Point license renewal are met. For additional discussion ofsettlement, including the CZMA proceedings related to Indian Point license renewal, see “Entergy
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Wholesale Commodities Authorizations to Operate Its Nuclear PlantsIndian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
Effluent Limitation Guidelines
In April 2013 the EPA issued proposed effluent limitation guidelines that, if adopted as final, would apply to discharges from Entergy’s generating facilities that hold national pollutant discharge elimination system permits under the Clean Water Act. The limitations proposed primarily affect coal units. The proposal includes several options for public consideration. Entergy submitted comments on the proposed rule and will continue to engage in the public comment process as appropriate. The EPA announced that the final rule will be issued no later than September 30, 2015.
Federal Jurisdiction of Waters of the United States
In September 2013 the EPA and the U.S. Army Corps of Engineers announced the intention to propose a rule to clarify federal Clean Water Act jurisdiction over waters of the United States. The announcement was made in conjunction with the EPA’s release of a draft scientific report on the “connectivity” of waters that the agency says willsaid would inform the rulemaking. This report was finalized in January 2015. The proposedfinal rule was published in the Federal Register in April 2014.June 2015. The initial 90-day public comment period was extended until November 2014. Preliminary review indicates that this proposalrule could significantly increase the number and types of waters included in the EPA’s and the U.S. Army Corps of Engineers’ jurisdiction, which in turn could pose additional permitting and pollutant management burdens on Entergy’s operations. EntergyThe final rule has been challenged in various federal courts by several parties, including most states. In August 2015 the District Court for North Dakota issued a preliminary injunction staying the new rule in 13 states, including Arkansas. In October 2015 the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the rule. In February 2017 the current administration issued an executive order instructing the EPA and the U.S. Army Corps of Engineers to review the Waters of the United States rule and to revise or rescind, as appropriate. In June 2017 the EPA and the U.S. Army Corps of Engineers released a proposed rule that rescinds the June 2015 rule and recodifies the definition of “waters of the U.S.” that was in effect prior to the 2015 rule. The administration is actively engagedexpected to propose a definition of “waters of the U.S.” at a later date. In January 2018 the Supreme Court determined that the Sixth Circuit lacked jurisdiction over the petition to review the 2015 rule and that the challenges should be heard in the federal district court. The matter has been remanded to the Sixth Circuit, which is expected to lift the nationwide stay. After the Supreme Court decision, the EPA and the U.S. Army Corps of Engineers finalized a rule delaying the applicability date of the 2015 rule to early 2020. In February 2018 the states of Louisiana, Mississippi, and Texas filed suit in Texas federal district court seeking a preliminary injunction of the 2015 rule. Entergy will continue to monitor this rulemaking process and anticipates a final rule in April 2015.
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Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to regularly monitor and report regularly the presence of radioactive material in the environment. Entergy joined other nuclear utilities and the Nuclear Energy Institute in 2006 to develop a voluntary groundwater monitoring and protection program. This initiative began after detection of very low levels of radioactive material, primarily tritium, in groundwater at several plants in the United States. Tritium is a radioactive form of hydrogen that occurs naturally and is also a byproduct of nuclear plant operations. In addition to tritium, other radionuclides have been found in site groundwater at nuclear plants.
As part of the groundwater monitoring and protection program, Entergy has: (1) performed reviews of plant groundwater characteristics (hydrology) and historical records of past events on site that may have potentially impacted groundwater; (2) implemented fleet procedures on how to handle events that could impact groundwater; and (3) installed groundwater monitoring wells and began periodic sampling. The program also includes protocols for notifying local officials if contamination is found. To date, radionuclides such as tritium have been detected at Arkansas Nuclear One, FitzPatrick, Indian Point, Palisades, Pilgrim, Grand Gulf, Vermont Yankee, and River Bend. Each of these sites has installed groundwater monitoring wells and implemented a program for testing groundwater at the sites for the presence of tritium and other radionuclides. Based on current information, the concentrations and locations of radionuclides detected at these plants pose no threat to public health or safety, but each site continues to evaluate the results from its groundwater monitoring program.
In February 2016, Entergy disclosed that elevated tritium levels had been detected in samples from several monitoring wells that are part of Indian Point’s groundwater monitoring program. Investigation of the source of elevated tritium has determined that the source is related to a temporary system to process water in preparation for the regularly scheduled refueling outage at Indian Point Units 12. The system was secured and 2 Hazardous Waste Remediationis no longer in use and additional measures have been taken to prevent reoccurrence should the system be needed again. In June 2016, Indian Point detected trace amounts of cobalt 58 in a single well. This was associated with the draining and disassembly of a temporary heat
Prior to Entergy’s purchase270
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exchanger operated in support of the Indian Point Unit 1,2 outage. Oversight by NRC and other federal/state government bodies continues. The NRC has issued a green notice of violation related to the previous owneradequacy of Entergy’s controls to prevent the introduction of radioactivity into the site groundwater. Entergy has completed all required corrective actions and expects the cleanup and desludgingNRC to close the notice of the Unit 1 water storage pool, generating mixed waste. The existing mixed waste storage permit and an associated order on consent were transferred to Entergy upon purchasing the unit. The waste is stored in the Unit 1 containment building in accordance with NRC regulations controlling low level radioactive waste. An order on consent with NYSDEC requires a quarterly survey of the availability of any commercial facility capable of treating, processing, and disposing of this waste in a commercially reasonable manner. However, in 2005, NYSDEC revised its regulations to conditionally exempt the storage and disposal of mixed waste that is regulatedviolation by the NRC. Thus, in October 2005 and again in January 2013, Entergy requested that NYSDEC terminate the mixed waste permit and order on consent because the waste falls within the mixed waste exemption. In April 2013, NYSDEC agreed with Entergy’s request to terminate the permit finding that as long as the facility continues to meet the exemption, the mixed waste permit is not required. NYSDEC denied the request to terminate the consent order, however, reasoning that it contains provisions for storage and reporting that are still applicable. Entergy continues to manage the waste according to applicable regulatory requirements.March 2018.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various disposal sites over the years, and releases have occurred at Entergy facilities. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for
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such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities that are not de minimisare discussed in the “Other“Other Environmental Matters”Matters” section below.
Coal Combustion Residuals
In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained two primary regulatory options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of RCRA Subtitle C; or (2) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes under Subtitle D of RCRA. Under both options, CCRs that are beneficially usedreused in certain processes would remain excluded from hazardous waste regulation. In December 2014April 2015 the EPA issuedpublished the final CCR rule with the material being regulated under the second scenario presented above - as non-hazardous wastes regulated under RCRA Subtitle D.
The final regulations create new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse. As of December 31, 2017, Entergy’s has recorded asset retirement obligations related to CCR management of $8.6 million, including $3.9 million at Entergy Arkansas, $1.8 million at Entergy Louisiana, $1.1 million at Entergy Mississippi, and $1.3 million at Entergy Texas.
In December 2016 the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for a permit programs. In September 2017 the EPA agreed to reconsider certain provisions of the CCR rule in light of the WIIN Act. The EPA has not yet initiated a new round of rulemaking and did not extend the existing mid-October 2017 groundwater monitoring deadline. Entergy met the existing monitoring deadline, is monitoring state agency actions, and will participate in the regulatory development process.
In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Entergy is taking action to address the operational and regulatory management of these facilities. Entergy also has monitored levels of constituents in the groundwater monitoring system surrounding its coal combustion residual landfills at these locations that require reporting and additional monitoring. Reporting has occurred as required, and monitoring will continue. Any potential
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requirements for corrective action or operational changes under the new EPA rule are currently being assessed. Moreover, the rule is currently under review at the EPA for potential changes, and the nature and cost of any corrective action requirements may depend, in part, on the outcome of the EPA’s review.
Other Environmental Matters
Entergy Gulf States Louisiana and Entergy Texas
Several class action and other suits have been filedEntergy Louisiana, as successor in state and federal courts seeking relief from Entergy Gulf States, Inc. and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Gulf States, Inc.’s premises (see “Litigation” below).
interest to Entergy Gulf States Louisiana, currently is currently involved in the second phase of the remedial investigation of the Lake Charles Service Center site, located in Lake Charles, Louisiana. A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, apparently was apparently routed to a portion of the property for disposal. The same area also has also been used as a landfill. In 1999, Entergy Gulf States, Inc. signed a second administrative consent order with the EPA to perform a removal action at the site. In 2002 approximately 7,400 tons of contaminated soil and debris were excavated and disposed of from an area within the service center. In 2003 a cap was constructed over the remedial area to prevent the migration of contamination to the surface. In August 2005 an administrative order was issued by the EPA requiring that a 10-year groundwater study be conducted at this site. The groundwater monitoring study commenced in January 2006 and is continuing. In 2010The EPA released the EPA conducted asecond Five Year Review (FYR) ofin 2015. The EPA indicated that the 10-year groundwater monitoring program at Lake Charles. Negotiations are on-going regarding whether additional actions will be necessary atcurrent remediation technique was insufficient and that Entergy would need to utilize other remediation technologies on the site. If additional actions are necessary, site expenditures will increase commensurate with the additional chosen site remedies.In July 2015, Entergy does not have sufficient information at this time to estimate additional site costs, if any. Entergy also has madesubmitted a paymentFocused Feasibility Study to the EPA outlining the potential remedies and suggesting installation of $275,000 for past agency oversight costs. Entergy Gulf States Louisiana and Entergy Texas each believe that its remaining responsibilitya waterloo barrier. The estimated cost for this site willremedy is approximately $2 million. Entergy is awaiting comments and direction from the EPA on the Focused Feasibility Study and potential remedy selection. In early 2017 the EPA indicated that the new remedial method, a waterloo barrier, may not materially exceedbe necessary and requested revisions to the existing clean-up provisions of $0.3 million forFocused Feasibility Study. The EPA plans to provide comments on the revised 2017 Focused Feasibility Study in the next Five Year Review in 2020. Entergy Gulf States Louisiana and $0.2 million for Entergy Texas. Meetings to discuss the status of this projectis continuing discussions with the EPA are scheduled in 2015.regarding the ongoing actions at the site.
Entergy Louisiana, and Entergy New Orleans
Several class action and other suits have been filed in state and federal courts seeking relief from Entergy Louisiana and Entergy New Orleans and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Louisiana’s and Entergy New Orleans’s premises (see “Litigation” below).
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy New Orleans, and Entergy Texas that the TCEQ believes those entities are potentially responsible parties (PRPs) concerning contamination existing at the San Angelo Electric Service Company (SESCO) facility in San Angelo, Texas. The facility operated as a transformer repair and scrapping facility from the 1930s until 2003. Both soil and groundwater contamination exists at the site. Entergy subsidiaries sent transformers to this facility. Entergy Gulf States Louisiana, Entergy Texas,Arkansas, Entergy Louisiana, and Entergy ArkansasTexas responded to an information request from the TCEQ and continue to cooperate in this investigation. Entergy Gulf States Louisiana and Entergy Texas and Entergy Louisiana joined a group of PRPs responding to site conditions in cooperation with the State of Texas, creating cost allocation models based on review of SESCO documents and employee interviews, and investigating contribution actions against other PRPs. Entergy Gulf States Louisiana, Entergy Louisiana and Entergy Texas have agreed to contribute to the remediation of contaminated soil and groundwater at the site in a measure proportionate to those companies’ involvement at the site, while Entergy Arkansas likely will pay a de minimis amount. Current estimates, although preliminary and variable depending on the level of third-party cost contributions,ultimate remediation design and performance, indicate that Entergy’s total share of remediation costs likely will be in the range ofapproximately $1.5 million to $2 million. Remediation activities continue at the site.
Entergy Mississippi, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
In December 2016 a transformer inside the Hartburg, Texas Substation had an internal fault resulting in a release of approximately 15,000 gallons of non-PCB mineral oil. Cleanup ensued immediately; however, rain caused much of the oil to spread across the substation yard and into a nearby wetland. The EPATexas Commission on Environmental Quality (TCEQ) and the National Response Center were immediately notified, and TCEQ responded to the site approximately two hours after the cleanup was initiated. The remediation liability is estimated at $2.2 million; however, this number could fluctuate depending on the remediation extent and wetland mitigation requirements. In July 2017,
Part I Item 1
Entergy Mississippi, Corporation, Utility operating companies, and System Energy
Entergy Gulf States Louisiana, entered into the Voluntary Cleanup Program with TCEQ. Additional direction is expected from TCEQ regarding final remediation requirements for the site.
Entergy Texas,
In May 2015 a transformer at the Indian Point facility failed, resulting in a fire and Entergy New Orleans that the EPA believes those entities are PRPs concerning contaminationrelease of an area known as “Devil’s Swamp Lake” nearnon-PCB oil to the Port of Baton Rouge, Louisiana.ground surface. The area allegedlyfire was contaminatedextinguished by the operationsfacility’s fire deluge system. No injuries occurred due to the transformer failure or company response. An estimated 3,000 gallons of Rollinsoil were released into the facility’s discharge canal and the environment surrounding the transformer and discharge canal, including the Hudson River, as a result of the failure, fire, and fire suppression. Once the fire was extinguished, Indian Point personnel and contractors began recovering free-product from the damaged transformer, the transformer containment moat, and the area surrounding the transformer. The United States Coast Guard designated Entergy as the responsible party under the Oil Pollution Act of 1990 and assessed a $1,000 civil penalty for the discharge of oil into navigable waters. As required, Entergy established a claims process including a voluntary hotline. Entergy received no reports to the voluntary hotline or claims under the established claims process. In September 2016, Indian Point personnel identified an oil sheen in the discharge canal. Further investigation revealed that an estimated 600 gallons of lubricating oil had leaked from the Indian Point 3 turbine system. The leaking component has been taken out of service and no oil has been discovered in the Hudson River. In October 2016 the New York Department of Environmental (LA), Inc, which operatedConservation issued two notices of violation, one for each of these events, and a disposal facilityproposed order on consent for the 2015 event. In January 2017, Entergy and the New York Department of Environmental Conservation resolved this matter with an order on consent. Pursuant to which many companies contributed waste. Documents provided by the EPA indicate thatorder, Entergy Louisiana may also bepaid approximately $600 thousand in civil penalties, natural resource damages, and oversight costs. Additionally, Entergy repaired a PRP.section of the discharge canal wall and will conduct daily visual inspections of the discharge canal wall to help identify additional material erosion or material structural deficiencies. Entergy continues to monitor this developing situation.has completed all compliance obligations under the consent order and the Department of Environmental Conservation closed the matter in December 2017.
Litigation
Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Ratepayer and Fuel Cost Recovery Lawsuits (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Texas Power Price Lawsuit
See Note 2 to the financial statements for a discussion of this proceeding.
Mississippi Attorney General Complaint
See Note 2 to the financial statements for a discussion of this proceeding.
Asbestos Litigation (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2014,2017, Entergy subsidiaries employed 13,39313,504 people.
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| | |
| Utility: | |
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| Entergy Arkansas | 1,160 |
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Entergy Gulf States Louisiana | 7291,278 |
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| Entergy Louisiana | 8901,713 |
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| Entergy Mississippi | 673737 |
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| Entergy New Orleans | 298274 |
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| Entergy Texas | 596616 |
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| System Energy | — |
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| Entergy Operations | 2,7643,361 |
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| Entergy Services | 2,8523,264 |
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| Entergy Nuclear Operations | 3,3762,211 |
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| Other subsidiaries | 5550 |
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| Total Entergy | 13,39313,504 |
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Approximately 5,2004,600 employees are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Teamsters, the United Government Security Officers of America, and the International Union, Security, Police, Fire Professionals of America.
Availability of SEC filings and other information on Entergy’s website
Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. The public may read and copy any materials that Entergy files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov.
Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include our annual and quarterly reports on Forms 10-K and 10-Q (including related filings in XBRL format) and current reports on Form 8-K; our proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its Internetinternet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
RISK FACTORS
Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that arecan be lengthy and subject to appeal that could result in delays in effecting rate changes and uncertainty as to ultimate results.
The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment.adjustment, including adjustment upon the initiative of a regulator or affected stakeholders.
In addition, regulators canmay initiate proceedings to investigate the prudence of costs in the Utility operating companies’ base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators canmay disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. TheTraditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of thethese base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings.
The base rates of Entergy Arkansas and Entergy Texas are established largely in traditional base rate case proceedings. Apart from base rate proceedings, Entergy Arkansas recovers fuel and purchased energyTexas has also filed to use rate riders to recover the revenue requirements associated with certain authorized historical costs. For example, Entergy Texas has recovered distribution-related capital investments through the distribution cost recovery factor rider mechanism, transmission-related capital investments and certain non-fuel costs through other APSC-approved tariffs. Entergy Mississippi infrequently has traditional base rate cases, although one was filed and settled in 2014. More commonly, it obtains base rate adjustments through its formula rate plan, which operates annually. In the event that this formula rate plan were terminated, Entergy Mississippi would at that time revert to the more traditional rate case environment.
In January 2013, Entergy Gulf States Louisiana’s and Entergy Louisiana’s then-existing formula rate plans expired, and each company filed full rate cases in February 2013. As part of the rate cases that Entergy Louisiana and Entergy Gulf States Louisiana filed, each company requested that the LPSC approve new formula rate plans. In December 2013 the LPSC voted to approve a settlement that provides for the continued use,MISO charges through the test year 2016 filing, of formula rate plans by Entergy Louisianatransmission cost recovery factor rider mechanism, and Entergy Gulf States Louisiana. Entergy Louisiana’s formula rate plan changes are capped at a cumulative total of $30 million through the formula rate plan cycle. Entergy Gulf States Louisiana has no cap but is not permitted to increase rates prior to the test year 2015 filing. As part of the settlement, both companies established mechanisms to recover non-fuel MISO-related costs calculated separately from the formula rate plan requirements, but embedded in the formula rate plan factor applied on customer bills. MISO fuel and energy-related costs through the fixed fuel factor mechanism. Entergy Texas is also required to make a filing every three years, at a minimum, reconciling its fuel and purchased power costs and fuel factor revenues. In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are recoverable innecessary and reasonable, and makes a prudence finding for each of the fuel-related contracts for the reconciliation period.
Between base rate cases, Entergy Gulf States Louisiana’sArkansas and Entergy Louisiana’s fuel adjustmentMississippi are able to adjust base rates annually through formula rate plans that utilize a forward test year (Entergy Arkansas) or forward-looking features (Entergy Mississippi). In response to Entergy Arkansas’s application for a general change in rates in 2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term. The initial five-year term expires in 2021 unless Entergy Arkansas requests, and the APSC approves, the extension of the formula rate plan tariff for an additional five years through 2026. In the event that Entergy Arkansas’s formula rate plan is terminated or is not extended beyond the initial term, Entergy Arkansas could file an
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
clauses.application for a general change in rates that may include a request for continued regulation under a formula rate review mechanism. If Entergy Mississippi’s formula rate plan is terminated, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan. Entergy Arkansas and Entergy Mississippi recover fuel and purchased energy and certain non-fuel costs through other APSC-approved and MPSC-approved tariffs, respectively.
Entergy Louisiana historically sets electric base rates annually through a formula rate plan using an historic test year. The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013. The formula rate plans continueplan was approved for continued use through the test year 2016 filing and included a cap in cost of service increases at a cumulative total of $30 million through the formula rate plan cycle, which cap was not reached. The LPSC also approved in the business combination Entergy Louisiana’s continuation of a mechanism to retainrecover non-fuel MISO-related costs, which are calculated separately from the formula rate plan requirements, but embedded in the formula rate plan factor applied on customer bills. This recovery mechanism expired following the 2015 test year, but was renewed for the 2016 test year. MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause. The formula rate plan includes exceptions from the rate cap/restrictionscap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities, as well as purchase power agreements approved by the Ninemile 6 generating facility.LPSC, among other items. In August 2017, Entergy Louisiana filed to extend the formula rate plan for an additional three years and to reset rates to the authorized mid-point return on equity of 9.95%. The filing also seeks certain modifications to the formula rate plan, including a narrower, 80 basis points earnings sharing bandwidth and implementation of a rider to recover certain transmission-related investments, when those investments begin delivering benefits to customers. In the event that thesethe electric formula rate plans were terminated,plan is not renewed or expire without renewal or extension, Entergy Gulf States Louisiana andextended, Entergy Louisiana would at that time revert to the more traditional rate case environment. Additionally, in September 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed with the LPSC a joint application seeking to combine the two companies. In connection with this request, the companies are also seeking to combine the formula rate plans approved for each company into a single formula rate plan with a single combined-company filing for 2014. Most of the provisions under the existing separate formula rate plans would be retained under the combined formula rate plan. Further, Entergy Louisiana and
Entergy New Orleans have filed with the Council of the City of New Orleans a joint application seeking authorization to transfer certain assets of Entergy Louisiana used to serve the Fifteenth Ward of New Orleans (commonly referred to as Algiers) to Entergy New Orleans. Entergy New Orleans haspreviously operated under a formula rate plan that ended with the 2011 test year and has not yet been extended. Ifyear. Currently, based on a settlement agreement approved by the City Council, with limited exceptions, no formula rate plan is approved going forward,action may be taken with respect to Entergy New Orleans will continue operatingOrleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. The limited exceptions include implementation of the final year of a four-year phased-in rate increase for its Algiers operations in the more traditional rate case environment.Fifteenth Ward of the City of New Orleans and certain exceptional cost increases or decreases in its base revenue requirement.
The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which allows monthly adjustments to reflect the current operating costs of, and investment in, Grand Gulf.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments, and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms. For information regarding rate case proceedings and formula rate plans applicable to certain of the Utility operating companies, see Note 2 to the financial statements.
The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.
The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred, including the cost of replacement power purchased when generators experience outages, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs. Regulators canmay also initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies.companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises very dramatically, some of the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power costs recovery, see Note 2 to the financial statements.
As a resultThere remains uncertainty regarding the effect of a challenge by the LPSC,termination of the manner in whichSystem Agreement on the Utility operating companies have traditionally shared the costs associated with coordinated planning, construction, and operation of generating resources has been changed by the FERC, a development which has had and could continue to require adjustment of retail and wholesale rates in the jurisdictions where the Utility operating companies provide service and has introduced additional uncertainty in the ratemaking process.companies.
The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating resources and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that hashad been approved by the FERC. In 2005 the FERC issued a decision requiring changes to the cost allocation methodology usedThe System Agreement terminated in that rate schedule.its entirety on August 31, 2016.
In 2007 through 2012, payments were made by Entergy Arkansas to certainThere remains uncertainty regarding the long-term effect of the termination of the System Agreement on the Utility operating companies because of the significant effect of the agreement on the generation and transmission functions of the Utility operating companies and the significant period of time (over 30 years) that it had been in compliance withexistence. In the 2005absence of the System Agreement, there remains uncertainty around the effectiveness of governance processes and the potential absence of federal authority to resolve certain issues among the Utility operating companies and their retail regulators.
In addition, although the System Agreement terminated in its entirety in August 2016, there are a number of outstanding System Agreement proceedings at the FERC decision on the cost allocation methodology, and in 2013 and 2014, payments were made by Entergy Texas to Entergy New Orleans. There have beenthat may require future adjustments, including challenges to the level and timing of payments
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
made by Entergy Arkansas under the FERC’s decision and the prudence of the Utility operating companies’ production costs. The ability to recover in rates any changes to the cost allocation resulting from the challenges, and timing of such recovery, could be uncertain and could be the subject of additional regulatory and other proceedings. For information regarding these and other proceedings associated with the System Agreement, as well as additional information regarding the System Agreement itself, see Note 2 to financial statements, System Agreement Cost Equalization Proceedings.Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
The withdrawal and notices of withdrawal of certain Utility operating companies from the System Agreement create uncertainty regarding the System Agreement and the effect of the absence of such an arrangement on the Utility operating companies.
Entergy Arkansas’s participation in the System Agreement terminated in December 2013, and Entergy Mississippi’s participation in the System Agreement is scheduled to terminate in November 2015.
In October 2013, the Utility operating companies filed at the FERC seeking to shorten to 60 months the provision in the System Agreement that requires a Utility operating company seeking to withdraw from the System Agreement to provide 96 months advance notice of termination of participation. In October 2013, Entergy Texas provided its notice to the other Utility operating companies to terminate its participation in the System Agreement after expiration of the proposed 60-month notice period or such other period as approved by the FERC. Subsequently, Entergy Texas filed its notice to terminate its participation in the System Agreement at FERC in October 2013. In January 2014, the LPSC directed Entergy Louisiana and Entergy Gulf States Louisiana to provide no later than February 15, 2014 notice of their intention to terminate their participation in the System Agreement, and to use their reasonable best efforts to achieve a consensual resolution permitting early termination of the System Agreement. Entergy Louisiana and Entergy Gulf States Louisiana provided notice of their termination on February 14, 2014. Accordingly, there is uncertainty regarding the continuation of the System Agreement and the effect of the absence of such an arrangement on the Utility operating companies.
For further information regarding the regulatory proceedings relating to the System Agreement, see Note 2 to the “Rate, Cost-recovery, and Other Regulation - Federal Regulation - System Agreement” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries.financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
On December 19, 2013, the Utility operating companies integrated into the MISO RTO. For further information regarding the FERC and proceedings related to the MISO RTO, see the “Rate, Cost-recovery, and Other Regulation - Federal Regulation - Entergy’s Integration Into the MISO Regional Transmission Organization” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The Utility operating companies are subject to economic risks associated with participation in the MISO markets. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell power in certain regions and/or the economic value of such sales, and MISO market rules may change in ways including the implementation of competition among transmission providers, that cause additional risk.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. TheMISO is currently evaluating through its stakeholder process potential changes in the transmission project criteria in MISO. These changes, if adopted, could potentially result in a larger
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
volume of competitively bid and regionally cost allocated transmission projects. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from these projects, there is a risk that the Utility operating companies’ business and financial position could be harmed as a result of lost investment opportunities and other effects that flow from an increased number of competitive projects being approved and constructed that are interconnected with their transmission systems. Further, the terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC. The operation of the Utility operating companies’ transmission system pursuant to the MISO tariff and their participation in the MISO wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements. In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies make periodic filings setting forth the results of analysis of the costs and benefits realized from MISO membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO. These filings have been submitted periodically by each of the Utility operating companies as required by their respective retail regulators, and the outcome of the resulting proceedings may affect the Utility operating companies’ continued membership in MISO.
(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather could have material effects on Entergy and those Utility operating companies affected by severe weather.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred or revenues lost as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather.
Nuclear Operating, Shutdown and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Gulf StatesLouisiana, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities must consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies, System Energy, and Entergy Wholesale Commodities. Nuclear plant operations involve substantial fixed operating costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity factors.factors, consistent with safety requirements. For the Utility operating companies that own nuclear plants, lower capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs. For the Entergy Wholesale Commodities nuclear plants, lower capacity factors directly affect revenues and cash flow from operations. Entergy Wholesale Commodities’ forward sales are comprised of various hedge products, many of which have some degree of operational-contingent price risk. Certain unit-contingent contracts guarantee specified minimum capacity factors. In the event plants with these contracts were operating below the guaranteed capacity factors, Entergy would be subject to price risk for the undelivered power. Further, Entergy Wholesale Commodities’ nuclear forward sales contracts can also be on a firm LD basis, which subjects Entergy to increasing price risk as capacity factors decrease. Many of these firm hedge products have damages risk, capped through the use of risk management products.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months and average approximately 30 days in duration. Plant maintenance and upgrades are often scheduled during such planned outages. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease and maintenance costs may increase. Lower than forecasted capacity factors may cause Entergy Wholesale Commodities to experience reduced revenues and may also create damages risk with certain hedge products as previously discussed.
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication), and the risk of being unable to effectively manage these. These risks by purchasing from a diversified mix of sellers located in a diversified mix of countries could materially affect Entergy’s and their results of operations, financial condition and liquidity.
Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through most of 2015.2018. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment is being adjusted to reflect reduced overall requirements related to the planned permanent shutdown of the Palisades, Pilgrim, Indian Point 2 and Indian Point 3 plants over the next two to five years. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners and enrichers.miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy also may draw upon its own inventory intended for later generation periods, depending upon its risk management strategy at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to normal inherent market uncertainties, and price increaseschanges could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel; therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon countries, such as Russia, in which deteriorating economic conditions or international sanctions could restrict the ability of such suppliers to continue to supply fuel or provide such services. The inability of such suppliers or service providers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities.
Certain of the Utility operating companies,Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, or suspend, not renew, or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, not renew, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for
Part I Item 1A & 1B
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nuclear facilities. The license renewal process in some cases may be the subject of significant public debate and legislative review and scrutiny at the federal and, in some cases, state level, though the decision whether to renew is subject to the exclusive jurisdiction of the NRC. Interested parties may also intervene which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy (through Entergy Wholesale Commodities), its Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the change in classification.For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business, see “Regulation of Entergy’s Business- Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1 and Note 8 to the financial statements.
Events at nuclear plants owned by others,one of these companies, as well as those owned by oneothers, may lead to a change in laws or regulations or the terms of these companies,the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate such actions.actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect
Part I Item 1A & 1B
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the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities. For example, the earthquake of March 11, 2011 that affected the Fukushima Daiichi nuclear plants in Japan resulted in the NRC issuing three orders effective on March 12, 2012 requiring U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that will, among other things, result in increased capital and operating costs associated with operating Entergy’s nuclear plants, some of which could be material.
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in reduced profitability.increased costs, some of which costs may not be fully recoverable by the Utility operating companies and System Energy in regulatory proceedings. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For the Utility operating companies and System Energy, this could result in certain costs being stranded and potentially not fully recoverable in regulatory proceedings. For Entergy Wholesale Commodities, this could result in lost revenue and increased fuel and purchased power expense to meet supply commitments and penalties for failure to perform under their contracts with customers. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
The nuclear industry continues to address susceptibility to the effects of stress corrosion cracking and other corrosion mechanisms on certain materials within plant systems. The issue is applicable at all nuclear units to varying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished. In addition, certain major parts have long lead-times to manufacture
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if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities nuclear power plants, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies, System Energy and the owners of the Entergy Wholesale Commodities nuclear plants incur costs on a periodic basis for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the Obama administration has expressed its intention and taken specific steps to discontinueNRC licensing of the Yucca Mountain project and studyrepository is effectively at a new spent fuel strategy.standstill. These actions may prolongare prolonging the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE plans towill commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites.sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy.Energy and Note 8 to the financial statements.
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Certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool of up to approximately $127.318$127.3 million per reactor. With 104102 reactors currently participating, this translates to a total public liability cap of approximately $13.241$13 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As required by the Price-Anderson Act, the Utility operating companies, System Energy, and Entergy Wholesale Commodities carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers (currently $375(which is $450 million for each operating site)site as of January 1, 2018). Claims for any nuclear incident exceeding that amount are covered under the retrospective premiums paid into the secondary insurance pool. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the $375 million in primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies, System Energy, and the Entergy Wholesale Commodities plant owners, regardless of fault or proximity to the incident, will be required to pay a retrospective premium, equal to its proportionate share of the loss in excess of the $375 million primary insurance level, up to a maximum of $127.318approximately $127.3 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.4$1.146 billion). The retrospective premium payment is currently limited to $18.963approximately $19 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $127.318$127.3 million cap.
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NEIL is a utility industry mutual insurance company, owned by its members.members, including the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities plants. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the surplus (reserve) be significantly depleted due to insured losses. As of April 1, 2014,December 31, 2017, the maximum annual assessment amounts total $105.7$112.2 million for the Utility plants and $126.4 million for the Entergy Wholesale Commodities plants. Retrospective Premium Insurancepremium insurance available through NEIL’s reinsurance treaty can cover the potential assessments. Theassessments and the Entergy Wholesale Commodities plants currently maintain the Retrospective Premium Insuranceretrospective premium insurance to cover thisthose potential assessment.assessments.
As an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, System Energy, or the Entergy Wholesale Commodities subsidiaries.
MarketThe decommissioning trust fund assets for the nuclear power plants owned by the Utility operating companies, System Energy and the Entergy Wholesale Commodities nuclear plant owners may not be adequate to meet decommissioning obligations if market performance and other changes may decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies, System Energy, and owners of the Entergy Wholesale Commodities nuclear power plants maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. In connection with the acquisition of certain nuclear plants, the Entergy Wholesale Commodities plant owners also acquired decommissioning trust funds that are funded in accordance with NRC regulations. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds. As part of the Pilgrim, Indian Point 1 and 2, Vermont Yankee, and Palisades/Big Rock Point purchases, the former owners transferred decommissioning trust funds, along
In connection with the liability to decommission theacquisition of certain nuclear plants, to the
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respective Entergy Wholesale Commodities nuclear power plant owners. In addition, the former owner of Indian Point 3 and FitzPatrick retained the decommissioning trusts and related liability to decommission these plants, but has the right to require the respective Entergy Wholesale Commodities nuclear plant owners to assume the decommissioning liability provided that it assigns the funds in the corresponding decommissioning trust, up to a specified level, to such owners. Alternatively, the former owner may contract with Entergy Nuclear, Inc. for the decommissioning work at a price equal to the funds in the corresponding decommissioning trust up to a specified amount. As part of the Indian Point 1 and 2 purchase, the Entergy Wholesale Commodities nuclear power plant owner also funded an additional $25 million to a supplementalowners acquired decommissioning trust fund. As part of the Palisades transaction, the Entergy Wholesale Commodities business assumed responsibility for spent fuel at the decommissioned Big Rock Point nuclear plant, which is located near Charlevoix, Michigan. Once the spent fuel is removed from the site, the Entergy Wholesale Commodities business will dismantle the spent fuel storage facility and complete site decommissioning. The Entergy Wholesale Commodities business expects to fund this activity from operating revenue, and Entergy is providing $5 millionfunds that are funded in credit support to provide financial assurance to theaccordance with NRC for this obligation.
In 2008, Entergy experienced declines in the market value of assets held in the trust funds for meeting its decommissioning funding assurance obligations for its plants. This decline adversely affected Entergy’s ability to demonstrate compliance with the NRC’s requirements for providing financial assurance for decommissioning funding for some of its plants, which deficiencies have now been corrected. An early plant shutdown, poor investment results or higher than anticipated decommissioning costs could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that the Entergy Wholesale Commodities nuclear plant owners may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. For further information regarding nuclear decommissioning costs, see the “Critical Accounting Estimates– Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy and Note 9 to the financial statements.
Changes in NRC regulations or other binding regulatory requirements may cause increased funding requirements for nuclear plant decommissioning trusts.
NRC regulations require certain minimum financial assurance requirements for meeting obligations to decommission nuclear power plants. Those financial assurance requirements may change from time to time, and certain changes may result in a material increase in the financial assurance required for decommissioning the Utility operating companies’, System Energy’s and owners of the Entergy Wholesale Commodities nuclear power plants. Such changes could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. For further information regarding nuclear decommissioning costs, see the “Critical Accounting Estimates– Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy and Note 9 to the financial statements.
New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation of Entergy’s nuclear power plants.
New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel, in particular in the northeastern United States, which is where five of the six units in the current fleet of Entergy Wholesale Commodities nuclear power plants are located. These concerns have led to, and are expected to continue to lead to, various proposals to Federal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that could lead to the shutdown of nuclear units, denial of license renewal applications, restrictions on nuclear units as a result of unavailability of sites for spent nuclear fuel storage and disposal, or other adverse effects on owning and operating nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect on Entergy’s results of operations, financial condition, and liquidity.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation)
A failure to obtain renewed licenses or other approvals required for the continued operation of the Entergy Wholesale Commodities nuclear power plants could have a material effect on Entergy’s results of operations, financial condition, and liquidity and could lead to an increase in depreciation rates or an acceleration of the timing for the funding of decommissioning obligations.
The license renewal and related processes for the Entergy Wholesale Commodities nuclear power plants have been and may continue to be the subject of significant public debate and regulatory and legislative review and scrutiny at the federal and, in certain cases, state level. The original expiration date of the operating license for Indian Point 2 was September 2013 and the original expiration date of the operating license for Indian Point 3 is December 2015. Because these plants filed timely license renewal applications, the NRC’s rules provide that these plants may continue to operate under their existing operating licenses until their renewal applications have been finally determined. Various parties have expressed opposition to renewal of these licenses. Renewal of the Indian Point licenses is the subject of ongoing proceedings before the Atomic Safety and Licensing Board (ASLB) of the NRC and, with respect to issues resolved by the ASLB, before the NRC on appeal.
In relation to Indian Point 2 and Indian Point 3, the New York State Department of Environmental Conservation has taken the position that these plant owners must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process. In addition, before the NRC may issue renewed operating licenses it must resolve its obligation to address the requirements of the Coastal Zone Management Act (CZMA). Most commonly, those requirements are met by the applicant's demonstration that the activity authorized by the federal permit being sought is consistent with the host state's federally-approved coastal management policies. Entergy has undertaken three independent initiatives to resolve CZMA issues: "grandfathering," "previous review," and a "consistency certification." In December 2014 the New York Supreme Court, Appellate Division, issued a unanimous ruling stating that Indian Point 2 and Indian Point 3 “are exempt from New York’s Coastal Management Program.” That decision could be appealed. For further information regarding these environmental regulations see the “Regulation of Entergy's Business - Environmental Regulation - Clean Water Act” section in Part I, Item 1.
If the NRC finally denies the applications for the renewal of operating licenses for one or more of the Entergy Wholesale Commodities nuclear power plants, or a state in which any such nuclear power plant is located is able to prevent the continued operation of such plant, Entergy’s results of operations, financial condition, and liquidity could be materially affected by loss of revenue and cash flow associated with the plant or plants, potential impairments of the carrying value of the plants, increased depreciation rates, and an accelerated need for decommissioning funds, which could require additional funding. In addition, Entergy may incur increased operating costs depending on any conditions that may be imposed in connection with license renewal. For further discussion regarding the license renewal processes for the Entergy Wholesale Commodities nuclear power plants, see the “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
The decommissioning trust fund assets for the nuclear power plants owned by Entergy Wholesale Commodities nuclear plant owners may not be adequate to meet decommissioning obligations if one or more of their nuclear power plants is retired earlier than the anticipated shutdown date, the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require additional funding.
regulations. Under NRC regulations, Entergy Wholesale Commodities’ nuclear subsidiaries are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each of the Entergy Wholesale Commodities nuclear power plant’s decommissioning trusts combined with other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used, for each of these nuclear power plants. As a result, if the projected amount of individual plants’ decommissioning trusts exceeds the NRC-required decommissioning amount, then its
Part I Item 1A & 1B
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decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs the applicable Entergy subsidiaries would be required to incur to decommission these nuclear power plants, andor funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs. In addition to NRC requirements, there are other decommissioning-related obligations for certain of the Entergy Wholesale Commodities nuclear power plants, which management believes it will be able to satisfy.
If any Entergy Wholesale Commodities subsidiary decides to shut down one of its nuclear power plants earlier than the scheduled shutdown date and conduct decommissioning without the benefit of a safe storage period, the applicable Entergy subsidiary may be unable to rely upon only the decommissioning trust to fund the entire decommissioning obligations, which would require it to obtain funding from other sources.
Vermont Yankee submitted notification of permanent cessation of operations and permanent removal of fuel from the reactor in January 2015 after final shutdown in December 2014. The Post Shutdown Decommissioning Activities Report for Vermont Yankee, including a site specific cost estimate, was submitted to the NRC in December 2014. Vermont Yankee’s future certifications to satisfy the NRC’s financial assurance requirements will now be based on the site specific cost estimate, including the estimated cost of managing spent fuel, rather than the NRC minimum formula for estimating decommissioning costs. Entergy expects that amounts available in Vermont Yankee’s decommissioning trust fund, including expected earnings, together with the credit facilities entered into in January 2015 that are expected to be repaid with recoveries from DOE litigation related to spent fuel storage, will be sufficient to cover expected costs of decommissioning, spent fuel management costs, and site restoration. Filings with the NRC for planned shutdown activities will determine whether any other financial assurance may be required and will specifically address funding for spent fuel management, which will be required until the federal government takes possession of the fuel and removes it from the site, per its current obligation.
Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of,
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or accelerate the timing for funding of, the obligations related to the decommissioning of Entergy Wholesale Commodities nuclear power plants.plants or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. As a result, under any of these circumstances, Entergy’s results of operations, liquidity, and financial condition could be materially affected.
An early plant shutdown (either generally or relative to current expectations), poor investment results or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that the Utility operating companies, System Energy or the Entergy Wholesale Commodities nuclear plant owners may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to the Utility operating companies, may not be recoverable from customers in a timely fashion or at all.
For further information regarding nuclear decommissioning costs, management’s decision to exit the merchant power business and the impairment charges that resulted from such decision, see the “Critical Accounting Estimates- Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy, the “Entergy Wholesale Commodities Exit from the Merchant Power Business” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and Notes 9 and 14 to the financial statements.
Changes in NRC regulations or other binding regulatory requirements may cause increased funding requirements for nuclear plant decommissioning trusts.
NRC regulations require certain minimum financial assurance requirements for meeting obligations to decommission nuclear power plants. Those financial assurance requirements may change from time to time, and certain changes may result in a material increase in the financial assurance required for decommissioning the Utility operating companies’, System Energy’s, and owners of Entergy Wholesale Commodities nuclear power plants. Such changes could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. For further information regarding nuclear decommissioning costs, see the “Critical Accounting Estimates– Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 9 to the financial statements.
New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation and decommissioning of Entergy’s nuclear power plants.
New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel, in particular in the northeastern United States, which is where most of the current fleet of Entergy Wholesale Commodities nuclear power plants is located. These concerns have led to, and are expected to continue to lead to, various proposals to Federal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that could lead to the shutdown of nuclear units, denial of license renewal applications, additional requirements or restrictions related to spent nuclear fuel on-site storage and eventual disposal, or other adverse effects on owning, operating and decommissioning nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect on Entergy’s results of operations, financial condition, and liquidity.
(Entergy Corporation)
A failure to obtain renewed licenses or other approvals required for the continued operation of the Entergy Wholesale Commodities’ Indian Point nuclear power plants could have a material effect on Entergy’s results of operations, financial condition, and liquidity and could lead to an acceleration of the timing for the funding of decommissioning obligations.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The license renewal and related processes for the Entergy Wholesale Commodities’ Indian Point nuclear power plants have been and may continue to be the subject of significant public debate and regulatory and legislative review and scrutiny at the federal and, in certain cases, state level. The original expiration date of the operating license for Indian Point 2 was September 2013 and the original expiration date of the operating license for Indian Point 3 was December 2015. Because these plants filed timely license renewal applications, the NRC’s rules provide that these plants may continue to operate under their existing operating licenses until their renewal applications have been finally determined.
In January 2017, Entergy announced that it plans to shut down Indian Point 2 in 2020 and Indian Point 3 in 2021. The early and orderly shutdown is part of a settlement under which New York State has agreed to drop legal challenges and support renewal of the operating licenses for Indian Point. For additional discussion of the settlement agreement with New York State, see the “Entergy Wholesale Commodities Authorizations to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
If the NRC were to deny the applications for the renewal of operating licenses for the Indian Point nuclear power plants, or if Indian Point fails to obtain other approvals, Entergy’s results of operations, financial condition, and liquidity could be materially affected by loss of revenue and cash flow associated with the plant or plants until the proposed shutdown date, potential impairments of the carrying value of the plants, increased depreciation rates, and an accelerated need for decommissioning funds, which could require additional funding. In addition, Entergy may incur increased operating costs depending on any conditions that may be imposed in connection with license renewal. For further discussion regarding the license renewal processes for the Indian Point nuclear power plants, see the “Entergy Wholesale Commodities Authorizations to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
Entergy Wholesale Commodities nuclear power plants are exposed to price risk.
Entergy and its subsidiaries do not have a regulator-authorized rate of return on their capital investments in non-utility businesses. In particular,As a result, the sale of capacity and energy from the Entergy Wholesale Commodities nuclear power plants, unless otherwise contracted, is subject to the fluctuation of market power prices. In order to reduce future price risk to desired levels, Entergy Wholesale Commodities utilizes contracts that are unit-contingent and Firm LD and various products such as forward sales, options, and collars. As of December 31, 2014,2017, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 86%,98% in 2018, 91% in 2019, 51% in 2020, 74%, 39%, 17%, in 2021, and 19%67% in 2022 of its generation portfolio’s planned energy output, for 2015, 2016, 2017, 2018, and 2019, respectively.reflecting the planned shutdown or sale of the Entergy Wholesale Commodities nuclear power plants by mid-2022.
Market conditions such as product cost, market liquidity, and other portfolio considerations influence the product and contractual mix. The obligations under unit-contingent agreements depend on a generating asset that is operating; if the generation asset is not operating, the seller generally is not liable for damages. For some unit-contingent obligations, however, there is also a guarantee of availability that provides for the payment to the power purchaser of contract damages, if incurred, in the event the unit owner fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. Firm LD sales transactions may be exposed to substantial operational price risk, a portion of which may be capped through the use of risk management products, to the extent that the plants do not run as expected and market prices exceed contract prices.
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Market prices may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases. Demand for electricity and its fuel stock can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, from time to time there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, credit requirements, bidding rules and other mechanisms to address volatility and other issues in these markets.
Part I Item 1A & 1B
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The effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the power regions where the Entergy Wholesale Commodities nuclear power plants are located. In addition, currently the market design under which the plants operate does not adequately compensate merchant nuclear plants for their environmental and fuel diversity benefits in the region. These conditions were primary factors leading to Entergy’s decision to shut down (or sell) Entergy Wholesale Commodities’ nuclear power plants before the end of their operating licenses (or requested operating licenses for Indian Point 2 and Indian Point 3).
The price that different counterparties offer for various products including forward sales is influenced both by market conditions as well as the contract terms such as damage provisions, credit support requirements, and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Entergy Wholesale Commodities’ contract portfolio may have average contract prices above or below current market prices, including at the expiration of the contracts, which may significantly affect Entergy Wholesale Commodities’ results of operations, financial condition, or liquidity. New hedges are generally layered into on a rolling forward basis, which tends to drive hedge over-performance to market in a falling price environment, and hedge underperformance to market in a rising price environment; however, hedge timing, product choice, and hedging costs will also affect these results. See the “Results of Operations -Realized Revenue per MWh for Entergy Wholesale Commodities Nuclear PlantsMarket and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. With operating licenses for Indian Point 2 and Indian Point 3 expiring in 2013 and 2015, respectively (see discussion above regardingSince Entergy Wholesale Commodities has announced the continued operationclosure (or sale) of Indian Point 2 and 3 past the license expiration dates), and as a consequence of any delays in obtaining extension of the operating licenses and any other approvals required for continued operation of theits nuclear plants, Entergy Wholesale Commodities may enter into fewer unit-contingent forward sales contracts for output from such plants for periods beyond the license expiration.plants.
Among the factors that could affect market prices for electricity and fuel, all of which are beyond Entergy’s control to a significant degree, are:
prevailing market prices for natural gas, uranium (and its conversion, enrichment, and fabrication), coal, oil, and other fuels used in electric generation plants, including associated transportation costs, and supplies of such commodities;
seasonality and realized weather deviations compared to normalized weather forecasts;
availability of competitively priced alternative energy sources and the requirements of a renewable portfolio standard;
changes in production and storage levels of natural gas, lignite, coal and crude oil, and refined products;
liquidity in the general wholesale electricity market, including the number of creditworthy counterparties available and interested in entering into forward sales agreements for Entergy’s full hedging term;
the actions of external parties, such as the FERC and local independent system operators and other state or Federal energy regulatory bodies, that may impose price limitations and other mechanisms to address some of the volatility in the energy markets;
electricity transmission, competing generation or fuel transportation constraints, inoperability, or inefficiencies;
the general demand for electricity, which may be significantly affected by national and regional economic conditions;
weather conditions affecting demand for electricity or availability of hydroelectric power or fuel supplies;
the rate of growth in demand for electricity as a result of population changes, regional economic conditions, and the implementation of conservation programs or distributed generation;
regulatory policies of state agencies that affect the willingness of Entergy Wholesale Commodities customers to enter into long-term contracts generally, and contracts for energy in particular;
increases in supplies due to actions of current Entergy Wholesale Commodities competitors or new market entrants, including the development of new generation facilities, expansion of existing generation facilities, the disaggregation of vertically integrated utilities, and improvements in transmission that allow additional supply to reach Entergy Wholesale Commodities’ nuclear markets;
union and labor relations;
changes in Federal and state energy and environmental laws and regulations and other initiatives, such as the Regional Greenhouse Gas Initiative, including but not limited to, the price impacts of proposed emission controls;
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changes in Federal and state energy and environmental laws and regulations and other initiatives, including but not limited to, the price impacts of proposed emission controls such as the Regional Greenhouse Gas Initiative (RGGI);
changes in law resulting from federal or state energy legislation or legislation subjecting energy derivatives used in hedging and risk management transactions to governmental regulation; and
natural disasters, terrorist actions, wars, embargoes, and other catastrophic events.
The Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
The Entergy Wholesale Commodities business is subject to extensive regulation under federal, state, and local laws and regulation.laws. Compliance with the requirements under these various regulatory regimes may cause the Entergy Wholesale Commodities business to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines and/or civil or criminal liability.
Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Each of the owners of the Entergy Wholesale Commodities nuclear power plants that generates electricity, as well as Entergy Nuclear Power Marketing, LLC, is a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted these generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant the Entergy Wholesale Commodities’ generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that the Entergy Wholesale Commodities business can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, the Entergy Wholesale Commodities’ market-based sales are subject to certain market behavior rules, and if any of its generating and power marketing companies were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1 million per day per violation. If the Entergy Wholesale Commodities’ generating or power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates the Entergy Wholesale Commodities business charges for power from its facilities.
The Entergy Wholesale Commodities business is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operators. The Independent System Operators that oversee most of the wholesale power markets may impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of the Entergy Wholesale Commodities business’ generation facilities that sell energy and capacity into the wholesale power markets. Further, the New York Independent System Operator could determine that the timing of the shutdown of the Indian Point units could be inconsistent with its market power rules, and impose certain penalties that could affect Entergy Wholesale Commodities. For further information regarding federal, state and local laws and regulation applicable to the Entergy Wholesale Commodities business, see the “Regulation of Entergy’s Business” section in Part I, Item 1.
The regulatory environment applicable to the electric power industry has undergone substantialis subject to changes over the past several years as a result of restructuring initiatives at both the state and federal levels. These changes are ongoing and Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on the Entergy Wholesale Commodities business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, and have raised claims that the competitive marketplace is not working because energy prices in wholesale markets exceed the marginal cost of operating nuclear power plants, as well asand have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other
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proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which
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could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, the Entergy Wholesale Commodities business’ results of operations, financial condition, and liquidity could be materially affected.
The power plants owned by the Entergy Wholesale Commodities business are subject to impairment charges in certain circumstances, which could have a material effect on Entergy’s results of operations, financial condition or liquidity.
Entergy reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from the operations of such assets. Projected net cash flows depend on the expected operating life of the assets, the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy and capacity over the remaining life of the assets. In particular, the assets of the Entergy Wholesale Commodities business are subject to further impairment if adverse market conditions arise and continue (such as expected long-term declines in market prices for electricity), if adverse regulatory events occur (includingconnection with respectthe closure or sale of the plants discussed below. Moreover, prior to environmental regulation), if a unit ceases operationthe closure or if a unit’s operating license is not renewed. Moreover,sale of these plants, the failure of the Entergy Wholesale Commodities business to achieve forecasted operating results and cash flows, an unfavorable change in forecasted operating results or cash flows, a reduction in the expected remaining useful life of a unit (including if the operating licenses for the Indian Point power plants are not renewed by the NRC), or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
As discussed in the “Entergy Wholesale Commodities - Property” section in Part I, Item 1, the original expiration dates of the operating licenses for Indian Point 2 and Indian Point 3 are 2013 and 2015, respectively (see discussion above regarding the continued operation of Indian Point 2 and 3 past the license expiration dates),and are currently the subject of license renewal processes at the NRC and the state in which the plants operate. On August 27, 2013, Entergy announced its plan to close and decommission Vermont Yankee. Vermont Yankee ceased power production in the fourth quarter 2014 at the end of a fuel cycle. This decision was approved by the Board in August 2013, and resulted in the recognition of impairment charges in 2013 and 2014. In October 2015, Entergy determined that it will close the Pilgrim and FitzPatrick plants. The Pilgrim plant will cease operations no later than June 1, 2019. FitzPatrick was expected to shut down at the end of its current fuel cycle, planned for January 27, 2017, but in March 2017, Entergy sold the FitzPatrick plant to Exelon Generation Company, LLC which continues to operate the plant. During the third quarter 2015, Entergy recorded impairment and other related charges to write down the carrying values of the FitzPatrick and Pilgrim plants and related assets to their fair values. In addition, in the fourth quarter 2015, Entergy recorded impairment and other related charges to write down the carrying value of the Palisades plant and related assets to their fair value. In December 2016, Entergy reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant and to shut down the plant in 2018, but the agreement was terminated in September 2017 after the Michigan Public Service Commission decided that Consumers Power could not recover costs incurred under the agreement. Entergy intends to shut down the Palisades plant permanently on May 31, 2022. In January 2017, Entergy announced that it reached a settlement with New York State and plans to close the Indian Point 2 plant in 2020 and the Indian Point 3 plant in 2021. As a result, in the fourth quarter of 2016, Entergy recorded impairment and other related charges to write down the carrying values of the Palisades and Indian Point 2 and Indian Point 3 plants and related assets to their fair value. In addition to the impairments and other related charges, Entergy has incurred severance and employee retention costs and expects to incur additional charges through 2022 relating to the decisions to shut down Vermont Yankee, Palisades, Pilgrim, Indian Point 2 and Indian Point 3, and the sale of FitzPatrick.
If Entergy concludes that any of its nuclear power plants is unlikely to operate through its current useful life,planned shutdown date, which conclusion would be based on a variety of factors, such a conclusion could result in ana further impairment of part or all of the carrying value of the plant. Any impairment charge taken by Entergy with respect to its long-lived assets, including the power plants owned by the Entergy Wholesale Commodities business, would likely be material in the quarter that the charge is taken and could otherwise have a material effect on Entergy’s results of operations, financial condition, or liquidity. For further information regarding evaluating long-lived assets for impairment, see the “Critical Accounting Estimates - Nuclear Decommissioning CostsImpairment of Long-lived Assets and Trust Fund Investments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries.Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
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General Business
(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Entergy and the Utility operating companies depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.
Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies and Entergy Wholesale Commodities. In addition, Entergy’s and the Utility operating companies’ liquidity needs could significantly increase in the event of a hurricane or other weather-
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relatedweather-related or unforeseen disaster similar to that experienced in Entergy’s service territory with Hurricane Katrina and Hurricane Rita in 2005, Hurricane Gustav and Hurricane Ike in 2008, and Hurricane Isaac in 2012. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, higher than expected pension contributions, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, or other unknown events, such as future storms, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy and the Utility operating companies, which in turn could negatively affect access to the capital markets.
The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Events beyond Entergy’s control such as the volatility and disruption in global capital and credit markets in 2008 and 2009, may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay raising capital, issue shorter-term securities and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.
(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital and/or could require Entergy Corporation or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy Corporation and the Registrant Subsidiaries, including each Registrant’s regulatory framework, ability to recover costs and earn returns, diversification and financial strength and liquidity. If one or more rating agencies downgrade Entergy Corporation’s, any of the Utility operating companies’, or System Energy’s ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.
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Most of Entergy Corporation’s and its subsidiaries’ large customers, suppliers, and counterparties require sufficient creditworthiness to enter into transactions. If Entergy Corporation’s or its subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy Corporation or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy Corporation or its subsidiaries. At December 31, 2014,2017, based on power prices at that time, Entergy had liquidity exposure of $159$167 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $5$8 million of posted cash collateral. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2014,2017, Entergy would have been required to provide approximately $51$98 million of additional cash or letters of credit under some of the agreements. In the event of a decrease in the credit ratings of Entergy’s Utility operating companies to below investment grade, those companies collectively could be required to provide up to $50 million of additional cash or letters of credit to MISO. As of December 31, 2014,2017, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously postedreceived collateral from counterparties, would increase by $52$372 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets.
Recent U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, cash flows, and credit ratings.
The recently enacted H.R. 1, also known as the Tax Cuts and Jobs Act of 2017, will significantly change the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The legislation is unclear in certain respects and will require interpretations and implementing regulations by the IRS, as well as state tax authorities, and the legislation could be subject to potential amendments and technical corrections, any of which could lessen or increase certain impacts of the legislation. In addition, the regulatory treatment of the impacts of this legislation, particularly on companies like Entergy and the Registrant Subsidiaries, will be subject to the discretion of federal, state, and local public utility regulators.
As further described in Note 3 to the financial statements, Entergy recorded a reduction of certain of its net deferred income tax assets (including the value of its net operating loss carryforwards) and regulatory liabilities, resulting in a charge against earnings in the fourth quarter 2017 of $526 million, including a $34 million net-of-tax reduction of regulatory liabilities, and Entergy and the Utility operating companies recorded a reduction of approximately $3.7 billion on a consolidated basis in certain of its net deferred tax liabilities and a corresponding increase in net regulatory liabilities. Depending on the outcome of the ratemaking process, IRS examinations, or tax positions and elections that Entergy may elect, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense. Further, the amount and timing of the return of the deferred taxes to customers is dependent upon the regulatory treatment received, and, if the Registrant Subsidiaries are unsuccessful in receiving balanced regulatory treatment, Entergy’s or the Utility operating companies’ cash flow could be materially adversely affected. Further, there may be other material effects resulting from the legislation that have not been identified. While Entergy plans to finance its cash needs that result from the Act through a combination of Registrant Subsidiary debt and Entergy Corporation debt and equity, there can be no assurance that Entergy or the Registrant Subsidiaries will obtain debt or equity financing on terms that are satisfactory or consistent with their current expectations.
In addition, while Moody’s changed the ratings outlooks for Entergy Corporation to negative from stable in reaction to the legislation, it is unclear when or how capital markets, other credit rating agencies, the FERC or state or local regulators may respond to this legislation. Entergy expects that certain financial metrics used by credit rating agencies will be negatively affected as a result of the return of excess deferred taxes to customers, increased debt, and the decrease in the Registrant Subsidiaries’ revenue requirements, and related decrease in operating cash flows, expected as a consequence of the lower federal corporate income tax rate while, at the same time, the loss of the bonus depreciation tax deduction will increase taxable income in the future. Also, the timing of the return of excess deferred income taxes
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to customers will not exactly match the lower taxes that Entergy will be paying which will result in cash outflows to customers. It is also uncertain how other credit rating agencies will treat the impacts of this legislation on their credit ratings and metrics, and whether additional avenues will evolve for companies to manage the adverse aspects of this legislation. These avenues, to the extent available and if successfully applied, could lessen the impacts on certain credit metrics, although there can be no assurance in this regard.
Entergy believes that interpretations and implementing regulations by the IRS, as well as potential amendments and technical corrections, could result in lessening the impacts of certain aspects of this legislation. If Entergy is unable to successfully pursue avenues to manage the effects of the new tax legislation, or if additional interpretations, regulations, amendments, or technical corrections exacerbate the effects of the legislation, the legislation could have a material effect on Entergy’s results of operations, financial condition, and cash flows, and could result in additional credit rating agency actions. Any such actions by credit rating agencies may make it more difficult and costly for Entergy to issue debt securities and certain other types of financing and could increase borrowing costs under its credit facilities.
For further information regarding the effects of the Act, see the “Income Tax Legislation” section of Management’s Financial Discussion and Analysis for Entergy. Also, Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses proceedings commenced or other responses by Entergy’s regulators to the Act.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition and liquidity.
Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include provisions for potential adverse outcomes regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity. For further information regarding Entergy’s income taxes, see Note 3 to the financial statements.
Entergy and its subsidiaries’ ability to successfully complete strategic transactions, including merger, acquisition, divestiture, joint venture, restructuring or other strategic transactions, is subject to significant risks, including the risk that required regulatory or governmental approvals may not be obtained, risks relating to unknown or undisclosed problems or liabilities, and the risk that for these or other reasons, Entergy and its subsidiaries may be unable to achieve some or all of the benefits that they anticipate from such transactions.
From time to time, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring or other strategic transactions. In particular, as discussedFor example, in Note 2 to the financial statements, two of Entergy’s subsidiaries,November 2016, Entergy Louisiana and Entergy Gulf States Louisiana, are undertaking a transactionannounced that would result in the combination of those entitiesit had entered into a single public utility.purchase and sale agreement with NorthStar for the sale of 100% of the membership interests in Entergy Nuclear Vermont Yankee, which owns the Vermont Yankee plant. In addition, as discussed in the “Capital Expenditure Plans and Other Uses of Capital - Union Power Station Purchase Agreement” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries, certainpart of Entergy’s subsidiaries have entered into an asset purchase agreementplan to acquireexit the Union Power Station, consisting of four natural gas-fired, combined-cycle gas turbinemerchant power blocks, each rated at 495 MW (summer rating), from Union Power Partners, L.P. Each of thesebusiness, it plans to shut down its remaining merchant nuclear power plants by mid-2022. These transactions isand plans are or may become subject to regulatory approval and other material conditions or contingencies. The failure to complete these transactions or plans or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy’s financial condition, results of operations and the market’s perception of Entergy’s ability to execute its strategy. Further, these transactions, and any completed or future strategic transactions, involve substantial risks, including the following:
Part I Item 1A & 1B
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the disposition of a business or asset may involve continued financial involvement in the divested business, such as through continuing equity ownership, transition service agreements, guarantees, indemnities, or other current or contingent financial obligations;
Entergy may encounter difficulty in finding buyers or executing alternative exit strategies on acceptable terms in a timely manner when it decides to sell an asset or a business, which could delay the accomplishment of its strategic objectives. Alternatively, Entergy may dispose of a business or asset at a price or on terms that are less than what it had anticipated, or with the exclusion of assets that must be divested or run off separately;
the disposition of a business could result in impairments and related write-offs of the carrying values of the relevant assets;
acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;
acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;
Entergy and/or its subsidiaries may assume liabilities that were not disclosed to them, that exceed their estimates, or for which their rights to indemnification from the seller are limited;
the disposition of a business, including Entergy’s planned exit from the merchant power business, could divert management’s attention from other business concerns;
Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable to them, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets; and
Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.
Entergy may not be successful in managing these or any other significant risks that it may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on its business.
The construction of, and capital improvements to, power generation facilities involve substantial risks. Should construction or capital improvement efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially affected.
Entergy’s and the Utility operating companies’ ability to complete construction of power generation facilities, or make other capital improvements, in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise and escalating costs for materials, labor, and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors not performing as required under their contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, and other events beyond the control of the Utility operating companies or the Entergy Wholesale Commodities business may occur that may materially affect the schedule, cost, and performance of these projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments, or face increased risk of potential write-off of the investment in the project. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of new generation needed to meet the reliability needs of customers at the lowest reasonable cost.
For further information regarding capital expenditure plans and other uses of capital in connection with the potential construction of additional generation supply sources within the Utility operating companies’ service territory, and as to the Entergy Wholesale Commodities business, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs to fulfill their obligations related to environmental and other matters.
The businesses in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business operate are subject to extensive environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business conduct their operations and make capital expenditures. These laws and regulations also affect how the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business potentially are subject to liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies, System Energy, and Entergy Wholesale Commodities and of property contaminated by hazardous substances they generate. The Utility operating companies are currently involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business have incurred and expect to incur significant costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated air emissions from generating plants are potentially subject to increased regulation, controls and mitigation expenses. In addition, existing air regulations and programs promulgated by the EPA often are challenged legally, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to compel greenhouse gas emission reductions, and water availability issues are discussed below.
Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, see the “Regulation of Entergy’s Business – Environmental Regulation” section of Part I, Item 1.
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs related to reliability standards.
Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the North American Electric Reliability Corporation (NERC), the SERC Reliability Corporation (SERC), and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. The changes to the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy Wholesale Commodities.
(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
The effects of weather and economic conditions, and the related impact on electricity and gas usage, may materially affect the Utility operating companies’ results of operations.
Temperatures above normal levels in the summer tend to increase summerelectric cooling electricity demand and revenues, and temperatures below moderatenormal levels in the winter tend to increase winter heating electricityelectric and gas heating demand and revenues. As a corollary, moderate temperatures in either season tend to decrease usage of energy and resulting revenues. Seasonal pricing differentials, coupled with higher consumption levels, typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. Extreme weather conditions or storms, however, may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.
Entergy’s electricity sales volumes are affected by a number of factors, including the state of the national and regional economies,economic conditions, weather, customer bill sizes (large bills tend to induce conservation), trends in energy efficiency, new technologies and self-generation alternatives, including the willingness and ability of large industrial customers to develop co-generation facilities that greatly reduce their demand from Entergy. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting impacteffect on Entergy’s operating results. Others, such as the increasing adoption of energy efficient appliances, andnew building codes, distributed energy resources, energy storage, demand side management and new technologies such as rooftop solar are having a more permanent impacteffect of reducing sales growth rates from historical norms. NewerAs a result of these emerging efficiencies and technologies, such as distributed generation have not yet had a substantive impact on Entergy’s electricity sales, butthe Utility operating companies may experience lower usage per customer in the residential and commercial classes, and further advances have the potential to do solimit sales growth in the future. Since the national economy emerged from the last recession in 2009, Entergy’sElectricity sales to industrial salescustomers, in particular, have benefitedbenefit from steady economic growth and relatively low natural gas prices from an historical perspective.favorable commodity prices; however, they are sensitive to changes in conditions in the markets in which its customers operate. Any substantial negative change in any of these or other factors has the potential to result in slower or declining sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity.
The effects of climate change and environmental and regulatory obligations intended to compel greenhouse gas emission reductions or to place a price on greenhouse gas emissions could materially affect the financial condition, results of operations, and liquidity of Entergy, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
In an effort to address climate change concerns, federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, in response to the United States Supreme Court’s 2007 decision holding that the EPA has authority to regulate emissions of CO2CO2 and other “greenhouse gases” under the Clean Air Act, the EPA, various environmental interest groups, and other organizations are focusing considerable attention on CO2CO2 emissions from power generation facilities and their potential role in climate change. In 2010, the EPA promulgated its first regulations controlling greenhouse gas emissions from certain vehicles and from new and significantly modified stationary sources of emissions, including electric generating units. InDuring 2012 and 2013,2014, the EPA proposed a CO2CO2 emission standardstandards for new sources; this standard is expected to beand existing sources. The EPA finalized these standards in 2015. Additionally,2015; however, in late 2017, the EPA proposed a CO2to repeal the regulations and issued an Advanced Notice of Proposed Rulemaking for replacing certain aspects of the standards for existing source performance standard regulation in 2014 for finalization in 2015.sources. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative (RGGI) establishes a cap on CO2CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2CO2 emissions, and a similar program has been developed in California.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
developed in California. The impact that recent changes in the federal government will have on existing and pending environmental laws and regulations related to greenhouse gas emissions is currently unclear.
Developing and implementing plans for compliance with greenhouse gas emissions reduction requirements can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects; moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where the Utility operating companies, System Energy, or Entergy Wholesale Commodities do business. Violations of such requirements may subject Entergy Wholesale Commodities and the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy’s regulators and, in extreme cases, Entergy’s regulators might deny or defer timely recovery of these costs. Future changes in environmental regulation governing the emission of CO2CO2 and other greenhouse gases could make some of Entergy’s electric generating units uneconomical to maintain or operate, and could increase the difficulty that Entergy and its subsidiaries have with obtaining or maintaining required environmental regulatory approvals, which could also materially affect the financial condition, results of operations and liquidity of Entergy and its subsidiaries. In addition, lawsuits currently are pendinghave occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.
In addition to the regulatory and financial risks associated with climate change discussed above, potential physical risks from climate change include an increase in sea level, wind and storm surge damages, wetland and barrier island erosion, risks of flooding and changes in weather conditions, such(such as changesincreases in precipitation, drought, or changes in average temperatures,temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas infrastructure is located in these areas and susceptible to storm damage that could be aggravated by wetland and barrier island erosion, which could give rise to fuel supply interruptions and price spikes. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supply necessary for operations.
These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy System’s ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s, Entergy Wholesale Commodities’, System Energy’s, and the Utility operating companies’ financial condition, results of operations, and liquidity.
Continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
Water is a vital natural resource that is also critical to the Utility operating companies’, System Energy's,Energy’s, and Entergy Wholesale Commodities’ business operations. Entergy’s facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. TwoThree of Entergy’s Utility operating companies own and/or operate hydroelectric facilities. Accordingly, water availability and quality are critical to Entergy’s business operations. Impacts to water availability or quality could negatively impact both operations and revenues.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Entergy secures water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operates under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy also obtains and operates in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act.Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, and the potential impacts of climate change on water resources may cause water use restrictions that affect Entergy and its subsidiaries.
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.
To manage near-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies and the Entergy Wholesale Commodities business, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.
Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.
Entergy’s over-the-counter financial derivatives are subject to rules implementing the Dodd-Frank Wall Street Reform and Consumer Protection Act that are designed to promote transparency, mitigate systemic risk and protect against market abuse. Entergy cannot predict the impact any proposed or not fully-implemented final rules will have on its ability to hedge its commodity price risk or on over-the-counter derivatives markets as a whole, but such rules and regulations could have a material effect on Entergy's risk exposure, as well as reduce market liquidity and further increase the cost of hedging activities.
Entergy has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities. Reductions in Entergy’s or its subsidiaries’ credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy’s or its subsidiaries’ liquidity and financial position.
The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy Wholesale Commodities.
The hedging and risk management practices of the Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations. Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to perform, Entergy or its subsidiaries may enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements, which credit
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
support may not always be adequate to cover the related obligations. In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties. In addition, the credit commitments of Entergy’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.
The Wall Street Transparency and Accountability Act of 2010 and rules and regulations promulgated under the act may adversely affect the ability of the Utility operating companies and the Entergy Wholesale Commodities business to utilize certain commodity derivatives for hedging and mitigating commercial risk.
The Wall Street Transparency and Accountability Act of 2010, which was enacted on July 21, 2010 as part of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Act), and the rules and regulations promulgated under the act impose governmental regulation on the over-the-counter derivative market, including the commodity
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
swaps used by the Utility operating companies and the Entergy Wholesale Commodities business to hedge and mitigate commercial risk. Under the Act, certain swaps are subject to mandatory clearing and exchange trading requirements. Swap dealers and major market participants in the swap market are subject to capital, margin, registration, reporting, recordkeeping, and business conduct requirements with respect to their swap activities. Entergy is not a swap dealer or a major swap participant, and does not expect to qualify as either in the future. Non-swap dealers and non-major swap participants, such as Entergy, are subject to reporting, recordkeeping, and business conduct requirements (i.e., anti-manipulation, anti-disruptive trading practices, and whistleblower provisions) with respect to their swap activities. Position limits may also apply to certain swaps activities. Position limit rules promulgated by the Commodity Futures Trading Commission were vacated by the US District Court for the District of Columbia. The Commodity Futures Trading Commission has subsequently proposed new position limit rules. If the Commodity Futures Trading Commission’s issues final position limit rules, those rules may apply to certain of Entergy’s swaps activities.
The Act required the applicable regulators, which in the case of commodity swaps will be the Commodity Futures Trading Commission, to engage in substantial rulemaking in order to implement the provisions of the Act and such rulemaking has been largely completed. Both the Utility operating companies and the Entergy Wholesale Commodities business currently utilize commodity swaps to hedge and mitigate commodity price risk. It is not known whether the Act and regulations promulgated under the Act will have an adverse effect upon the market for the commodity swaps used by the Utility operating companies and the Entergy Wholesale Commodities business. However, to the extent that the Act and regulations promulgated under the Act have the effect of increasing the price of such commodity swaps or limiting or reducing the availability of such commodity swaps, whether through the imposition of additional capital, margin, or compliance costs upon market participants, the imposition of position limits, or otherwise, the financial performance of the Utility operating companies and/or the Entergy Wholesale Commodities business may be adversely affected. To the extent that the Utility operating companies and the Entergy Wholesale Commodities business may be required to post margin in connection with existing or future commodity swaps in addition to any margin currently posted by such entities, such entities may need to secure additional sources of capital to meet such liquidity needs or cease utilizing such commodity swaps.
Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding.funding and result in increased benefit plan costs.
The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement benefit plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy’s benefit plan liabilities.liabilities and also result in higher benefit costs. As the value of the assets decreases, the “expected return on assets” component of benefit costs decreases, resulting in higher benefits costs. Additionally, asset losses are incorporated into benefit costs over time, thus increasing benefits costs. Volatility in the capital markets has affected the market value of these assets, which may affect Entergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding.funding and recognition of higher liability carrying costs. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or Federal regulations. For further information regarding Entergy’s pension and other postretirement benefit plans, refer to the “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.
The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.
Entergy and its subsidiaries are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and ratepayer matters, and injuries and damages issues, among other matters. The states in which the Utility operating companies operate, in particular Louisiana, Mississippi, and Texas, have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
business tort cases. Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the litigation environment in these states poses a significant business risk.
Domestic or international terrorist attacks, including cyber attacks, and failures or breaches of Entergy’s and its subsidiaries’ technology systems may adversely affect Entergy’s results of operations.
As power generators and distributors, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, including physical and cyber attacks, either as a direct act against one of Entergy’s generation facilities, transmission operations centers, or distribution infrastructure used to manage and transport power to customers. An actual act could affect Entergy’s ability to operate, including its ability to operate the necessary information technology systems and network infrastructure.infrastructure on which it relies to conduct its business. While malware was recently discovered on our corporate network and remediated on a timely basis, it did not affect the company’s operational systems, nuclear plants or transmission network, nor did it have a material effect on our operations. Additionally, within Entergy’s industry, there have been attacks on energy infrastructure, but with minimal impact to operations, and there may be more attacks in the future. The Utility operating companies also face heightened risk of an act or threat by cyber criminals intent on accessing personal information for the purpose of committing identity theft.theft, taking company-sensitive data, or disrupting the company’s ability to operate.
Entergy and its subsidiaries operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure in accordance with mandatory and prescriptive standards. Despite the implementation of multiple layers of security by Entergy and its subsidiaries,
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
technology systems remain vulnerable to potential threats that could lead to unauthorized access or loss of availability to critical systems essential to the reliable operation of Entergy’s electric system. Moreover, the functionality of Entergy’s technology systems depends on both its and third-party systems to which Entergy is connected directly or indirectly (such as systems belonging to suppliers, vendors and contractors). While Entergy has processes in place to assess systems of certain of these suppliers, vendors and contractors, Entergy does not ultimately control the adequacy of their defenses against cyber and other attacks, but has implemented oversight measures to assess maturity and manage third-party risk. If Entergy’s or its subsidiaries’ technology systems were compromised and unable to detect or recover in a timely fashion to a normal state of operations, Entergy or its subsidiaries may be unable to perform critical business functions that are essential to the company’s well-being and the health, safety, and security needs of its customers. In addition, an attack on its information technology infrastructure may result in a loss of its confidential, sensitive, and proprietary information, including personal information of its customers, employees, vendors, and others in Entergy’s care.
If anyAny such attacks, failures or breaches were to occur,could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, and results of operations couldor reputation. Insurance may not be materially and adversely affected.adequate to cover losses that might arise in connection with these events. The risk of such attacks, failures, or breaches may cause Entergy and the Utility operating companies to incur increased capital and operating costs to implement increased security for its nuclear power plantsgeneration, transmission, and distribution assets and other facilities, such as additional physical facility security and additional security personnel, and for systems to protect its information technology and network infrastructure systems. Such events may also expose Entergy to an increased risk of judgmentslitigation (and associated damages and fines.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition and liquidity.
Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include provisions for potential adverse outcomes regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity. For further information regarding Entergy’s income taxes, refer to Note 3 to the financial statements.fines).
(Entergy Gulf States Louisiana and Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy Gulf States Louisiana’s and Entergy New Orleans’s results of operations and liquidity.
Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy Gulf States Louisiana or Entergy New Orleans, and distribution charges, which provide
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
a return or profit to the utility. Distribution charges are affected by the amount of gas sold to customers. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy Gulf States Louisiana or Entergy New Orleans recovers from its customers. Entergy Gulf States Louisiana’s or Entergy New Orleans’s cash flows can be affected by differences between the time period when gas is purchased and the time when ultimate recovery from customers occurs. When purchased gas cost charges increase substantially reflecting higher gas procurement costs incurred by Entergy Gulf States Louisiana or Entergy New Orleans, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy Gulf States Louisiana or Entergy New Orleans, which could adversely affect results of operations.
(System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on affiliated companies for all of its revenues.
System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies as consideration for their respective entitlements to receive capacity and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which is currently due to expire onexpires in November 1, 2024. System Energy filed in October 2011 an application with the NRC for an extension of Grand Gulf’s operating license to 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies under the Unit Power Sales Agreement and on the continued commercial operation of Grand Gulf.
For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to the Entergy System companies’ support of System Energy (including the Capital Funds
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Agreement), see the “Grand Gulf-Related Agreements” section of NoteNotes 8 to the financial statements and the “Sale and Leaseback Transactions” section of Note 10 to the financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.
(Entergy Corporation)
As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock.
Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The payments of dividends or distributions to Entergy Corporation by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings, and on any applicable legal, regulatory, or contractual limitations on subsidiaries’ ability to pay such dividends or distributions. Provisions in the organizational documents, indentures for debt issuances, and other agreementsarticles of incorporation of certain of Entergy Corporation’s subsidiaries restrict the payment of cash dividends to Entergy Corporation. For further information regarding dividend or distribution restrictions to Entergy Corporation, see the “Retained Earnings and Dividend Restrictions” section of Note 7 to the financial statements.
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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Net Income
20142017 Compared to 20132016
Net income decreased by $40.6$27.4 million primarily due to higher other operation and maintenancenuclear refueling outage expenses, lower other income, higher depreciation and amortization expenses, higher taxes other than income taxes, and a higher effective income tax rate,interest expense, partially offset by higher net revenue.other income.
20132016 Compared to 20122015
Net income increased $9.6$92.9 million primarily due to higher net revenue higher other income,and lower nuclear refueling outage expenses, and a lower effective income tax rate, partially offset by higher other operation and maintenance expenses, partially offset by a higher interest expense,effective income tax rate and higher depreciation and amortization expenses.
Net Revenue
20142017 Compared to 20132016
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory credits.charges (credits). Following is an analysis of the change in net revenue comparing 20142017 to 2013.2016.
|
| | | |
| | Amount |
| | (In Millions) |
| | |
20132016 net revenue |
| $1,301.51,520.5 |
|
| Retail electric price | 43.333.8 |
|
Reserve equalizationOpportunity sales | 16.5 |
|
Transmission revenue | 13.75.6 |
|
| Asset retirement obligation | 12.7 |
|
MISO deferral | (11.114.8 | ) |
| Volume/weather | (13.0 | ) |
Net wholesale revenue | (20.529.0 | ) |
| Other | (7.26.5 | )
|
20142017 net revenue |
| $1,335.91,522.6 |
|
The retail electric price variance is primarily due to the implementation of formula rate plan rates effective with the first billing cycle of January 2017 and an increase in base rates effective February 24, 2016, each as approved by the APSC. A significant portion of the base rate increase was related to the purchase of Power Block 2 of the Union Power Station in March 2016. The increase was partially offset by decreases in the energy efficiency rider, as approved by the APSC, effective July 2013April 2016 and July 2014, and the effect of the APSC’s order in the 2013 rate case, including an annual base rate increase effective January 2014, offset by a MISO rider to provide customers credits in rates for transmission revenue received through MISO. Energy efficiency revenues are largely offset by costs included in other operation and maintenance expenses and have minimal effect on net income.2017. See Note 2 to the financial statements for further discussion of the rate case.case and formula rate plan filings. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
The reserve equalizationopportunity sales variance is primarily dueresults from the estimated net revenue effect of the 2017 and 2016 FERC orders in the opportunity sales proceeding attributable to wholesale customers. See Note 2 to the absencefinancial statements for further discussion of reserve equalization expenses as compared to 2013 resulting from Entergy Arkansas’s exit from the System Agreement.opportunity sales proceeding.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The transmission revenue variance is primarily due to changes as a result of participation in the MISO RTO in 2014.
The asset retirement obligation affects net revenue because Entergy Arkansas records a regulatory debitcharge or credit for the difference between asset retirement obligation-related expenses and decommissioning trust fund earnings plus asset retirement obligation relatedobligation-related costs collected in revenue. The variance is primarily caused by an increasea decrease in regulatory credits because of a decreasean increase in decommissioning trust earnings.fund earnings, including portfolio rebalancing for the ANO 1 and ANO 2 decommissioning trust funds.
The MISO deferral variance is due to the deferral in April 2013, as approved by the APSC, of costs incurred
from March 2010 through December 2012 related to the transition and implementation of joining the MISO RTO.
The volume/weather variance is primarily due to a decrease inthe effect of less favorable weather on residential and commercial sales volume during the billed and unbilled sales period,periods. The decrease was partially offset by an increase of 190733 GWh, or 1%11%, in billed electricityindustrial usage primarily in the residential sector.
The net wholesale revenue variance is primarily due to lower margins on co-owner contracts due to contract changes.a new customer in the primary metals industry.
20132016 Compared to 20122015
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory credits.charges (credits). Following is an analysis of the change in net revenue comparing 20132016 to 2012.2015.
|
| | | |
| | Amount |
| | (In Millions) |
| | |
20122015 net revenue |
| $1,253.01,362.2 |
|
| Retail electric price | 46.4161.5 |
|
MISO deferral | 11.1 |
|
Net wholesale revenue | 6.5 |
|
Volume/weatherOther | (10.73.2 | ) |
Asset retirement obligation | (10.4 | ) |
Other | 5.6 |
|
20132016 net revenue |
| $1,301.51,520.5 |
|
The retail electric price variance is primarily due to:
to an increase in the capacity acquisition rider,base rates, as approved by the APSC,APSC. The new base rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. The increase includes an interim base rate adjustment surcharge, effective with the first billing cycle of December 2012, relatingApril 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. A significant portion of the increase was related to the Hot Spring plant acquisition. The net income effectpurchase of Power Block 2 of the Hot Spring plant cost recovery is limitedUnion Power Station in March 2016. See Note 2 to a portion representing an allowed return on equity on the net plant investmentfinancial statements for further discussion of the rate case. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
Other Income Statement Variances
2017 Compared to 2016
Nuclear refueling outage expenses increased primarily due to the amortization of higher costs associated with the remainder offset by the Hot Spring plant costs in othermost recent outages compared to previous outages.
Other operation and maintenance expenses depreciation expenses, and taxes other than income taxes; andincreased primarily due to:
increases
the deferral in the energy efficiency rider,first quarter 2016 of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC effective July 2014 and July 2013. Energy efficiency revenuesas part of the 2015 rate case settlement. These costs are largely offset by costs included in other operation and maintenance expenses and have minimal effect on net income.
The MISO deferral variance is duebeing amortized over a ten-year period beginning March 2016. See Note 2 to the deferralfinancial statements for further discussion of the rate case settlement;
an increase of $9.5 million in April 2013, as approved by the APSC, of costs incurred
from March 2010 through December 2012 related to the transitiontransmission and implementation of joining the MISO RTO.
The net wholesale revenue variance isdistribution expenses primarily due to higher margins on co-owner contracts.vegetation maintenance costs and higher labor costs, including contract labor;
an increase of $5.9 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to the prior year; and
the effect of recording in July 2016 the final court decision in a lawsuit against the DOE related to spent nuclear fuel storage costs. The damages awarded included the reimbursement of $5.5 million of spent nuclear fuel
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The volume/weather variance is duestorage costs previously recorded as other operation and maintenance expense. See Note 8 to lower weather-adjusted usage across all sectors, partially offset by the effectfinancial statements for further discussion of more favorable weather on residential sales. The decrease in the industry usage was primarily driven by the pulp and paper industry, the chemicals industry, and the food products industry.Entergy Arkansas’s spent nuclear fuel litigation.
The asset retirement obligation affects net revenue because Entergy Arkansas records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation related costs collected in revenue. The variance is primarily caused by a decrease in regulatory credits because of an increase in decommissioning trust earnings.
Other Income Statement Variances
2014 Compared to 2013
Other operation and maintenance expenses increased primarily due to:was partially offset by:
a net increasedecrease of $26.4 million in energy efficiency costs, including a $4.3 million true-up to the 2013 energy efficiency filing for fixed costs collected from customers. These costs are recovered through the energy efficiency rider and have a minimal effect on net income;
an increase of $21.2$16 million in nuclear generation expenses primarily due to higher materiala decrease in regulatory compliance costs compared to the prior year, partially offset by higher nuclear labor costs, including contract labor, to position the nuclear fleet to meet its operational goals. The decrease in regulatory compliance costs is primarily related to NRC inspection activities in 2016 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. See Note 8 to the financial statements for a discussion of the ANO stator incident and subsequent NRC reviews;
a decrease of $11.5 million in energy efficiency expenses primarily due to the timing of recovery from customers; and
a decrease of $5.2 million in fossil-fueled generation expenses primarily due to lower long-term service agreement costs, partially offset by an overall higher NRC fees;scope of work including plant outages in 2017 compared to 2016.
an increase of $13.9 million
Taxes other than income taxes increased primarily due to an increase in storm damage accruals effective January 2014, as approved byad valorem taxes primarily due to higher assessments and higher millage rates and an increase in local franchise taxes primarily due to higher billing factors.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Block 2 of the APSC;Union Power Station purchased in March 2016. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
Other income increased primarily due to higher realized gains in 2017 compared to 2016 on the decommissioning trust fund investments, including portfolio rebalancing for the ANO 1 and ANO 2 decommissioning trust funds.
Interest expense increased primarily due to:
an increase of $7.5$3.3 million in administration feesestimated interest expense recorded in 2014 related to participation inconnection with the MISO RTO;
an increase of $7.2 million due to the amortization in 2014 of human capital management costs that were deferred in 2013, as approved by the APSC.opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the deferralopportunity sales proceeding; and
the issuance in May 2017 of these costs;$220 million of 3.5% Series first mortgage bonds and the issuance in June 2016 of $55 million of 3.5% Series first mortgage bonds, partially offset by the redemption in July 2016 of $60 million of 6.38% Series first mortgage bonds and the redemption in February 2016 of $175 million of 5.66% Series first mortgage bonds. See Note 5 to the financial statements for further discussion of long-term debt.
an increase of $5.2 million
2016 Compared to 2015
Nuclear refueling outage expenses increased primarily due to the amortization in 2014 of higher costs deferred in 2013 relatedassociated with the most recent outages compared to the transition and implementation of joining the MISO RTO, as discussed above; andprevious outages.
the effects of recording the final court decision in 2013 in the Entergy Arkansas lawsuit against the U.S. Department of Energy related to spent nuclear fuel disposal. The damages awarded include the reimbursement of approximately $3.2 million of spent nuclear fuel storage costs previously recorded as other
Other operation and maintenance expense.
The increase was partially offset by:expenses decreased primarily due to:
a decrease of $20.8$21.6 million in compensation and benefits costs primarily due to an increasea decrease in the discount rates used to determine net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit costs,liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement benefit plan design changes, fewer employees, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan.costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
a decrease of $9 million resulting from costs incurred in 2013 related to the generator stator incident at ANO, including an offset for insurance proceeds. See “ANO Damage, Outage, and NRC Reviews” below for further discussion of the incident; and
a decrease of $8.6 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business.
Depreciation and amortization expenses increased primarily due to additions to plant in service, higher depreciation rates in 2014, as approved by the APSC, and the effects of recording the final court decision in 2013 in the Entergy Arkansas lawsuit against the U.S. Department of Energy related to spent nuclear fuel disposal. The damages awarded include the reimbursement of approximately $3.6 million of spent nuclear fuel storage costs previously recorded as depreciation expense.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Other income decreased primarily due to lower earnings in 2014 on decommissioning trust fund investments. There is no effect on net income as the trust fund earnings are offset by a corresponding amount of regulatory charges.
2013 Compared to 2012
Nuclear refueling outage expenses decreased primarily due to lowerthe deferral of $7.7 million of previously-incurred costs associated with the most recent outage as compared to the previous outages.
Other operation and maintenance expenses increased primarily due to:
an increase of $24.3 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative, partially offset by the deferral,ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC as part of $21.8 million of these costs.the 2015 rate case settlement. These costs are being amortized over a ten-year period beginning March 2016. See “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and AnalysisNote 2 to the financial statements for further discussion;
discussion of the rate case settlement; anda decrease of $7.2 million in energy efficiency costs, including the effects of true-ups to the energy efficiency filings for fixed costs to be collected from customers and incentives recognized as a result of participation in energy efficiency programs.
The decrease was partially offset by an increase of $16.2$24.1 million in nuclear generation expenses primarily due to an overall higher scope of work performed during plant outages and higher nuclear labor costs compared to prior year and an increase of $8.2 million in fossil-fueled generation expenses primarily due to the additionpurchase of Power Block 2 of the Hot Spring plantUnion Power Station in November 2012;
an increase of $16.1 million in energy efficiency costs. These costs are recovered through the energy efficiency rider and have minimal effect on net income;
an increase of $10.8 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out of the non-qualified pension plan.March 2016. See “Critical Accounting Estimates” below and Note 1114 to the financial statements for further discussion of benefits costs; and
the Union Power Station purchase.
an increase of $9 millionTaxes other than income taxes decreased primarily due to a decrease in local franchise taxes resulting from costs relatedlower residential and commercial revenues compared to the generator stator incident at ANO, including an offset for expected insurance proceeds. See “ANO Damage, Outage,prior year and NRC Reviews” below for further discussion of the incident.
The increase was partially offset by:
a decrease of $4.6 million due to costs incurred in 2012 related to the transition and implementation of joining the MISO RTO. In April 2013, Entergy Arkansas began deferring these costs as approved by the APSC; andpayroll taxes.
the effects of recording the final court decision in 2013 in the Entergy Arkansas lawsuit against the U.S. Department of Energy related to spent nuclear fuel disposal. The damages awarded include the reimbursement of approximately $3.2 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense.
Also, other operation and maintenance expenses include $8.6 million in 2013 and $13.3 million in 2012 of costs incurred related to the now terminated plan to spin off and merge the transmission business.
Depreciation and amortization expenses increased primarily due to the acquisitionadditions to plant in service, including Power Block 2 of the Hot Spring plantUnion Power Station purchased in November 2012, partially offset byMarch 2016. See Note 14 to the effectsfinancial statements for further discussion of recording the final court decision in 2013 in the Entergy Arkansas lawsuit against the U.S. Department of Energy related to spent nuclear fuel disposal. The damages awarded include the reimbursement of approximately $3.6 million of spent nuclear fuel storage costs previously recorded as depreciation expense.Union Power Station purchase.
Other income increased primarily due to higher realized gains in 2013 on the ANO 1 and ANO 2 decommissioning trust fund investments. There is no effect on net income as these investment gains are offset by a corresponding amount of regulatory charges.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Interest expense increased primarily due to:
$5.1 million in estimated interest expense recorded in connection with the FERC orders issued in April 2016 in the opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding; and
the net issuance of $200$230 million of 4.90% Series first mortgage bonds in December 2012;
2016. See Note 5 to the issuancefinancial statements for further discussion of $250 million of 3.05% Series first mortgage bonds bonds in May 2013; and
the issuance of $125 million of 4.75% Series first mortgage bonds in June 2013.
This increase was offset by the retirement, at maturity, of $300 million of 5.40% Series first mortgage bonds in August 2013.long-term debt.
Income Taxes
The effective income tax rates for 2014, 2013,2017, 2016, and 20122015 were 40.8%40.1%, 36.2%39.2%, and 38.4%35.3%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
ANO Damage, Outage, and NRC ReviewsIncome Tax Legislation
On March 31, 2013, during a scheduled refueling outage at ANO 1, a contractor-ownedSee the “Income Tax Legislation” section of Entergy Corporation and operated heavy-lifting apparatus collapsed while moving the generator stator outSubsidiaries Management’s Financial Discussion and Analysis for discussion of the turbine building. The collapse resultedTax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the deathfinancial statements contains additional discussion of an ironworkerthe effect of the Act on 2017 results of operations and injuries to several other contract workers, caused ANOfinancial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to shut down, and damaged the ANO turbine building. The turbine building serves both ANO 1 and 2 and is a non-radiological area of the plant. ANO 2 reconnectedfinancial statements discusses proceedings commenced or other responses by Entergy’s regulators to the grid on April 28, 2013 and ANO 1 reconnected to the grid on August 7, 2013. The total cost of assessment, restoration of off-site power, site restoration, debris removal, and replacement of damaged property and equipment was approximately $95 million. In addition, Entergy Arkansas incurred replacement power costs for ANO 2 power during its outage and incurred incremental replacement power costs for ANO 1 power because the outage extended beyond the originally-planned duration of the refueling outage. In February 2014 the APSC approved Entergy Arkansas’s request to exclude from the calculation of its revised energy cost rate $65.9 million of deferred fuel and purchased energy costs incurred in 2013 as a result of the ANO stator incident. The APSC authorized Entergy Arkansas to retain the $65.9 million in its deferred fuel balance with recovery to be reviewed in a later period after more information regarding various claims associated with the ANO stator incident is available.Act.
Entergy Arkansas is pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. Entergy is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants, including ANO. NEIL has notified Entergy that it believes that a $50 million course of construction sublimit applies to any loss associated with the lifting apparatus failure and stator drop at ANO. Entergy has responded that it disagrees with NEIL’s position and is evaluating its options for enforcing its rights under the policy. During 2014, Entergy Arkansas collected $50 million from NEIL and is pursuing additional recoveries due under the policy. On July 12, 2013, Entergy Arkansas filed a complaint in the Circuit Court in Pope County, Arkansas against the owner of the heavy-lifting apparatus that collapsed, an engineering firm, a contractor, and certain individuals asserting claims of breach of contract, negligence, and gross negligence in connection with their responsibility for the stator drop.
Shortly after the stator incident, the NRC deployed an augmented inspection team to review the plant’s response. In July 2013 a second team of NRC inspectors visited ANO to evaluate certain items that were identified as requiring follow-up inspection to determine whether performance deficiencies existed. In March 2014 the NRC issued an inspection report on the follow-up inspection that discussed two preliminary findings, one that was preliminarily determined to be “red with high safety significance” for Unit 1 and one that was preliminarily determined to be “yellow with substantial safety significance” for Unit 2, with the NRC indicating further that these preliminary findings may warrant additional regulatory oversight. This report also noted that one additional item related to flood barrier effectiveness was still under review.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
In May 2014 the NRC met with Entergy during a regulatory conference to discuss the preliminary red and yellow findings and Entergy’s response to the findings. During the regulatory conference, Entergy presented information on the facts and assumptions the NRC used to assess the potential findings. The NRC used the information provided by Entergy at the regulatory conference to finalize its decision regarding the inspection team’s findings. In a letter dated June 23, 2014, the NRC classified both findings as “yellow with substantial safety significance.” In an assessment follow-up letter for ANO dated July 29, 2014, the NRC stated that given the two yellow findings, it determined that the performance at ANO is in the “degraded cornerstone column,” or column 3, of the NRC’s reactor oversight process action matrix beginning the first quarter 2014. Corrective actions in response to the NRC’s findings have been taken and remain ongoing at ANO. The NRC plans to conduct supplemental inspection activity to review the actions taken to address the yellow findings. Entergy will continue to interact with the NRC to address the NRC’s findings.
In September 2014 the NRC issued an inspection report on the flood barrier effectiveness issue that was still under review at the time of the March 2014 inspection report. While Entergy believes that the flood barrier issues that led to the finding have been addressed at ANO, NRC processes still required that the NRC assess the safety significance of the deficiencies. In its September 2014 inspection report, the NRC discussed a preliminary finding of “yellow with substantial safety significance” for the Unit 1 and Unit 2 auxiliary and emergency diesel fuel storage buildings. The NRC indicated that these preliminary findings may warrant additional regulatory oversight. Entergy requested a public regulatory conference regarding the inspection, and the conference was held on October 28, 2014. During the regulatory conference, Entergy presented information related to the facts and assumptions used by the NRC in arriving at its preliminary finding of “yellow with substantial safety significance.” In January 2015 the NRC issued its final risk significance determination for the flood barrier violation originally cited in the September 2014 report. The NRC’s final risk significance determination was classified as “yellow with substantial safety significance.”
The NRC’s January 2015 letter did not advise ANO of the additional level of oversight that will result from the yellow finding related to the flood barrier issue, and it stated that the NRC would inform ANO of this decision by separate correspondence. The yellow finding may result in ANO being placed into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. Placement into this column would require significant additional NRC inspection activities at the ANO site, including a review of the site’s root cause evaluation associated with the flood barrier and stator issues, an assessment of the effectiveness of the site’s corrective action program, an additional design basis inspection, a safety culture assessment, and possibly other inspection activities consistent with the NRC’s Inspection Procedure. The additional NRC inspection activities at the site are expected to increase ANO’s operating costs.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2014, 2013,2017, 2016, and 20122015 were as follows:
| | | | 2014 | | 2013 | | 2012 | | 2017 | | 2016 | | 2015 |
| | (In Thousands) | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $127,022 |
| |
| $34,533 |
| |
| $22,599 |
| |
| $20,509 |
| |
| $9,135 |
| |
| $218,505 |
|
| | | | | | | | | | | | |
| Net cash provided by (used in): | | | |
| | |
| | | | |
| | |
|
| Operating activities | 403,826 |
| | 401,250 |
| | 509,117 |
| | 555,556 |
| | 676,511 |
| | 474,890 |
|
| Investing activities | (600,628 | ) | | (524,473 | ) | | (723,248 | ) | | (829,312 | ) | | (947,995 | ) | | (685,274 | ) |
| Financing activities | 288,285 |
| | 215,712 |
| | 226,065 |
| | 259,463 |
| | 282,858 |
| | 1,014 |
|
| Net increase in cash and cash equivalents | 91,483 |
| | 92,489 |
| | 11,934 |
| | |
| Net increase (decrease) in cash and cash equivalents | | (14,293 | ) | | 11,374 |
| | (209,370 | ) |
| | | | | | | | | | | | |
| Cash and cash equivalents at end of period |
| $218,505 |
| |
| $127,022 |
| |
| $34,533 |
| |
| $6,216 |
| |
| $20,509 |
| |
| $9,135 |
|
Operating Activities
Net cash flow provided by operating activities decreased $121 million in 2017 primarily due to income tax refunds of $8.1 million in 2017 compared to income tax refunds of $135.7 million in 2016. Entergy Arkansas had income tax refunds in 2016 and 2017 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2017 resulted from the utilization of Entergy Arkansas’s net operating losses. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audit.
Net cash flow provided by operating activities increased $201.6 million in 2016 primarily due to:
income tax refunds of $135.7 million in 2016 compared to income tax payments of $103.3 million in 2015. Entergy Arkansas had income tax refunds in 2016 and income tax payments in 2015 in accordance with an intercompany income tax allocation agreement. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit whereas the income tax payments in 2015 resulted primarily from final settlement of amounts outstanding associated with the 2006-2007 IRS audit as well as adjustments associated with the settlement of the 2008-2009 IRS audit. See Note 3 to the financial statements for further discussion of the income tax audits;
the timing of payments to vendors; and
an increase in net revenue.
The increase was partially offset by a decrease due to the timing of recovery of fuel and purchased power costs.
Investing Activities
Net cash flow used in investing activities decreased $118.7 million in 2017 primarily due to the purchase of Power Block 2 of the Union Power Station in March 2016 for approximately $237 million and a decrease of $35.5 million in transmission construction expenditures primarily due to a lower scope of work performed in 2017. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Operating Activities
Net cash flow provided by operating activities increased $2.6 million in 2014 primarily due to:
income tax refunds of $48.9 million in 2014 compared to income tax payments of $184.6 million in 2013. Entergy Arkansas received income tax refunds in 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax refunds in 2014 resulted primarily from the utilization of Entergy Arkansas’s net operating losses by the consolidated group whereas the income tax payments in 2013 resulted primarily from the reversal of temporary differences for which Entergy Arkansas had previously claimed a tax deduction;
approximately $25 million in spending in 2013 related to the generator stator incident at ANO, as discussed
above; and
$13.4 million in insurance proceeds received in 2014 for property damages related to the generator stator
incident at ANO, as discussed above.
The increase was partially offset by:
a decrease in the recovery of fuel and purchased power costs including a $68 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period and a $33.7 million System Agreement bandwidth remedy payment made in September 2014 as a result of the compliance filing pursuant to the FERC’s orders related to the bandwidth payments/receipts for the comprehensive recalculation for 2007, 2008, and 2009. See Note 2 to the financial statements for a discussion of the System Agreement bandwidth remedy payments;
an increase of $60.1 million in pension contributions in 2014. See “Critical Accounting Estimates”below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;
proceeds of $38 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel;
the timing of payments to vendors; and
an increase of $24.6 million in storm spending in 2014.
Net cash flow provided by operating activities decreased $107.9 million in 2013 primarily due to:
income tax payments of $184.6 million in 2013 compared to income tax refunds of $20.5 million in 2012. Entergy Arkansas had income tax payments in 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2013 resulted primarily from the reversal of temporary differences for which Entergy Arkansas had previously claimed a tax deduction;
approximately $25 million in spending related to the generator stator incident at ANO, as discussed above;
$22.6 million in storm restoration spending in 2013 resulting from the December 2012 winter storm which caused significant damage to Entergy Arkansas’s distribution lines, equipment, poles and other facilities; and
a decrease in the recovery of fuel and purchased power costs.
The decrease was partially offset by:
proceedsan increase of $38 million associated with the payments received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel; and
the $30.6 million June 2012 refund to AmerenUE, including interest, in rough production cost equalization payments previously collected from Ameren UE .
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Investing Activities
Net cash used in investing activities increased $76.2$50.4 million in 2014nuclear construction expenditures primarily due to:
to a higher scope of work performed on various nuclear projects in 2017;
an increase of $101.4$37.7 million storm spending in 2014;
as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and servicesservice deliveries, and the timing of cash payments during the nuclear fuel cycle;
an increase of $32.9 million in information technology construction expenditures primarily due to increased spending on substation technology upgrades;
an increase of $22.3 million in fossil-fueled generation construction expenditures primarily due to a higher scope of work performed on various projects in 2017; and
proceedsan increase of $10.3$11.2 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel.
The decrease was partially offset by:
approximately $69 million indue to increased spending in 2013 related to the generator stator incident at ANO, as discussed above;
$36.6 million in insurance proceeds received in 2014 for property damages related to the generator stator incident at ANO, as discussed above; and
money pool activity.
Decreases in Entergy Arkansas’s receivable from the money pool are a source of cash flow, and Entergy Arkansas’s receivable from the money pool decreased by $15.3 million in 2014 as compared to increasing by $9.5 million in 2013. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.on advanced metering infrastructure.
Net cash flow used in investing activities decreased $198.8increased $262.7 million in 20132016 primarily due to the purchase of Power Block 2 of the Hot Spring Energy FacilityUnion Power Station in March 2016 for approximately $253 million in November 2012 and$237 million. See Note 14 to the financial statements for further discussion of the Union Power Station purchase. The increase was partially offset by fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and servicesservice deliveries, and the timing of cash payments during the nuclear fuel cycle. See Note 15
Financing Activities
Net cash flow provided by financing activities decreased $23.4 million in 2017 primarily due to:
a $200 million capital contribution received from Entergy Corporation in March 2016 primarily in anticipation of Entergy Arkansas’s purchase of Power Block 2 of the Union Power Station;
the net issuance of $119.1 million of long-term debt in 2017 compared to the financial statements for a discussionnet issuance of $189.1 million of long-term debt in 2016; and
$15 million in common stock dividends paid in 2017 resulting from Entergy Arkansas’s routine evaluation of its ability to pay dividends. There were no common stock dividends paid in 2016 in anticipation of the purchase of Power Block 2 of the Hot Spring Energy Facility.Union Power Station.
The decrease was partially offset by:
approximately $69 million in spending related to the generator stator incident at ANO, as discussed above;
$39.6 million in storm restoration spending in 2013 resulting from the December 2012 winter storm;
$7.6 million in storm restoration spending in 2013 resulting from the December 2013 winter storm; and
money pool activity.
Increases in Entergy Arkansas’s receivable from the money pool are a use of cash flow, and Entergy Arkansas’s receivable from the money pool increased by $9.5 million in 2013 as compared to decreasing by $9.3 million in 2012.
Financing Activities
Net cash provided by financing activities increased $72.6 million in 2014 primarily due to:
activity;
the issuanceredemptions of $375$75 million of 3.70%6.45% Series first mortgage bonds in March 2014;
the retirement, at maturity, of $300preferred stock and $10 million of 5.40%6.08% Series first mortgage bondspreferred stock in August 2013;
the issuance of $90 million of 9% Series L notes by the nuclear fuel company variable interest entity in July 2014;
the issuance of $250 million of 4.95% Series first mortgage bonds in December 2014;2016; and
net short-term borrowings of $48$50 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 20142017 compared to net repayments of $36.7$11.7 million in 2013;2016.
Increases in Entergy Arkansas’s payable to the money pool are a source of cash flow, and Entergy Arkansas’s payable to the money pool increased by $114.9 million in 2017 compared to decreasing by $1.5 million in 2016. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Net cash flow provided by financing activities increased $281.8 million in 2016 primarily due to:
the net issuance of $189.1 million of long-term debt in 2016 compared to the net retirement of $13.2 million of long-term debt in 2015;
a $200 million capital contribution received from Entergy Corporation in March 2016 primarily in anticipation of Entergy Arkansas’s purchase of Power Block 2 of the Union Power Station; and
net repayments of $11.7 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2016 compared to net repayments of $36.3 million in 2015.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
the retirement, at maturity, of $30 million of 9% Series H notes by the nuclear fuel company variable interest entity in June 2013; and
a decrease of $5 million in common stock dividends paid in 2014.
The increase was partially offset by:by the redemptions of $75 million of 6.45% Series preferred stock and $10 million of 6.08% Series preferred stock in 2016 and money pool activity.
borrowings onDecreases in Entergy Arkansas’s payable to the money pool are a $250 million term loan credit facility entered into in July 2013use of cash flow, and its repayment, priorEntergy Arkansas’s payable to maturity, in March 2014;
the issuance of $250 million of 3.05% Series first mortgage bonds in May 2013;
the issuance of $125 million of 4.75% Series first mortgage bonds in June 2013;
the retirement, prior to maturity, of $115 million of 5.0% Series first mortgage bonds in April 2014; and
the retirement, at maturity, of $70 million of 5.69% Series I notesmoney pool decreased by the nuclear fuel company variable interest entity in July 2014.
Net cash provided by financing activities decreased $10.4$1.5 million in 2013 primarily due to:
the retirement, at maturity, of $30 million of 9% Series H notes by the nuclear fuel company variable interest entity in June 2013;
the retirement, at maturity, of $300 million of 5.40% Series first mortgage bonds in August 2013;
the issuance of $200 million of 4.9% Series first mortgage bonds in December 2012;
the issuance of $60 million of 2.62% Series K notes by the nuclear fuel company variable interest entity in December 2012; and
the net repayment of $36.7 million of borrowings on the nuclear fuel company variable interest entity credit facility in 20132016 compared to net borrowings of $2.8increasing by $52.7 million in 2012.
The decrease was partially offset by:
the issuance of $250 million of 3.05% Series first mortgage bonds in May 2013 and $125 million of 4.75% Series first mortgage bonds in June 2013; and
borrowings on a $250 million term loan credit facility entered into in July 2013.2015.
See Note 5 to the financial statements for further details of long-term debt.
Capital Structure
Entergy Arkansas’s capitalization is balanced between equity and debt, as shown in the following table. The
increase in the debt to capital ratio for Entergy Arkansas is primarily due to an increase in long-term debt as a result of the issuance of $375 million of 3.70% Series first mortgage bonds in March 2014.
| | | | December 31,
2014 | | December 31,
2013 | December 31,
2017 | | December 31,
2016 |
| Debt to capital | 58.4% | | 56.7% | 55.5% | | 55.3% |
| Effect of excluding the securitization bonds | (0.7%) | | (0.9%) | (0.3%) | | (0.4%) |
| Debt to capital, excluding securitization bonds (a) | 57.7% | | 55.8% | 55.2% | | 54.9% |
| Effect of subtracting cash | (2.2%) | | (1.4%) | —% | | (0.2%) |
| Net debt to net capital, excluding securitization bonds (a) | 55.5% | | 54.4% | 55.2% | | 54.7% |
| |
| (a) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Arkansas. |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratios
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because the securitization bonds are non-recourse to Entergy Arkansas, as more fully described in Note 5 to the financial statements. Entergy Arkansas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy Arkansas may receive equity contributions to maintain the targeted capital structure.
Uses of Capital
Entergy Arkansas requires capital resources for:
construction and other capital investments;
debt and preferred stock maturities or retirements;
working capital purposes, including the financing of fuel and purchased power costs; and
dividend and interest payments.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
| | | | 2015 | | 2016 | | 2017 | 2018 | | 2019 | | 2020 |
| | (In Millions) | (In Millions) |
| Planned construction and capital investment: | | | |
| | |
| | | |
| | |
|
| Generation |
| $405 |
| |
| $155 |
| |
| $235 |
|
| $190 |
| |
| $240 |
| |
| $225 |
|
| Transmission | 255 |
| | 130 |
| | 80 |
| 170 |
| | 165 |
| | 175 |
|
| Distribution | 195 |
| | 180 |
| | 165 |
| 225 |
| | 245 |
| | 225 |
|
| Other | 35 |
| | 20 |
| | 20 |
| |
| Utility Support | | 110 |
| | 85 |
| | 85 |
|
| Total |
| $890 |
| |
| $485 |
| |
| $500 |
|
| $695 |
| |
| $735 |
| |
| $710 |
|
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | 2015 | | 2016-2017 | | 2018-2019
| | after 2020 | | Total | 2018 | | 2019-2020 | | 2021-2022 | | after 2022 | | Total |
| | (In Millions) | (In Millions) |
| Long-term debt (a) |
| $105 |
| |
| $378 |
| |
| $203 |
| |
| $3,963 |
| |
| $4,649 |
|
| $125 |
| |
| $266 |
| |
| $672 |
| |
| $4,208 |
| |
| $5,271 |
|
| Operating leases |
| $28 |
| |
| $40 |
| |
| $22 |
| |
| $9 |
| |
| $99 |
|
| $17 |
| |
| $29 |
| |
| $16 |
| |
| $24 |
| |
| $86 |
|
| Purchase obligations (b) |
| $760 |
| |
| $986 |
| |
| $761 |
| |
| $1,694 |
| |
| $4,201 |
|
| $595 |
| |
| $1,050 |
| |
| $863 |
| |
| $5,369 |
| |
| $7,877 |
|
| |
| (a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
| (b) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Arkansas, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which are discussed in Note 8 to the financial statements. |
In addition to the contractual obligations given above, Entergy Arkansas currently expects to contribute approximately $92.5$64.1 million to its qualified pension plans and approximately $16.9 million$472 thousand to its other postretirement health care and life insurance plans in 2015,2018, although the 2018 required pension contributions will not be known with more certainty untilwhen the January 1, 20152018 valuations are completed, which is expected by April 1, 2015.2018. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy Arkansas has $1.9($117.7) million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes specific investments, such as the Union Power Station acquisition discussed below; NRC post-Fukushima requirements; environmental compliance spending, including potential scrubbers at White Bluff to meet pending Arkansas state requirements under the Clean Air Visibility Rule; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including investment to support advanced metering; resource planning;planning, including potential generation projects; system improvements; investments in ANO 1 and 2; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints requirements, and oversight,requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.
As a wholly-owned subsidiary,discussed above in “Capital Structure,” Entergy Arkansas paysroutinely evaluates its ability to pay dividends to Entergy Corporation from its earnings at a percentage determined monthly.earnings. Provisions in Entergy Arkansas’s long-term debt indenture restrictsarticles of incorporation relating to preferred
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
stock restrict the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock. As of December 31, 2014,
Advanced Metering Infrastructure (AMI)
In September 2016, Entergy Arkansas had restricted retained earnings unavailable for distribution tofiled an application seeking a finding from the APSC that Entergy CorporationArkansas’s deployment of $394.9 million.
Union Power Station Purchase Agreement
In December 2014,AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Gulf States Louisiana,Arkansas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $208 million. The filing identified a number of quantified and Entergy Texas entered into an asset purchase agreement to acquire the Union Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas-fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Pursuant to the agreement, Entergy Gulf States Louisiana will acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility,unquantified benefits, and Entergy Arkansas and Entergy Texas will each acquire one power block andprovided a 25% undivided ownership interest in such related assets. (If Entergy Arkansas or Entergy Texas do not obtain approval for the purchase of their power blocks, Entergy Gulf States Louisiana will seek to purchase the power blocks not approved.) The base purchase pricecost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $406 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value of existing meters, which was approximately $57 million at December 31, 2015, that will be approximately $948 million (approximately $237 million for each power block) subject to adjustments. In addition, Entergy Gulf States Louisiana anticipates selling 20%retired as part of the capacityAMI deployment and energy associated with its two power blocksalso to depreciate those assets using current depreciation rates. Entergy New Orleans throughArkansas proposed a cost-based, life-of-unit power purchase agreement. The purchase15-year depreciable life for the new advanced meters, the three-year deployment of which is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federalexpected to begin in 2019. Deployment of the communications network is expected to begin in 2018. Entergy Arkansas proposed to include the AMI deployment costs and state regulatorythe quantified benefits in future formula rate plan filings, and permitting agencies. These include regulatory approvals fromthe 2018 costs were approved in the 2017 formula rate plan filing. In June 2017 the APSC LPSC, PUCT,staff and FERC, as well as clearance underArkansas Attorney General filed direct testimony. The APSC staff generally supported Entergy Arkansas’s AMI deployment conditioned on various recommendations. The Arkansas Attorney General’s consultant primarily recommended denial of Entergy Arkansas’s application but alternatively suggested recommendations in the Hart-Scott-Rodino anti-trust law. In December 2014,event the APSC approves Entergy Texas filed its application with the PUCT for approval of the acquisition. The PUCT has indicated that it will convene the hearing on the merits of this case in June 2015. Entergy Texas intends to file a rate application to seek cost recovery later in 2015. In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC andArkansas’s proposal. Entergy Arkansas filed rebuttal testimony in June 2017, substantially accepting the APSC staff’s recommendations. In August 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement. In October 2017 the APSC issued an order finding that Entergy Arkansas’s AMI deployment is in the public interest and approving the settlement agreement subject to a minor modification. Entergy Arkansas expects to recover the undepreciated balance of its applicationexisting meters through a regulatory asset to be amortized over 15 years. Entergy Arkansas has begun discussions with the APSC, each for approvalother parties to implement the items in the settlement agreement including pre-pay and time of the acquisition and cost recovery. Closing is targeted to occur in late-2015.use programs.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt or preferred stock issuances; and
bank financing under new or existing facilities.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred stock issuances by Entergy Arkansas require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s corporate charters, bond indentures, and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2014 | | 2013 | | 2012 | | 2011 |
| (In Thousands) |
| $2,218 | | $17,531 | | $8,035 | | $17,362 |
|
| | | | | | |
| 2017 | | 2016 | | 2015 | | 2014 |
| (In Thousands) |
| ($166,137) | | ($51,232) | | ($52,742) | | $2,218 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has a credit facilitiesfacility in the amount of $20 million and $150 million scheduled to expire in August 2022. Entergy Arkansas also has a $20 million credit facility scheduled to expire in April 2015 and March 2019, respectively.2018. The $150 million credit facility allows Entergy Arkansas to issuepermits the issuance of letters of credit against 50%$5 million of the borrowing capacity of the facility. As of December 31, 2014,2017, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas entered intois a party to an uncommitted letter of credit facility in 2014 as a means to post collateral to support its obligations underto MISO. As of December 31, 2014,2017, a $2$1 million letter of credit was outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for additionalfurther discussion of the credit facilities.
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $85$80 million scheduled to expire in June 2016.May 2019. As of December 31, 2014, $482017, $50 million wasin letters of credit to support a like amount of commercial paper issued and $24.9 million in loans were outstanding onunder the Entergy Arkansas nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additionalfurther discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorizations from the FERC through October 20152019 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and long-term borrowings by its nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of Entergy Arkansas’s short-term borrowing limits. The long-term securities issuances of Entergy Arkansas are limited to amounts authorized by the APSC, and the Tennessee Regulatory Authority; the current authorizations extendauthorization extends through December 2015.2018.
In March 2014, Entergy Arkansas issued $375 million of 3.70% Series first mortgage bonds due June 2024. Entergy Arkansas used the proceeds to pay, prior to maturity, its $250 million term loan, to pay, prior to maturity, its $115 million of 5.0% Series first mortgage bonds due July 2018,State and for general corporate purposes.Local Rate Regulation and Fuel-Cost Recovery
Retail Rates
2015 Base Rate Filing
In July 2014 theApril 2015, Entergy Arkansas nuclear fuel trust variable interest entity issued $90filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In September 2015 the APSC staff and intervenors filed direct testimony, with the APSC staff recommending a revenue requirement of $217.9 million and a 9.65% return on common equity. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity. A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of 3.65% Series L notes due July 2021.previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. A settlement hearing was held in January 2016. In February 2016 the APSC approved the settlement with one exception that reduced the retail rate increase proposed in the settlement by $5 million. The settling parties agreed to the APSC modifications in February 2016. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. In March 2016, Entergy Arkansas nuclear fuel trust variable interest entity usedmade a compliance filing regarding the proceeds to pay, at maturity, its $70 million of 5.69% Series I notes due July 2014 and to purchase additional nuclear fuel.
In December 2014, Entergy Arkansas issued $250 million of 4.95% Series first mortgage bonds due December 2044. Entergy Arkansas used the proceeds for general corporate purposes.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
State and Local Rate Regulation and Fuel-Cost Recoverynew rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.
Retail Rates
2013 Base2016 Formula Rate Plan Filing
In March 2013,July 2016, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. Theits 2016 formula rate plan filing assumedshowing Entergy Arkansas’s transitionprojected earned return on common equity for the twelve months ended December 31, 2017 test period to MISO in December 2013, and requested abe below the formula rate increase of $174 million, including $49 million of revenue being transferred from collection in riders to base rates. The filing also proposed a new transmission rider and a capacity cost recovery rider.plan bandwidth. The filing requested a 10.4% return on common equity. In September 2013,$67.7 million revenue requirement increase to achieve Entergy Arkansas filed testimony reflecting an updated rate increase request of $145 million, with no change to its requestedArkansas’s target earned return on common equity of 10.4%9.75%. Hearings in the proceeding began inIn October 2013, and in December 2013 the APSC issued an order. The order authorized a base rate increase of $81 million and included an authorized return on common equity of 9.3%. The order allows Entergy Arkansas to amortize its human capital management costs over a three-and-a-half year period, but also orders Entergy Arkansas to file a detailed report of the Arkansas-specific costs, savings and final payroll changes upon conclusion of the human capital management strategic imperative. The detailed report was subsequently filed in February 2015. The substance of the report will be addressed in Entergy Arkansas’s next base rate filing. New rates were implemented in the first billing cycle of March 2014, effective as of January 2014. Additionally, in January 2014, Entergy Arkansas filed a petition for rehearing or clarification of several aspects of the APSC’s order, including the 9.3% authorized return on common equity. In February 2014 the APSC granted Entergy Arkansas’s petition for the purpose of considering the additional evidence identified by Entergy Arkansas. In August 2014 the APSC issued an order amending certain aspects of the original order, including providing for a 9.5% authorized return on common equity. Pursuant to the August 2014 order, revised rates are effective for all bills rendered after December 31, 2013 and were implemented in the first billing cycle of October 2014.
On January 30, 2015,2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved the settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017. In April 2017, Entergy Arkansas filed a motion consented to by all parties requesting that it be permitted to submit the supplemental information requested by the APSC in conjunction with its 2017 formula rate plan filing, which was subsequently made in July 2017 and is discussed below. In May 2017 the APSC approved the joint motion and proposal to review Entergy Arkansas’s supplemental information on a concurrent schedule with the 2017 formula rate plan filing. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the docket and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and recovery of the 2017 and 2018 nuclear costs.
2017 Formula Rate Plan Filing
In July 2017, Entergy Arkansas filed with the APSC its 2017 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2018 test period to be below the formula rate plan bandwidth. The filing projected a $129.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. Entergy Arkansas’s formula rate plan is subject to a four percent annual revenue constraint and the projected annual revenue requirement increase exceeded the four percent, resulting in a proposed increase for the 2017 formula rate plan of $70.9 million. In October 2017, Entergy Arkansas filed with the APSC revised formula rate plan attachments that projected a $126.2 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors. The revised formula rate plan filing included a proposed $71.1 million revenue requirement increase based on a revision to the four percent constraint calculation. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the docket and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and the $71.1 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2018.
Internal Restructuring
In November 2017, Entergy Arkansas filed an application with the APSC seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy Arkansas to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. The restructuring is subject to regulatory review and approval by the APSC, the FERC, and the NRC. Entergy Arkansas also filed a notice with the Missouri Public Service Commission in December 2017 out of intent to file a rate case within 60 to 90 days.an abundance of caution, although
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas does not serve any retail customers in Missouri. If the APSC approves the restructuring by September 1, 2018, and the restructuring closes on or before December 1, 2018, Entergy Arkansas proposed in its application to credit retail customers $66 million over six years, beginning in 2019. In February 2018, Entergy Arkansas filed supplemental testimony reducing the proposed retail customer credits to $39.6 million over six years. If the APSC, the FERC, and the NRC approvals are obtained, Entergy Arkansas expects the restructuring will be consummated on or before December 1, 2018.
It is currently contemplated that Entergy Arkansas would undertake a multi-step restructuring, which would include the following:
Entergy Arkansas would redeem its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million, which includes call premiums, plus accumulated and unpaid dividends, if any.
Entergy Arkansas would convert from an Arkansas corporation to a Texas corporation.
Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas will allocate substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power will assume substantially all of the liabilities of Entergy Arkansas, in a transaction regarded as a merger under the TXBOC. Entergy Arkansas will remain in existence and hold the membership interests in Entergy Arkansas Power.
Entergy Arkansas will contribute the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power will be a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
Entergy Arkansas will change its name to Entergy Utility Property, Inc., and Entergy Arkansas Power will then change its name to Entergy Arkansas, LLC.
Upon the completion of the restructuring, Entergy Arkansas, LLC will hold substantially all of the assets, and will have assumed substantially all of the liabilities, of Entergy Arkansas. Entergy Arkansas may modify or supplement the steps to be taken to effectuate the restructuring.
Production Cost Allocation Rider
The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings.proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below. These costs cause an increase in Entergy Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects themthe costs from customers over twelve months. See Note 2 to the financial statements and Entergy Corporation and Subsidiaries “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS -System Agreement” for discussions of the System Agreement proceedings.
In May 2014, Entergy Arkansas filed its annual redetermination of the production cost allocation rider to recover the $3 million unrecovered retail balance as of December 31, 2013 and the $67.8 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. In June 2014 the APSC suspended the annual redetermination of the production cost allocation rider and scheduled a hearing in September 2014. Upon a joint motion of the parties, the APSC canceled the September 2014 hearing and in January 2015 the APSC issued an order approving Entergy Arkansas’s request for recovery of the $3 million under-recovered amount based on the true-up of the production cost allocation rider and the $67.8 million May 2014 System Agreement bandwidth remedy payment subject to refund with interest, with recovery of these payments concluding with the last billing cycle in December 2015. The APSC also found that Entergy Arkansas is entitled to carrying charges pursuant to the current terms of the production cost allocation rider. Entergy Arkansas made its compliance filing pursuant to the order in January 2015 and the APSC issued its approval order, also in January 2015. The redetermined rate went into effect with the first billing cycle of February 2015.
In May 2015, Entergy Arkansas filed its annual redetermination of the production cost allocation rider, which included a $38 million payment made by Entergy Arkansas as a result of the FERC’s February 2014 order related to the comprehensive bandwidth recalculation for calendar year 2006, 2007, and 2008 production costs. The redetermined rate for the 2015 production cost allocation rider update was added to the redetermined rate from the 2014 production
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
cost allocation rider update and the combined rate was effective with the first billing cycle of July 2015. This combined rate was effective through December 2015. The collection of the remainder of the redetermined rate for the 2015 production cost allocation rider update continued through June 2016.
In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update became effective with the first billing cycle of July 2016, and the rates were effective through June 2017.
In May 2017, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected recovery of the production cost allocation rider true-up adjustment of the 2016 unrecovered retail balance in the amount of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over- or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
In October 2005 the APSC initiated an investigation into Entergy Arkansas’s interim energy cost recovery rate. The investigation focused on Entergy Arkansas’s 1) gas contracting, portfolio, and hedging practices; 2) wholesale purchases during the period; 3) management of the coal inventory at its coal generation plants; and 4) response to the contractual failure of the railroads to provide coal deliveries. In March 2006 the APSC extended its investigation to cover the costs included in Entergy Arkansas’s March 2006 annual energy cost rate filing, and a hearing was held in the APSC investigation in October 2006.
In January 2007 the APSC issued an order in its review of the energy cost rate. The APSC found that Entergy Arkansas failed to maintain an adequate coal inventory level going into the summer of 2005 and that Entergy Arkansas should be responsible for any incremental energy costs that resulted from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas has since resolved litigation with the railroad regarding the delivery problems. The APSC staff was directed to perform an analysis with Entergy Arkansas’s assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within sixty days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas will be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider. Entergy Arkansas requested rehearing of the order.
In February 2010 the APSC denied Entergy Arkansas’s request for rehearing, and held a hearing in September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas. A decision is pending. Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.
The APSC also established a separate docket to consider the resolved railroad litigation, and in February 2010 it established a procedural schedule that concluded with testimony through September 2010. The testimony has been filed, and the APSC will decide the case based on the record in the proceeding.
In January 2014, Entergy Arkansas filed a motion with the APSC relating to its redetermination of its energy cost rate to bethat was subsequently filed in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude $65.9 million of deferred fuel and purchased energy costs incurred in 2013 from the redetermination of its 2014 energy cost rate. The $65.9 million is an estimate of the incremental fuel and replacement energy costs that Entergy Arkansas incurred as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information is available regarding various claims associated with the ANO stator incident. The APSC approved Entergy Arkansas’s request in February 2014. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a proceeding for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs previously noted, subject to certain timelines and conditions set forth in the settlement agreement. See the “ANO Damage, Outage, and NRC Reviews” section abovein Note 8 to the financial statements for further discussion of the ANO stator incident.
Storm Cost RecoveryIn March 2017, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01164 per kWh to $0.01547 per kWh. The APSC staff filed testimony in March 2017 recommending that the redetermined rate be implemented with the first billing cycle of April 2017 under the normal operation of the tariff. Accordingly, the redetermined rate went into effect on March 31, 2017 pursuant to the tariff. In July 2017 the Arkansas Attorney General requested additional information to support certain of the costs included in Entergy Arkansas’s 2017 energy cost rate redetermination.
Entergy Arkansas December 2012 Winter Storm
In December 2012 a severe winter storm consisting of ice, snow, and high winds caused significant damage to Entergy Arkansas’s distribution lines, equipment, poles, and other facilities. Total restoration costs for the repair and/or replacement of Entergy Arkansas’s electrical facilities in areas damaged from the winter storm were $63 million,
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
including costs recorded as regulatory assets of approximately $22 million. In the Entergy Arkansas 2013 rate case, the APSC approved inclusion of the construction spending in rate base and approved an increase in the normal storm cost accrual, which will effectively amortize the regulatory asset over a five-year period.
Opportunity Sales Proceeding
In June 2009 the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocateallocated the energy generated by Entergy System resources, (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity, and (c) violated the provision of the System Agreement that prohibitsprohibited sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challengeschallenged sales made beginning in 2002 and requests refunds. In July 2009 the Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System. In their response, the Utility operating companies explained that the System Agreement clearly contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The response further explained thatFERC subsequently ordered a hearing in the FERC already had determined that Entergy Arkansas’s short-term wholesale sales did not trigger the “right-of-first-refusal” provision of the System Agreement. While the D.C. Circuit recently determined that the “right-of-first-refusal” issue was not properly before the FERC at the time of its earlier decision on the issue, the LPSC raised no additional claims or facts that would warrant the FERC reaching a different conclusion.proceeding.
The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies’ customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies’ customers and these customers should be compensated for this harm by Entergy. In subsequent testimony, the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills. The Utility operating companies believe the LPSC’s allegations are without merit. A hearing in the matter was held in August 2010.
In December 2010 the ALJ issued an initial decision. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load, but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. Quantifying the effect of the FERC’s decision will requirerequires re-running intra-system bills for a ten-year period, and the FERC in its decision established further hearing procedures to determine the calculation of the effects. In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision, which are pending with the FERC.
As required by the procedural schedule established in the calculation proceeding, Entergy filed its direct testimony that included a proposed illustrative re-run, consistent with the directives in FERC’s order, of intra-system bills for 2003, 2004, and 2006, the three years with the highest volume of opportunity sales. Entergy’s proposed illustrative re-run of intra-system bills shows that the potential cost for Entergy Arkansas would be up to $12 million
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
for the years 2003, 2004, and 2006, excluding interest, and the potential benefit would be significantly less than that for each of the other Utility operating companies. Entergy’s proposed illustrative re-run of the intra-system bills also shows an offsetting potential benefit to Entergy Arkansas for the years 2003, 2004, and 2006 resulting from the effects of the FERC’s order on System Agreement Service Schedules MSS-1, MSS-2, and MSS-3, and the potential offsetting cost would be significantly less than that for each of the other Utility operating companies. Entergy provided to the LPSC an illustrative intra-system bill recalculation as specified by the LPSC for the years 2003, 2004, and 2006, and the LPSC then filed answering testimony in December 2012. In its testimony the LPSC claims that the damages, excluding interest, that should be paid by Entergy Arkansas to the other Utility operating company’s customers for 2003, 2004, and 2006 are $42 million to Entergy Gulf States, Inc., $7 million to Entergy Louisiana, $23 million to Entergy Mississippi, and $4 million to Entergy New Orleans. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. In April 2013, Entergy filed its rebuttal testimony in that proceeding, including a revised illustrative re-run of the intra-system bills for the years 2003, 2004, and 2006. The revised calculation determines the re-pricing of the opportunity sales based on consideration of moveable resources only and the removal of exchange energy received by Entergy Arkansas, which increases the potential cost for Entergy Arkansas over the three years 2003, 2004, and 2006 by $2.3 million from the potential costs identified in the Utility operating companies’ prior filings in September and October 2012.decision. A hearing was held in May 2013 to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision.
In August 2013 the presiding judge issued an initial decision in the calculation proceeding. The initial decision concludesconcluded that the methodology proposed by the LPSC, rather than the methodologies proposed by Entergy or the FERC Staff, should be used to calculate the payments that Entergy Arkansas is to make to the other Utility operating companies. The initial decision also concludesconcluded that the other System Agreement service schedules should not be adjusted and that payments by Entergy Arkansas should not be reflected in the rough production cost equalization bandwidth calculations for the applicable years. The initial decision does recognizerecognized that the LPSC’s methodology would result in an inequitable windfall to the other Utility operating companies and, therefore, concludesconcluded that any payments by Entergy Arkansas should be reduced by 20%. The Utility operating companies are currently analyzing the effects of the initial decision. The LPSC, APSC, City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that the FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
In April 2016 the FERC issued orders addressing requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denied Entergy’s request for rehearing and affirmed the FERC’s earlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s August 2013 initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed, but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account, but ordered further proceedings before an ALJ to address whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.
In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order arguing that payments made by Entergy Arkansas should be reduced as a result of the timing of the LPSC’s approval of certain contracts. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. In September 2017 the FERC issued an order denying the request for rehearing on the issue of whether any payments by Entergy Arkansas to the other Utility operating companies should be reduced due to the timing of the LPSC’s approval of Entergy Arkansas’s wholesale baseload contract with Entergy Louisiana. In November 2017 the FERC issued an order denying all of the remaining requests for rehearing of the April 2016 order. In November 2017, Entergy Services filed a petition for review in the D.C. Circuit of the FERC’s orders in the first two phases of the opportunity sales case. In December 2017 the D.C. Circuit granted Entergy Services’s request to hold the appeal in abeyance pending final resolution of the related proceeding still pending with the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services’s appeal and held all of the appeals in abeyance.
Pursuant to the procedural schedule established in the case, Entergy Services re-ran intra-system bills for the ten-year period 2000-2009 to quantify the effects of the FERC's ruling. In November 2016 the LPSC submitted testimony disputing certain aspects of the calculations. A hearing was held in May 2017. In July 2017, the ALJ issued an initial decision concluding that Entergy Arkansas should pay $86 million plus interest to the other Utility operating companies. In August 2017 the Utility operating companies, the LPSC, the APSC, and FERC staff filed individual briefs on exceptions challenging various aspects of the initial decisiondecision. In September 2017 the Utility operating companies, the LPSC, the APSC, the MPSC, the City Council, and FERC staff filed separate briefs opposing exceptions taken by various parties. The case is pending.pending before the FERC. No payments will be made or received by the Utility operating companies until the FERC issues an order reviewing the initial decision and Entergy submits a subsequent filing to comply with that order.
The effect of the FERC’s decisions thus far in the case would be that Entergy Arkansas will make payments to some or all of the other Utility operating companies. Because further proceedings will still occur in the case, the amount and recipients of payments by Entergy Arkansas are unknown at this time. Based on testimony previously submitted in the case and its assessment of the April 2016 FERC orders, in the first quarter 2016, Entergy Arkansas recorded a liability of $87 million, which includes interest, for its estimated increased costs and payment to the other Utility operating companies. This estimate is subject to change depending on how the FERC resolves the issues that are still outstanding in the case, including its review of the July 2017 initial decision. Entergy Arkansas’s increased costs will be attributed to Entergy Arkansas’s retail and wholesale businesses, and it is not probable that Entergy Arkansas will recover the wholesale portion. Entergy Arkansas, therefore, recorded a deferred fuel regulatory asset in the first quarter 2016 of approximately $75 million, which represents its estimate of the retail portion of the costs. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in November 2017
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
described above, in the fourth quarter 2017, Entergy Arkansas recorded an additional liability of $35 million and a regulatory asset of $31 million. Because management currently expects to recover the retail portion of the costs through a base rate proceeding or newly proposed rider, the regulatory asset is reflected as Other regulatory assets as of December 31, 2017.
Federal Regulation
See “Entergy’s Integration Into the MISO Regional Transmission Organization,” “System Agreement,” and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of these topics.federal regulation.
Nuclear Matters
Entergy Arkansas owns and, operates, through an affiliate, operates the ANO 1 and ANO 2 nuclear power plants. Entergy Arkansas is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks fromrelated to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, to position Entergy’s nuclear fleet to meet its operational goals, including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems and the Fukushima event; regulatory requirementrequirements and potential future regulatory changes, including changes resulting from events at other plants,affecting the regulations governing nuclear plant ownership, operations, license renewal and amendments, and decommissioning; the performance and capacity factors of these nuclear plants; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts and types of insurance commercially available for losses in connection with nuclear plant operations and technological and financial uncertainties related to decommissioningcatastrophic events such as a nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts.accident. In the event of an unanticipated early shutdown of either ANO 1 or ANO 2, Entergy Arkansas may be required to file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.
Entergy Arkansas, Inc.the NRC’s decision in March 2015 to move ANO into the “multiple/repetitive degraded cornerstone column,” or Column 4, of the NRC’s Reactor Oversight Process Action Matrix, and Subsidiaries
Management’s Financial Discussion and Analysis
The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system. The issue is applicable to ANO and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issuesresulting significant additional NRC inspection activities at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.ANO site.
After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators to undertake plant modifications and perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating nuclear plants. The NRC, with input from the industry, is continuing to determine the specific actions required by the orders. Entergy Arkansas’s estimated capital expenditures for 2015 through 2017 for complying with the NRC orders are included in the planned construction and other capital investments estimates given in “Liquidity and Capital Resources - Uses of Capital” above.
Environmental Risks
Entergy Arkansas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations.operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Arkansas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Arkansas’s financial position or results of operations.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
In 2014, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study. The revised estimates resulted in a $47.6 million increaseUtility Regulatory Accounting
See “Utility Regulatory Accounting” in the decommissioning cost liabilities, along with a corresponding increase in“Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the related asset retirement cost assets that will be depreciated over the remaining liveseffects of the units.rate regulation.
Unbilled Revenue
As discussedSee “Unbilled Revenue” in Note 1 to the financial statements,“Critical Accounting Estimates” section of Entergy Arkansas records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of the
Entergy Arkansas, Inc.Corporation and Subsidiaries
Management’s Financial Discussion and Analysis for discussion of the estimates associated with the unbilled revenue amounts.
Impairment of Long-lived Assets and Trust Fund Investments
unbilled receivable atSee “Impairment of Long-lived Assets and Trust Fund Investments” in the beginning“Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the periodestimates associated with the impairment of long-lived assets and trust fund investments.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the end“Critical Accounting Estimates” section of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled periodEntergy Corporation and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated priceSubsidiaries Management’s Financial Discussion and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Arkansas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost SensitivityCosts and Sensitivities
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | Actuarial Assumption | | Change in Assumption | | Impact on 2014 Qualified Pension Cost | | Impact on 2014 Qualified Projected Benefit Obligation | | Change in Assumption | | Impact on 2018 Qualified Pension Cost | | Impact on 2017 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $3,172 | | $51,882 | | (0.25%) | | $3,107 | | $47,040 |
| Rate of return on plan assets | | (0.25%) | | $2,153 | | $— | | (0.25%) | | $2,914 | | $- |
| Rate of increase in compensation | | 0.25% | | $1,238 | | $7,401 | | 0.25% | | $1,353 | | $6,446 |
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | Actuarial Assumption | | Change in Assumption | | Impact on 2014 Postretirement Benefit Cost | | Impact on 2014 Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2018 Postretirement Benefit Cost | | Impact on 2017 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $749 | | $10,813 | | (0.25%) | | $506 | |
| $7,552 |
|
| Health care cost trend | | 0.25% | | $1,276 | | $9,378 | | 0.25% | | $782 | |
| $5,513 |
|
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension cost for Entergy Arkansas in 20142017 was $42.4$37 million. Entergy Arkansas anticipates 20152018 qualified pension cost to be $62.7$43 million. In 2016, Entergy Arkansas refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $13.3 million. Entergy Arkansas contributed $95.5$79.6 million to its qualified pension plan in 20142017 and estimates 2015 pension contributions towill be approximately $92.5$64.1 million in 2018, although the 2018 required pension contributions will not be known with more certainty untilwhen the January 1, 20152018 valuations are completed, which is expected by April 1, 2015.2018.
Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 20142017 was $2.1$4 million. Entergy Arkansas expects 20152018 postretirement health care and life insurance benefit costsincome of approximately
$10.2 million. In 2016, Entergy Arkansas Inc.refined its approach to estimating the service cost and Subsidiaries
Management’s Financial Discussion and Analysis
$3.2interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $2.5 million. Entergy Arkansas contributed $15.3 million$695 thousand to its other postretirement plans in 20142017 and expects to contributeestimates 2018 contributions will be approximately $16.9 million in 2015.$472 thousand.
The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $106.9 million in the qualified pension benefit obligation and $16 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $15.4 million and other postretirement cost by approximately $2.2 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.
Federal Healthcare Legislation
See the “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and AnalysisNote 1 to the financial statements for further discussion.a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors and Shareholders of
Entergy Arkansas, Inc. and Subsidiaries
Little Rock, Arkansas
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Arkansas, Inc. and Subsidiaries (the “Company”) as of December 31, 20142017 and 2013, and2016, the related consolidated income statements, consolidated statements of income, cash flows and consolidated statements of changes in common equity (pages 316319 through 320324 and applicable items in page 61pages 55 through 234)230), for each of the three years in the period ended December 31, 2014. 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on thesethe Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Anmisstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit includesof its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements. An auditOur audits also includes assessingincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Arkansas, Inc. and Subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 20152018
We have served as the Company’s auditor since 2001.
315
| | ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | CONSOLIDATED INCOME STATEMENTS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | | | | |
| Electric | |
| $2,172,391 |
| |
| $2,190,159 |
| |
| $2,127,004 |
| |
| $2,139,919 |
| |
| $2,086,608 |
| |
| $2,253,564 |
|
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
| | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 327,695 |
| | 426,316 |
| | 480,464 |
| | 402,777 |
| | 325,036 |
| | 535,919 |
|
| Purchased power | | 528,815 |
| | 473,326 |
| | 431,932 |
| | 230,652 |
| | 233,350 |
| | 380,081 |
|
| Nuclear refueling outage expenses | | 43,258 |
| | 40,499 |
| | 47,103 |
| | 83,968 |
| | 56,650 |
| | 51,411 |
|
| Other operation and maintenance | | 647,461 |
| | 592,892 |
| | 545,782 |
| | 707,825 |
| | 706,573 |
| | 734,118 |
|
| Decommissioning | | 46,972 |
| | 43,058 |
| | 40,484 |
| | 56,860 |
| | 53,610 |
| | 50,414 |
|
| Taxes other than income taxes | | 91,470 |
| | 89,471 |
| | 89,527 |
| | 103,662 |
| | 93,109 |
| | 99,926 |
|
| Depreciation and amortization | | 236,770 |
| | 230,512 |
| | 222,734 |
| | 277,146 |
| | 264,215 |
| | 246,897 |
|
| Other regulatory credits - net | | (20,054 | ) | | (10,975 | ) | | (38,406 | ) | |
| Other regulatory charges (credits) - net | | | (16,074 | ) | | 7,737 |
| | (24,608 | ) |
| TOTAL | | 1,902,387 |
| | 1,885,099 |
| | 1,819,620 |
| | 1,846,816 |
| | 1,740,280 |
| | 2,074,158 |
|
| | | | | | | | | | | | | |
| OPERATING INCOME | | 270,004 |
| | 305,060 |
| | 307,384 |
| | 293,103 |
| | 346,328 |
| | 179,406 |
|
| | | | | | | | | | | | | |
| OTHER INCOME | | |
| | |
| | |
| | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 7,238 |
| | 10,913 |
| | 9,070 |
| | 18,452 |
| | 17,099 |
| | 14,227 |
|
| Interest and investment income | | 23,075 |
| | 30,148 |
| | 15,169 |
| | 35,882 |
| | 19,087 |
| | 22,382 |
|
| Miscellaneous - net | | (5,144 | ) | | (4,275 | ) | | (4,049 | ) | | (299 | ) | | (1,446 | ) | | (3,385 | ) |
| TOTAL | | 25,169 |
| | 36,786 |
| | 20,190 |
| | 54,035 |
| | 34,740 |
| | 33,224 |
|
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest expense | | 93,921 |
| | 91,318 |
| | 82,860 |
| | 122,075 |
| | 115,311 |
| | 105,622 |
|
| Allowance for borrowed funds used during construction | | (3,769 | ) | | (3,207 | ) | | (2,457 | ) | | (8,585 | ) | | (9,228 | ) | | (7,805 | ) |
| TOTAL | | 90,152 |
| | 88,111 |
| | 80,403 |
| | 113,490 |
| | 106,083 |
| | 97,817 |
|
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 205,021 |
| | 253,735 |
| | 247,171 |
| | 233,648 |
| | 274,985 |
| | 114,813 |
|
| | | | | | | | | | | | | |
| Income taxes | | 83,629 |
| | 91,787 |
| | 94,806 |
| | 93,804 |
| | 107,773 |
| | 40,541 |
|
| | | | | | | | | | | | | |
| NET INCOME | | 121,392 |
| | 161,948 |
| | 152,365 |
| | 139,844 |
| | 167,212 |
| | 74,272 |
|
| | | | | | | | | | | | | |
| Preferred dividend requirements | | 6,873 |
| | 6,873 |
| | 6,873 |
| | 1,428 |
| | 5,270 |
| | 6,873 |
|
| | | | | | | | | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | |
| $114,519 |
| |
| $155,075 |
| |
| $145,492 |
| |
| $138,416 |
| |
| $161,942 |
| |
| $67,399 |
|
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
(Page left blank intentionally)
| | ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| For the Years Ended December 31, |
| For the Years Ended December 31, |
| |
| 2014 |
| 2013 |
| 2012 |
| 2017 |
| 2016 |
| 2015 |
| |
| (In Thousands) |
| (In Thousands) |
| OPERATING ACTIVITIES | | | | | | | | | | | | |
| Net income | |
| $121,392 |
| |
| $161,948 |
| |
| $152,365 |
| |
| $139,844 |
| |
| $167,212 |
| |
| $74,272 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 387,945 |
| | 357,639 |
| | 357,913 |
| | 427,394 |
| | 414,933 |
| | 400,156 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 130,132 |
| | 130,707 |
| | (67,482 | ) | | 67,711 |
| | 201,219 |
| | (4,330 | ) |
| Changes in assets and liabilities: | | |
| | |
| | |
| | |
| | |
| | |
|
| Receivables | | 25,661 |
| | (26,320 | ) | | (30,786 | ) | | (23,397 | ) | | (39,118 | ) | | 20,813 |
|
| Fuel inventory | | (9,394 | ) | | 7,471 |
| | (68 | ) | | 3,402 |
| | 29,929 |
| | (11,791 | ) |
| Accounts payable | | (120,097 | ) | | 141,041 |
| | (179,009 | ) | | 16,011 |
| | 143,645 |
| | (2,528 | ) |
| Prepaid taxes and taxes accrued | | 14,261 |
| | (204,990 | ) | | 178,688 |
| | 40,127 |
| | 37,485 |
| | (54,531 | ) |
| Interest accrued | | (1,786 | ) | | (6,382 | ) | | (1,463 | ) | | 1,635 |
| | (3,303 | ) | | (367 | ) |
| Deferred fuel costs | | (140,483 | ) | | 28,609 |
| | 112,471 |
| | 33,190 |
| | (105,741 | ) | | 151,332 |
|
| Other working capital accounts | | 72,411 |
| | (34,909 | ) | | 55,735 |
| | 15,087 |
| | (46,490 | ) | | (44,784 | ) |
| Provisions for estimated losses | | (57 | ) | | (76 | ) | | 182 |
| | 16,047 |
| | 13,130 |
| | (137 | ) |
| Other regulatory assets | | (367,234 | ) | | 214,131 |
| | (88,119 | ) | | (76,762 | ) | | (95,464 | ) | | 60,279 |
|
| Other regulatory liabilities | | | 1,043,507 |
| | 62,994 |
| | (11,123 | ) |
| Deferred tax rate change recognized as regulatory liability/asset | | | (1,047,837 | ) | | — |
| | — |
|
| Pension and other postretirement liabilities | | 252,639 |
| | (295,435 | ) | | 75,725 |
| | (70,826 | ) | | (36,805 | ) | | (110,936 | ) |
| Other assets and liabilities | | 38,436 |
| | (72,184 | ) | | (57,035 | ) | | (29,577 | ) | | (67,115 | ) | | 8,565 |
|
| Net cash flow provided by operating activities | | 403,826 |
| | 401,250 |
| | 509,117 |
| | 555,556 |
| | 676,511 |
| | 474,890 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Construction expenditures | | (535,464 | ) | | (489,079 | ) | | (361,858 | ) | | (735,816 | ) | | (666,289 | ) | | (624,546 | ) |
| Allowance for equity funds used during construction | | 10,789 |
| | 14,550 |
| | 12,441 |
| | 19,211 |
| | 17,754 |
| | 15,882 |
|
| Nuclear fuel purchases | | (195,092 | ) | | (88,637 | ) | | (215,968 | ) | | (151,424 | ) | | (102,050 | ) | | (132,252 | ) |
| Proceeds from sale of nuclear fuel | | 75,860 |
| | 36,478 |
| | 96,700 |
| | 51,029 |
| | 39,313 |
| | 52,281 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 181,489 |
| | 266,391 |
| | 144,275 |
| | 339,434 |
| | 197,390 |
| | 212,954 |
|
| Investment in nuclear decommissioning trust funds | | (190,062 | ) | | (274,519 | ) | | (154,608 | ) | | (352,138 | ) | | (213,093 | ) | | (223,357 | ) |
| Payment for purchase of plant | | — |
| | — |
| | (253,043 | ) | | — |
| | (237,323 | ) | | — |
|
| Change in money pool receivable - net | | 15,313 |
| | (9,496 | ) | | 9,327 |
| |
| Changes in securitization account | | (261 | ) | | 568 |
| | (514 | ) | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | — |
| | 10,271 |
| | — |
| |
Counterparty collateral deposit
| | — |
| | 9,000 |
| | — |
| |
| Changes in money pool receivable - net | | | — |
| | — |
| | 2,218 |
|
| Insurance proceeds | | 36,600 |
| | — |
| | — |
| | — |
| | 10,404 |
| | 11,654 |
|
| Other | | 200 |
| | — |
| | — |
| | 392 |
| | 5,899 |
| | (108 | ) |
| Net cash flow used in investing activities | | (600,628 | ) |
| (524,473 | ) |
| (723,248 | ) | | (829,312 | ) |
| (947,995 | ) |
| (685,274 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 707,465 |
| | 716,595 |
| | 252,347 |
| | 294,656 |
| | 817,563 |
| | — |
|
| Retirement of long-term debt | | (447,815 | ) | | (442,302 | ) | | (12,230 | ) | | (175,560 | ) | | (628,433 | ) | | (13,234 | ) |
| Capital contribution from parent | | | — |
| | 200,000 |
| | — |
|
| Redemption of preferred stock | | | — |
| | (85,283 | ) | | — |
|
| Change in money pool payable - net | | | 114,905 |
| | (1,510 | ) | | 52,742 |
|
| Changes in short-term borrowings - net | | 47,968 |
| | (36,735 | ) | | 2,821 |
| | 49,974 |
| | (11,690 | ) | | (36,278 | ) |
| Dividends paid: | | |
| | |
| | |
| | |
| | |
| | |
|
| Common stock | | (10,000 | ) | | (15,000 | ) | | (10,000 | ) | | (15,000 | ) | | — |
| | — |
|
| Preferred stock | | (6,873 | ) | | (6,873 | ) | | (6,873 | ) | | (1,428 | ) | | (6,631 | ) | | (6,873 | ) |
| Other | | (2,460 | ) | | 27 |
| | — |
| | (8,084 | ) | | (1,158 | ) | | 4,657 |
|
| Net cash flow provided by financing activities | | 288,285 |
| | 215,712 |
| | 226,065 |
| | 259,463 |
| | 282,858 |
| | 1,014 |
|
| Net increase in cash and cash equivalents | | 91,483 |
| | 92,489 |
| | 11,934 |
| |
| Net increase (decrease) in cash and cash equivalents | | | (14,293 | ) | | 11,374 |
| | (209,370 | ) |
| Cash and cash equivalents at beginning of period | | 127,022 |
| | 34,533 |
| | 22,599 |
| | 20,509 |
| | 9,135 |
| | 218,505 |
|
| Cash and cash equivalents at end of period | |
| $218,505 |
| |
| $127,022 |
| |
| $34,533 |
| |
| $6,216 |
| |
| $20,509 |
| |
| $9,135 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | |
| | |
| | | | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $90,285 |
| |
| $92,353 |
| |
| $79,271 |
| |
| $115,162 |
| |
| $112,912 |
| |
| $100,435 |
|
| Income taxes | |
| ($48,948 | ) | |
| $184,592 |
| |
| ($20,480 | ) | |
| ($8,141 | ) | |
| ($135,709 | ) | |
| $103,296 |
|
| See Notes to Financial Statements. |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| | ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | CONSOLIDATED BALANCE SHEETS | ASSETS | | | | | | |
| | | December 31, | | December 31, |
| | | 2014 | | 2013 | | 2017 | | 2016 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT ASSETS | | | | | | | | |
| Cash and cash equivalents: | | | | | | | | |
| Cash | |
| $10,526 |
| |
| $4,181 |
| |
| $6,184 |
| |
| $20,174 |
|
| Temporary cash investments | | 207,979 |
| | 122,841 |
| | 32 |
| | 335 |
|
| Total cash and cash equivalents | | 218,505 |
| | 127,022 |
| | 6,216 |
| | 20,509 |
|
| Securitization recovery trust account | | 4,096 |
| | 3,835 |
| | 3,748 |
| | 4,140 |
|
| Accounts receivable: | | |
| | |
| | |
| | |
|
| Customer | | 97,314 |
| | 102,328 |
| | 110,016 |
| | 102,229 |
|
| Allowance for doubtful accounts | | (32,247 | ) | | (30,113 | ) | | (1,063 | ) | | (1,211 | ) |
| Associated companies | | 32,187 |
| | 68,875 |
| | 38,765 |
| | 35,286 |
|
| Other | | 110,269 |
| | 94,256 |
| | 65,209 |
| | 58,153 |
|
| Accrued unbilled revenues | | 80,704 |
| | 82,298 |
| | 105,120 |
| | 100,193 |
|
| Total accounts receivable | | 288,227 |
| | 317,644 |
| | 318,047 |
| | 294,650 |
|
| Accumulated deferred income taxes | | 21,533 |
| | 33,556 |
| |
| Deferred fuel costs | | 143,279 |
| | 68,696 |
| | 63,302 |
| | 96,690 |
|
| Fuel inventory - at average cost | | 50,898 |
| | 41,504 |
| | 29,358 |
| | 32,760 |
|
| Materials and supplies - at average cost | | 162,792 |
| | 152,429 |
| | 192,853 |
| | 182,600 |
|
| Deferred nuclear refueling outage costs | | 29,690 |
| | 31,135 |
| | 56,485 |
| | 81,313 |
|
| System agreement cost equalization | | — |
| | 30,000 |
| |
| Prepayments and other | | 9,588 |
| | 58,911 |
| | 12,108 |
| | 14,293 |
|
| TOTAL | | 928,608 |
| | 864,732 |
| | 682,117 |
| | 726,955 |
|
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
| | |
| | |
|
| Decommissioning trust funds | | 769,883 |
| | 710,913 |
| | 944,890 |
| | 834,735 |
|
| Other | | 14,170 |
| | 30,845 |
| | 3,160 |
| | 7,912 |
|
| TOTAL | | 784,053 |
| | 741,758 |
| | 948,050 |
| | 842,647 |
|
| | | | | | | | | |
| UTILITY PLANT | | |
| | |
| | |
| | |
|
| Electric | | 9,139,181 |
| | 8,798,458 |
| | 11,059,538 |
| | 10,488,060 |
|
| Property under capital lease | | 961 |
| | 1,064 |
| | — |
| | 716 |
|
| Construction work in progress | | 284,322 |
| | 209,036 |
| | 280,888 |
| | 304,073 |
|
| Nuclear fuel | | 293,695 |
| | 321,901 |
| | 277,345 |
| | 307,352 |
|
| TOTAL UTILITY PLANT | | 9,718,159 |
| | 9,330,459 |
| | 11,617,771 |
| | 11,100,201 |
|
| Less - accumulated depreciation and amortization | | 4,191,959 |
| | 4,034,880 |
| | 4,762,352 |
| | 4,635,885 |
|
| UTILITY PLANT - NET | | 5,526,200 |
| | 5,295,579 |
| | 6,855,419 |
| | 6,464,316 |
|
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
| | |
| | |
|
| Regulatory assets: | | |
| | |
| | |
| | |
|
| Regulatory asset for income taxes - net | | 64,214 |
| | 73,864 |
| | — |
| | 62,646 |
|
| Other regulatory assets (includes securitization property of $67,877 as of December 31, 2014 and $80,963 as of December 31, 2013) | | 1,391,276 |
| | 1,014,392 |
| |
| Other regulatory assets (includes securitization property of $28,583 as of December 31, 2017 and $41,164 as of December 31, 2016) | | | 1,567,437 |
| | 1,428,029 |
|
| Deferred fuel costs | | 65,900 |
| | — |
| | 67,096 |
| | 66,898 |
|
| Other | | 47,674 |
| | 44,565 |
| | 13,910 |
| | 14,626 |
|
| TOTAL | | 1,569,064 |
| | 1,132,821 |
| | 1,648,443 |
| | 1,572,199 |
|
| | | | | | | | | |
| TOTAL ASSETS | |
| $8,807,925 |
| |
| $8,034,890 |
| |
| $10,134,029 |
| |
| $9,606,117 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | CONSOLIDATED BALANCE SHEETS | LIABILITIES AND EQUITY | | | | | | |
| | | December 31, | | December 31, |
| | | 2014 | | 2013 | | 2017 | | 2016 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing long-term debt | |
| $— |
| |
| $70,000 |
| |
| $— |
| |
| $114,700 |
|
| Short-term borrowings | | 47,968 |
| | — |
| | 49,974 |
| | — |
|
| Accounts payable: | | |
| | |
| | |
| | |
|
| Associated companies | | 56,078 |
| | 149,802 |
| | 365,915 |
| | 239,711 |
|
| Other | | 174,998 |
| | 228,160 |
| | 215,942 |
| | 185,153 |
|
| Customer deposits | | 115,647 |
| | 86,512 |
| | 97,687 |
| | 97,512 |
|
| Taxes accrued | | 24,240 |
| | 9,979 |
| | 47,321 |
| | 7,194 |
|
| Accumulated deferred income taxes | | 15,009 |
| | 9,231 |
| |
| Interest accrued | | 20,250 |
| | 22,036 |
| | 18,215 |
| | 16,580 |
|
| Other | | 27,872 |
| | 55,656 |
| | 29,922 |
| | 36,557 |
|
| TOTAL | | 482,062 |
| | 631,376 |
| | 824,976 |
| | 697,407 |
|
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
| | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 1,997,983 |
| | 1,906,562 |
| | 1,190,669 |
| | 2,186,623 |
|
| Accumulated deferred investment tax credits | | 37,708 |
| | 38,958 |
| | 34,104 |
| | 35,305 |
|
| Regulatory liability for income taxes - net | | | 985,823 |
| | — |
|
| Other regulatory liabilities | | 254,036 |
| | 219,370 |
| | 363,591 |
| | 305,907 |
|
| Decommissioning | | 818,351 |
| | 723,771 |
| | 981,213 |
| | 924,353 |
|
| Accumulated provisions | | 5,689 |
| | 5,746 |
| | 34,729 |
| | 18,682 |
|
| Pension and other postretirement liabilities | | 571,870 |
| | 319,211 |
| | 353,274 |
| | 424,234 |
|
| Long-term debt (includes securitization bonds of $76,164 as of December 31, 2014 and $88,961 as of December 31, 2013) | | 2,671,343 |
| | 2,335,802 |
| |
| Long-term debt (includes securitization bonds of $34,662 as of December 31, 2017 and $48,139 as of December 31, 2016) | | | 2,952,399 |
| | 2,715,085 |
|
| Other | | 28,296 |
| | 18,026 |
| | 5,147 |
| | 13,854 |
|
| TOTAL | | 6,385,276 |
| | 5,567,446 |
| | 6,900,949 |
| | 6,624,043 |
|
| | | | | | | | | |
| Commitments and Contingencies | |
|
| |
|
| |
|
| |
|
|
| | | | | | | | | |
| Preferred stock without sinking fund | | 116,350 |
| | 116,350 |
| | 31,350 |
| | 31,350 |
|
| | | | | | | | | |
| COMMON EQUITY | | |
| | |
| | |
| | |
|
| Common stock, $0.01 par value, authorized 325,000,000 shares; issued and outstanding 46,980,196 shares in 2014 and 2013 | | 470 |
| | 470 |
| |
| Common stock, $0.01 par value, authorized 325,000,000 shares; issued and outstanding 46,980,196 shares in 2017 and 2016 | | | 470 |
| | 470 |
|
| Paid-in capital | | 588,471 |
| | 588,471 |
| | 790,264 |
| | 790,243 |
|
| Retained earnings | | 1,235,296 |
| | 1,130,777 |
| | 1,586,020 |
| | 1,462,604 |
|
| TOTAL | | 1,824,237 |
| | 1,719,718 |
| | 2,376,754 |
| | 2,253,317 |
|
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $8,807,925 |
| |
| $8,034,890 |
| |
| $10,134,029 |
| |
| $9,606,117 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY | | For the Years Ended December 31, 2014, 2013, and 2012 | |
| For the Years Ended December 31, 2017, 2016, and 2015 | | For the Years Ended December 31, 2017, 2016, and 2015 |
| | | | | | | | | |
| | | Common Equity | | | | Common Equity | | |
| | | Common Stock | | Paid-in Capital | | Retained Earnings | | Total | | Common Stock | | Paid-in Capital | | Retained Earnings | | Total |
| | | (In Thousands) | | | | (In Thousands) | | |
| | | | | | | | | | | | | | | | | |
| Balance at December 31, 2011 | |
| $470 |
| |
| $588,444 |
| |
| $855,210 |
| |
| $1,444,124 |
| |
| Balance at December 31, 2014 | | |
| $470 |
| |
| $588,471 |
| |
| $1,235,296 |
| |
| $1,824,237 |
|
| Net income | | — |
| | — |
| | 152,365 |
| | 152,365 |
| | — |
| | — |
| | 74,272 |
| | 74,272 |
|
| Common stock dividends | | — |
| | — |
| | (10,000 | ) | | (10,000 | ) | |
| Preferred stock dividends | | — |
| | — |
| | (6,873 | ) | | (6,873 | ) | | — |
| | — |
| | (6,873 | ) | | (6,873 | ) |
| Balance at December 31, 2012 | |
| $470 |
| |
| $588,444 |
| |
| $990,702 |
| |
| $1,579,616 |
| |
| Other | | | — |
| | 22 |
| | — |
| | 22 |
|
| Balance at December 31, 2015 | | |
| $470 |
| |
| $588,493 |
| |
| $1,302,695 |
| |
| $1,891,658 |
|
| Net income | | | — |
| | — |
| | 167,212 |
| | 167,212 |
|
| Capital contributions from parent | | | — |
| | 200,000 |
| | — |
| | 200,000 |
|
| Capital stock redemption | | | — |
| | 1,750 |
| | (2,033 | ) | | (283 | ) |
| Preferred stock dividends | | | — |
| | — |
| | (5,270 | ) | | (5,270 | ) |
| Balance at December 31, 2016 | | |
| $470 |
| |
| $790,243 |
| |
| $1,462,604 |
| |
| $2,253,317 |
|
| Net income | | — |
| | — |
| | 161,948 |
| | 161,948 |
| | — |
| | — |
| | 139,844 |
| | 139,844 |
|
| Common stock dividends | | — |
| | — |
| | (15,000 | ) | | (15,000 | ) | | — |
| | — |
| | (15,000 | ) | | (15,000 | ) |
| Preferred stock dividends | | — |
| | — |
| | (6,873 | ) | | (6,873 | ) | | — |
| | — |
| | (1,428 | ) | | (1,428 | ) |
| Other | | — |
| | 27 |
| | — |
| | 27 |
| | — |
| | 21 |
| | — |
| | 21 |
|
| Balance at December 31, 2013 | |
| $470 |
| |
| $588,471 |
| |
| $1,130,777 |
| |
| $1,719,718 |
| |
| Net income | | — |
| | — |
| | 121,392 |
| | 121,392 |
| |
| Common stock dividends | | — |
| | — |
| | (10,000 | ) | | (10,000 | ) | |
| Preferred stock dividends | | — |
| | — |
| | (6,873 | ) | | (6,873 | ) | |
| Balance at December 31, 2014 | |
| $470 |
| |
| $588,471 |
| |
| $1,235,296 |
| |
| $1,824,237 |
| |
| Balance at December 31, 2017 | | |
| $470 |
| |
| $790,264 |
| |
| $1,586,020 |
| |
| $2,376,754 |
|
| | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| | ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | | | | | | | | | | | | | | | | | | | | | | |
| | | 2014 | | 2013 | | 2012 | | 2011 | | 2010 | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | | | | | | | | | |
| Operating revenues | |
| $2,172,391 |
| |
| $2,190,159 |
| |
| $2,127,004 |
| |
| $2,084,310 |
| |
| $2,082,447 |
| |
| $2,139,919 |
| |
| $2,086,608 |
| |
| $2,253,564 |
| |
| $2,172,391 |
| |
| $2,190,159 |
|
| Net Income | |
| $121,392 |
| |
| $161,948 |
| |
| $152,365 |
| |
| $164,891 |
| |
| $172,618 |
| |
| Net income | | |
| $139,844 |
| |
| $167,212 |
| |
| $74,272 |
| |
| $121,392 |
| |
| $161,948 |
|
| Total assets | |
| $8,807,925 |
| |
| $8,034,890 |
| |
| $7,819,445 |
| |
| $7,212,212 |
| |
| $6,751,368 |
| |
| $10,134,029 |
| |
| $9,606,117 |
| |
| $8,747,774 |
| |
| $8,777,655 |
| |
| $8,007,707 |
|
| Long-term obligations (a) | |
| $2,787,693 |
| |
| $2,452,152 |
| |
| $1,910,245 |
| |
| $1,992,271 |
| |
| $1,946,494 |
| |
| $2,983,749 |
| |
| $2,746,435 |
| |
| $2,691,189 |
| |
| $2,757,423 |
| |
| $2,424,969 |
|
| | | | | | | | | | | | | | | | | | | | | |
(a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund. | | | | | | | | | | | | | | | | | | | | | | |
| | | 2014 | | 2013 | | 2012 | | 2011 | | 2010 | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | | (Dollars In Millions) | | (Dollars In Millions) |
| | | | | | | | | | | | | | | | | | | | | |
| Electric Operating Revenues: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Residential | |
| $755 |
| |
| $772 |
| |
| $766 |
| |
| $756 |
| |
| $773 |
| |
| $768 |
| |
| $789 |
| |
| $824 |
| |
| $755 |
| |
| $772 |
|
| Commercial | | 461 |
| | 469 |
| | 472 |
| | 450 |
| | 441 |
| | 495 |
| | 495 |
| | 515 |
| | 461 |
| | 469 |
|
| Industrial | | 424 |
| | 433 |
| | 439 |
| | 421 |
| | 415 |
| | 472 |
| | 446 |
| | 477 |
| | 424 |
| | 433 |
|
| Governmental | | 18 |
| | 19 |
| | 20 |
| | 20 |
| | 20 |
| | 19 |
| | 18 |
| | 20 |
| | 18 |
| | 19 |
|
| Total retail | | 1,658 |
| | 1,693 |
| | 1,697 |
| | 1,647 |
| | 1,649 |
| | 1,754 |
| | 1,748 |
| | 1,836 |
| | 1,658 |
| | 1,693 |
|
| | | | | | | | | | | | |
| Sales for resale: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Associated companies | | 131 |
| | 346 |
| | 320 |
| | 279 |
| | 302 |
| | 128 |
| | 49 |
| | 128 |
| | 131 |
| | 346 |
|
| Non-associated companies | | 282 |
| | 83 |
| | 49 |
| | 96 |
| | 78 |
| | 121 |
| | 118 |
| | 195 |
| | 282 |
| | 83 |
|
| Other | | 101 |
| | 68 |
| | 61 |
| | 62 |
| | 53 |
| | 137 |
| | 172 |
| | 95 |
| | 101 |
| | 68 |
|
| Total | |
| $2,172 |
| |
| $2,190 |
| |
| $2,127 |
| |
| $2,084 |
| |
| $2,082 |
| |
| $2,140 |
| |
| $2,087 |
| |
| $2,254 |
| |
| $2,172 |
| |
| $2,190 |
|
| | | | | | | | | | | | | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | | |
| | |
| | |
| | |
| | | | |
| | |
| | |
| | |
|
| Residential | | 8,070 |
| | 7,921 |
| | 7,859 |
| | 8,229 |
| | 8,501 |
| | 7,298 |
| | 7,618 |
| | 8,016 |
| | 8,070 |
| | 7,921 |
|
| Commercial | | 5,934 |
| | 5,929 |
| | 6,046 |
| | 6,051 |
| | 6,144 |
| | 5,825 |
| | 5,988 |
| | 6,020 |
| | 5,934 |
| | 5,929 |
|
| Industrial | | 6,808 |
| | 6,769 |
| | 6,925 |
| | 7,029 |
| | 7,082 |
| | 7,528 |
| | 6,795 |
| | 6,889 |
| | 6,808 |
| | 6,769 |
|
| Governmental | | 238 |
| | 241 |
| | 257 |
| | 275 |
| | 277 |
| | 237 |
| | 237 |
| | 235 |
| | 238 |
| | 241 |
|
| Total retail | | 21,050 |
| | 20,860 |
| | 21,087 |
| | 21,584 |
| | 22,004 |
| | 20,888 |
| | 20,638 |
| | 21,160 |
| | 21,050 |
| | 20,860 |
|
| | | | | | | | | | | | |
| Sales for resale: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Associated companies | | 2,299 |
| | 7,918 |
| | 7,926 |
| | 6,893 |
| | 7,853 |
| | 1,782 |
| | 1,609 |
| | 2,239 |
| | 2,299 |
| | 7,918 |
|
| Non-associated companies | | 8,003 |
| | 1,011 |
| | 1,093 |
| | 1,304 |
| | 850 |
| | 6,549 |
| | 7,115 |
| | 7,980 |
| | 8,003 |
| | 1,011 |
|
| Total | | 31,352 |
| | 29,789 |
| | 30,106 |
| | 29,781 |
| | 30,707 |
| | 29,219 |
| | 29,362 |
| | 31,379 |
| | 31,352 |
| | 29,789 |
|
ENTERGY GULF STATES LOUISIANA, L.L.C.LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
In June 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed a business combination study report with the LPSC. The report contained a preliminary analysis of the potential combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility, including an overview of the combination that identified its potential customer benefits. Although not part of the business combination, Entergy Louisiana provided notice to the City Council in June 2014 that it would seek authorization to transfer to Entergy New Orleans the assets that currently support the provision of service to Entergy Louisiana’s customers in Algiers. Entergy Louisiana subsequently filed the referenced application with the City Council in October 2014. In the summer of 2014, Entergy Louisiana and Entergy Gulf States Louisiana held technical conferences and face-to-face meetings with LPSC staff and other stakeholders to discuss potential effects of the combination, solicit suggestions and concerns, and identify areas in which additional information might be needed.
On September 30, 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed an application with the LPSC seeking authorization to undertake the transactions that would result in the combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility.
The combination is subject to regulatory review and approval of the LPSC, the FERC, and the NRC. In June 2014, Entergy submitted an application to the NRC for approval of River Bend and Waterford 3 license transfers as part of the steps to complete the business combination. The combination also could be subject to regulatory review of the City Council if Entergy Louisiana continues to own the assets that currently support Entergy Louisiana’s customers in Algiers at the time the combination is effectuated. In November 2014, Entergy Louisiana filed an application with the City Council seeking authorization to undertake the combination. The application provides that if the City Council approves the Algiers asset transfer before the business combination occurs, the City Council may not need to issue a public interest finding regarding the combination. In December 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed applications with the FERC requesting authorization for the business combination and the Algiers asset transfer. In January 2015, Entergy Services filed an application with the FERC for financing authority for the combined company. If approvals are obtained from the LPSC, the FERC, the NRC, and, if required, the City Council, Entergy Louisiana and Entergy Gulf States Louisiana expect the combination will be effected in the second half of 2015.
The procedural schedule in the LPSC business combination proceeding calls for LPSC Staff and intervenor testimony to be filed in March 2015, with a hearing scheduled for June 2015. Entergy Louisiana and Entergy Gulf States Louisiana have requested that the LPSC issue its decision regarding the business combination in August 2015. In the City Council business combination proceeding, the City Council announced through a resolution that it would not initiate an active review of the business combination filing, but instead would establish a business combination docket for the limited purpose of receiving information filings relative to the business combination proceedings at the LPSC.
It is currently contemplated that Entergy Louisiana and Entergy Gulf States Louisiana will undertake multiple steps to effectuate the combination, which steps would include the following:
Each of Entergy Louisiana and Entergy Gulf States Louisiana will redeem or repurchase all of their respective outstanding preferred membership interests (which interests have a $100 million liquidation value in the case of Entergy Louisiana and $10 million liquidation value in the case of Entergy Gulf States Louisiana).
Entergy Gulf States Louisiana will convert from a Louisiana limited liability company to a Texas limited liability company.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Under the Texas Business Organizations Code (TXBOC), Entergy Louisiana will allocate substantially all of its assets to a new subsidiary (New Entergy Louisiana) and New Entergy Louisiana will assume all of the liabilities of Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Entergy Louisiana will remain in existence and hold the membership interests in New Entergy Louisiana.
Under the TXBOC, Entergy Gulf States Louisiana will allocate substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana will assume all of the liabilities of Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. Entergy Gulf States Louisiana will remain in existence and hold the membership interests in New Entergy Gulf States Louisiana.
Entergy Louisiana and Entergy Gulf States Louisiana will contribute the membership interests in New Entergy Louisiana and New Entergy Gulf States Louisiana to an affiliate the common membership interests of which will be owned by Entergy Louisiana, Entergy Gulf States Louisiana and Entergy Corporation.
New Entergy Gulf States Louisiana will merge into New Entergy Louisiana with New Entergy Louisiana surviving the merger.
Upon the completion of the steps, New Entergy Louisiana will hold substantially all of the assets, and will have assumed all of the liabilities, of Entergy Louisiana and Entergy Gulf States Louisiana. Entergy Louisiana and Entergy Gulf States Louisiana may modify or supplement the steps to be taken to effect the combination.
Results of Operations
Net Income
20142017 Compared to 20132016
Net income decreased $305.7 million primarily due to the effect of the enactment of the Tax Cuts and Jobs Act, in December 2017, which resulted in a decrease of $182.6 million in net income in 2017, and the effect of a settlement with the IRS related to the 2010-2011 IRS audit, which resulted in a $136.1 million reduction of income tax expense in 2016. Also contributing to the decrease in net income were higher other operation and maintenance expenses. The decrease was partially offset by higher net revenue and higher other income. See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act and the IRS audit.
2016 Compared to 2015
Net income increased slightly, by $0.8$175.4 million primarily due to higher net revenue andthe effect of a settlement with the IRS related to the 2010-2011 IRS audit, which resulted in a $136.1 million reduction of income tax expense in 2016. Also contributing to the increase were lower other operation and maintenance expenses, substantiallyhigher net revenue, and higher other income. The increase was partially offset by a higher effective income tax rate, lower other income, higher depreciation and amortization expenses, higher interest expense, and higher taxes other than income taxes.
2013 Compared to 2012
Net income increased $2.7 million primarily due to higher net revenue and higher other income, substantially offset by higher other operation and maintenance expenses, higher depreciation and amortization expenses, higher taxes other than income taxes, and a higher effective income tax rate partially due to the settlement of the tax treatment related to Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing in June 2012.nuclear refueling outage expenses. See Note 3 to the financial statements for additional discussion of the tax treatment.IRS audit.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Net Revenue
20142017 Compared to 20132016
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 20142017 to 2013.2016.
|
| | | |
| | Amount |
| | (In Millions) |
| | |
|
20132016 net revenue |
| $913.42,438.4 |
|
Volume/weatherRegulatory credit resulting from reduction of the federal corporate income tax rate | 19.2 |
|
Asset retirement obligation | 14.3 |
|
MISO deferral | 8.4 |
|
Transmission equalization | 3.555.5 |
|
| Retail electric price | 3.342.8 |
|
OtherLouisiana Act 55 financing savings obligation | 1.517.2 |
|
2014Volume/weather | (12.4 | ) |
| Other | 19.0 |
|
| 2017 net revenue |
| $963.62,560.5 |
|
The volume/weather variance is primarily due to an increase of 1,160 GWh, or 6%, in billed electricity usage, including the effect of more favorable weather on residential sales and higher industrial usage primarily in the chemicals industry.
The asset retirement obligation affects net revenue because Entergy Gulf States Louisiana records a regulatory debit or credit forresulting from reduction of the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The variance is primarily caused by an increase in regulatory credits because of a decrease in decommissioning trust earnings and an increase in regulatory credits to realign the asset retirement obligation regulatory asset with regulatory treatment.
The MISO deferralfederal corporate income tax rate variance is due to the deferral in 2014reduction of the non-fuel MISO-related charges, as approvedVidalia purchased power agreement regulatory liability by $30.5 million and the LPSC. The deferral of non-fuel MISO-related charges is partially offset in other operation and maintenance expenses. See Note 2 to the financial statements for further discussionreduction of the recovery of non-fuel MISO-related charges.
The transmission equalization variance is primarily due to changes in transmission investment equalization billings under the Entergy System Agreement compared to the same period in 2013 primarilyLouisiana Act 55 financing savings obligation regulatory liabilities by $25 million as a result of Entergy Arkansas’s exit from the System Agreementenactment of the Tax Cuts and Jobs Act, in December 2013.2017, which lowered the federal corporate income tax rate from 35% to 21%. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The retail electric price variance is primarily due to an increase in purchased power capacity costs that are recovered through base rates set in the annual formula rate plan mechanism.revenues, implemented with the first billing cycle of March 2016, to collect the estimated first-year revenue requirement related to the purchase of Power Blocks 3 and 4 of the Union Power Station in March 2016 and a provision recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding. See Note 2 to the financial statements for further discussion of Entergy Gulf States Louisiana’sthe formula rate plan.plan revenues and the Waterford 3 replacement steam generator prudence review proceeding.
Entergy Gulf Statesthe Louisiana L.L.C.
Management’s Financial DiscussionAct 55 financing of storm costs for Hurricane Gustav and AnalysisHurricane Ike. See Note 3 to the financial statements for additional discussion of the settlement and benefit sharing.
The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales and decreased usage during the unbilled sales period. The decrease was partially offset by an increase of 1,237 GWh, or 4%, in industrial usage primarily due to an increase in demand from existing customers and expansion projects in the chemicals industry.
20132016 Compared to 20122015
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 20132016 to 2012.2015.
|
| | | |
| | Amount |
| | (In Millions) |
| | |
|
20122015 net revenue |
| $865.92,408.8 |
|
| Retail electric price | 62.5 |
|
| Volume/weather | (6.7 | ) |
| Louisiana Act 55 financing savings obligation | 27.8(17.2 |
|
Net wholesale revenue | 8.3 |
|
Volume/weather | 7.5 |
) |
| Other | 3.9(9.0 |
) |
20132016 net revenue |
| $913.42,438.4 |
|
The retail electric price variance is primarily due to an increase in formula rate plan revenues, implemented with the first billing cycle of March 2016, to collect the estimated first-year revenue requirement related to the purchase of Power Blocks 3 and 4 of the Union Power Station. See Note 2 to the financial statements for further discussion.
The volume/weather variance is primarily due to the effect of less favorable weather on residential sales, partially offset by an increase in industrial usage and an increase in volume during the unbilled period. The increase in industrial usage is primarily due to increased demand from new customers and expansion projects, primarily in the chemicals industry.
The Louisiana Act 55 financing savings obligation variance results from a regulatory charge recorded in the second quarter 2012 because Entergy Gulf States Louisiana was requiredfor tax savings to sharebe shared with customers per an agreement approved by the LPSC. The tax savings resulted from the tax2010-2011 IRS audit settlement on the treatment related toof the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing.financing of storm costs for Hurricane Gustav and Hurricane Ike. See Note 3 to the financial statements for additional discussion of the tax treatment.settlement and benefit sharing.
The net wholesale revenue varianceIncluded in Other is primarily duea provision of $23 million recorded in 2016 related to higher prices.the settlement of the Waterford 3 replacement steam generator prudence review proceeding, offset by a provision of $32 million recorded in 2015 related to the uncertainty at that time associated with the resolution of the Waterford 3 replacement steam generator prudence
The volume/weather variance is primarily due327
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
review proceeding. See Note 2 to an increase of 82 GWh, or 0.4%, in billed electricity usage asthe financial statements for a resultdiscussion of the effect of more favorable weather, as compared to the prior period, primarily on residential sales. The increase was also driven by higher industrial usage primarily in the chemicals industry.Waterford 3 replacement steam generator prudence review proceeding.
Other Income Statement Variances
20142017 Compared to 20132016
Other operation and maintenance expenses increased primarily due to:
an increase of $17.8 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor, to position the nuclear fleet to meet its operational goals, partially offset by a lower scope of work performed during plant outages in 2017;
an increase of $9.5 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to the prior year;
an increase of $4.1 million as a result of the amount of transmission costs allocated by MISO. See Note 2 to the financial statements for further information on the recovery of these costs;
an increase of $3.6 million in transmission and distribution expenses due to higher vegetation maintenance costs; and
an increase of $3.2 million in write-offs of customer accounts.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes, state franchise taxes, and payroll taxes. Ad valorem taxes increased primarily due to higher assessments, including the assessment of Arkansas ad valorem taxes on the Union Power Station beginning in 2017. State franchise taxes increased primarily due to a change in the Louisiana franchise tax law which became effective for 2017.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Blocks 3 and 4 of the Union Power Station purchased in March 2016, and the effects of recording in third quarter 2016 final court decisions in the River Bend and Waterford 3 lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $6 million of spent nuclear fuel storage costs previously recorded as depreciation expense. See Note 14 to the financial statements for discussion of the Union Power Station purchase. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Other income increased primarily due to an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2017, which includes the St. Charles Power Station project, and higher realized gains in 2017 on the River Bend decommissioning trust fund investments, including portfolio rebalancing to the 30% interest in River Bend formerly owned by Cajun.
Interest expense decreased primarily due to an increase in the allowance for borrowed funds used during construction due to higher construction work in progress in 2017, which includes the St. Charles Power Station project.
2016 Compared to 2015
Nuclear refueling outage expenses increased primarily due to the amortization of higher expenses associated with the refueling outages at Waterford 3.
Other operation and maintenance expenses decreased primarily due to:
the $45 million write-off recorded in 2015 to recognize the portion of the assets associated with the Waterford 3 replacement steam generator project no longer probable of recovery. See Note 2 to the financial statements for further discussion of the prudence review proceeding; and
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
a decrease of $20.7$35 million in compensation and benefits costs primarily due to an increasea decrease in the discount rates used to determine net periodic pension and other postretirement costs as a result of higher discount rates used to value the benefit costs,liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement benefit plan design changes, fewer employees, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan.costs. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits”below and Note 11 to the financial statements for further discussion of benefits costs;pension and other postretirement benefit costs.
a decrease of $7.2 million due to costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business; and
a decrease of $2.3 million in loss reserves.
The decrease was partially offset by:
by an increase of $6.9 million due to administration fees in 2014 related to participation in the MISO RTO. The LPSC approved deferral of these expenses resulting in no net income effect;
an increase of $3.6$19.9 million in outside regulatory, consulting, and legal fees;
an increase of $1.7 million in customer service costsnuclear generation expenses primarily due to write-offs in 2014 of uncollectible customer accounts; and
several individually insignificant items.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Taxes other than income taxes increased primarily due to an increase in local franchise taxes resulting from higher residential and commercial revenues as compared to prior year and an increase in ad valorem taxes resulting from higher assessments.nuclear labor costs, including contract labor.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other income decreased primarily due to higher realized gains in 2013 on the River Bend decommissioning trust fund investments. There is no effect on net income as these investment gains are offset by a corresponding amount of regulatory charges.
Interest expense increased primarily due to $3.6 million of carrying charges recorded in 2014 on storm restoration costs related to Hurricane Isaac, as approved by the LPSC,service, including Power Blocks 3 and the issuance of $110 million of 3.78% Series first mortgage bonds in July 2014.
2013 Compared to 2012
Other operation and maintenance expenses increased primarily due to:
an increase of $15 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out4 of the non-qualified pension plan. See “Critical Accounting Estimates” belowand Note 11 to the financial statements for further discussion of benefits costs;
the deferral recordedUnion Power Station purchased in the second quarter 2012, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced expenses by $4.2 million in 2012;
an increase of $13.5 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative, partially offset by the deferral, as approved by the LPSC, of $9.8 million of these costs. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion;
an increase of $3.5 million in fossil-fueled generation expenses due to an overall higher scope of work done during plant outages as compared to the prior year;
an increase of $2.9 million in loss reserves; and
several individually insignificant items.
Also, other operation and maintenance expenses include $7.2 million in 2013 and $4.7 million in 2012 of costs incurred related to the now terminated plan to spin off and merge the transmission business.
Taxes other than income taxes increased primarily due to an increase in local franchise taxes resulting from higher residential and commercial revenues as compared to prior year and an increase in ad valorem taxes resulting from higher assessments. Franchise taxes have no effect on net income as these taxes are recovered through the franchise tax rider.
Depreciation and amortization expenses increased primarily due to increased plant in service.March 2016.
Other income increased primarily due to an increase in the allowance for equity funds used during construction due to higher realized gainsconstruction work in 2013progress in 2016, which included the St. Charles Power Station project, and increased distribution and transmission spending. The increase was also due to higher income in 2016 on the River Bend and Waterford 3 decommissioning trust fund investments. There is no effect on net income as these investment gains are
Interest expense increased primarily due to:
the issuance in March 2016 of $425 million of 3.25% Series collateral trust mortgage bonds;
the issuance in March 2016 of $200 million of 4.95% Series first mortgage bonds; and
the issuance in October 2016 of $400 million of 2.40% Series collateral trust mortgage bonds.
The increase was partially offset by a corresponding amountthe refinancing at lower interest rates of regulatory charges.certain first mortgage bonds. See Note 5 to the financial statements for details of long-term debt.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Income Taxes
The effective income tax rates for 2017, 2016, and 2015 were 35.3%60.5%, 26%12.6%, and 24.9%28.6%, respectively. The difference in the effective income tax rate of 60.5% for 2014, 2013,2017 versus the statutory rate of 35% for 2017 was primarily due to the enactment of the Tax Cuts and 2012, respectively.Jobs Act, signed by President Trump in December 2017, which changed the federal corporate income tax rate from 35% to 21% effective in 2018. See Note 3 to the financial statements for further discussion of the effects of the Tax Cuts and Jobs Act. The difference in the effective income tax rate of 12.6% for 2016 versus the statutory rate of 35% for 2016 was primarily due to the reversal of a portion of the provision for uncertain tax positions as a result of the settlement of the 2010-2011 IRS audit in the second quarter 2016 and book and tax differences related to the non-taxable income distributions earned on preferred membership interests, partially offset by state income taxes. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses proceedings commenced or other responses by Entergy’s regulators to the Act.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2014, 2013,2017, 2016, and 20122015 were as follows:
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| | (In Thousands) | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $15,581 |
| |
| $35,686 |
| |
| $24,845 |
|
| $213,850 |
| |
| $35,102 |
| |
| $320,516 |
|
| | | | | | | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
| | | |
| | |
|
| Operating activities | 592,551 |
| | 434,726 |
| | 346,208 |
| 1,337,545 |
| | 1,037,912 |
| | 1,155,516 |
|
| Investing activities | (391,283 | ) | | (336,644 | ) | | (201,440 | ) | (1,787,409 | ) | | (1,474,065 | ) | | (994,208 | ) |
| Financing activities | (53,886 | ) | | (118,187 | ) | | (133,927 | ) | 271,921 |
| | 614,901 |
| | (446,722 | ) |
| Net increase (decrease) in cash and cash equivalents | 147,382 |
| | (20,105 | ) | | 10,841 |
| (177,943 | ) | | 178,748 |
| | (285,414 | ) |
| | | | | | | | | | | |
| Cash and cash equivalents at end of period |
| $162,963 |
| |
| $15,581 |
| |
| $35,686 |
|
| $35,907 |
| |
| $213,850 |
| |
| $35,102 |
|
Operating Activities
Net cash flow provided by operating activities increased $157.8$299.6 million in 20142017 primarily due to:
proceedsincome tax refunds of $69$234.2 million in 2017 compared to income tax payments of $156.6 million in 2016. Entergy Louisiana received income tax refunds in 2017 and made income tax payments in 2016 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2017 resulted from the Louisiana Utilities Restoration Corporation as a resultutilization of Entergy Louisiana’s net operating losses. The income tax payments in 2016 resulted primarily from adjustments associated with the settlement of the Louisiana Act 55 storm cost financing.2010-2011 IRS audit, payments for state taxes resulting from the effect of the final settlement of the 2006-2007 IRS audit, and the effect of net operating loss limitations. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;
lower nuclear refueling outage spending at River Bend. River Bend had a refueling outage in 2013 and did not have one in 2014; and
the timing of collections from customers.
The increase was partially offset by an increase of $18.6 million in pension contributions in 2014. See “Critical Accounting Estimates” below and Note 113 to the financial statements for a discussion of qualified pensionthe audits;
an increase due to the timing of recovery of fuel and other postretirement benefits funding.purchased power costs; and
an interest payment of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets.
The increase was partially offset by:
a refund to customers in January 2017 of approximately $71 million as a result of the settlement approved by the LPSC related to the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for discussion of the settlement and refund;
an increase of $62.8 million in spending on nuclear refueling outages; and
proceeds of $37.8 million received in August 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation.
Net cash flow provided by operating activities increased $88.5decreased $117.6 million in 20132016 primarily due to:
a decreasean increase of $84.1$67.5 million in income tax payments in 2013 compared to 2012.2016. Entergy Gulf States Louisiana had income tax payments in 2016 and 2015 in accordance with intercompany income tax allocation agreements. The income tax payments in 2016 resulted primarily from adjustments associated with the Entergy Corporationsettlement of the 2010-2011 IRS audit, payments for state taxes resulting from the effect of the final settlement of the 2006-2007 IRS audit, and Subsidiary Companies Intercompany Income Tax Allocation Agreement. In 2013, the effect of net operating loss limitations. The 2015 income tax payments resulted primarily from the reversal of temporary differences for which Entergy Gulf States Louisiana had previously claimed a tax deduction. In 2012, Entergy Gulf States Louisiana no longer had a net operating loss carryover from prior years to reduce current taxable income; and
decreased Hurricane Isaac storm spending in 2013.adjustments
The increase was partially offset by higher nuclear refueling outage spending at River Bend. River Bend had a refueling outage in 2013 and did not have one in 2012.
Entergy Gulf States Louisiana, L.L.C.LLC and Subsidiaries
Management’s Financial Discussion and Analysis
associated with the settlement of the 2008-2009 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audits;
an increase of $80.7 million in interest paid resulting from an increase in interest expense, including a payment of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets. See Note 10 to the financial statements for a discussion of the purchase of a beneficial interest in the Waterford 3 leased assets;
the timing of collections from customers and payments to vendors; and
a decrease due to the timing of recovery of fuel and purchased power costs in 2016.
The decrease was partially offset by proceeds of $37.8 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed and a decrease of $30.5 million in spending on nuclear refueling outages in 2016. See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation.
Investing Activities
Net cash flow used in investing activities increased $54.6$313.3 million in 20142017 primarily due to:
an increase of $364.3 million in fossil-fueled generation construction expenditures primarily due to higher spending on the St. Charles Power Station and Lake Charles Power Station projects in 2017;
an increase of $148.9 million in transmission construction expenditures due to a higher scope of work performed in 2017;
an increase of $144.9 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle;
proceeds of $57.9 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;
an increase of $53.6 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2017;
an increase of $30.4 million in distribution construction expenditures due to increased spending on digital technology improvements within the customer contact centers;
an increase of $19.9 million due to increased spending on advanced metering infrastructure; and
an increase of $12.3 million due to various information technology projects and upgrades in 2017.
The increase was partially offset by:
the purchase of Power Blocks 3 and 4 of the Union Power Station for an aggregate purchase price of approximately $475 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;
money pool activity; and
an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2017.
Decreases in Entergy Louisiana’s receivable from the money pool are a source of cash flow, and Entergy Louisiana’s receivable from the money pool decreased by $11.3 million in 2017 compared to increasing by $16.3 million in 2016. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Net cash flow used in investing activities increased $479.9 million in 2016 primarily due to:
the deposit in 2014purchase of $68.5 million intoPower Blocks 3 and 4 of the storm escrow account;
the investment in 2014Union Power Station for an aggregate purchase price of $66.2approximately $475 million in affiliate securities as a result of the Act 55 storm cost financing.March 2016. See Note 214 to the financial statements andfor discussion of the Union Power Station purchase;
an increase of $130.7 million in fossil-fueled generation construction expenditures primarily due to spending on the St. Charles Power Station project in 2016;
cash proceeds of $59.6 million received in 2015 from the transfer of Algiers assets to Entergy New Orleans in September 2015. See “Hurricane IsaacState and Local Rate Regulation and Fuel-Cost Recovery- Retail Rates - Electric - Filings with the City Council” below for afurther discussion of the Act 55 storm cost financing;transfer;
the withdrawalan increase of $65.5$52 million from the storm reserve escrow account in 2013;transmission construction expenditures due to a higher scope of work performed in 2016; and
an increase of $20.5 million due to various information technology projects and upgrades in fossil-fueled generation expenditures as a result of an increased scope of work in 2014.2016.
The increase was partially offset by:
fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and servicesservice deliveries, and the timing of cash payments during the nuclear fuel cycle;
a decreaseproceeds of $57.9 million received in nuclear construction expenditures as a result of spending on nuclear projects during2016 from the River Bend refueling outage in 2013. River Bend had a refueling outage in 2013 and did not have one in 2014; and
a decrease in transmission construction expenditures due to a decreased scope of work performed in 2014.
Net cash flow used in investing activities increased $135.2 million in 2013 primarily due to:
fluctuations inDOE resulting from litigation regarding spent nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle;
$51 million in proceeds in 2012 from the sale of a portion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests to a third party.storage costs that were previously capitalized. See Note 28 to the financial statements for discussion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests;the spent nuclear fuel litigation; and
money pool activity;
an increasea decrease of $16.9 million in nuclear construction expenditures as a result ofprimarily due to decreased spending on nuclear projects during the River Bend refueling outage in 2013; and
an increase in transmission construction expenditures due to additional reliability work performed in 2013.compliance with NRC post-Fukushima requirements.
The increase was partially offset by:
the withdrawal of $65.5 million from the storm reserve escrow account in 2013;
a decrease in distribution construction expenditures due to prior year Hurricane Isaac spending; and
a decrease in fossil-fueled generation construction expenditures as a result of decreased scope of work in 2013.
Increases in Entergy Gulf States Louisiana’s receivable from the money pool are a use of cash flow, and Entergy Gulf States Louisiana’s receivable from the money pool increased by $1.9 million in 2013 compared to decreasing by $23.6 million in 2012. The money pool is an inter-company borrowing arrangement designed to reduce the Utility operating companies’ need for external short-term borrowings.
Financing Activities
Net cash flow used inprovided by financing activities decreased $64.3$343 million in 20142017 primarily due to:
to the net issuance of $110$325.6 million of 3.78% Series first mortgage bondslong-term debt in July 2014;
2017 compared to the retirement, at maturity,net issuance of $75$961.2 million of 5.56% Series N notes by the nuclear fuel company variable interest entity in May 2013; and
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
money pool activity.
2016. The decrease was partially offset by:
the issuancea decrease of $70$194.3 million of 3.38% Series R notes bycommon equity distributions primarily as a result of higher construction expenditures and higher nuclear fuel purchases in 2017; and
net borrowings of $39.7 million on the nuclear fuel company variable interest entityentities’ credit facilities in February 2013;2017 compared to net repayments of $56.6 million in 2016.
Entergy Louisiana’s financing activities provided $614.9 million of cash in 2016 compared to using $446.7 million in 2015 primarily due to the following activity:
the net issuance of $961.2 million of long-term debt in 2016 compared to the net retirement of $103.4 million of long-term debt in 2015;
the redemption in September 2015 of $100 million of 6.95% Series and $10 million of 8.25% Series preferred membership interests in connection with the Entergy Louisiana and Entergy Gulf States Louisiana business combination;
net repayments of borrowings of $56.6 million on the nuclear fuel company variable interest entity’s credit facility in 2016 compared to net borrowings of $14.3 million in 2015; and
an increase of $47$59.5 million in common equity distributions in 2014;2016. Equity distributions were lower in 2015 in anticipation of the purchase of Power Blocks 3 and
payments 4 of $14.8 million on credit borrowings in 2014 compared to an increase of $14.8 million in credit borrowings in 2013 against the nuclear fuel company variable interest entity credit facility.
Union Power Station.
Decreases in Entergy Gulf States Louisiana’s payable to the money pool are a use of cash flow, and Entergy Gulf States Louisiana’s payable to the money pool decreased by $7.1 million in 2013.
Net cash flow used in financing activities decreased $15.7 million in 2013 primarily due to $14.8 million in credit borrowings in 2013 compared to payments of $29.4 million on credit borrowings in 2012 against the nuclear fuel company variable interest entity credit facility.
The decrease was partially offset by:
money pool activity;
an increase of $5.7 million in common equity distributions;
the issuance of $75 million of 3.25% Series Q notes by the nuclear fuel company variable interest entity in July 2012 compared to the issuance of $70 million of 3.38% Series R notes by the nuclear fuel company variable interest entity in February 2013;
the retirement, at maturity, of $75 million of 5.56% Series N notes by the nuclear fuel company variable interest entity in May 2013 compared to the retirement, at maturity, of $60 million of 5.41% Series O notes by the nuclear fuel company variable interest entity in July 2012; and
the redemption of $10.84 million of pollution control revenue bonds in 2012.
Decreases in Entergy Gulf States Louisiana’s payable to the money pool are a use of cash flow, and Entergy Gulf States Louisiana’s payable to the money pool decreased by $7.1 million in 2013 compared to increasing by $7.1 million in 2012.
See Note 5 to the financial statements for more details onof long-term debt.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Capital Structure
Entergy Gulf States Louisiana’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital ratio for Entergy Gulf States Louisiana is primarily due to an increase in long-term debt as a result of the issuance of $110 million of 3.78% Series first mortgage bonds in July 2014.
| | | | December 31,
2014 | | December 31,
2013 | December 31,
2017 | | December 31,
2016 |
| Debt to capital | 53.1 | % | | 51.1 | % | 53.8 | % | | 53.4 | % |
| Effect of excluding securitization bonds | | (0.3 | %) | | (0.5 | %) |
| Debt to capital, excluding securitization bonds (a) | | 53.5 | % | | 52.9 | % |
| Effect of subtracting cash | (2.6 | %) | | (0.2 | %) | (0.1 | %) | | (0.9 | %) |
| Net debt to net capital | 50.5 | % | | 50.9 | % | |
| Net debt to net capital, excluding securitization bonds (a) | | 53.4 | % | | 52.0 | % |
| |
| (a) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Louisiana. |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Gulf States Louisiana uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because the securitization bonds are non-recourse to Entergy Louisiana, as more fully described in Note 5 to the financial statements. Entergy Louisiana also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Gulf States Louisiana’s
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
financial condition. Entergy Gulf States Louisiana uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Gulf States Louisiana’s financial condition because net debt indicates Entergy Gulf States Louisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Louisiana seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy Louisiana may receive equity contributions to maintain the targeted capital structure.
Uses of Capital
Entergy Gulf States Louisiana requires capital resources for:
construction and other capital investments;
debt and preferred equity maturities or retirements;
working capital purposes, including the financing of fuel and purchased power costs; and
distribution and interest payments.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Gulf States Louisiana’s planned construction and other capital investments.
| | | | 2015 | | 2016 | | 2017 | 2018 | | 2019 | | 2020 |
| | (In Millions) | (In Millions) |
| Planned construction and capital investment: | | | | | | | | | | |
| Generation |
| $570 |
| |
| $145 |
| |
| $210 |
|
| $875 |
| |
| $530 |
| |
| $330 |
|
| Transmission | 195 |
| | 150 |
| | 160 |
| 465 |
| | 350 |
| | 285 |
|
| Distribution | 95 |
| | 100 |
| | 125 |
| 325 |
| | 395 |
| | 365 |
|
| Other | 40 |
| | 30 |
| | 30 |
| |
| Utility Support | | 165 |
| | 110 |
| | 135 |
|
| Total |
| $900 |
| |
| $425 |
| |
| $525 |
|
| $1,830 |
| |
| $1,385 |
| |
| $1,115 |
|
Following are the amounts of Entergy Gulf States Louisiana’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | 2015 | | 2016-2017 | | 2018-2019 | | After 2019 | | Total | 2018 | | 2019-2020 | | 2021-2022 | | After 2022 | | Total |
| | (In Millions) | (In Millions) |
| Long-term debt (a) |
| $115 |
| |
| $244 |
| |
| $509 |
| |
| $1,582 |
| |
| $2,450 |
|
| $940 |
| |
| $903 |
| |
| $843 |
| |
| $6,785 |
| |
| $9,471 |
|
| Operating leases |
| $13 |
| |
| $21 |
| |
| $20 |
| |
| $26 |
| |
| $80 |
|
| $22 |
| |
| $41 |
| |
| $24 |
| |
| $19 |
| |
| $106 |
|
| Purchase obligations (b) |
| $308 |
| |
| $490 |
| |
| $398 |
| |
| $275 |
| |
| $1,471 |
|
| $633 |
| |
| $1,420 |
| |
| $1,366 |
| |
| $7,125 |
| |
| $10,544 |
|
| |
| (a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
| (b) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Gulf States Louisiana, it primarily includesalmost all of the total consists of unconditional fuel and purchased power obligations.obligations, including its obligations under the Vidalia purchased power agreement and the Unit Power Sales Agreement, both of which are discussed in Note 8 to the financial statements. |
In addition to the contractual obligations given above, Entergy Gulf States Louisiana currently expects to contribute approximately $32.5$71.9 million to its qualified pension plans and approximately $8.9$19 million to its other postretirement health care and life insurance plans in 2015,2018, although the 2018 required pension contributions will not be known with more certainty untilwhen the January 1, 20152018 valuations are completed, which is expected by April 1, 2015.2018. See “Critical Accounting Estimates- Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also, in addition to the contractual obligations, Entergy Gulf States Louisiana has $427.9$926.6 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Gulf States Louisiana includes specific investments, such as the UnionSt. Charles Power Station acquisitionand Lake Charles Power Station, each discussed below; NRC post-Fukushima requirements; environmental compliance spending; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including investment to support advanced metering; resource planning;planning, including potential generation projects; system improvements; investments in River Bend and Waterford 3; and other investments. Entergy’s Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements,
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
Management provides more information on long-term debt maturities in Note 5 to the financial statements.
As an indirect,a wholly-owned subsidiary of Entergy Corporation,Utility Holding Company, LLC, Entergy Gulf States Louisiana pays distributions from its earnings at a percentage determined monthly. Entergy Gulf States Louisiana’s long-term debt indenture contains restrictions on the payment of cash dividends or other distributions on its common and preferred membership interests.
UnionSt. Charles Power Station Purchase Agreement
In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire the Union Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas-fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Pursuant to the agreement, Entergy Gulf States Louisiana will acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas will each acquire one power block and a 25% undivided ownership interest in such related assets. (If Entergy Arkansas or Entergy Texas do not obtain approval for the purchase of their power blocks, Entergy Gulf States Louisiana will seek to purchase the power blocks not approved.) The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments. In addition, Entergy Gulf States Louisiana anticipates selling 20% of the capacity and energy associated with its two power blocks to Entergy New Orleans through a cost-based, life-of-unit power purchase agreement. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. These include regulatory approvals from the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino anti-trust law. In December 2014, Entergy Texas filed its application with the PUCT for approval of the acquisition. The PUCT has indicated that it will convene the hearing on the merits of this case in June 2015. Entergy Texas intends to file a rate application to seek cost recovery later in 2015. In JanuaryAugust 2015, Entergy Gulf States Louisiana filed its application with the LPSC and Entergy Arkansas filed its application with the APSC, each for approval of the acquisition and cost recovery. Closing is targeted to occur in late-2015.
New Nuclear Development
Entergy Gulf States Louisiana and Entergy Louisiana have been developing and are preserving a project option for new nuclear generation at River Bend. In the first quarter 2010, Entergy Gulf States Louisiana and Entergy Louisiana each paid for and recognized on its books $24.9 million in costs associated with the development of new nuclear generation at the River Bend site; these costs previously had been recorded on the books of Entergy New Nuclear Utility Development, LLC, a System Energy subsidiary. Entergy Gulf States Louisiana and Entergy Louisiana will share costs going forward on a 50/50 basis, which reflects each company’s current participation level in the project.
In March 2010, Entergy Gulf States Louisiana and Entergy Louisiana filed with the LPSC an application seeking approvalcertification that the public necessity and convenience would be served by the construction of the St. Charles Power Station, a nominal 980 megawatt combined-cycle generating unit, on land adjacent to the existing Little Gypsy plant in St. Charles Parish, Louisiana. It is currently estimated to cost $869 million to construct, including transmission interconnection and other related costs. The LPSC issued an order approving certification of St. Charles Power Station in December 2016. Construction is in progress and commercial operation is estimated to occur by mid-2019.
Lake Charles Power Station
In November 2016, Entergy Louisiana filed an application with the LPSC seeking certification that the public convenience and necessity would be served by the construction of the Lake Charles Power Station, a nominal 994 megawatt combined-cycle generating unit in Westlake, Louisiana, on land adjacent to the existing Nelson plant in Calcasieu Parish. The current estimated cost of the Lake Charles Power Station is $872 million, including estimated costs of transmission interconnection and other related costs. In May 2017 the parties to the proceeding agreed to an uncontested stipulation finding that construction of the Lake Charles Power Station is in the public interest and authorizing an in-service rate recovery plan. In July 2017 the LPSC issued an order unanimously approving the stipulation and approved certification of the unit. Construction is in progress and commercial operation is expected to occur by mid-2020.
Washington Parish Energy Center
In April 2017, Entergy Louisiana signed a purchase and sale agreement with a subsidiary of Calpine Corporation for the acquisition of a peaking plant. Calpine will construct the plant, which will consist of two natural gas-fired combustion turbine units with a total nominal capacity of approximately 361 MW. The plant, named the Washington Parish Energy Center, will be located in Bogalusa, Louisiana and, subject to permits and approvals, is expected to be completed in 2021. Subject to regulatory approvals, Entergy Louisiana will purchase the plant once it is complete for an estimated total investment of approximately $261 million, including transmission and other related costs. In May 2017, Entergy Louisiana filed an application with the LPSC seeking certification of the plant. A procedural schedule has been established, with the deadlines recently extended and the hearing continued from March 2018 until June 2018 in order to allow the parties an opportunity to reach settlement.
Advanced Metering Infrastructure (AMI)
In November 2016, Entergy Louisiana filed an application seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing included an estimate of implementation costs for AMI of $330 million. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the limited development activities necessaryremaining book value, approximately $92 million at December 31, 2015, of the existing electric meters and also to preserve an optiondepreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which is expected to construct a new unit at River Bend.begin in 2019. The communications network deployment
Entergy Gulf States Louisiana, L.L.C.LLC and Subsidiaries
Management’s Financial Discussion and Analysis
At its June 2012 meetingis expected to begin by late-2018, after the necessary information technology infrastructure is in place. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. The parties reached an uncontested stipulation permitting implementation of Entergy Louisiana’s proposed AMI system, with modifications to the proposed customer charge. In July 2017 the LPSC voted to uphold an ALJ recommendation thatapproved the request of Entergy Gulf States Louisiana andstipulation. Entergy Louisiana be declined onexpects to recover the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification. The LPSC directed that Entergy Gulf States Louisiana and Entergy Louisiana be permitted to seek recoveryundepreciated balance of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding, the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of a new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2014, Entergy Gulf States Louisiana and Entergy Louisiana each haveits existing meters through a regulatory asset of $29.2 million on its balance sheet related to these new nuclear generation development costs.at current depreciation rates.
Sources of Capital
Entergy Gulf States Louisiana’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt or preferred membership interest issuances; and
bank financing under new or existing facilities.
Entergy Gulf States Louisiana may refinance, redeem, or otherwise retire debt and preferred equity/membership interests prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred equity/membership interest issuances by Entergy Gulf States Louisiana require prior regulatory approval. Preferred equity/membership interest and debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Gulf States Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Gulf States Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2014 | | 2013 | | 2012 | | 2011 |
| (In Thousands) |
| $1,166 | | $1,925 | | ($7,074) | | $23,596 |
|
| | | | | | |
| 2017 | | 2016 | | 2015 | | 2014 |
| (In Thousands) |
| $11,173 | | $22,503 | | $6,154 | | $2,815 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Gulf States Louisiana has a credit facility in the amount of $150$350 million scheduled to expire in March 2019.August 2022. The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against 50%$15 million of the borrowing capacity of the facility. NoAs of December 31, 2017, there were no cash borrowings wereand a $9.1 million letter of credit outstanding under the credit facility as of December 31, 2014.facility. In addition, Entergy Gulf States Louisiana entered intois a party to an uncommitted letter of credit facility in 2014 as a means to post collateral to support its obligations underto MISO. As of December 31, 2014,2017, a $27.9$29.7 million letter of credit was outstanding under Entergy Gulf States Louisiana’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
The Entergy Gulf StatesLouisiana nuclear fuel company variable interest entities have two separate credit facilities, one in the amount of $105 million and one in the amount of $85 million, both scheduled to expire in May 2019. As of December 31, 2017, $65.7 million of loans were outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity. As of December 31, 2017, $43.5 million in letters of credit to support a like amount of commercial paper issued and $36.4 million in loans were outstanding under the Entergy Louisiana Waterford nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facilities.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Louisiana obtained authorizations from the FERC through October 20152019 for the following:
short-term borrowings not to exceed an aggregate amount of $200$450 million at any time outstanding;
long-term borrowings and security issuances; and
long-term borrowings by its nuclear fuel company variable interest entity.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
See Note 4 to the financial statements for further discussion of Entergy Gulf States Louisiana’s short-term borrowing limits.
The Entergy Gulf States Louisiana nuclear fuel company variable interest entity has a credit facility in the amount of $100 million scheduled to expire in June 2016. No borrowings were outstanding under the credit facility as of December 31, 2014. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facility.Hurricane Isaac
In JulyJune 2014 Entergy Gulf States Louisiana issued $110 million of 3.78% Series first mortgage bonds due April 2025. Entergy Gulf States Louisiana used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.
Hurricane Isaac
In August 2012, Hurricane Isaac caused extensive damage to Entergy Gulf States Louisiana’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. In January 2013, Entergy Gulf States Louisiana drew $65 million from its funded storm reserve escrow accounts. In April 2013, Entergy Gulf States Louisiana and Entergy Louisiana filed a joint application with the LPSC relating to Hurricane Isaac system restoration costs. In May 2013, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane Isaac system restoration costs incurred by Entergy Gulf States Louisiana and Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of each company’s costs. Following an evidentiary hearing and recommendations by the ALJ, the LPSC voted in June 2014 to approve a series of orders which (i) quantify the amountquantified $290.8 million of Hurricane Isaac system restoration costs as prudently incurred ($66.5incurred; (ii) determined $290 million for Entergy Gulf States Louisiana and $224.3 million for Entergy Louisiana); (ii) determineas the level of storm reserves to be re-established ($90 million for Entergy Gulf States Louisiana and $200 million for Entergy Louisiana);re-established; (iii) authorize Entergy Gulf States Louisiana andauthorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) grantgranted other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Gulf States Louisiana committed to pass on to customers a minimum of $6.9$30.8 million of customer benefits through annual customer credits of approximately $1.4$6.2 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.
In July 2014, Entergy Gulf States Louisiana issued $110 million See Note 2 to the financial statements for a discussion of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes. In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $71 million inissuance of bonds under Act 55 of the Louisiana Legislature. From
Little Gypsy Repowering Project
In April 2007, Entergy Louisiana announced that it intended to pursue the $69solid fuel repowering of a 538 MW unit at its Little Gypsy plant. In March 2009 the LPSC voted in favor of a motion directing Entergy Louisiana to temporarily suspend the repowering project and, based upon an analysis of the project’s economic viability, to make a recommendation regarding whether to proceed with the project. This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital/financial markets. In April 2009, Entergy Louisiana complied with the LPSC’s directive and recommended that the project be suspended for an extended period of time of three years or more. In May 2009 the LPSC issued an order declaring that Entergy Louisiana’s decision to place the Little Gypsy project into a longer-term suspension of three years or more is in the public interest and prudent.
In October 2009, Entergy Louisiana made a filing with the LPSC seeking permission to cancel the Little Gypsy repowering project and seeking project cost recovery over a five-year period. In June 2010 and August 2010, the LPSC staff and intervenors filed testimony. The LPSC staff (1) agreed that it was prudent to move the project from long-term suspension to cancellation and that the timing of the decision to suspend on a longer-term basis was not imprudent; (2) indicated that, except for $0.8 million in compensation-related costs, the costs incurred should be deemed prudent; (3) recommended recovery from customers over ten years but stated that the LPSC may want to consider 15 years; (4) allowed for recovery of carrying costs and earning a return on project costs, but at a reduced rate approximating the cost of debt, while also acknowledging that the LPSC may consider ordering no return; and (5) indicated that Entergy Louisiana should be directed to securitize project costs, if legally feasible and in the public interest. In the third quarter 2010, in accordance with accounting standards, Entergy Louisiana determined that it was probable that the Little Gypsy repowering project would be abandoned and accordingly reclassified $199.8 million of bond proceeds loaned byproject costs from construction work in progress to a regulatory asset. A hearing on the LCDA toissues, except for cost allocation among customer classes, was held before the LURC, the LURC deposited $3 millionALJ in November 2010. In January 2011 all parties participated in a restricted escrow account asmediation on the disputed issues, resulting in a storm damage reservesettlement of all disputed issues, including cost recovery and cost allocation. The settlement provides for Entergy Gulf States Louisiana to recover $200 million as of March 31, 2011, and transferred $66 million directlycarrying costs on that amount on specified terms thereafter. The settlement also provides for Entergy Louisiana to recover the approved project costs by securitization. In April 2011, Entergy Gulf States Louisiana. Entergy Gulf States Louisiana usedfiled an application with the $66 million received fromLPSC to authorize the LURC to acquire 662,426.80 Class C preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 7.5% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2014, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the termssecuritization of the LLC agreement. The terms ofinvestment recovery costs associated with the membership interests include certain financial covenantsproject and to issue a financing order by which Entergy Holdings Company LLC is subject, includingLouisiana could accomplish such securitization. In August 2011 the requirement to maintain a net worth of at least $1.75 billion.LPSC issued an order approving the settlement and also
Entergy Gulf States Louisiana does not report the bonds on its balance sheet because the bonds are the obligation of the LCDA and there is no recourse against Entergy Gulf States Louisiana in the event of a bond default. To service
Entergy Gulf States Louisiana, L.L.C.LLC and Subsidiaries
Management’s Financial Discussion and Analysis
issued a financing order for the bonds, Entergy Gulf States Louisiana collectssecuritization. See Note 5 to the financial statements for a system restoration charge on behalfdiscussion of the LURC, and remitsSeptember 2011 issuance of the collections to the bond indenture trustee. Entergy Gulf States Louisiana does not report the collections as revenue because it is merely acting as the billing and collection agent for the state.securitization bonds.
Entergy Louisiana’s Ninemile Point Unit 6 Self-Build Project
In June 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station. Ninemile 6 is a nominally-sized 560 MW unit that is expected to cost approximately $655 million to construct when spending is complete, excluding interconnection and transmission upgrades. Entergy Gulf States Louisiana joined in the application, seeking certification of its purchase under a life-of-unit power purchase agreement of up to 25% of the capacity and energy generated by Ninemile 6. The Ninemile 6 capacity and energy is allocated 55% to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20% to Entergy New Orleans. In February 2012 the City Council passed a resolution authorizing Entergy New Orleans to purchase 20% of the Ninemile 6 energy and capacity. In March 2012 the LPSC unanimously voted to grant the certifications requested by Entergy Gulf States Louisiana and Entergy Louisiana. Following approval by the LPSC, Entergy Louisiana issued full notice to proceed to the project’s engineering, procurement, and construction contractor.
Under the terms approved by the LPSC, non-fuel costs may be recovered through Entergy Gulf States Louisiana’s formula rate plan beginning in the month after the unit is placed in service. In July 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed an unopposed stipulation with the LPSC that estimates a first year revenue requirement associated with Ninemile 6 and provides a mechanism to update the revenue requirement as the in-service date approaches, which was subsequently approved by the LPSC. In late December 2014, roughly contemporaneous with the unit’s placement in service, a final updated estimated revenue requirement of $26.8 million for Entergy Gulf States Louisiana was filed. The December 2014 estimate forms the basis of rates implemented effective with the first billing cycle of January 2015.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Gulf States Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Gulf States Louisiana is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.
Retail Rates - Electric
Filings with the LPSC
2014 Formula Rate Plan Filing
In November 2011connection with the LPSC approved a one-year extensionapproval of the business combination of Entergy Gulf States Louisiana’sLouisiana and Entergy Louisiana, the LPSC authorized the filing of a single, joint, formula rate plan. In May 2012,plan evaluation report for Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2011 test year.Louisiana’s and Entergy Louisiana’s 2014 calendar year operations. The filing reflected an 11.94% earned return on common equity, whichjoint evaluation report was above the earnings bandwidthfiled in September 2015 and indicated a $6.5 million cost of service rate decrease was necessary under the formula rate plan. The filing also reflected a $22.9 million rate decrease for the incremental capacity rider. Subsequently, in August 2012, Entergy Gulf States Louisiana submitted a revised filing that reflected an earned return on common equity of 11.86%, which indicated a $5.7 million cost of service9.09%. As such, no adjustment to base formula rate decreaseplan revenue was necessaryrequired. The following adjustments were required under the formula rate plan. The revised filing also indicated thatplan, however: a decrease in the additional capacity mechanism for Entergy Louisiana of $17.8 million; an increase in the additional capacity mechanism for Entergy Gulf States Louisiana of $4.3 million; and a reduction of $20.3$5.5 million should beto the MISO cost recovery mechanism to collect approximately $35.7 million on a combined-company basis. Under the order approving the business combination, following completion of the prescribed review period, rates were implemented with the first billing cycle of December 2015, subject to refund. In June 2017 the LPSC staff and Entergy Louisiana filed an unopposed joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of this proceeding with no changes to rates already implemented.
2015 Formula Rate Plan Filing
In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflected an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue was required. The following other adjustments, however, were required under the formula rate plan: an increase in the incrementallegacy Entergy Louisiana additional capacity rider. The rate reductionsmechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented subject to refund, effective for bills rendered inwith the first billing cycle of September 2012. Subsequently,2016, subject to refund. Following implementation of the as-filed rates in September 2016, there were several interim updates to Entergy Louisiana’s formula rate plan, including the one submitted in December 2012,2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. In June 2017 the LPSC staff and Entergy Louisiana filed a joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of the May 2016 evaluation report, interim updates, and corresponding proceedings with no changes to rates already implemented.
Extension of MISO Cost Recovery Mechanism Rider
In November 2016, Entergy Louisiana filed with the LPSC a request to extend the MISO cost recovery mechanism rider provision of its formula rate plan. In March 2017 the LPSC staff submitted direct testimony generally supportive of a one-year extension of the MISO cost recovery mechanism and the intervenor in the proceeding did not
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
oppose an extension for this period of time. In July 2017 an uncontested joint stipulation authorizing a one-year extension of the MISO cost recovery mechanism rider was approved.
2016 Formula Rate Plan Filing
In May 2017, Entergy Louisiana filed its formula rate plan evaluation report for its 2016 calendar year operations. The evaluation report reflected an earned return on common equity of 9.84%. As such, no adjustment to base formula rate plan revenue was required. Adjustments, however, were required under the formula rate plan; the 2016 formula rate plan evaluation report showed a decrease in formula rate plan revenue of approximately $16.9 million, comprised of a decrease in legacy Entergy Louisiana formula rate plan revenue of $3.5 million, a decrease in legacy Entergy Gulf States Louisiana submittedformula rate plan revenue of $9.7 million, and a reviseddecrease in incremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 million in the MISO cost recovery revenue requirement from the present level of $46.8 million to $6.3 million. Rates reflecting these adjustments were implemented with the first billing cycle of September 2017, subject to refund. In September 2017 the LPSC issued its report indicating that no changes to Entergy Louisiana’s original formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report.
Formula Rate Plan Extension Request
In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications to its terms. Those modifications include: a one-time resetting of base rates to the midpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95% for the 2017 test year; narrowing of the formula rate plan bandwidth from a total of 160 basis points to 80 basis points; and a forward-looking mechanism that would allow Entergy Louisiana to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers. Entergy Louisiana requested that the LPSC consider its request on an expedited basis, in an effort to maintain Entergy Louisiana’s current cycle for implementing rate adjustments, i.e., September 2018, without the need for filing a full base rate case proceeding. Several parties have intervened in the proceeding and all parties have been participating in settlement discussions.
Waterford 3 Replacement Steam Generator Project
Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana. An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent. Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. At the hearing the parties maintained the positions reflected expected retail jurisdictional costin pre-filed testimony. Entergy Louisiana believed that the replacement steam generator costs were prudently incurred and applicable legal principles supported their recovery in rates. Nevertheless, Entergy Louisiana recorded a write-off of $17$16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Louisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contained significant factual and legal errors.
In October 2016 the parties reached a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectively provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to customers of approximately $71 million as a result of the settlement approved by the LPSC was made to customers in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the first-year capacity charges forcumulative revenues recorded through December 2016 related to the purchase from$67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future. Following a review by the parties, an unopposed joint report of one-thirdproceedings was filed by the LPSC staff and Entergy Louisiana in May 2017 and the LPSC accepted the joint report of Acadia Unit 2 capacityproceedings resolving the matter.
Ninemile 6
In July 2014, Entergy Gulf States Louisiana and energy. This rate changeEntergy Louisiana filed an unopposed stipulation with the LPSC, which was subsequently approved, that estimated a first year revenue requirement associated with Ninemile 6 and provided a mechanism to update the revenue requirement as the in-service date approached. In late-December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of $26.8 million for Entergy Gulf States Louisiana and $51.1 million for Entergy Louisiana was filed. The December 2014 estimate formed the basis of rates implemented effective with the first billing cycle of January 2013.2015. In July 2015, Entergy Louisiana submitted to the LPSC a compliance filing including an estimate at completion, inclusive of interconnection costs and transmission upgrades, of approximately $648 million, or $76 million less than originally estimated, along with other project details and supporting evidence, to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project. Testimony filed by the LPSC staff generally supported the prudence of the management of the project and recovery of the costs incurred to complete the project. The 2011 test year filings, as revised, wereLPSC staff had questioned the warranty coverage for one element of the project. In October 2016 all parties agreed to a stipulation providing that 100% of Ninemile 6 construction costs was prudently incurred and is eligible for recovery from customers, but reserving the LPSC’s rights to review the prudence of Entergy Louisiana’s actions regarding one element of the project. This stipulation was approved by the LPSC in February 2013. January 2017.
Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana Plants
In April 2013,January 2015, Entergy Gulf States Louisiana submitted a revised evaluation report increasingfiled its application with the incremental capacity rider byLPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $7.3$237 million per power block, subject to reflectadjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the costtwo power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an additional capacity contract.aggregate purchase price of approximately $474 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.
Entergy Gulf States Louisiana, L.L.C.LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In connectionAs a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to extendretire Little Gypsy 1. In January 2016, Entergy Louisiana made its compliance filing with the formula rate planLPSC. Entergy Louisiana, LPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the 2011 test year,current deactivation decisions for the LPSC required that a base rate case be filedten-year planning horizon. Parties have requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4. No party contests the prudence of the decision to deactivate Willow Glen 2 and 4 or suggests reactivation of these units; however, issues have been raised related to Entergy Louisiana’s decision to give up its transmission service rights in MISO for Willow Glen 2 and 4 rather than placing the units into suspended status for the three-year term permitted by Entergy Gulf States Louisiana,MISO. An evidentiary hearing was held in August 2017 and the required filing was madepost-hearing briefs were submitted in February 2013. The filing anticipated Entergy Gulf States Louisiana’s integration into MISO. In the filing Entergy Gulf States Louisiana requested, among other relief:October 2017. A decision is expected in 2018.
authorization to increase the revenue it collects from customers by approximately $24 million;
an authorized return on common equity of 10.4%;
authorization to increase depreciation rates embedded in the proposed revenue requirement; and,
authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.
Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. Major terms of the settlement include approval of a three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Gulf States Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain special recovery items; (3) three-year amortization of costs to achieve savings associated with the human capital management strategic imperative, with savings to be reflected as they are realized in subsequent years; (4) eight-year amortization of costs incurred in connection with potential development of a new nuclear unit at River Bend, without carrying costs, beginning December 2014, provided, however, that amortization of these costs shall not result in a future rate increase; (5) no change in rates related to test year 2013, except with respect to recovery of the non-fuel MISO-related costs and any changes to the additional capacity revenue requirement; and (6) no increase in rates related to test year 2014, except for those items eligible for recovery outside of the earnings sharing mechanism. Existing depreciation rates will not change. Implementation of rate changes for items recoverable outside of the earnings sharing mechanism occurred in December 2014.
Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Gulf States Louisiana submitted a compliance filing in May 2014 reflecting the effects of the estimated MISO cost recovery mechanism revenue requirement and adjustment of the additional capacity mechanism. In November 2014, Entergy Gulf States Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data. Based on this updated filing, a net increase of $5.8 million in formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings are subject to the review in accordance with the review process set forth in Entergy Gulf States Louisiana’s formula rate plan.
Retail Rates - GasHurricane Isaac
In January 2012,June 2014 the LPSC voted to approve a series of orders which (i) quantified $290.8 million of Hurricane Isaac system restoration costs as prudently incurred; (ii) determined $290 million as the level of storm reserves to be re-established; (iii) authorized Entergy Gulf States Louisiana filedto utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) granted other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation and the Louisiana State Bond Commission. See Note 2 to the financial statements for a discussion of the August 2014 issuance of bonds under Act 55 of the Louisiana Legislature.
Little Gypsy Repowering Project
In April 2007, Entergy Louisiana announced that it intended to pursue the solid fuel repowering of a 538 MW unit at its Little Gypsy plant. In March 2009 the LPSC voted in favor of a motion directing Entergy Louisiana to temporarily suspend the repowering project and, based upon an analysis of the project’s economic viability, to make a recommendation regarding whether to proceed with the project. This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital/financial markets. In April 2009, Entergy Louisiana complied with the LPSC’s directive and recommended that the project be suspended for an extended period of time of three years or more. In May 2009 the LPSC issued an order declaring that Entergy Louisiana’s decision to place the Little Gypsy project into a longer-term suspension of three years or more is in the public interest and prudent.
In October 2009, Entergy Louisiana made a filing with the LPSC its gas rate stabilization plan forseeking permission to cancel the test year ended September 30, 2011. The filing showed an earned return on common equity of 10.48%, which is within the earnings bandwidth of 10.5%, plus or minus fifty basis points.Little Gypsy repowering project and seeking project cost recovery over a five-year period. In April 2012 the LPSC Staff filed its findings, suggesting adjustments that produced an 11.54% earned return on common equity for the test yearJune 2010 and a $0.1 million rate reduction. Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate reduction was effective with the first billing cycle of May 2012.
In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012. The filing showed an earned return on common equity of 11.18%, which results in
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
a $43 thousand rate reduction. In March 2013 the LPSC Staff issued its proposed findings and recommended two adjustments. Entergy Gulf States Louisiana and the LPSC Staff reached agreement regarding the LPSC Staff’s proposed adjustments. As reflected in an unopposed joint report of proceedings filed by Entergy Gulf States Louisiana and the LPSC Staff in May 2013, Entergy Gulf States Louisiana accepted, with modification, the LPSC Staff’s proposed adjustment to property insurance expense and agreed to: (1) a three-year extension of the gas rate stabilization plan with a midpoint return on equity of 9.95%, with a first year midpoint reset; (2) dismissal of a docket initiated by the LPSC to evaluate the allowed return on equity for Entergy Gulf States Louisiana’s gas rate stabilization plan; and (3) presentation to the LPSC by November 2014 by Entergy Gulf States Louisiana and the LPSC Staff of their recommendation for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment. The LPSC approved the agreement in May 2013.
In January 2014, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2013. The filing showed an earned return on common equity of 5.47% which results in a $1.5 million rate increase. In April 2014 the LPSC Staff issued a report indicating “that Entergy Gulf States Louisiana has properly determined its earnings for the test year ended September 30, 2013.” The $1.5 million rate increase was implemented effective with the first billing cycle of April 2014.
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014 Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by2010, the LPSC staff and inclusionintervenors filed testimony. The LPSC staff (1) agreed that it was prudent to move the project from long-term suspension to cancellation and that the timing of certain customer safeguards required bythe decision to suspend on a longer-term basis was not imprudent; (2) indicated that, except for $0.8 million in compensation-related costs, the costs incurred should be deemed prudent; (3) recommended recovery from customers over ten years but stated that the LPSC staff, in December 2014, Entergy Gulf States Louisianamay want to consider 15 years; (4) allowed for recovery of carrying costs and earning a return on project costs, but at a reduced rate approximating the cost of debt, while also acknowledging that the LPSC staff submittedmay consider ordering no return; and (5) indicated that Entergy Louisiana should be directed to securitize project costs, if legally feasible and in the public interest. In the third quarter 2010, in accordance with accounting standards, Entergy Louisiana determined that it was probable that the Little Gypsy repowering project would be abandoned and accordingly reclassified $199.8 million of project costs from construction work in progress to a jointregulatory asset. A hearing on the issues, except for cost allocation among customer classes, was held before the ALJ in November 2010. In January 2011 all parties participated in a mediation on the disputed issues, resulting in a settlement of all disputed issues, including cost recovery and cost allocation. The settlement provides for implementationEntergy Louisiana to recover $200 million as of an accelerated gas pipe replacement program providingMarch 31, 2011, and carrying costs on that amount on specified terms thereafter. The settlement also provides for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a riderEntergy Louisiana to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of 10.45% as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20 percent annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding ten percent; and an annual true-up. The joint settlement was approved project costs by the LPSC in January 2015. Implementation of the infrastructure rider will commence with bills rendered on and after the first billing cycle ofsecuritization. In April 2015.
In January 2015,2011, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2014. The filing showed an earned return on common equity of 7.20%, which results in a $706 thousand rate increase. The rate increase, if approved, will be implemented effective with the first billing cycle of April 2015.
Fuel and purchased power cost recovery
Entergy Gulf States Louisiana recovers electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Gulf States Louisiana’s purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
In December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009. Discovery is in progress, but a procedural schedule has not been established.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Gulf States Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery has yet to commence.
Industrial and Commercial Customers
Entergy Gulf States Louisiana’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Gulf States Louisiana’s industrial customer base. Entergy Gulf States Louisiana responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Entergy Gulf States Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers. Entergy Gulf States Louisiana does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Gulf States Louisiana’s marketing efforts in retaining industrial customers.
Federal Regulation
See “Entergy’s Integration Into the MISO Regional Transmission Organization,” “System Agreement,” and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of these topics.
Nuclear Matters
Entergy Gulf States Louisiana owns and, through an affiliate, operates the River Bend nuclear power plant. Entergy Gulf States Louisiana is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of River Bend, Entergy Gulf States Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.
The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system. The issue is applicable to River Bend and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators to undertake plant modifications and perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating nuclear plants. The NRC, with input from the industry, is continuing to determine the specific actions required by the orders. Entergy Gulf States Louisiana’s estimated capital expenditures for 2015 through 2017 for complying with the NRC orders are included in the planned construction and other capital investments estimates given in “Liquidity and Capital Resources - Uses of Capital” above.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Environmental Risks
Entergy Gulf States Louisiana’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Gulf States Louisiana is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Gulf States Louisiana’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy’s financial position or results of operations.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
In the fourth quarter 2014, Entergy Gulf States Louisiana recorded a revision to its estimated decommissioning cost liability for River Bend as a result of a revised decommissioning cost study. The revised estimate resulted in a $20 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining useful life of the unit.
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy Gulf States Louisiana records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Qualified Pension and Other Postretirement Benefits
Entergy Gulf States Louisiana’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
|
| | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2014 Qualified Pension Cost | | Impact on 2014 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $1,737 | | $26,342 |
| Rate of return on plan assets | | (0.25%) | | $1,117 | | $— |
| Rate of increase in compensation | | 0.25% | | $669 | | $4,020 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
|
| | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2014 Postretirement Benefit Cost | | Impact on 2014 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $534 | | $7,188 |
| Health care cost trend | | 0.25% | | $956 | | $6,643 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension cost for Entergy Gulf States Louisiana in 2014 was $18.6 million. Entergy Gulf States Louisiana anticipates 2015 qualified pension cost to be $27.5 million. Entergy Gulf States Louisiana contributed $30.2 million to its pension plans in 2014 and estimates 2015 pension contributions to be approximately $32.5 million, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.
Total postretirement health care and life insurance benefit costs for Entergy Gulf States Louisiana in 2014 were $12.2 million. Entergy Gulf States Louisiana expects 2015 postretirement health care and life insurance benefit costs of approximately $13.1 million. Entergy Gulf States Louisiana contributed $8.3 million to its other postretirement plans in 2014 and expects to contribute approximately $8.9 million in 2015.
The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $51.3 million in the qualified pension benefit obligation and $11.8 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $7.6 million and other postretirement cost by approximately $1.6 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Federal Healthcare Legislation
See the “Qualified Pension and Other Postretirement Benefits -Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Members of
Entergy Gulf States Louisiana, L.L.C.
Jefferson, Louisiana
We have audited the accompanying balance sheets of Entergy Gulf States Louisiana, L.L.C. (the “Company”) as of December 31, 2014 and 2013, and the related income statements, statements of comprehensive income, statements of cash flows, and statements of changes in equity (pages 343 through 348 and applicable items in pages 61 through 234) for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Gulf States Louisiana, L.L.C. as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2015
|
| | | | | | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. |
| INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $2,079,236 |
| |
| $1,881,895 |
| |
| $1,606,165 |
|
| Natural gas | | 71,690 |
| | 59,238 |
| | 48,729 |
|
| TOTAL | | 2,150,926 |
| | 1,941,133 |
| | 1,654,894 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 350,765 |
| | 286,625 |
| | 194,878 |
|
| Purchased power | | 849,165 |
| | 731,611 |
| | 562,247 |
|
| Nuclear refueling outage expenses | | 21,443 |
| | 20,345 |
| | 17,565 |
|
| Other operation and maintenance | | 392,398 |
| | 398,589 |
| | 361,415 |
|
| Decommissioning | | 16,844 |
| | 15,908 |
| | 15,024 |
|
| Taxes other than income taxes | | 84,178 |
| | 80,307 |
| | 76,295 |
|
| Depreciation and amortization | | 155,383 |
| | 150,929 |
| | 146,673 |
|
| Other regulatory charges (credits) - net | | (12,640 | ) | | 9,482 |
| | 31,835 |
|
| TOTAL | | 1,857,536 |
| | 1,693,796 |
| | 1,405,932 |
|
| | | | | | | |
| OPERATING INCOME | | 293,390 |
| | 247,337 |
| | 248,962 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 7,433 |
| | 8,062 |
| | 8,694 |
|
| Interest and investment income | | 40,448 |
| | 52,953 |
| | 42,773 |
|
| Miscellaneous - net | | (7,608 | ) | | (11,567 | ) | | (8,928 | ) |
| TOTAL | | 40,273 |
| | 49,448 |
| | 42,539 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 86,705 |
| | 81,118 |
| | 83,251 |
|
| Allowance for borrowed funds used during construction | | (4,315 | ) | | (2,814 | ) | | (3,343 | ) |
| TOTAL | | 82,390 |
| | 78,304 |
| | 79,908 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 251,273 |
| | 218,481 |
| | 211,593 |
|
| | | | | | | |
| Income taxes | | 88,782 |
| | 56,819 |
| | 52,616 |
|
| | | | | | | |
| NET INCOME | | 162,491 |
| | 161,662 |
| | 158,977 |
|
| | | | | | | |
| Preferred distribution requirements and other | | 827 |
| | 825 |
| | 825 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | |
| $161,664 |
| |
| $160,837 |
| |
| $158,152 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. |
| STATEMENTS OF COMPREHENSIVE INCOME |
| | |
| | For the Years Ended December 31, |
| | 2014 | | 2013 | | 2012 |
| | (In Thousands) |
| | | | | | |
| Net Income |
| $162,491 |
| |
| $161,662 |
| |
| $158,977 |
|
| | | | | | |
| Other comprehensive income | |
| | |
| | |
|
| Pension and other postretirement liabilities | |
| | |
| | |
|
| (net of tax expense (benefit) of ($15,777), $34,126, and $8,732) | (25,145 | ) | | 37,027 |
| | 4,381 |
|
| Other comprehensive income | (25,145 | ) | | 37,027 |
| | 4,381 |
|
| | | | | | |
| Comprehensive Income |
| $137,346 |
| |
| $198,689 |
| |
| $163,358 |
|
| | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
|
|
| | | | | | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. |
| STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $162,491 |
| |
| $161,662 |
| |
| $158,977 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 230,795 |
| | 223,420 |
| | 214,929 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 99,404 |
| | 86,125 |
| | 92,523 |
|
| Changes in working capital: | | |
| | |
| | |
|
| Receivables | | 31,710 |
| | (61,561 | ) | | 87,089 |
|
| Fuel inventory | | 10,348 |
| | 412 |
| | (3,718 | ) |
| Accounts payable | | 3,646 |
| | 24,694 |
| | (1,725 | ) |
| Prepaid taxes and taxes accrued | | (2,050 | ) | | (43,029 | ) | | (86,346 | ) |
| Interest accrued | | 1,267 |
| | 371 |
| | (647 | ) |
| Deferred fuel costs | | 20,205 |
| | (10,573 | ) | | (96,230 | ) |
| Other working capital accounts | | 22,323 |
| | (5,434 | ) | | (5,548 | ) |
| Changes in provisions for estimated losses | | 69,839 |
| | (60,084 | ) | | (2,222 | ) |
| Changes in other regulatory assets | | (101,173 | ) | | 123,254 |
| | (73,082 | ) |
| Changes in pension and other postretirement liabilities | | 126,889 |
| | (140,643 | ) | | 83,440 |
|
| Other | | (83,143 | ) | | 136,112 |
| | (21,232 | ) |
| Net cash flow provided by operating activities | | 592,551 |
| | 434,726 |
| | 346,208 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (272,738 | ) | | (267,122 | ) | | (284,458 | ) |
| Allowance for equity funds used during construction | | 7,433 |
| | 8,062 |
| | 8,694 |
|
| Nuclear fuel purchases | | (40,319 | ) | | (141,176 | ) | | (51,610 | ) |
| Proceeds from sale of nuclear fuel | | 66,220 |
| | 19,401 |
| | 67,632 |
|
| Investment in affiliates | | (66,243 | ) | | — |
| | — |
|
| Payment to storm reserve escrow account | | (68,523 | ) | | (29 | ) | | (99 | ) |
| Receipts from storm reserve escrow account | | — |
| | 65,475 |
| | 3,364 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 173,530 |
| | 193,792 |
| | 131,042 |
|
| Investment in nuclear decommissioning trust funds | | (191,402 | ) | | (213,122 | ) | | (150,601 | ) |
| Change in money pool receivable - net | | 759 |
| | (1,925 | ) | | 23,596 |
|
| Proceeds from the sale of investment | | — |
| | — |
| | 51,000 |
|
| Net cash flow used in investing activities | | (391,283 | ) | | (336,644 | ) | | (201,440 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 108,730 |
| | 69,770 |
| | 74,251 |
|
| Retirement of long-term debt | | — |
| | (75,000 | ) | | (70,840 | ) |
| Change in money pool payable - net | | — |
| | (7,074 | ) | | 7,074 |
|
| Changes in credit borrowings - net | | (14,800 | ) | | 14,800 |
| | (29,400 | ) |
| Dividends/distributions paid: | | |
| | |
| | |
|
| Common equity | | (166,901 | ) | | (119,900 | ) | | (114,200 | ) |
| Preferred membership interests | | (825 | ) | | (825 | ) | | (825 | ) |
| Other | | 19,910 |
| | 42 |
| | 13 |
|
| Net cash flow used in financing activities | | (53,886 | ) | | (118,187 | ) | | (133,927 | ) |
| | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | 147,382 |
| | (20,105 | ) | | 10,841 |
|
| Cash and cash equivalents at beginning of period | | 15,581 |
| | 35,686 |
| | 24,845 |
|
| Cash and cash equivalents at end of period | |
| $162,963 |
| |
| $15,581 |
| |
| $35,686 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $82,531 |
| |
| $77,882 |
| |
| $80,848 |
|
| Income taxes | |
| ($1,009 | ) | |
| $5,064 |
| |
| $89,191 |
|
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. |
| BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2014 | | 2013 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $53,394 |
| |
| $1,739 |
|
| Temporary cash investments | | 109,569 |
| | 13,842 |
|
| Total cash and cash equivalents | | 162,963 |
| | 15,581 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 67,006 |
| | 69,648 |
|
| Allowance for doubtful accounts | | (625 | ) | | (909 | ) |
| Associated companies | | 86,966 |
| | 107,723 |
|
| Other | | 18,379 |
| | 22,945 |
|
| Accrued unbilled revenues | | 54,079 |
| | 58,867 |
|
| Total accounts receivable | | 225,805 |
| | 258,274 |
|
| Deferred fuel costs | | — |
| | 9,625 |
|
| Fuel inventory - at average cost | | 16,207 |
| | 26,555 |
|
| Materials and supplies - at average cost | | 121,237 |
| | 122,909 |
|
| Deferred nuclear refueling outage costs | | 7,416 |
| | 25,975 |
|
| Prepayments and other | | 45,122 |
| | 36,698 |
|
| TOTAL | | 578,750 |
| | 495,617 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Investment in affiliate preferred membership interests | | 355,906 |
| | 289,664 |
|
| Decommissioning trust funds | | 637,744 |
| | 573,744 |
|
| Non-utility property - at cost (less accumulated depreciation) | | 193,407 |
| | 174,134 |
|
| Storm reserve escrow account | | 90,061 |
| | 21,538 |
|
| Other | | 14,887 |
| | 14,145 |
|
| TOTAL | | 1,292,005 |
| | 1,073,225 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 7,600,730 |
| | 7,400,689 |
|
| Natural gas | | 148,586 |
| | 143,902 |
|
| Construction work in progress | | 127,436 |
| | 105,314 |
|
| Nuclear fuel | | 131,901 |
| | 196,508 |
|
| TOTAL UTILITY PLANT | | 8,008,653 |
| | 7,846,413 |
|
| Less - accumulated depreciation and amortization | | 4,176,242 |
| | 4,071,762 |
|
| UTILITY PLANT - NET | | 3,832,411 |
| | 3,774,651 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Regulatory asset for income taxes - net | | 161,714 |
| | 165,456 |
|
| Other regulatory assets | | 426,381 |
| | 321,466 |
|
| Deferred fuel costs | | 100,124 |
| | 100,124 |
|
| Other | | 12,438 |
| | 12,049 |
|
| TOTAL | | 700,657 |
| | 599,095 |
|
| | | | | |
| TOTAL ASSETS | |
| $6,403,823 |
| |
| $5,942,588 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. |
| BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2014 | | 2013 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $31,955 |
| |
| $— |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 102,933 |
| | 95,853 |
|
| Other | | 108,874 |
| | 103,314 |
|
| Customer deposits | | 56,749 |
| | 51,839 |
|
| Accumulated deferred income taxes | | 21,095 |
| | 36,330 |
|
| Interest accrued | | 27,075 |
| | 25,808 |
|
| Deferred fuel costs | | 10,580 |
| | — |
|
| Other | | 44,517 |
| | 43,097 |
|
| TOTAL | | 403,778 |
| | 356,241 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 1,601,032 |
| | 1,512,547 |
|
| Accumulated deferred investment tax credits | | 72,277 |
| | 75,295 |
|
| Other regulatory liabilities | | 176,305 |
| | 159,429 |
|
| Decommissioning and asset retirement cost liabilities | | 446,619 |
| | 403,084 |
|
| Accumulated provisions | | 106,985 |
| | 37,146 |
|
| Pension and other postretirement liabilities | | 401,144 |
| | 274,315 |
|
| Long-term debt | | 1,590,862 |
| | 1,527,465 |
|
| Long-term payables - associated companies | | 26,156 |
| | 27,900 |
|
| Other | | 148,102 |
| | 108,189 |
|
| TOTAL | | 4,569,482 |
| | 4,125,370 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| EQUITY | | |
| | |
|
| Preferred membership interests without sinking fund | | 10,000 |
| | 10,000 |
|
| Member’s equity | | 1,473,910 |
| | 1,479,179 |
|
| Accumulated other comprehensive loss | | (53,347 | ) | | (28,202 | ) |
| TOTAL | | 1,430,563 |
| | 1,460,977 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $6,403,823 |
| |
| $5,942,588 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. |
| STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2014, 2013, and 2012 |
| | | | | | |
| | | | Common Equity | | |
| | Preferred
Membership
Interests | | Member’s Equity | | Accumulated Other Comprehensive Loss | | Total |
| | (In Thousands) |
| | | | | | | | |
| Balance at December 31, 2011 |
| $10,000 |
| |
| $1,393,386 |
| |
| ($69,610 | ) | |
| $1,333,776 |
|
| Net income | — |
| | 158,977 |
| | — |
| | 158,977 |
|
| Member contribution | — |
| | 1,000 |
| | — |
| | 1,000 |
|
| Other comprehensive income | — |
| | — |
| | 4,381 |
| | 4,381 |
|
| Dividends/distributions declared on common equity | — |
| | (114,200 | ) | | — |
| | (114,200 | ) |
| Dividends/distributions declared on preferred membership interests | — |
| | (825 | ) | | — |
| | (825 | ) |
| Other | — |
| | (105 | ) | | — |
| | (105 | ) |
| Balance at December 31, 2012 |
| $10,000 |
| |
| $1,438,233 |
| |
| ($65,229 | ) | |
| $1,383,004 |
|
| Net income | — |
| | 161,662 |
| | — |
| | 161,662 |
|
| Other comprehensive income | — |
| | — |
| | 37,027 |
| | 37,027 |
|
| Dividends/distributions declared on common equity | — |
| | (119,900 | ) | | — |
| | (119,900 | ) |
| Dividends/distributions declared on preferred membership interests | — |
| | (825 | ) | | — |
| | (825 | ) |
| Other | — |
| | 9 |
| | — |
| | 9 |
|
| Balance at December 31, 2013 |
| $10,000 |
| |
| $1,479,179 |
| |
| ($28,202 | ) | |
| $1,460,977 |
|
| Net income | — |
| | 162,491 |
| | — |
| | 162,491 |
|
| Other comprehensive income | — |
| | — |
| | (25,145 | ) | | (25,145 | ) |
| Dividends/distributions declared on common equity | — |
| | (166,901 | ) | | — |
| | (166,901 | ) |
| Dividends/distributions declared on preferred membership interests | — |
| | (827 | ) | | — |
| | (827 | ) |
| Other | — |
| | (32 | ) | | — |
| | (32 | ) |
| Balance at December 31, 2014 |
| $10,000 |
| |
| $1,473,910 |
| |
| ($53,347 | ) | |
| $1,430,563 |
|
| | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2014 | | 2013 | | 2012 | | 2011 | | 2010 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $2,150,926 |
| |
| $1,941,133 |
| |
| $1,654,894 |
| |
| $2,134,409 |
| |
| $2,097,021 |
|
| Net Income |
| $162,491 |
| |
| $161,662 |
| |
| $158,977 |
| |
| $201,604 |
| |
| $174,319 |
|
| Total assets |
| $6,403,823 |
| |
| $5,942,588 |
| |
| $5,803,119 |
| |
| $5,763,719 |
| |
| $5,690,376 |
|
| Long-term obligations (a) |
| $1,590,862 |
| |
| $1,527,465 |
| |
| $1,442,429 |
| |
| $1,482,430 |
| |
| $1,584,332 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt). |
| | | | | | | | | | |
| | 2014 | | 2013 | | 2012 | | 2011 | | 2010 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $502 |
| |
| $465 |
| |
| $389 |
| |
| $479 |
| |
| $498 |
|
| Commercial | 448 |
| | 417 |
| | 349 |
| | 416 |
| | 426 |
|
| Industrial | 588 |
| | 502 |
| | 392 |
| | 490 |
| | 489 |
|
| Governmental | 23 |
| | 22 |
| | 18 |
| | 22 |
| | 21 |
|
| Total retail | 1,561 |
| | 1,406 |
| | 1,148 |
| | 1,407 |
| | 1,434 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 407 |
| | 375 |
| | 377 |
| | 562 |
| | 463 |
|
| Non-associated companies | 62 |
| | 45 |
| | 34 |
| | 52 |
| | 79 |
|
| Other | 49 |
| | 56 |
| | 47 |
| | 49 |
| | 40 |
|
| Total |
| $2,079 |
| |
| $1,882 |
| |
| $1,606 |
| |
| $2,070 |
| |
| $2,016 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
|
| Residential | 5,368 |
| | 5,206 |
| | 5,176 |
| | 5,383 |
| | 5,538 |
|
| Commercial | 5,298 |
| | 5,208 |
| | 5,287 |
| | 5,239 |
| | 5,274 |
|
| Industrial | 9,925 |
| | 9,021 |
| | 8,890 |
| | 9,041 |
| | 8,801 |
|
| Governmental | 232 |
| | 228 |
| | 228 |
| | 222 |
| | 210 |
|
| Total retail | 20,823 |
| | 19,663 |
| | 19,581 |
| | 19,885 |
| | 19,823 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 6,966 |
| | 6,580 |
| | 7,727 |
| | 8,595 |
| | 8,516 |
|
| Non-associated companies | 925 |
| | 887 |
| | 941 |
| | 1,013 |
| | 1,705 |
|
| Total | 28,714 |
| | 27,130 |
| | 28,249 |
| | 29,493 |
| | 30,044 |
|
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
In June 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed a business combination study report with the LPSC. The report contained a preliminary analysis of the potential combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility, including an overview of the combination that identified its potential customer benefits. Although not part of the business combination, Entergy Louisiana provided notice to the City Council in June 2014 that it would seek authorization to transfer to Entergy New Orleans the assets that currently support the provision of service to Entergy Louisiana’s customers in Algiers. Entergy Louisiana subsequently filed the referenced application with the City Council in October 2014. In the summer of 2014, Entergy Louisiana and Entergy Gulf States Louisiana held technical conferences and face-to-face meetings with LPSC staff and other stakeholders to discuss potential effects of the combination, solicit suggestions and concerns, and identify areas in which additional information might be needed.
On September 30, 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed an application with the LPSC seeking authorization to undertakeauthorize the transactions that would result in the combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility.
The combination is subject to regulatory review and approvalsecuritization of the LPSC, the FERC, and the NRC. In June 2014, Entergy submitted an application to the NRC for approval of River Bend and Waterford 3 license transfers as part of the steps to complete the business combination. The combination also could be subject to regulatory review of the City Council if Entergy Louisiana continues to own the assets that currently support Entergy Louisiana’s customers in Algiers at the time the combination is effectuated. In November 2014, Entergy Louisiana filed an applicationinvestment recovery costs associated with the City Council seeking authorization to undertake the combination. The application provides that if the City Council approves the Algiers asset transfer before the business combination occurs, the City Council may not needproject and to issue a public interest finding regarding the combination. In December 2014,financing order by which Entergy Louisiana and Entergy Gulf States Louisiana filed applications with the FERC requesting authorization for the business combination and the Algiers asset transfer.could accomplish such securitization. In January 2015, Entergy Services filed an application with the FERC for financing authority for the combined company. If approvals are obtained fromAugust 2011 the LPSC issued an order approving the FERC, the NRC,settlement and if required, the City Council, Entergy Louisiana and Entergy Gulf States Louisiana expect the combination will be effected in the second half of 2015.also
The procedural schedule in the LPSC business combination proceeding calls for LPSC Staff and intervenor testimony to be filed in March 2015, with a hearing scheduled for June 2015. Entergy Louisiana and Entergy Gulf States Louisiana have requested that the LPSC issue its decision regarding the business combination in August 2015. In the City Council business combination proceeding, the City Council announced through a resolution that it would not initiate an active review of the business combination filing, but instead would establish a business combination docket for the limited purpose of receiving information filings relative to the business combination proceedings at the LPSC.
It is currently contemplated that Entergy Louisiana and Entergy Gulf States Louisiana will undertake multiple steps to effectuate the combination, which steps would include the following:
Each of Entergy Louisiana and Entergy Gulf States Louisiana will redeem or repurchase all of their respective outstanding preferred membership interests (which interests have a $100 million liquidation value in the case of Entergy Louisiana and $10 million liquidation value in the case of Entergy Gulf States Louisiana).
Entergy Gulf States Louisiana will convert from a Louisiana limited liability company to a Texas limited liability company.
Under the Texas Business Organizations Code (TXBOC), Entergy Louisiana will allocate substantially all of its assets to a new subsidiary (New Entergy Louisiana) and New Entergy Louisiana will assume all
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
issued a financing order for the securitization. See Note 5 to the financial statements for a discussion of the liabilitiesSeptember 2011 issuance of the securitization bonds.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Louisiana in a transaction regarded as a merger under the TXBOC.charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Louisiana will remainis regulated and the rates charged to its customers are determined in existence and holdregulatory proceedings. A governmental agency, the membership interests in New Entergy Louisiana.
Under the TXBOC, Entergy Gulf States Louisiana will allocate substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana will assume allLPSC, is primarily responsible for approval of the liabilitiesrates charged to customers.
Retail Rates - Electric
Filings with the LPSC
2014 Formula Rate Plan Filing
In connection with the approval of Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. Entergy Gulf States Louisiana will remain in existence and hold the membership interests in New Entergy Gulf States Louisiana.
Entergy Louisiana and Entergy Gulf States Louisiana will contribute the membership interests in New Entergy Louisiana and New Entergy Gulf States Louisiana to an affiliate the common membership interestsbusiness combination of which will be owned by Entergy Louisiana, Entergy Gulf States Louisiana and Entergy Corporation.
NewLouisiana, the LPSC authorized the filing of a single, joint, formula rate plan evaluation report for Entergy Gulf States Louisiana’s and Entergy Louisiana’s 2014 calendar year operations. The joint evaluation report was filed in September 2015 and reflected an earned return on common equity of 9.09%. As such, no adjustment to base formula rate plan revenue was required. The following adjustments were required under the formula rate plan, however: a decrease in the additional capacity mechanism for Entergy Louisiana of $17.8 million; an increase in the additional capacity mechanism for Entergy Gulf States Louisiana will merge into New Entergy Louisiana with New Entergy Louisiana survivingof $4.3 million; and a reduction of $5.5 million to the merger.
UponMISO cost recovery mechanism to collect approximately $35.7 million on a combined-company basis. Under the order approving the business combination, following completion of the steps, Newprescribed review period, rates were implemented with the first billing cycle of December 2015, subject to refund. In June 2017 the LPSC staff and Entergy Louisiana will hold substantially allfiled an unopposed joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of this proceeding with no changes to rates already implemented.
2015 Formula Rate Plan Filing
In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflected an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue was required. The following other adjustments, however, were required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the assets, and will have assumed alltermination of the liabilities, of Entergy Louisiana and Entergy Gulf States Louisiana. Entergy Louisiana andSystem Agreement; an increase in the legacy Entergy Gulf States Louisiana may modify or supplement the steps to be taken to effect the combination.
Resultsadditional capacity mechanism of Operations
Net Income
2014 Compared to 2013
Net income increased $31.1$0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily due to higher net revenuereflect the effects of the termination of the System Agreement; and higher other income, partially offset by higher other operation and maintenance expenses, higher depreciation and amortization expenses, and higher interest expense.
2013 Compared to 2012
Net income decreased $28.6an increase of $11 million primarily due to higher other operation and maintenance expenses, higher depreciation and amortization expenses, higher interest expense, and higher nuclear refueling outage expenses, partially offset by higher net revenue. Also contributing to the decreaseMISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in net income wasSeptember 2016, there were several interim updates to Entergy Louisiana’s formula rate plan, including the one submitted in December 2016, reflecting implementation of the settlement of the tax treatment related toWaterford 3 replacement steam generator project prudence review described below. In June 2017 the Hurricane KatrinaLPSC staff and Hurricane RitaEntergy Louisiana Act 55 financingfiled a joint report of proceedings, which was accepted by the LPSC in June 2012, which resulted in a $142.7 million reduction of income tax expense partially offset by a $137.1 million ($84.3 million net-of-tax) regulatory charge, which reduced net revenue in 2012. See Note 3 to2017, finalizing the financial statements for additional discussionresults of the tax treatment.May 2016 evaluation report, interim updates, and corresponding proceedings with no changes to rates already implemented.
Extension of MISO Cost Recovery Mechanism Rider
In November 2016, Entergy Louisiana filed with the LPSC a request to extend the MISO cost recovery mechanism rider provision of its formula rate plan. In March 2017 the LPSC staff submitted direct testimony generally supportive of a one-year extension of the MISO cost recovery mechanism and the intervenor in the proceeding did not
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Net Revenueoppose an extension for this period of time. In July 2017 an uncontested joint stipulation authorizing a one-year extension of the MISO cost recovery mechanism rider was approved.
2014 Compared to 20132016 Formula Rate Plan Filing
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2014 to 2013.
|
| | | |
| Amount |
| (In Millions) |
| |
2013 net revenue |
| $1,208.8 |
|
MISO deferral | 16.9 |
|
Retail electric price | 15.7 |
|
Asset retirement obligation | 15.2 |
|
Volume/weather | 12.6 |
|
Other | 13.3 |
|
2014 net revenue |
| $1,282.5 |
|
The MISO deferral variance is due to the deferral in 2014 of non-fuel MISO-related charges, as approved by the LPSC. The deferral of non-fuel MISO-related charges is partially offset in other operation and maintenance expenses. See Note 2 to the financial statements for further discussion of the recovery of non-fuel MISO-related charges.
The retail electric price variance is primarily due to an increase in affiliated purchased power capacity costs that are recovered through base rates set in the annualIn May 2017, Entergy Louisiana filed its formula rate plan mechanism and aevaluation report for its 2016 calendar year operations. The evaluation report reflected an earned return on common equity of 9.84%. As such, no adjustment to base formula rate plan increase effective December 2014. Entergy Louisiana’srevenue was required. Adjustments, however, were required under the formula rate plan; the 2016 formula rate plan is discussedevaluation report showed a decrease in Note 2 to the financial statements.
The asset retirement obligation affects netformula rate plan revenue because Entergy Louisiana records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The variance is primarily caused by an increase in regulatory credits becauseof approximately $16.9 million, comprised of a decrease in decommissioning trust earnings, increaseslegacy Entergy Louisiana formula rate plan revenue of $3.5 million, a decrease in depreciationlegacy Entergy Gulf States Louisiana formula rate plan revenue of $9.7 million, and accretion expenses, and an increasea decrease in regulatory creditsincremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 million in the MISO cost recovery revenue requirement from the present level of $46.8 million to realign$6.3 million. Rates reflecting these adjustments were implemented with the asset retirement obligation regulatory asset with regulatory treatment.first billing cycle of September 2017, subject to refund. In September 2017 the LPSC issued its report indicating that no changes to Entergy Louisiana’s original formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report.
The volume/weather variance is primarily dueFormula Rate Plan Extension Request
In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications to its terms. Those modifications include: a one-time resetting of base rates to the midpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95% for the 2017 test year; narrowing of the formula rate plan bandwidth from a total of 160 basis points to 80 basis points; and a forward-looking mechanism that would allow Entergy Louisiana to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers. Entergy Louisiana requested that the LPSC consider its request on an increaseexpedited basis, in an effort to maintain Entergy Louisiana’s current cycle for implementing rate adjustments, i.e., September 2018, without the need for filing a full base rate case proceeding. Several parties have intervened in the proceeding and all parties have been participating in settlement discussions.
Waterford 3 Replacement Steam Generator Project
Following the completion of 682 GWh,the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or 2%,documentation from Entergy Louisiana. An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent. Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in billed electricity usage,December 2014. At the hearing the parties maintained the positions reflected in pre-filed testimony. Entergy Louisiana believed that the replacement steam generator costs were prudently incurred and applicable legal principles supported their recovery in rates. Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the effectselection, use, and oversight of more favorable weather on residentialcontractors, and commercial sales as comparedcould not reasonably have anticipated the damage to the prior yearsteam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and an increasesubcontractor and, therefore, recommended a disallowance of $67 million in industrial usage primarily due to increased consumptioncapital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by a large industrial customerthe LPSC, after considering the progress of the proceeding in light of the chemicals industry as a result of a prior year plant outage and the addition of new mid-small industrial customers.ALJ recommendation, Entergy
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2013 Compared to 2012
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2013 to 2012.
|
| | | |
| Amount |
| (In Millions) |
| |
2012 net revenue |
| $933.3 |
|
Louisiana Act 55 financing savings obligation | 137.6 |
|
Retail electric price | 91.5 |
|
Volume/weather | 23.9 |
|
Net wholesale revenue | 18.1 |
|
Fuel recovery | 9.4 |
|
Other | (5.0 | ) |
2013 net revenue |
| $1,208.8 |
|
The Louisiana Act 55 financing savings obligation variance results from a regulatory charge recorded in the secondfourth quarter 2012 because Entergy Louisiana was required2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to share with customers the savings from the tax treatment related to the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing. See Note 3 to the financial statements for additional discussionreflect that a portion of the tax treatment.
The retail electric price variance is primarily due to a formula rate plan increase effective January 2013. See Note 2 to the financial statements for discussion of the formula rate plan increase.
The volume/weather variance is primarily due to an increase of 512 GWh in billed electricity usage in all sectors due to the effect of more favorable weather as compared to the previous year on residential sales and the effect of Hurricane Isaac, which decreased sales volume in 2012. The increase in industrial usage was also driven by a higher capacity factor in the petroleum industry.
The net wholesale revenue variance is primarily due to the sale to Entergy Gulf States Louisiana of one-third of Acadia Unit 2 capacity and energy.
The fuel recovery variance is primarily due to the expiration of the Evangeline gas contract on January 1, 2013.
Other Income Statement Variances
2014 Compared to 2013
Other operation and maintenance expenses increased primarily due to:
a $16 million write-off recorded in 2014 because of the uncertaintyassets associated with the resolution of the Waterford 3 replacement steam generator project prudence review. See Note 2was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contained significant factual and legal errors.
In October 2016 the parties reached a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectively provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to the financial statements for further discussioncustomers of approximately $71 million as a result of the prudence review;
an increasesettlement approved by the LPSC was made to customers in January 2017. Of the $71 million of $10.5refunds, $68 million duewas credited to administration feescustomers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 related to the participation$67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the MISO RTOfuture. Following a review by the parties, an unopposed joint report of proceedings was filed by the LPSC staff and Entergy Louisiana in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.
Ninemile 6
In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with the LPSC, which was subsequently approved, that estimated a first year revenue requirement associated with Ninemile 6 and provided a mechanism to update the revenue requirement as the in-service date approached. In late-December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of $26.8 million for Entergy Gulf States Louisiana and $51.1 million for Entergy Louisiana was filed. The December 2014 estimate formed the basis of rates implemented effective December 2013.with the first billing cycle of January 2015. In July 2015, Entergy Louisiana submitted to the LPSC a compliance filing including an estimate at completion, inclusive of interconnection costs and transmission upgrades, of approximately $648 million, or $76 million less than originally estimated, along with other project details and supporting evidence, to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project. Testimony filed by the LPSC staff generally supported the prudence of the management of the project and recovery of the costs incurred to complete the project. The LPSC staff had questioned the warranty coverage for one element of the project. In October 2016 all parties agreed to a stipulation providing that 100% of Ninemile 6 construction costs was prudently incurred and is eligible for recovery from customers, but reserving the LPSC’s rights to review the prudence of Entergy Louisiana’s actions regarding one element of the project. This stipulation was approved deferralby the LPSC in January 2017.
Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana Plants
In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of these expenses resultingthe acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in no net income effect;the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $474 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.
an increase of $9.7 million in regulatory, consulting, and legal fees;
an increase of $7.9 million in nuclear generation expenses primarily due to higher labor costs, including contract labor, higher materials costs, and higher NRC fees;
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
an increase of $7.3 million in fossil-fueled generation expenses primarily due to an overall higher scope of work done during plant outages as compared to prior year;
an increase of $4.4 million in transmission expenses primarily due to increased transmission equalization expenses and higher vegetation maintenance;
an increase of $2.1 million as a result of higher write-offs of uncollectible accounts in 2014;
an increase of $1.7 million in distribution vegetation maintenance expenses; and
several individually insignificant items.
The increase was partially offset by:
a decrease of $24 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
a decrease of $6.1 million relating to the sale of surplus oil inventory in 2014; and
a decrease of $5.9 million due to costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other income increased primarily due to:
an increase of $9.5 million due to distributions earned on preferred membership interests purchased from Entergy Holdings Company with the proceeds received in August 2014 from the Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;
$7.6 million of carrying charges recorded in 2014 on storm restoration costs related to Hurricane Isaac as approved by the LPSC; and
the increase in allowance for equity funds used during construction due to a higher construction work in progress balance in 2014, including the Ninemile Unit 6 Self-Build Project.
The increase was partially offset by higher realized gains in 2013 on Waterford 3 decommissioning trust fund investments.
Interest expense increased primarily due to:
the issuance of $325 million of 4.05% Series first mortgage bonds in August 2013;
the issuance of $170 million of 5.0% Series first mortgage bonds in June 2014; and
the issuance of $190 million of 3.78% Series first mortgage bonds in July 2014.
The increase was partially offset by an increase in the allowance for borrowed funds used during construction due to a higher construction work in progress balance in 2014, including the Ninemile Unit 6 Self-Build Project.
2013 Compared to 2012
Nuclear refueling outage expenses increased primarily due to the amortization of higher expenses associated with the refueling outage at Waterford 3.
Other operation and maintenance expenses increased primarily due to:
an increase of $20.9 million in compensation and benefits costs primarily due to a decrease in the discount
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates”below and Note 11 to the financial statements for further discussion of benefits costs;
an increase of $16.5 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative, substantially offset by the deferral, as approved by the LPSC, of $13 million of these costs. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion;
an increase of $5.4 million in nuclear generation expenses primarily due to higher labor and materials costs; and
the prior year deferral, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced 2012 expenses by $5.2 million.
The increase was partially offset by a decrease of $9.2 million in fossil-fueled generation expenses due to an overall lower scope of work done during plant outages as compared to the prior year.
Also, other operation and maintenance expenses include $5.9 million in 2013 and $6.7 million in 2012 of costs incurred related to the now terminated plan to spin off and merge the transmission business.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including placing in service the Waterford 3 steam generator project in December 2012.
Interest expense increased primarily due to:
the issuance of $200 million of 5.25% Series first mortgage bonds in July 2012;
the issuance of $200 million of 3.30% Series first mortgage bonds in December 2012;
the issuance of $100 million of 4.70% Series first mortgage bonds in May 2013; and
the issuance of $325 million of 4.05% Series first mortgage bonds in August 2013.
Income Taxes
The effective income tax rates for 2014, 2013, and 2012, were 25.3%, 24.5%, and (84.7%), respectively. The effective income tax rate of (84.7%) for 2012 was primarily due to the settlement of the tax treatment of the Louisiana Act 55 financing of the Hurricane Katrina and Hurricane Rita storm costs and the reversal of the provision for the uncertain tax positions related to that item. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates and for a discussion of the IRS settlement and audits.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2014, 2013, and 2012 were as follows:
|
| | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $124,007 |
| |
| $30,086 |
| |
| $878 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 1,126,040 |
| | 662,772 |
| | 447,698 |
|
| Investing activities | (938,758 | ) | | (540,807 | ) | | (850,866 | ) |
| Financing activities | (153,736 | ) | | (28,044 | ) | | 432,376 |
|
| Net increase in cash and cash equivalents | 33,546 |
| | 93,921 |
| | 29,208 |
|
| | | | | | |
| Cash and cash equivalents at end of period |
| $157,553 |
| |
| $124,007 |
| |
| $30,086 |
|
Operating Activities
Net cash flow provided by operating activities increased $463.3 million in 2014 primarily due to proceeds of $240 million received from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financing, an increase in income tax refunds of $207.8 million, and the timing of collections from customers. The increase was partially offset by an increase of $33.4 million in pension contributions in 2014 and an increase of $15.6 million in interest paid resulting from an increase in interest expense, as discussed above. Entergy Louisiana had income tax refunds in 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds are primarily due to favorable adjustments allowed in the IRS Audit of the 2006-2007 tax years and a carryback of a 2008 net operating loss. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Net cash flow provided by operating activities increased $215.1 million in 2013 primarily due to decreased Hurricane Isaac storm spending in 2013 and a decrease of $7.7 million in pension contributions. The increase was partially offset by an increase of $12.4 million in interest paid resulting from the increase in interest expense, as discussed above, and a decrease of $7.8 million in income tax refunds. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Investing Activities
Net cash flow used in investing activities increased $398 million in 2014 primarily due to:
the investment in 2014 of $227 million in affiliate securities as a result of the Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;
the deposit of $200 million into the storm reserve escrow account in 2014;
receipts of $187 million from the storm reserve escrow account in 2013;
an increase in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
an increase in transmission construction expenditures as a result of additional reliability work performed in 2014.
The increase was partially offset by a decrease in fossil-fueled generation construction expenditures due to lower spending on the Ninemile Unit 6 self-rebuild project and money pool activity.
Decreases in Entergy Louisiana’s receivable from the money pool are a source of cash flow, and Entergy Louisiana’s receivable from the money pool decreased by $16 million in 2014 compared to increasing by $8.2 million in 2013. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Net cash flow used in investing activities decreased $310.1 million in 2013 primarily due to:
receipts of $187 million from the storm reserve escrow account in 2013 compared to receipts of $14.5 million in 2012;
a decrease in nuclear construction expenditures due to the Waterford 3 steam generator replacement project in 2012;
a decrease in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and
a decrease in distribution construction expenditures due to higher Hurricane Isaac spending in prior year.
The decrease was partially offset by an increase in fossil-fueled generation construction expenditures due to spending on the Ninemile Unit 6 self-build project and an increase in transmission construction expenditures as a result of additional reliability work performed in 2013.
Financing Activities
Net cash used by financing activities increased $125.7 million in 2014 primarily due to the net issuance of $130.7 million of long-term debt in 2014 compared to the net issuance of $386.9 million of long-term debt in 2013, partially offset by borrowings of $43.1 million on the nuclear fuel company variable interest entity’s credit facility in 2014 compared to the repayment of borrowings of $51.7 million in 2013 and a decrease of $35.7 million in common equity distributions in 2014.
Entergy Louisiana’s financing activities used $28 million of cash in 2013 compared to providing $432.4 million of cash in 2012 primarily due to:
an increase of $340.7 million in common equity distributions in 2013;
the net issuance of $386.9 million of long-term debt in 2013 compared to the net issuance of $613.1 million of long-term debt in 2012; and
money pool activity.
Decreases in Entergy Louisiana’s payable to the money pool are a use of cash flow, and Entergy Louisiana’s payable to the money pool decreased by $118.4 million in 2012.
See Note 5 to the financial statements for details of long-term debt.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Capital Structure
Entergy Louisiana’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital ratio for Entergy Louisiana is primarily due to an increase in long-term debt as a result of the issuance of $190 million of 3.78% Series first mortgage bonds in July 2014.
|
| | | | | |
| | December 31,
2014 | | December 31,
2013 |
| Debt to capital | 53.8 | % | | 52.0 | % |
| Effect of excluding securitization bonds | (1.0 | %) | | (1.3 | %) |
| Debt to capital, excluding securitization bonds (a) | 52.8 | % | | 50.7 | % |
| Effect of subtracting cash | (1.3 | %) | | (1.1 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 51.5 | % | | 49.6 | % |
| |
(a) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Louisiana. |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Louisiana uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition. Entergy Louisiana uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluation Entergy Louisiana’s financial condition because net debt indicates Entergy Louisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents.
Uses of Capital
Entergy Louisiana requires capital resources for:
construction and other capital investments;
debt and preferred equity maturities or retirements;
working capital purposes, including the financing of fuel and purchased power costs; and
distribution and interest payments.
Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.
|
| | | | | | | | | | | |
| | 2015 | | 2016 | | 2017 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $225 |
| |
| $205 |
| |
| $395 |
|
| Transmission | 100 |
| | 90 |
| | 155 |
|
| Distribution | 160 |
| | 185 |
| | 140 |
|
| Other | 30 |
| | 20 |
| | 20 |
|
| Total |
| $515 |
| |
| $500 |
| |
| $710 |
|
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
|
| | | | | | | | | | | | | | | | | | | |
| | 2015 | | 2016-2017 | | 2018-2019 | | After 2019 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $183 |
| |
| $476 |
| |
| $580 |
| |
| $4,682 |
| |
| $5,921 |
|
| Operating leases |
| $11 |
| |
| $18 |
| |
| $11 |
| |
| $5 |
| |
| $45 |
|
| Purchase obligations (b) |
| $682 |
| |
| $1,260 |
| |
| $1,135 |
| |
| $3,623 |
| |
| $6,700 |
|
| |
(a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
(b) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Louisiana, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Vidalia purchased power agreement and the Unit Power Sales Agreement, both of which are discussed in Note 8 to the financial statements. |
In addition to the contractual obligations given above, Entergy Louisiana currently expects to contribute approximately $57 million to its pension plans and approximately $9.9 million to other postretirement plans in 2015, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also, in addition to the contractual obligations, Entergy Louisiana has $38.1 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes specific investments such as NRC post-Fukushima requirements; environmental compliance spending; transmission projects to enhance reliability, reduce congestion, and enable economic growth; resource planning; generation projects; system improvements; and other investments. Entergy’s Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
Management provides more information on long-term debt maturities in Note 5 to the financial statements.
As an indirect, majority-owned subsidiarya term of Entergy Corporation,the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana pays distributions from its earnings atagreed to make a percentage determined monthly. Entergy Louisiana’s long-term debt indenture contains restrictions on the payment of cash dividends or other distributions on its common and preferred membership interests.
Ninemile Point Unit 6 Self-Build Project
In June 2011, Entergy Louisiana filedfiling with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station. Ninemile 6 is a nominally-sized 560 MW unit that is expected to cost approximately $655 million to construct when spending is complete, excluding interconnection and transmission upgrades. Entergy Gulf States Louisiana joined in the application, seeking certification of its purchase under a life-of-unit power purchase agreement of up to 25% of the capacity and energy
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
generated by Ninemile 6. The Ninemile 6 capacity and energy is allocated 55% to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20% to Entergy New Orleans. In February 2012 the City Council passed a resolution authorizing Entergy New Orleans to purchase 20% of the Ninemile 6 energy and capacity. In March 2012 the LPSC unanimously voted to grant the certifications requested by Entergy Gulf States Louisiana and Entergy Louisiana. Following approval by the LPSC, Entergy Louisiana issued full notice to proceed to the project’s engineering, procurement, and construction contractor.
Under terms approved by the LPSC, non-fuel costs may be recovered through Entergy Louisiana’s formula rate plan beginning in the month after the unit is placed in service. In July 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed an unopposed stipulation with the LPSC that estimates a first year revenue requirement associated with Ninemile 6 and provides a mechanism to update the revenue requirement as the in-service date approaches, which was subsequently approved by the LPSC. In late December 2014, roughly contemporaneous with the unit’s placement in service, a final updated estimated revenue requirement of $51.1 million for Entergy Louisiana was filed. The December 2014 estimate forms the basis of rates implemented effective with the first billing cycle of January 2015. Entergy Louisiana will submit project and cost information to the LPSC in mid-2015 to enable the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1. In January 2016, Entergy Louisiana made its compliance filing with the LPSC. Entergy Louisiana, LPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the current deactivation decisions for the ten-year planning horizon. Parties have requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4. No party contests the prudence of the decision to deactivate Willow Glen 2 and 4 or suggests reactivation of these units; however, issues have been raised related to Entergy Louisiana’s management ofdecision to give up its transmission service rights in MISO for Willow Glen 2 and 4 rather than placing the project.units into suspended status for the three-year term permitted by MISO. An evidentiary hearing was held in August 2017 and post-hearing briefs were submitted in October 2017. A decision is expected in 2018.
New Nuclear Development
Entergy Gulf States Louisiana and Entergy Louisiana have been developing and are preserving a project option for new nuclear generation at River Bend. In the first quarter 2010, Entergy Gulf States Louisiana and Entergy Louisiana each paid for and recognized on its books $24.9 million in costs associated with the development of new nuclear generation at the River Bend site; these costs previously had been recorded on the books of Entergy New Nuclear Utility Development, LLC, a System Energy subsidiary. Entergy Gulf States Louisiana and Entergy Louisiana will share costs going forward on a 50/50 basis, which reflects each company’s current participation level in the project.
In March 2010, Entergy Gulf States Louisiana and Entergy Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend. At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Gulf States Louisiana and Entergy Louisiana be declined on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification. The LPSC directed that Entergy Gulf States Louisiana and Entergy Louisiana be permitted to seek recovery of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding, the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of a new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2014, Entergy Gulf States Louisiana and Entergy Louisiana each have a regulatory asset of $29.2 million on its balance sheet related to these new nuclear generation development costs.
Sources of Capital
Entergy Louisiana’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt or preferred membership interest issuances; and
bank financing under new or existing facilities.
Entergy Louisiana may refinance, redeem, or otherwise retire debt and preferred membership interests prior to maturity, to the extent market conditions and interest and distribution rates are favorable.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
All debt and common and preferred membership interest issuances by Entergy Louisiana require prior regulatory approval. Preferred membership interest and debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2014 | | 2013 | | 2012 | | 2011 |
| (In Thousands) |
| $1,649 | | $17,648 | | $9,433 | | ($118,415) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Louisiana has a credit facility in the amount of $200 million scheduled to expire in March 2019. The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, there were no cash borrowings and no letters of credit outstanding under the credit facility. See Note 4 to the financial statements for additional discussion of the credit facility. In addition, Entergy Louisiana entered into an uncommitted letter of credit facility in 2014 as a means to post collateral to support its obligations under MISO. As of December 31, 2014, a $4.7 million letter of credit was outstanding under Entergy Louisiana’s letter of credit facility.
The Entergy Louisiana nuclear fuel company variable interest entity has a credit facility in the amount of $90 million scheduled to expire in June 2016. As of December 31, 2014, $46.1 million of letters of credit were outstanding under the credit facility to support a like amount of commercial paper issued by the Entergy Louisiana nuclear fuel company variable interest entity. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Louisiana obtained authorizations from the FERC through October 2015 for the following:
short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding;
long-term borrowings and security issuances; and
long-term borrowings by its nuclear fuel company variable interest entity.
See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.
In February 2014 the Entergy Louisiana nuclear fuel company variable interest entity issued $40 million of 3.92% Series H Notes due February 2021. The Entergy Louisiana nuclear fuel company variable interest entity used the proceeds to purchase additional nuclear fuel.
In June 2014, Entergy Louisiana issued $170 million of 5% Series first mortgage bonds due July 2044. Entergy Louisiana used the proceeds to pay, prior to maturity, its $70 million 6.4% Series first mortgage bonds due October 2034 and to pay, prior to maturity, its $100 million 6.3% Series first mortgage bonds due September 2035.
In July 2014, Entergy Louisiana issued $190 million of 3.78% Series first mortgage bonds due April 2025. Entergy Louisiana used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.
In July 2014 the Entergy Louisiana nuclear fuel company variable interest entity redeemed, at maturity, its $50 million of 5.69% Series E Notes.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In November 2014, Entergy Louisiana issued $250 million of 4.95% Series first mortgage bonds due January 2045. Entergy Louisiana used the proceeds to repay, at maturity, its $250 million of 1.875% Series first mortgage bonds due December 2014.
Hurricane Isaac
In August 2012, Hurricane Isaac caused extensive damage to Entergy Louisiana’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. In January 2013, Entergy Louisiana drew $187 million from its funded storm reserve escrow account. In April 2013, Entergy Gulf States Louisiana and Entergy Louisiana filed a joint application withJune 2014 the LPSC relating to Hurricane Isaac system restoration costs. In May 2013, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane Isaac system restoration costs incurred by Entergy Gulf States Louisiana and Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of each company’s costs. Following an evidentiary hearing and recommendations by the ALJ, the LPSC voted in June 2014 to approve a series of orders which (i) quantify the amountquantified $290.8 million of Hurricane Isaac system restoration costs as prudently incurred ($66.5incurred; (ii) determined $290 million for Entergy Gulf States Louisiana and $224.3 million for Entergy Louisiana); (ii) determineas the level of storm reserves to be re-established ($90 million for Entergy Gulf States Louisiana and $200 million for Entergy Louisiana);re-established; (iii) authorize Entergy Gulf States Louisiana andauthorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) grantgranted other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Louisiana committed to pass on to customers a minimum of $23.9$30.8 million of customer benefits through annual customer credits of approximately $4.8$6.2 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.
In July 2014, Entergy Louisiana issued $190 million See Note 2 to the financial statements for a discussion of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.
In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $243.85 million inissuance of bonds under Act 55 of the Louisiana Legislature. From the $240 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $13 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $227 million directly to Entergy Louisiana. Entergy Louisiana used the $227 million received from the LURC to acquire 2,272,725.89 Class C preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 7.5% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2014, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1.75 billion.
Entergy Louisiana does not report the bonds on its balance sheet because the bonds are the obligation of the LCDA and there is no recourse against Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee. Entergy Louisiana does not report the collections as revenue because it is merely acting as the billing and collection agent for the state.
Little Gypsy Repowering Project
In April 2007, Entergy Louisiana announced that it intended to pursue the solid fuel repowering of a 538 MW unit at its Little Gypsy plant. In March 2009 the LPSC voted in favor of a motion directing Entergy Louisiana to
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
temporarily suspend the repowering project and, based upon an analysis of the project’s economic viability, to make a recommendation regarding whether to proceed with the project. This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital/financial markets. In April 2009, Entergy Louisiana complied with the LPSC’s directive and recommended that the project be suspended for an extended period of time of three years or more. In May 2009 the LPSC issued an order declaring that Entergy Louisiana’s decision to place the Little Gypsy project into a longer-term suspension of three years or more is in the public interest and prudent.
In October 2009, Entergy Louisiana made a filing with the LPSC seeking permission to cancel the Little Gypsy repowering project and seeking project cost recovery over a five-year period. In June 2010 and August 2010, the LPSC Staffstaff and Intervenorsintervenors filed testimony. The LPSC Staffstaff (1) agreed that it was prudent to move the project from long-term suspension to cancellation and that the timing of the decision to suspend on a longer-term basis was not imprudent; (2) indicated that, except for $0.8 million in compensation-related costs, the costs incurred should be deemed prudent; (3) recommended recovery from customers over ten years but stated that the LPSC may want to consider 15 years; (4) allowed for recovery of carrying costs and earning a return on project costs, but at a reduced rate approximating the cost of debt, while also acknowledging that the LPSC may consider ordering no return; and (5) indicated that Entergy Louisiana should be directed to securitize project costs, if legally feasible and in the public interest. In the third quarter 2010, in accordance with accounting standards, Entergy Louisiana determined that it was probable that the Little Gypsy repowering project would be abandoned and accordingly reclassified $199.8 million of project costs from construction work in progress to a regulatory asset. A hearing on the issues, except for cost allocation among customer classes, was held before the ALJ in November 2010. In January 2011 all parties participated in a mediation on the disputed issues, resulting in a settlement of all disputed issues, including cost recovery and cost allocation. The settlement provides for Entergy Louisiana to recover $200 million as of March 31, 2011, and carrying costs on that amount on specified terms thereafter. The settlement also provides for Entergy Louisiana to recover the approved project costs by securitization. In April 2011, Entergy Louisiana filed an application with the LPSC to authorize the securitization of the investment recovery costs associated with the project and to issue a financing order by which Entergy Louisiana could accomplish such securitization. In August 2011 the LPSC issued an order approving the settlement and also
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Management’s Financial Discussion and Analysis
issued a financing order for the securitization. See Note 5 to the financial statements for a discussion of the September 2011 issuance of the securitization bonds.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Louisiana is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.
Retail Rates - Electric
Filings with the LPSC
2014 Formula Rate Plan Filing
In May 2005connection with the approval of the business combination of Entergy Gulf States Louisiana and Entergy Louisiana, the LPSC approved a rateauthorized the filing settlement that included the adoption of a three-yearsingle, joint, formula rate plan the terms of which included an ROE mid-point of 10.25%evaluation report for the initial three-year term of the planEntergy Gulf States Louisiana’s and permit Entergy Louisiana to recover incremental capacity costs outside of a traditional base rate proceeding. Under the formula rate plan, over- and under-earnings outside an allowed regulatory range of 9.45% to 11.05% will be allocated 60% to customers and 40% to Entergy Louisiana. The initial formula rate plan filing was made in May 2006. As discussed below the formula rate plan has been extended, with return on common equity provisions consistent with previously approved provisions, to cover the 2008, 2009, 2010, and 2011 test years.
In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan. In May 2012, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2011 test year.2014 calendar year operations. The filingjoint evaluation report was filed in September 2015 and reflected a 9.63%an earned return on common equity of 9.09%. As such, no adjustment to base formula rate plan revenue was required. The following adjustments were required under the formula rate plan, however: a decrease in the additional capacity mechanism for Entergy Louisiana of $17.8 million; an increase in the additional capacity mechanism for Entergy Gulf States Louisiana of $4.3 million; and a reduction of $5.5 million to the MISO cost recovery mechanism to collect approximately $35.7 million on a combined-company basis. Under the order approving the business combination, following completion of the prescribed review period, rates were implemented with the first billing cycle of December 2015, subject to refund. In June 2017 the LPSC staff and Entergy Louisiana filed an unopposed joint report of proceedings, which is withinwas accepted by the earnings bandwidthLPSC in June 2017, finalizing the results of this proceeding with no changes to rates already implemented.
2015 Formula Rate Plan Filing
In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflected an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue was required. The following other adjustments, however, were required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and resultedan increase of $11 million to the MISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in September 2016, there were several interim updates to Entergy Louisiana’s formula rate plan, including the one submitted in December 2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. In June 2017 the LPSC staff and Entergy Louisiana filed a joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of the May 2016 evaluation report, interim updates, and corresponding proceedings with no changes to rates already implemented.
Extension of MISO Cost Recovery Mechanism Rider
In November 2016, Entergy Louisiana filed with the LPSC a request to extend the MISO cost recovery mechanism rider provision of serviceits formula rate plan. In March 2017 the LPSC staff submitted direct testimony generally supportive of a one-year extension of the MISO cost recovery mechanism and the intervenor in the proceeding did not
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Management’s Financial Discussion and Analysis
change underoppose an extension for this period of time. In July 2017 an uncontested joint stipulation authorizing a one-year extension of the MISO cost recovery mechanism rider was approved.
2016 Formula Rate Plan Filing
In May 2017, Entergy Louisiana filed its formula rate plan.plan evaluation report for its 2016 calendar year operations. The filing also reflected an $18.1 million rate increase for the incremental capacity rider. In August 2012, Entergy Louisiana submitted a revised filing thatevaluation report reflected an earned return on common equity of 10.38%, which is still within9.84%. As such, no adjustment to base formula rate plan revenue was required. Adjustments, however, were required under the earnings bandwidth, resultingformula rate plan; the 2016 formula rate plan evaluation report showed a decrease in no costformula rate plan revenue of serviceapproximately $16.9 million, comprised of a decrease in legacy Entergy Louisiana formula rate change. The revised filing also indicated that an increaseplan revenue of $15.9$3.5 million, should be reflecteda decrease in legacy Entergy Gulf States Louisiana formula rate plan revenue of $9.7 million, and a decrease in incremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 million in the incremental capacity rider. The rate change wasMISO cost recovery revenue requirement from the present level of $46.8 million to $6.3 million. Rates reflecting these adjustments were implemented subject to refund, effective for bills renderedwith the first billing cycle of September 2012. Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflected two items: 1) a $17 million reduction for the first-year capacity charges for the purchase by Entergy Gulf States Louisiana from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project, which was in-service in December 2012. These rate changes were implemented,2017, subject to refund, effective with the first billing cycle of January 2013.refund. In April 2013, Entergy Louisiana andSeptember 2017 the LPSC staff filed a jointissued its report resolving the 2011 test yearindicating that no changes to Entergy Louisiana’s original formula rate plan and recovery relatedevaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report.
Formula Rate Plan Extension Request
In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications to its terms. Those modifications include: a one-time resetting of base rates to the Grand Gulf uprate. This report was approved bymidpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95% for the 2017 test year; narrowing of the formula rate plan bandwidth from a total of 160 basis points to 80 basis points; and a forward-looking mechanism that would allow Entergy Louisiana to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers. Entergy Louisiana requested that the LPSC consider its request on an expedited basis, in April 2013.an effort to maintain Entergy Louisiana’s current cycle for implementing rate adjustments, i.e., September 2018, without the need for filing a full base rate case proceeding. Several parties have intervened in the proceeding and all parties have been participating in settlement discussions.
WithWaterford 3 Replacement Steam Generator Project
Following the completion of the Waterford 3 replacement steam generator project, the LPSC is conductingundertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC Staffstaff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana. An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent. Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. At the hearing the parties maintained the positions reflected in pre-filed testimony. A post-hearing briefing schedule has not been established. Entergy Louisiana believesbelieved that the replacement steam generator costs were prudently incurred and applicable legal principles supportsupported their recovery in rates. Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Louisiana, and the required filing was made on February 15, 2013. The filing anticipated Entergy Louisiana’s integration into MISO. In the filing Entergy Louisiana requested, among other relief:
authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service);
an authorized return on common equity of 10.4%;
authorization to increase depreciation rates embedded in the proposed revenue requirement; and
authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirements on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.
Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. The settlement provides for a $10 million rate increase effective with the first billing cycle of December 2014. Major terms of the settlement include approval of a three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain
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Management’s Financial Discussion and Analysis
special recovery items; (3) three-year amortizationLouisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of costs to achieve savingsthe assets associated with the human capital management strategic imperative,Waterford 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contained significant factual and legal errors.
In October 2016 the parties reached a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectively provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to customers of approximately $71 million as a result of the settlement approved by the LPSC was made to customers in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with savings reflected aspotential service credits agreed to by the project contractor, to the extent they are realized in subsequent years; (4) eight-year amortizationthe future. Following a review by the parties, an unopposed joint report of costs incurredproceedings was filed by the LPSC staff and Entergy Louisiana in connectionMay 2017 and the LPSC accepted the joint report of proceedings resolving the matter.
Ninemile 6
In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with potential developmentthe LPSC, which was subsequently approved, that estimated a first year revenue requirement associated with Ninemile 6 and provided a mechanism to update the revenue requirement as the in-service date approached. In late-December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of a new nuclear unit at River Bend, without carrying costs, beginning$26.8 million for Entergy Gulf States Louisiana and $51.1 million for Entergy Louisiana was filed. The December 2014 provided, however, that amortizationestimate formed the basis of these costs shall not result in a future rate increase; (5) recovery of non-fuel MISO-related costs and any changes to the additional capacity revenue requirement related to test year 2013rates implemented effective with the first billing cycle of December 2014;January 2015. In July 2015, Entergy Louisiana submitted to the LPSC a compliance filing including an estimate at completion, inclusive of interconnection costs and (6) a cumulative $30transmission upgrades, of approximately $648 million, cap on costor $76 million less than originally estimated, along with other project details and supporting evidence, to enable the LPSC to review the prudence of service increases over the three-year formula rate plan cycle, except for those items outsideEntergy Louisiana’s management of the sharing mechanism. Existing depreciation rates will not change.
Pursuantproject. Testimony filed by the LPSC staff generally supported the prudence of the management of the project and recovery of the costs incurred to complete the rate case settlementproject. The LPSC staff had questioned the warranty coverage for one element of the project. In October 2016 all parties agreed to a stipulation providing that 100% of Ninemile 6 construction costs was prudently incurred and is eligible for recovery from customers, but reserving the LPSC’s rights to review the prudence of Entergy Louisiana’s actions regarding one element of the project. This stipulation was approved by the LPSC in December 2013,January 2017.
Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana submittedPlants
In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $474 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
As a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1. In January 2016, Entergy Louisiana made its compliance filing in May 2014 reflectingwith the effects of the $10 million agreed-upon increase in formula rate plan revenue, the estimated MISO cost recovery mechanism revenue requirement, and the adjustment of the additional capacity mechanism. In November 2014,LPSC. Entergy Louisiana, submitted an additional compliance filing updatingLPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the estimated MISO cost recovery mechanismcurrent deactivation decisions for the most recent actual data, as well as providing for a refund and prospective reduction in rates for the true-up of the estimated revenue requirement for the Waterford 3 replacement steam generator project. Basedten-year planning horizon. Parties have requested further proceedings on this updated filing, a net increase of $41.7 million in formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings are subject to the review in accordance with the review process set forth in Entergy Louisiana’s formula rate plan. Additionally, the adjustments of rates made related to the Waterford 3 replacement steam generator project included in the December 2014 compliance filing are subject to final true-up following completion of the LPSC’s determination regarding the prudence of the project.decision to deactivate Willow Glen 2 and 4. No party contests the prudence of the decision to deactivate Willow Glen 2 and 4 or suggests reactivation of these units; however, issues have been raised related to Entergy Louisiana’s decision to give up its transmission service rights in MISO for Willow Glen 2 and 4 rather than placing the units into suspended status for the three-year term permitted by MISO. An evidentiary hearing was held in August 2017 and post-hearing briefs were submitted in October 2017. A decision is expected in 2018.
Filings with the City CouncilRetail Rates - Gas
In March 2013,accordance with the settlement of Entergy Louisiana filed aGulf States Louisiana’s gas rate casestabilization plan for the Algiers area, which istest year ended September 30, 2012, in New OrleansAugust 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is regulatedsubject to the following conditions, among others: a ten-year term; application of any earnings in excess of 10.45% as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the City Council. Entergy Louisiana requested a rate increaseLPSC in January 2015. Implementation of $13 million over three years, including a 10.4% return on common equity and a formula rate plan mechanism identical to its LPSC request made in February 2013. In January 2014, the City Council Advisors filed direct testimony recommending a rate increase of $5.56 million over three years, including an 8.13% return on common equity. In June 2014 the City Council unanimously approved a settlement that includes the following:
a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;
recovery of an additional $853 thousand annually through a MISO recovery rider; and
adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.
The rate increase was effectiveinfrastructure rider commenced with bills rendered on and after the first billing cycle of July 2014. Additional compliance filings were madeApril 2015.
2014 Rate Stabilization Plan Filing
In January 2015, Entergy Gulf States Louisiana filed with the CouncilLPSC its gas rate stabilization plan for the test year ended September 30, 2014. The filing showed an earned return on common equity of 7.20%, which resulted in October 2014a $706 thousand rate increase. In April 2015 the LPSC issued findings recommending two adjustments to Entergy Gulf States Louisiana’s as-filed results, and an additional recommendation that did not affect the results. The LPSC staff’s recommended adjustments increase the earned return on equity for approvalthe test year to 7.24%. Entergy Gulf States Louisiana accepted the LPSC staff’s recommendations and a revenue increase of $688 thousand was implemented with the first billing cycle of May 2015.
2015 Rate Stabilization Plan Filing
In January 2016, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2015. The filing showed an earned return on common equity of 10.22%, which is within the authorized bandwidth, therefore requiring no change in rates. In March 2016 the LPSC staff issued its report stating that the 2015 gas rate stabilization plan filing was in compliance with the exception of several issues that required additional information, explanation, or clarification for which the LPSC staff had reserved the right to further review. In July 2016 the parties to the proceeding filed an unopposed joint report and motion for entry of order accepting the report that indicated no outstanding issues remained in the filing.
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Management’s Financial Discussion and Analysis
In February 2016, Entergy Louisiana filed a motion requesting to extend the term of the gas rate stabilization plan in substantially similar form for an additional three-year term and included a request for sharing of certainnon-jurisdictional compressed natural gas revenues. Following discovery and the filing of testimony by the LPSC staff, Entergy Louisiana and the LPSC submitted a joint motion for hearing an uncontested stipulated settlement resolving the proceeding. A hearing on the stipulation was held in November 2016. The ALJ issued a report of proceedings that was presented with the parties’ stipulation to the LPSC for consideration. The stipulation approving Entergy Louisiana’s requested extension of the rate riders, including among others,stabilization plan was approved by the LPSC in December 2016.
2016 Rate Stabilization Plan Filing
In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflected an earned return on common equity of 6.37%. As part of the original filing, pursuant to the extraordinary cost provision of the rate stabilization plan, Entergy Louisiana sought to recover approximately $1.5 million in deferred operation and maintenance expenses incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. Entergy Louisiana requested to recover the prudently incurred August 2016 storm restoration costs over ten years, outside of the rate stabilization plan sharing provisions. As a Ninemile 6 non-fuelresult, Entergy Louisiana’s filing sought an annual increase in revenue of $1.4 million. Following review of the filing, except for the proposed extraordinary cost recovery, interim rider, allowingthe LPSC staff confirmed Entergy Louisiana’s filing was consistent with the principles and requirements of the rate stabilization plan. The extraordinary cost recovery request associated with the 2016 flood-related deferred operation and maintenance expenses incurred for contemporaneousgas operations was removed from the rate stabilization plan pending LPSC consideration in a separate docket. In April 2017 the LPSC approved a joint report of proceedings and Entergy Louisiana submitted a revised evaluation report reflecting a $1.2 million annual increase in revenue with rates implemented with the first billing cycle of May 2017.
In connection with the joint report of proceedings accepted by the LPSC, in May 2017, Entergy Louisiana filed an application to initiate a separate proceeding to recover through the extraordinary cost provision of the gas rate stabilization plan the deferred operation and maintenance expenses of $1.4 million incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. The LPSC staff submitted its direct testimony in the proceeding recommending recovery of capacity costs related$0.9 million. Entergy Louisiana filed rebuttal testimony responding to the commencement of commercialLPSC staff’s recommendation. The procedural schedule was suspended to allow the parties to engage in settlement negotiations, and in February 2018 the LPSC staff and Entergy Louisiana filed an unopposed settlement. If approved by the LPSC, the settlement would provide for Entergy Louisiana to recover, over ten years, the approximately $1.4 million in deferred operation and maintenance expense and related carrying charges. The settlement further provides for recovery to commence in May 2018.
2017 Rate Stabilization Plan Filing
In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for test year ended September 30, 2017. The filing of the Ninemile 6 generating unitevaluation report for the test year 2017 reflected an earned return on common equity of 9.06%. This earned return is below the earnings sharing band of the rate stabilization plan and results in a purchased power capacity cost recovery rider. The Ninemile 6 cost recovery interim rider was implementedrate increase of $0.1 million. Due to the enactment in December 2014 to collect $915 thousand fromlate-December 2017 of the Tax Cuts and Jobs Act, Entergy Louisiana customersdid not have adequate time to reflect the effects of this tax legislation in the Algiers area.rate stabilization plan. As a result, Entergy Louisiana will file a supplement to the January 2018 evaluation report to reflect, among other things, a 21% federal corporate income tax rate. Any rate change resulting from the revised rate stabilization plan will become effective in rates in May 2018.
Fuel and purchased power recovery
Entergy Louisiana recovers electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Louisiana’s purchased gas adjustments include
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
In April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includesincluded a review of the reasonableness of charges flowed through the fuel adjustment clause by
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Management’s Financial Discussion and Analysis
Entergy Louisiana for the period from 2005 through 2009. The LPSC Staffstaff issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1 million from Entergy Louisiana’s fuel adjustment clause to base rates. The recommended refund was made by Entergy Louisiana in May 2013 in the form of a credit to customers through its fuel adjustment clause filing. TwoIn October 2016 the LPSC staff filed testimony affirming the recommendation in its audit report on the lone remaining issue that nuclear dry fuel storage costs should be realigned to base rates. The parties intervenedagreed to remove that remaining issue to a separate docket because the same issue was outstanding in the proceeding. A procedural schedule was establishedEntergy Gulf States Louisiana audit for the identificationsame time period. In November 2016 the LPSC approved the resolution of issuesthis audit and the creation of a new docket for the resolution of the proper method of recovery for nuclear dry fuel storage costs. In December 2016 the LPSC opened a new docket in order to resolve the issue regarding the proper methodology for the recovery of nuclear dry fuel storage costs. In October 2017 the LPSC approved the continued recovery of the nuclear dry fuel storage costs through the fuel adjustment clause, resolving the open issue in the audit.
In December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009. In March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that it was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained positions from its report. Subsequently, the parties entered into a settlement, which was approved by the intervenors and for Entergy Louisiana to submit comments regardingLPSC in November 2016. The settlement recognized the dry cask storage recovery method issue, which was addressed in the separate proceeding approved by the LPSC Staff reportin October 2017, provided for a refund of $5 million, which was made to legacy Entergy Gulf States Louisiana customers in December 2016, and anyresolved all other issues raised by intervenors. One intervenor is seeking further proceedings regarding certain issues it raised in its comments onthe audit.
In July 2014 the LPSC Staff report.authorized its staff to initiate an audit of Entergy Gulf States Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana has filed responses to boththrough its fuel adjustment clause for the LPSC Staff report and the issues raised by the intervenor. As required by the procedural schedule, a joint status report was submitted in October 2013 by the parties. A status conference was held in Decemberperiod from 2010 through 2013. Discovery iscommenced in progress, but a procedural scheduleJuly 2015. No report of audit has not been established.issued.
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015. No report of audit has yet to commence.been issued.
In June 2016 the LPSC staff provided notice of audits of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2014 through 2015 and charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2012 through 2015. Discovery commenced in March 2017. No report of audit has been issued.
Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs, Entergy Louisiana plans to cap the
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Management’s Financial Discussion and Analysis
average fuel adjustment charge to be billed in March 2018 at $0.03060 per kWh and to defer billing of all fuel costs in excess of the capped amounts by including such costs in the over- or under-recovery account.
Industrial and Commercial Customers
Entergy Louisiana’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Louisiana’s industrial customer base. Entergy Louisiana responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Entergy Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
Entergy Louisiana owns and, through an affiliate, operates the River Bend and Waterford 3 nuclear power plants. Entergy Louisiana is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, to position Entergy’s nuclear fleet to meet its operational goals, including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems and the Fukushima event; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license renewal and amendments, and decommissioning; the performance and capacity factors of these nuclear plants; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts and types of insurance commercially available for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of River Bend or Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.
Waterford 3’s operating license is currently due to expire in December 2024. In March 2016, Entergy Louisiana filed an application with the NRC for an extension of Waterford 3’s operating license to 2044. River Bend’s operating license is currently due to expire in August 2025. In May 2017, Entergy Louisiana filed an application with the NRC for an extension of River Bend’s operating license to 2045. In October 2017 an intervenor filed with the NRC a petition to intervene and request for a hearing on the River Bend license renewal application. As provided by NRC procedure, a panel of the Atomic Safety and Licensing Board has been designated to determine whether the intervenor’s three proposed contentions, or allegations of errors or omissions in the license renewal application, are admissible and, if so, to rule on any admitted contentions. In January 2018 the Atomic Safety and Licensing Board denied the petition to intervene and the request for hearing.
Environmental Risks
Entergy Louisiana’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Louisiana is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
“Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Louisiana’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Louisiana’s financial position or results of operations.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Unbilled Revenue
See “Unbilled Revenue” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the unbilled revenue amounts.
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets and trust fund investments.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Louisiana’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2018 Qualified Pension Cost | | Impact on 2017 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $3,737 | | $54,506 |
| Rate of return on plan assets | | (0.25%) | | $3,309 | | $— |
| Rate of increase in compensation | | 0.25% | | $1,726 | | $8,824 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2018 Postretirement Benefit Cost | | Impact on 2017 Accumulated postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $753 | | $10,727 |
| Health care cost trend | | 0.25% | | $1,219 | | $8,675 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension cost for Entergy Louisiana in 2017 was $44.3 million. Entergy Louisiana anticipates 2018 qualified pension cost to be $52.1 million. In 2016, Entergy Louisiana refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $14.2 million. Entergy Louisiana contributed $87.5 million to its pension plans in 2017 and estimates pension contributions will be approximately $71.9 million in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018.
Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 2017 were $12.6 million. Entergy Louisiana expects 2018 postretirement health care and life insurance benefit costs of approximately $11.2 million. In 2016, Entergy Louisiana refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $3.5 million. Entergy Louisiana contributed $14.4 million to its other postretirement plans in 2017 and estimates that 2018 contributions will be approximately $19 million.
Federal Healthcare Legislation
See “Qualified Pension and Other Postretirement Benefits -Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the members and Board of Directors of
Entergy Louisiana, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of income, comprehensive income, cash flows, and changes in equity (pages 349 through 354 and applicable items in pages 55 through 230), for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2018
We have served as the Company’s auditor since 2001.
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $4,246,020 |
| |
| $4,126,343 |
| |
| $4,361,524 |
|
| Natural gas | | 54,530 |
| | 50,705 |
| | 55,622 |
|
| TOTAL | | 4,300,550 |
| | 4,177,048 |
| | 4,417,146 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 912,060 |
| | 804,433 |
| | 850,869 |
|
| Purchased power | | 980,070 |
| | 890,058 |
| | 1,129,910 |
|
| Nuclear refueling outage expenses | | 52,074 |
| | 51,361 |
| | 44,480 |
|
| Other operation and maintenance | | 969,400 |
| | 923,779 |
| | 997,546 |
|
| Decommissioning | | 49,457 |
| | 46,944 |
| | 43,445 |
|
| Taxes other than income taxes | | 175,359 |
| | 165,665 |
| | 167,966 |
|
| Depreciation and amortization | | 467,369 |
| | 451,290 |
| | 437,036 |
|
| Other regulatory charges (credits) - net | | (152,080 | ) | | 44,131 |
| | 27,562 |
|
| TOTAL | | 3,453,709 |
| | 3,377,661 |
| | 3,698,814 |
|
| | | | | | | |
| OPERATING INCOME | | 846,841 |
| | 799,387 |
| | 718,332 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 51,485 |
| | 27,925 |
| | 19,192 |
|
| Interest and investment income | | 164,550 |
| | 154,778 |
| | 150,168 |
|
| Miscellaneous - net | | (11,960 | ) | | (11,597 | ) | | (13,190 | ) |
| TOTAL | | 204,075 |
| | 171,106 |
| | 156,170 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 275,185 |
| | 273,283 |
| | 259,894 |
|
| Allowance for borrowed funds used during construction | | (25,914 | ) | | (14,571 | ) | | (10,702 | ) |
| TOTAL | | 249,271 |
| | 258,712 |
| | 249,192 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 801,645 |
| | 711,781 |
| | 625,310 |
|
| | | | | | | |
| Income taxes | | 485,298 |
| | 89,734 |
| | 178,671 |
|
| | | | | | | |
| NET INCOME | | 316,347 |
| | 622,047 |
| | 446,639 |
|
| | | | | | | |
| Preferred distribution requirements and other | | — |
| | — |
| | 5,737 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | |
| $316,347 |
| |
| $622,047 |
| |
| $440,902 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | | | |
| Net Income | |
| $316,347 |
| |
| $622,047 |
| |
| $446,639 |
|
| | | | | | | |
| Other comprehensive income | | |
| | |
| | |
|
| Pension and other postretirement liabilities | | |
| | |
| | |
|
| (net of tax expense of $234, $5,034, and $14,316) | | 2,042 |
| | 7,970 |
| | 22,811 |
|
| Other comprehensive income | | 2,042 |
| | 7,970 |
| | 22,811 |
|
| | | | | | | |
| Comprehensive Income | |
| $318,389 |
| |
| $630,017 |
| |
| $469,450 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $316,347 |
| |
| $622,047 |
| |
| $446,639 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 621,018 |
| | 620,211 |
| | 593,635 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 575,804 |
| | 178,549 |
| | 97,461 |
|
| Changes in working capital: | | |
| | |
| | |
|
| Receivables | | (53,829 | ) | | (102,200 | ) | | (12,795 | ) |
| Fuel inventory | | 11,010 |
| | (2,693 | ) | | (887 | ) |
| Accounts payable | | 58,880 |
| | (36,720 | ) | | 23,641 |
|
| Prepaid taxes and taxes accrued | | 128,261 |
| | (235,246 | ) | | 105,687 |
|
| Interest accrued | | (70 | ) | | 1,218 |
| | 2,933 |
|
| Deferred fuel costs | | 23,236 |
| | (17,023 | ) | | 4,222 |
|
| Other working capital accounts | | (30,911 | ) | | 6,462 |
| | (41,890 | ) |
| Changes in provisions for estimated losses | | (8,324 | ) | | 490 |
| | (8,946 | ) |
| Changes in other regulatory assets | | 492,696 |
| | 57,579 |
| | 130,762 |
|
| Changes in other regulatory liabilities | | 605,453 |
| | 62,351 |
| | 96,234 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | (1,207,808 | ) | | — |
| | — |
|
| Changes in pension and other postretirement liabilities | | (32,309 | ) | | (52,559 | ) | | (98,695 | ) |
| Other | | (161,909 | ) | | (64,554 | ) | | (182,485 | ) |
| Net cash flow provided by operating activities | | 1,337,545 |
| | 1,037,912 |
| | 1,155,516 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (1,662,835 | ) | | (1,030,416 | ) | | (845,227 | ) |
| Allowance for equity funds used during construction | | 51,485 |
| | 27,925 |
| | 19,192 |
|
| Insurance proceeds | | 5,305 |
| | 10,564 |
| | — |
|
| Nuclear fuel purchases | | (197,829 | ) | | (73,618 | ) | | (244,040 | ) |
| Proceeds from the sale of nuclear fuel | | 42,634 |
| | 63,304 |
| | 54,595 |
|
| Payment for purchase of plant | | — |
| | (474,670 | ) | | — |
|
| Payments to storm reserve escrow account | | (2,110 | ) | | (1,063 | ) | | (308 | ) |
| Receipts from storm reserve escrow account | | 8,835 |
| | — |
| | — |
|
| Changes in securitization account | | 880 |
| | 351 |
| | (137 | ) |
| Proceeds from nuclear decommissioning trust fund sales | | 231,293 |
| | 219,182 |
| | 123,474 |
|
| Investment in nuclear decommissioning trust funds | | (266,592 | ) | | (257,209 | ) | | (158,028 | ) |
| Changes in money pool receivable - net | | 11,330 |
| | (16,349 | ) | | (3,339 | ) |
| Proceeds from sale of assets | | — |
| | — |
| | 59,610 |
|
| Payment for purchase of assets | | (9,805 | ) | | — |
| | — |
|
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | — |
| | 57,934 |
| | — |
|
| Net cash flow used in investing activities | | (1,787,409 | ) | | (1,474,065 | ) | | (994,208 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 733,344 |
| | 2,450,063 |
| | 77,172 |
|
| Retirement of long-term debt | | (407,736 | ) | | (1,488,870 | ) | | (180,595 | ) |
| Redemption of preferred membership interests | | — |
| | — |
| | (110,286 | ) |
| Changes in credit borrowings - net | | 39,746 |
| | (56,562 | ) | | 14,322 |
|
| Distributions paid: | | |
| | |
| | |
|
| Common equity | | (91,250 | ) | | (285,500 | ) | | (226,000 | ) |
| Preferred membership interests | | — |
| | — |
| | (6,082 | ) |
| Other | | (2,183 | ) | | (4,230 | ) | | (15,253 | ) |
| Net cash flow provided by (used in) financing activities | | 271,921 |
| | 614,901 |
| | (446,722 | ) |
| Net increase (decrease) in cash and cash equivalents | | (177,943 | ) | | 178,748 |
| | (285,414 | ) |
| Cash and cash equivalents at beginning of period | | 213,850 |
| | 35,102 |
| | 320,516 |
|
| Cash and cash equivalents at end of period | |
| $35,907 |
| |
| $213,850 |
| |
| $35,102 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $266,871 |
| |
| $324,456 |
| |
| $243,745 |
|
| Income taxes | |
| ($234,199 | ) | |
| $156,605 |
| |
| $89,124 |
|
| Non-cash financing activities: | | | | | | |
| Capital contribution from parent | |
| $— |
| |
| $— |
| |
| ($267,826 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $5,836 |
| |
| $49,972 |
|
| Temporary cash investments | | 30,071 |
| | 163,878 |
|
| Total cash and cash equivalents | | 35,907 |
| | 213,850 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 254,308 |
| | 213,517 |
|
| Allowance for doubtful accounts | | (8,430 | ) | | (6,277 | ) |
| Associated companies | | 143,524 |
| | 155,794 |
|
| Other | | 60,893 |
| | 54,186 |
|
| Accrued unbilled revenues | | 153,118 |
| | 159,176 |
|
| Total accounts receivable | | 603,413 |
| | 576,396 |
|
| Fuel inventory | | 39,728 |
| | 50,738 |
|
| Materials and supplies - at average cost | | 299,881 |
| | 294,421 |
|
| Deferred nuclear refueling outage costs | | 65,711 |
| | 22,535 |
|
| Prepaid taxes | | — |
| | 110,104 |
|
| Prepayments and other | | 34,035 |
| | 41,687 |
|
| TOTAL | | 1,078,675 |
| | 1,309,731 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Investment in affiliate preferred membership interests | | 1,390,587 |
| | 1,390,587 |
|
| Decommissioning trust funds | | 1,312,073 |
| | 1,140,707 |
|
| Storm reserve escrow account | | 284,759 |
| | 291,485 |
|
| Non-utility property - at cost (less accumulated depreciation) | | 245,255 |
| | 217,494 |
|
| Other | | 18,999 |
| | 28,844 |
|
| TOTAL | | 3,251,673 |
| | 3,069,117 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 19,678,536 |
| | 18,827,532 |
|
| Natural gas | | 191,899 |
| | 172,816 |
|
| Construction work in progress | | 1,281,452 |
| | 670,201 |
|
| Nuclear fuel | | 337,402 |
| | 249,807 |
|
| TOTAL UTILITY PLANT | | 21,489,289 |
| | 19,920,356 |
|
| Less - accumulated depreciation and amortization | | 8,703,047 |
| | 8,420,596 |
|
| UTILITY PLANT - NET | | 12,786,242 |
| | 11,499,760 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Regulatory asset for income taxes - net | | — |
| | 470,480 |
|
| Other regulatory assets (includes securitization property of $71,367 as of December 31, 2017 and $92,951 as of December 31, 2016) | | 1,145,842 |
| | 1,168,058 |
|
| Deferred fuel costs | | 168,122 |
| | 168,122 |
|
| Other | | 18,310 |
| | 16,003 |
|
| TOTAL | | 1,332,274 |
| | 1,822,663 |
|
| | | | | |
| TOTAL ASSETS | |
| $18,448,864 |
| |
| $17,701,271 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $675,002 |
| |
| $200,198 |
|
| Short-term borrowings | | 43,540 |
| | 3,794 |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 126,685 |
| | 82,106 |
|
| Other | | 404,374 |
| | 358,741 |
|
| Customer deposits | | 150,623 |
| | 148,601 |
|
| Taxes accrued | | 18,157 |
| | — |
|
| Interest accrued | | 75,528 |
| | 75,598 |
|
| Deferred fuel costs | | 71,447 |
| | 48,211 |
|
| Other | | 79,037 |
| | 80,013 |
|
| TOTAL | | 1,644,393 |
| | 997,262 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 2,050,371 |
| | 2,691,118 |
|
| Accumulated deferred investment tax credits | | 121,870 |
| | 126,741 |
|
| Regulatory liability for income taxes - net | | 725,368 |
| | — |
|
| Other regulatory liabilities | | 761,059 |
| | 880,974 |
|
| Decommissioning | | 1,140,461 |
| | 1,082,685 |
|
| Accumulated provisions | | 302,448 |
| | 310,772 |
|
| Pension and other postretirement liabilities | | 748,384 |
| | 780,278 |
|
| Long-term debt (includes securitization bonds of $77,736 as of December 31, 2017 and $99,217 as of December 31, 2016) | | 5,469,069 |
| | 5,612,593 |
|
| Other | | 176,637 |
| | 137,039 |
|
| TOTAL | | 11,495,667 |
| | 11,622,200 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| EQUITY | | |
| | |
|
| Member’s equity | | 5,355,204 |
| | 5,130,251 |
|
| Accumulated other comprehensive loss | | (46,400 | ) | | (48,442 | ) |
| TOTAL | | 5,308,804 |
| | 5,081,809 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $18,448,864 |
| |
| $17,701,271 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2017, 2016, and 2015 |
| | | | | | |
| | | | Common Equity | | |
| | Preferred Membership Interests | | Member’s Equity | | Accumulated Other Comprehensive Income (Loss) | | Total |
| | (In Thousands) |
| | | | | | | | |
| Balance at December 31, 2014 |
| $110,000 |
| |
| $4,316,210 |
| |
| ($79,223 | ) | |
| $4,346,987 |
|
| Net income | — |
| | 446,639 |
| | — |
| | 446,639 |
|
| Other comprehensive income | — |
| | — |
| | 22,811 |
| | 22,811 |
|
| Preferred stock redemption | (110,000 | ) | | — |
| | — |
| | (110,000 | ) |
| Non-cash contribution from parent | — |
| | 267,826 |
| | — |
| | 267,826 |
|
| Distributions to parent | — |
| | (226,000 | ) | | — |
| | (226,000 | ) |
| Distributions declared on preferred membership interests | — |
| | (5,737 | ) | | — |
| | (5,737 | ) |
| Other | — |
| | (5,214 | ) | | — |
| | (5,214 | ) |
| Balance at December 31, 2015 |
| $— |
| |
| $4,793,724 |
| |
| ($56,412 | ) | |
| $4,737,312 |
|
| Net income | — |
| | 622,047 |
| | — |
| | 622,047 |
|
| Other comprehensive income | — |
| | — |
| | 7,970 |
| | 7,970 |
|
| Distributions to parent | — |
| | (285,500 | ) | | — |
| | (285,500 | ) |
| Other | — |
| | (20 | ) | | — |
| | (20 | ) |
| Balance at December 31, 2016 |
| $— |
| |
| $5,130,251 |
| |
| ($48,442 | ) | |
| $5,081,809 |
|
| Net income | — |
| | 316,347 |
| | — |
| | 316,347 |
|
| Other comprehensive income | — |
| | — |
| | 2,042 |
| | 2,042 |
|
| Distributions declared on common equity | — |
| | (91,250 | ) | | — |
| | (91,250 | ) |
| Other | — |
| | (144 | ) | | — |
| | (144 | ) |
| Balance at December 31, 2017 |
| $— |
| |
| $5,355,204 |
| |
| ($46,400 | ) | |
| $5,308,804 |
|
| | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $4,300,550 |
| |
| $4,177,048 |
| |
| $4,417,146 |
| |
| $4,740,504 |
| |
| $4,399,511 |
|
| Net income |
| $316,347 |
| |
| $622,047 |
| |
| $446,639 |
| |
| $446,022 |
| |
| $414,126 |
|
| Total assets |
| $18,448,864 |
| |
| $17,701,271 |
| |
| $16,387,447 |
| |
| $16,423,825 |
| |
| $15,275,863 |
|
| Long-term obligations (a) |
| $5,469,069 |
| |
| $5,612,593 |
| |
| $4,806,790 |
| |
| $4,882,813 |
| |
| $4,383,273 |
|
| | | | | | | | | | |
(a) Includes long-term debt (excluding currently maturing debt).
| | | | |
| | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $1,198 |
| |
| $1,196 |
| |
| $1,292 |
| |
| $1,358 |
| |
| $1,304 |
|
| Commercial | 956 |
| | 930 |
| | 989 |
| | 1,044 |
| | 1,003 |
|
| Industrial | 1,534 |
| | 1,350 |
| | 1,420 |
| | 1,569 |
| | 1,457 |
|
| Governmental | 69 |
| | 67 |
| | 67 |
| | 70 |
| | 68 |
|
| Total retail | 3,757 |
| | 3,543 |
| | 3,768 |
| | 4,041 |
| | 3,832 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 278 |
| | 368 |
| | 406 |
| | 427 |
| | 320 |
|
| Non-associated companies | 64 |
| | 50 |
| | 36 |
| | 80 |
| | 48 |
|
| Other | 147 |
| | 165 |
| | 152 |
| | 121 |
| | 140 |
|
| Total |
| $4,246 |
| |
| $4,126 |
| |
| $4,362 |
| |
| $4,669 |
| |
| $4,340 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | |
| | |
| | |
| | |
| | |
|
| Residential | 13,357 |
| | 13,810 |
| | 14,399 |
| | 14,415 |
| | 14,026 |
|
| Commercial | 11,342 |
| | 11,478 |
| | 11,700 |
| | 11,555 |
| | 11,402 |
|
| Industrial | 29,754 |
| | 28,517 |
| | 27,713 |
| | 27,025 |
| | 25,734 |
|
| Governmental | 790 |
| | 794 |
| | 756 |
| | 732 |
| | 723 |
|
| Total retail | 55,243 |
| | 54,599 |
| | 54,568 |
| | 53,727 |
| | 51,885 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 4,793 |
| | 7,345 |
| | 7,500 |
| | 6,240 |
| | 5,168 |
|
| Non-associated companies | 1,711 |
| | 1,690 |
| | 770 |
| | 1,051 |
| | 979 |
|
| Total | 61,747 |
| | 63,634 |
| | 62,838 |
| | 61,018 |
| | 58,032 |
|
| | | | | | | | | | |
ENTERGY MISSISSIPPI, INC.
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Net Income
2017 Compared to 2016
Net income increased $0.8 million primarily due to higher other income, lower other operation and maintenance expenses, and lower interest expense, substantially offset by higher depreciation and amortization expenses and a higher effective income tax rate.
2016 Compared to 2015
Net income increased $16.5 million primarily due to lower other operation and maintenance expenses, higher net revenues, and a lower effective income tax rate, partially offset by higher depreciation and amortization expenses.
Net Revenue
2017 Compared to 2016
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory credits. Following is an analysis of the change in net revenue comparing 2017 to 2016.
|
| | | |
| Amount |
| (In Millions) |
| |
| 2016 net revenue |
| $705.4 |
|
| Volume/weather | (18.2 | ) |
| Retail electric price | 13.5 |
|
| Other | 2.4 |
|
| 2017 net revenue |
| $703.1 |
|
The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales.
The retail electric price variance is primarily due to a $19.4 million net annual increase in rates, effective with the first billing cycle of July 2016, and an increase in the energy efficiency rider, effective with the first billing cycle of February 2017, each as approved by the MPSC. The increase was partially offset by decreased storm damage rider revenues due to resetting the storm damage provision to zero beginning with the November 2016 billing cycle. Entergy Mississippi resumed billing the storm damage rider effective with the September 2017 billing cycle. See Note 2 to the financial statements for more discussion of the formula rate plan and the storm damage rider.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
2016 Compared to 2015
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
| 2015 net revenue |
| $696.3 |
|
| Retail electric price | 12.9 |
|
| Volume/weather | 4.7 |
|
| Net wholesale revenue | (2.4 | ) |
| Reserve equalization | (2.8 | ) |
| Other | (3.3 | ) |
| 2016 net revenue |
| $705.4 |
|
The retail electric price variance is primarily due to a $19.4 million net annual increase in revenues, as approved by the MPSC, effective with the first billing cycle of July 2016, and an increase in revenues collected through the storm damage rider. See Note 2 to the financial statements for more discussion of the formula rate plan and the storm damage rider.
The volume/weather variance is primarily due to an increase of 153 GWh, or 1%, in billed electricity usage, including an increase in industrial usage, partially offset by the effect of less favorable weather on residential and commercial sales. The increase in industrial usage is primarily due to expansion projects in the pulp and paper industry, increased demand for existing customers, primarily in the metals industry, and new customers in the wood products industry.
The net wholesale revenue variance is primarily due to Entergy Mississippi’s exit from the System Agreement in November 2015.
The reserve equalization revenue variance is primarily due to the absence of reserve equalization revenue as compared to the same period in 2015 resulting from Entergy Mississippi’s exit from the System Agreement in November 2015.
Other Income Statement Variances
2017 Compared to 2016
Other operation and maintenance expenses decreased primarily due to:
a decrease of $12 million in fossil-fueled generation expenses primarily due to lower long-term service agreement costs and a lower scope of work done during plant outages in 2017 as compared to the same period in 2016; and
a decrease of $3.6 million in storm damage provisions. See Note 2 to the financial statements for a discussion on storm cost recovery.
The decrease was partially offset by an increase of $4.8 million in energy efficiency costs and an increase of $2.7 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to the prior year.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other income increased primarily due to interest income recorded in connection with the opportunity sales proceeding, interest income recorded on the deferred fuel balance, and an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2017 as compared to 2016. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding.
Interest expense decreased primarily due to the refinancing at lower interest rates of certain first mortgage bonds in 2016 and the retirement, at maturity, of $125 million of 3.25% Series first mortgage bonds in June 2016. See Note 5 to the financial statements for details of long-term debt.
2016 Compared to 2015
Other operation and maintenance expenses decreased primarily due to:
a decrease of $9.4 million in fossil-fueled generation expenses primarily due to a lower scope of work done during plant outages in 2016 as compared to the same period in 2015;
a decrease of $6.1 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;
a decrease of $2 million due to lower write-offs of uncollectible customer accounts in 2016;
a decrease of $2 million in energy efficiency costs; and
several individually insignificant items.
The decrease was partially offset by an increase of $7.1 million in storm damage provisions and an increase of $6 million in distribution expenses primarily due to higher vegetation maintenance. See Note 2 to the financial statements for a discussion of storm cost recovery.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Income Taxes
The effective income tax rates for 2017, 2016, and 2015 were 40.2%, 36.9%, and 40.0%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses proceedings commenced or other responses by Entergy’s regulators to the Act.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2017, 2016, and 2015 were as follows:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $76,834 |
| |
| $145,605 |
| |
| $61,633 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 226,585 |
| | 212,280 |
| | 372,279 |
|
| Investing activities | (417,226 | ) | | (289,444 | ) | | (245,127 | ) |
| Financing activities | 119,903 |
| | 8,393 |
| | (43,180 | ) |
| Net increase (decrease) in cash and cash equivalents | (70,738 | ) | | (68,771 | ) | | 83,972 |
|
| | | | | | |
| Cash and cash equivalents at end of period |
| $6,096 |
| |
| $76,834 |
| |
| $145,605 |
|
Operating Activities
Net cash flow provided by operating activities increased $14.3 million in 2017 primarily due to the timing of recovery of fuel and purchased power costs in 2017 as compared to 2016 and an increase of $12.6 million in income tax refunds in 2017 as compared to 2016. Entergy Mississippi had income tax refunds in 2017 and 2016 in accordance with an intercompany income tax allocation agreement. The 2017 income tax refunds were primarily due to the utilization of Entergy Mississippi’s federal net operating losses and state income tax refunds resulting from the carryback of net operating losses. The increase was partially offset by the timing of payments to vendors.
Net cash flow provided by operating activities decreased $160 million in 2016 primarily due to the timing of recovery of fuel and purchased power costs in 2016 as compared to the same period in 2015 and $15.3 million in insurance proceeds received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013. The decrease was partially offset by income tax refunds of $12.5 million in 2016 compared to income tax payments of $61.3 million in 2015. Entergy Mississippi had income tax refunds in 2016 and income tax payments in 2015 in accordance with an intercompany income tax allocation agreement. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit whereas the income tax payments in 2015 were primarily due to the results of operations and the reversal of taxable temporary differences as well as final settlement of amounts outstanding associated with the 2006-2007 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audits.
Investing Activities
Net cash flow used in investing activities increased $127.8 million in 2017 primarily due to:
an increase of $48.4 million in transmission construction expenditures primarily due to a higher scope of work performed in 2017 as compared to 2016;
an increase of $39.2 million in fossil-fueled generation construction expenditures primarily due to a higher scope of work performed in 2017 as compared to 2016; and
an increase of $30.2 million in distribution construction expenditures primarily due to an increase in storm spending in 2017 as compared to 2016 and increased spending on digital technology improvements within the customer contact centers.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Net cash flow used in investing activities increased $44.3 million in 2016 primarily due to:
an increase of $72.4 million in transmission construction expenditures primarily due to a higher scope of work performed in 2016 as compared to 2015;
insurance proceeds of $12.9 million received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013;
an increase of $11.4 million in distribution construction expenditures primarily due to a higher scope of non-storm related work performed in 2016 as compared to 2015; and
an increase of $10.1 million due to various information technology projects and upgrades.
The increase was partially offset by a decrease of $20.1 million in fossil-fueled generation construction expenditures primarily due to a decreased scope of work performed during plant outages in 2016 as compared to 2015 and money pool activity.
Decreases in Entergy Mississippi’s receivable from the money pool are a source of cash flow, and Entergy Mississippi’s receivable from the money pool decreased by $15.3 million in 2016 compared to increasing by $25.3 million in 2015. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Net cash flow provided by financing activities increased $111.5 million in 2017 primarily due to the issuance of $150 million of 3.25% Series first mortgage bonds in November 2017 and the redemption of $30 million of 6.25% Series preferred stock in 2016, partially offset by the net issuance of $61.4 million of long-term debt in 2016.
Entergy Mississippi’s financing activities provided $8.4 million of cash in 2016 compared to using $43.2 million in 2015 primarily due to the net issuance of $61.4 million of long-term debt in 2016 and a decrease of $16 million in common stock dividends paid in 2016, partially offset by the redemption of $30 million of 6.25% Series preferred stock. The decrease in dividends paid was primarily because of lower operating cash flows and higher capital expenditures, each discussed above.
See Note 5 to the financial statements for details on long-term debt.
Capital Structure
Entergy Mississippi’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital ratio for Entergy Mississippi is primarily due to the issuance of long-term debt in 2017.
|
| | | | | |
| | December 31,
2017 | | December 31,
2016 |
| Debt to capital | 51.5 | % | | 50.2 | % |
| Effect of subtracting cash | (0.2 | %) | | (1.8 | %) |
| Net debt to net capital | 51.3 | % | | 48.4 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, capital lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Mississippi uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition. Entergy Mississippi uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
and creditors in evaluating Entergy Mississippi’s financial condition because net debt indicates Entergy Mississippi’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Mississippi seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Mississippi may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy Mississippi may receive equity contributions to maintain the targeted capital structure.
Uses of Capital
Entergy Mississippi requires capital resources for:
construction and other capital investments;
debt and preferred stock maturities or retirements;
working capital purposes, including the financing of fuel and purchased power costs; and
dividend and interest payments.
Following are the amounts of Entergy Mississippi’s planned construction and other capital investments.
|
| | | | | | | | | | | |
| | 2018 | | 2019 | | 2020 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $55 |
| |
| $45 |
| |
| $260 |
|
| Transmission | 145 |
| | 100 |
| | 105 |
|
| Distribution | 125 |
| | 140 |
| | 130 |
|
| Utility Support | 70 |
| | 50 |
| | 35 |
|
| Total |
| $395 |
| |
| $335 |
| |
| $530 |
|
Following are the amounts of Entergy Mississippi’s existing debt obligations and lease obligations (includes estimated interest payments) and other purchase obligations.
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2019-2020 | | 2021-2022 | | After 2022 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $50 |
| |
| $234 |
| |
| $80 |
| |
| $1,784 |
| |
| $2,148 |
|
| Operating leases |
| $12 |
| |
| $19 |
| |
| $12 |
| |
| $6 |
| |
| $49 |
|
| Purchase obligations (b) |
| $280 |
| |
| $519 |
| |
| $490 |
| |
| $5,304 |
| |
| $6,593 |
|
| |
| (a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
| (b) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Mississippi, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements. |
In addition to the contractual obligations given above, Entergy Mississippi currently expects to contribute approximately $14.9 million to its qualified pension plans and approximately $110 thousand to other postretirement health care and life insurance plans in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018 See “Critical Accounting Estimates
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
– Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Mississippi includes amounts associated with specific investments such as transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including investment to support advanced metering; resource planning, including potential generation projects; system improvements; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.
As a wholly-owned subsidiary, Entergy Mississippi dividends its earnings to Entergy Corporation at a percentage determined monthly. Provisions in Entergy Mississippi’s articles of incorporation relating to preferred stock restrict the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock.
Advanced Metering Infrastructure (AMI)
In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15-year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value, approximately $56 million at December 31, 2015, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC, with deployment of the communications network expected to begin in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable. In May 2017 the Mississippi Public Utilities Staff and Entergy Mississippi entered into and filed a joint stipulation supporting Entergy Mississippi’s filing, and the MPSC issued an order approving the filing without material changes, finding that Entergy Mississippi’s deployment of AMI is in the public interest and granting a certificate of public convenience and necessity. The MPSC order also confirmed that Entergy Mississippi shall continue to include in rate base the remaining book value of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates.
Sources of Capital
Entergy Mississippi’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt or preferred stock issuances; and
bank financing under new or existing facilities.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Entergy Mississippi may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred stock issuances by Entergy Mississippi require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in its corporate charter, bond indenture, and other agreements. Entergy Mississippi has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Mississippi’s receivables from the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2017 | | 2016 | | 2015 | | 2014 |
| (In Thousands) |
| $1,633 | | $10,595 | | $25,930 | | $644 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Mississippi has four separate credit facilities in the aggregate amount of $102.5 million scheduled to expire May 2018. No borrowings were outstanding under the credit facilities as of December 31, 2017. In addition, Entergy Mississippi is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2017, a $15.3 million letter of credit was outstanding under Entergy Mississippi’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy Mississippi obtained authorizations from the FERC through October 2019 for short-term borrowings not to exceed an aggregate amount of $175 million at any time outstanding and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Mississippi’s short-term borrowing limits.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Mississippi charges for electricity significantly influence its financial position, results of operations, and liquidity. Entergy Mississippi is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the MPSC, is primarily responsible for approval of the rates charged to customers.
Formula Rate Plan
In March 2016, Entergy Mississippi submitted its formula rate plan 2016 test year filing showing Entergy Mississippi’s projected earned return for the 2016 calendar year to be below the formula rate plan bandwidth. The filing showed a $32.6 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 9.96%, within the formula rate plan bandwidth. In June 2016 the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase includes a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also includes $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.
In March 2017, Entergy Mississippi submitted its formula rate plan 2017 test year filing and 2016 look-back filing showing Entergy Mississippi’s earned return for the historical 2016 calendar year and projected earned return for the 2017 calendar year to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2017, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Mississippi’s earned returns for both the 2016 look-back filing and 2017 test year were within the respective formula rate plan bandwidths. In June 2017 the MPSC approved the stipulation, which resulted in no change in rates.
Fuel and Purchased Power Cost Recovery
Entergy Mississippi’s rate schedules include an energy cost recovery rider that is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
Entergy Mississippi had a deferred fuel over-recovery balance of $58.3 million as of May 31, 2015, along with an under-recovery balance of $12.3 million under the power management rider. Pursuant to those tariffs, in July 2015, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider to flow through to customers the approximately $46 million net over-recovery over a six-month period. In August 2015, the MPSC approved the interim adjustments effective with September 2015 bills. In November 2015, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi should file a revised fuel factor with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor effective April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.
In November 2016, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an over-recovery of less than $2 million as of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also in January 2017 the MPSC certified to the Mississippi Legislature the audit reports of its independent auditors for the fuel year ending September 30, 2016. In its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016. The MPSC hired independent auditors to conduct an annual operations audit and a financial audit. The independent auditors issued their audit reports in December 2017. The audit reports included several recommendations for action by Entergy Mississippi but did not recommend any cost disallowances. In January 2018 the MPSC certified the audit reports to the Mississippi Legislature. In November 2017 the Public Utilities Staff separately engaged a consultant to review the outage at the Grand Gulf Nuclear Station that began in 2016. The review is currently in progress.
In November 2017, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $61.5 million as of September 30, 2017. Entergy Mississippi proposed a two-tiered energy cost factor designed to promote overall rate stability throughout 2018 particularly during the summer months. In January 2018 the MPSC approved the proposed energy cost factors effective for February 2018 bills.
Mississippi Attorney General Complaint
The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. In December 2008 the defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.
The defendant Entergy companies answered the complaint and filed a counterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. In May 2009 the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the Attorney General’s complaint. In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings.
In January 2014 the U.S. Supreme Court issued a decision in which it held that cases brought by attorneys general as the sole plaintiff to enforce state laws were not considered “mass actions” under the Class Action Fairness Act, so as to establish federal subject matter jurisdiction. One day later the Attorney General renewed his motion to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies responded to that motion reiterating the additional grounds asserted for federal question jurisdiction, and the District Court held oral argument on the renewed motion to remand in February 2014. In April 2015 the District Court entered an order denying the renewed motion to remand, holding that the District Court has federal question subject matter jurisdiction. The Attorney General appealed to the U.S. Fifth Circuit Court of Appeals the denial of the motion to remand. In July 2015 the Fifth Circuit issued an order denying the appeal, and the Attorney General subsequently filed a petition for rehearing of the request for interlocutory appeal, which was also denied. In December 2015 the District Court ordered that the parties submit to the court undisputed and disputed facts that are material to the Entergy defendants’ motion for judgment on the pleadings, as well as supplemental briefs regarding the same. Those filings were made in January 2016.
In September 2016 the Attorney General filed a mandamus petition with the U.S. Fifth Circuit Court of Appeals in which the Attorney General asked the Fifth Circuit to order the chief judge to reassign this case to another judge. In September 2016 the District Court denied the Entergy companies’ motion for judgment on the pleadings. The Entergy companies filed a motion seeking to amend the District Court’s order denying the Entergy companies’ motion for judgment on the pleadings and allowing an interlocutory appeal. In October 2016 the Fifth Circuit granted the Attorney General’s motion for writ of mandamus and directed the chief judge to assign the case to a new judge. The case was reassigned in October 2016. In January 2017 the District Court denied the Entergy companies’ motion to amend the order denying the motion for judgment on the pleadings. In June 2017 the District Court issued a case management order setting a trial date in November 2018. Discovery is currently in progress.
Storm Damage Provision
Entergy Mississippi has approval from the MPSC to collect a storm damage provision of $1.75 million per month. If Entergy Mississippi’s accumulated storm damage provision balance exceeds $15 million, the collection of the storm damage provision ceases until such time that the accumulated storm damage provision becomes less than $10 million. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance again exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with November 2016 bills. As of July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision was again less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with September 2017 bills.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Nuclear Matters
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
Environmental Risks
Entergy Mississippi’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Mississippi is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Mississippi’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of Entergy Mississippi’s financial position or results of operations.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Unbilled Revenue
See “Unbilled Revenue” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the unbilled revenue amounts.
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Mississippi’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
|
| | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2018 Qualified Pension Cost | | Impact on 2017 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $874 | |
| $13,479 |
|
| Rate of return on plan assets | | (0.25%) | | $867 | |
| $— |
|
| Rate of increase in compensation | | 0.25% | | $381 | |
| $1,848 |
|
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2018 Postretirement Benefit Cost | | Impact on 2017 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $184 | | $2,561 |
| Health care cost trend | | 0.25% | | $296 | | $2,024 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension cost for Entergy Mississippi in 2017 was $8.5 million. Entergy Mississippi anticipates 2018 qualified pension cost to be $10.8 million. In 2016, Entergy Mississippi refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $3.8 million. Entergy Mississippi contributed $19.1 million to its qualified pension plans in 2017 and estimates 2018 pension contributions will be approximately $14.9 million, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018.
Total postretirement health care and life insurance benefit income for Entergy Mississippi in 2017 was $1 million. Entergy Mississippi expects 2018 postretirement health care and life insurance benefit income of approximately $1.5 million. In 2016, Entergy Mississippi refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $770 thousand. In 2017, Entergy Mississippi’s contributions (that is, contributions to the external trusts plus claims payments) were offset by trust claims reimbursements, resulting in a net reimbursement of $2 thousand. Entergy Mississippi estimates that 2018 contributions will be approximately $110 thousand.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Federal Healthcare Legislation
See “Qualified Pension and Other Postretirement Benefits -Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors of
Entergy Mississippi, Inc.
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Entergy Mississippi, Inc. (the “Company”) as of December 31, 2017 and 2016, the related statements of income, cash flows and changes in common equity (pages 370 through 374 and applicable items in pages 55 through 230), for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2018
We have served as the Company’s auditor since 2001.
|
| | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $1,198,229 |
| |
| $1,094,649 |
| |
| $1,396,985 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 185,816 |
| | 95,090 |
| | 291,666 |
|
| Purchased power | | 328,463 |
| | 297,902 |
| | 389,950 |
|
| Other operation and maintenance | | 243,480 |
| | 250,443 |
| | 261,255 |
|
| Taxes other than income taxes | | 95,051 |
| | 94,482 |
| | 94,152 |
|
| Depreciation and amortization | | 143,479 |
| | 136,214 |
| | 129,029 |
|
| Other regulatory charges (credits) - net | | (19,134 | ) | | (3,721 | ) | | 19,027 |
|
| TOTAL | | 977,155 |
| | 870,410 |
| | 1,185,079 |
|
| | | | | | | |
| OPERATING INCOME | | 221,074 |
| | 224,239 |
| | 211,906 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 9,667 |
| | 5,801 |
| | 3,095 |
|
| Interest and investment income | | 85 |
| | 656 |
| | 195 |
|
| Miscellaneous - net | | 510 |
| | (3,531 | ) | | (4,418 | ) |
| TOTAL | | 10,262 |
| | 2,926 |
| | (1,128 | ) |
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 51,260 |
| | 57,114 |
| | 57,842 |
|
| Allowance for borrowed funds used during construction | | (3,875 | ) | | (2,987 | ) | | (1,644 | ) |
| TOTAL | | 47,385 |
| | 54,127 |
| | 56,198 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 183,951 |
| | 173,038 |
| | 154,580 |
|
| | | | | | | |
| Income taxes | | 73,919 |
| | 63,854 |
| | 61,872 |
|
| | | | | | | |
| NET INCOME | | 110,032 |
| | 109,184 |
| | 92,708 |
|
| | | | |
|
| | |
| Preferred dividend requirements and other | | 953 |
| | 2,443 |
| | 2,828 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | |
| $109,079 |
| |
| $106,741 |
| |
| $89,880 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $110,032 |
| |
| $109,184 |
| |
| $92,708 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 143,479 |
| | 136,214 |
| | 129,029 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 84,816 |
| | 60,986 |
| | 18,673 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | (29,528 | ) | | (28,819 | ) | | 50,199 |
|
| Fuel inventory | | 5,266 |
| | 401 |
| | (8,537 | ) |
| Accounts payable | | 3,595 |
| | 33,733 |
| | (26,682 | ) |
| Taxes accrued | | 18,803 |
| | 20,579 |
| | (10,104 | ) |
| Interest accrued | | 1,248 |
| | 822 |
| | (2,341 | ) |
| Deferred fuel costs | | (25,487 | ) | | (114,711 | ) | | 105,560 |
|
| Other working capital accounts | | 5,115 |
| | (5,222 | ) | | (663 | ) |
| Provisions for estimated losses | | (9,676 | ) | | 6,378 |
| | (2,080 | ) |
| Other regulatory assets | | (17,412 | ) | | (3,626 | ) | | 39,582 |
|
| Other regulatory liabilities | | 405,395 |
| | (2,986 | ) | | 9,172 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | (452,429 | ) | | — |
| | — |
|
| Pension and other postretirement liabilities | | (8,055 | ) | | (10,648 | ) | | (14,939 | ) |
| Other assets and liabilities | | (8,577 | ) | | 9,995 |
| | (7,298 | ) |
| Net cash flow provided by operating activities | | 226,585 |
| | 212,280 |
| | 372,279 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (427,616 | ) | | (310,356 | ) | | (235,894 | ) |
| Allowance for equity funds used during construction | | 9,667 |
| | 5,801 |
| | 3,095 |
|
| Insurance proceeds | | — |
| | — |
| | 12,932 |
|
| Changes in money pool receivable - net | | 8,962 |
| | 15,335 |
| | (25,286 | ) |
| Payment for purchase of assets | | (6,958 | ) | | — |
| | — |
|
| Other | | (1,281 | ) | | (224 | ) | | 26 |
|
| Net cash flow used in investing activities | | (417,226 | ) | | (289,444 | ) | | (245,127 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 148,185 |
| | 623,812 |
| | — |
|
| Retirement of long-term debt | | — |
| | (562,400 | ) | | — |
|
| Redemption of preferred stock | | — |
| | (30,000 | ) | | — |
|
| Dividends paid: | | |
| | |
| | |
|
| Common stock | | (26,000 | ) | | (24,000 | ) | | (40,000 | ) |
| Preferred stock | | (953 | ) | | (2,755 | ) | | (2,828 | ) |
| Other | | (1,329 | ) | | 3,736 |
| | (352 | ) |
| Net cash flow provided by (used in) financing activities | | 119,903 |
| | 8,393 |
| | (43,180 | ) |
| Net increase (decrease) in cash and cash equivalents | | (70,738 | ) | | (68,771 | ) | | 83,972 |
|
| Cash and cash equivalents at beginning of period | | 76,834 |
| | 145,605 |
| | 61,633 |
|
| Cash and cash equivalents at end of period | |
| $6,096 |
| |
| $76,834 |
| |
| $145,605 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $47,631 |
| |
| $53,693 |
| |
| $57,576 |
|
| Income taxes | |
| ($25,043 | ) | |
| ($12,487 | ) | |
| $61,333 |
|
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $1,607 |
| |
| $16 |
|
| Temporary cash investments | | 4,489 |
| | 76,818 |
|
| Total cash and cash equivalents | | 6,096 |
| | 76,834 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 72,039 |
| | 51,218 |
|
| Allowance for doubtful accounts | | (574 | ) | | (549 | ) |
| Associated companies | | 45,081 |
| | 45,973 |
|
| Other | | 9,738 |
| | 12,006 |
|
| Accrued unbilled revenues | | 54,256 |
| | 51,327 |
|
| Total accounts receivable | | 180,540 |
| | 159,975 |
|
| Deferred fuel costs | | 32,444 |
| | 6,957 |
|
| Fuel inventory - at average cost | | 45,606 |
| | 50,872 |
|
| Materials and supplies - at average cost | | 42,571 |
| | 41,146 |
|
| Prepayments and other | | 7,041 |
| | 8,873 |
|
| TOTAL | | 314,298 |
| | 344,657 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Non-utility property - at cost (less accumulated depreciation) | | 4,592 |
| | 4,608 |
|
| Escrow accounts | | 31,969 |
| | 31,783 |
|
| TOTAL | | 36,561 |
| | 36,391 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 4,660,297 |
| | 4,321,214 |
|
| Property under capital lease | | 125 |
| | 1,590 |
|
| Construction work in progress | | 149,367 |
| | 118,182 |
|
| TOTAL UTILITY PLANT | | 4,809,789 |
| | 4,440,986 |
|
| Less - accumulated depreciation and amortization | | 1,681,306 |
| | 1,602,711 |
|
| UTILITY PLANT - NET | | 3,128,483 |
| | 2,838,275 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Regulatory asset for income taxes - net | | — |
| | 38,284 |
|
| Other regulatory assets | | 397,909 |
| | 342,213 |
|
| Other | | 2,124 |
| | 2,320 |
|
| TOTAL | | 400,033 |
| | 382,817 |
|
| | | | | |
| TOTAL ASSETS | |
| $3,879,375 |
| |
| $3,602,140 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Accounts payable: | | |
| | |
|
| Associated companies | |
| $55,689 |
| |
| $43,647 |
|
| Other | | 77,326 |
| | 80,227 |
|
| Customer deposits | | 83,654 |
| | 84,112 |
|
| Taxes accrued | | 82,843 |
| | 64,040 |
|
| Interest accrued | | 22,901 |
| | 21,653 |
|
| Other | | 12,785 |
| | 9,554 |
|
| TOTAL | | 335,198 |
| | 303,233 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 488,806 |
| | 861,331 |
|
| Accumulated deferred investment tax credits | | 8,867 |
| | 8,667 |
|
| Regulatory liability for income taxes - net | | 411,011 |
| | — |
|
| Asset retirement cost liabilities | | 9,219 |
| | 8,722 |
|
| Accumulated provisions | | 44,764 |
| | 54,440 |
|
| Pension and other postretirement liabilities | | 101,498 |
| | 109,551 |
|
| Long-term debt | | 1,270,122 |
| | 1,120,916 |
|
| Other | | 11,639 |
| | 20,108 |
|
| TOTAL | | 2,345,926 |
| | 2,183,735 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| Preferred stock without sinking fund | | 20,381 |
| | 20,381 |
|
| | | | | |
| COMMON EQUITY | | |
| | |
|
| Common stock, no par value, authorized 12,000,000 shares; issued and outstanding 8,666,357 shares in 2017 and 2016 | | 199,326 |
| | 199,326 |
|
| Capital stock expense and other | | 167 |
| | 167 |
|
| Retained earnings | | 978,377 |
| | 895,298 |
|
| TOTAL | | 1,177,870 |
| | 1,094,791 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $3,879,375 |
| |
| $3,602,140 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| STATEMENTS OF CHANGES IN COMMON EQUITY |
| For the Years Ended December 31, 2017, 2016, and 2015 |
| | | | |
| | Common Equity | | |
| | Common Stock | | Capital Stock Expense and Other | | Retained Earnings | | Total |
| | (In Thousands) |
| | | | | | | | |
| Balance at December 31, 2014 |
| $199,326 |
| |
| ($690 | ) | |
| $763,534 |
| |
| $962,170 |
|
| Net income | — |
| | — |
| | 92,708 |
| | 92,708 |
|
| Common stock dividends | — |
| | — |
| | (40,000 | ) | | (40,000 | ) |
| Preferred stock dividends | — |
| | — |
| | (2,828 | ) | | (2,828 | ) |
| Balance at December 31, 2015 |
| $199,326 |
| |
| ($690 | ) | |
| $813,414 |
| |
| $1,012,050 |
|
| Net income | — |
| | — |
| | 109,184 |
| | 109,184 |
|
| Common stock dividends | — |
| | — |
| | (24,000 | ) | | (24,000 | ) |
| Preferred stock dividends | — |
| | — |
| | (2,443 | ) | | (2,443 | ) |
| Preferred stock redemption | — |
| | 857 |
| | (857 | ) | | — |
|
| Balance at December 31, 2016 |
| $199,326 |
| |
| $167 |
| |
| $895,298 |
| |
| $1,094,791 |
|
| Net income | — |
| | — |
| | 110,032 |
| | 110,032 |
|
| Common stock dividends | — |
| | — |
| | (26,000 | ) | | (26,000 | ) |
| Preferred stock dividends | — |
| | — |
| | (953 | ) | | (953 | ) |
| Balance at December 31, 2017 |
| $199,326 |
| |
| $167 |
| |
| $978,377 |
| |
| $1,177,870 |
|
| | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $1,198,229 |
| |
| $1,094,649 |
| |
| $1,396,985 |
| |
| $1,524,193 |
| |
| $1,334,540 |
|
| Net income |
| $110,032 |
| |
| $109,184 |
| |
| $92,708 |
| |
| $74,821 |
| |
| $82,159 |
|
| Total assets |
| $3,879,375 |
| |
| $3,602,140 |
| |
| $3,477,407 |
| |
| $3,358,625 |
| |
| $3,234,875 |
|
| Long-term obligations (a) |
| $1,290,503 |
| |
| $1,141,924 |
| |
| $972,058 |
| |
| $1,097,182 |
| |
| $1,092,786 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and preferred stock without sinking fund. |
| | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $502 |
| |
| $459 |
| |
| $565 |
| |
| $585 |
| |
| $527 |
|
| Commercial | 423 |
| | 374 |
| | 465 |
| | 481 |
| | 432 |
|
| Industrial | 159 |
| | 134 |
| | 164 |
| | 175 |
| | 156 |
|
| Governmental | 41 |
| | 38 |
| | 47 |
| | 47 |
| | 42 |
|
| Total retail | 1,125 |
| | 1,005 |
| | 1,241 |
| | 1,288 |
| | 1,157 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | — |
| | 1 |
| | 75 |
| | 153 |
| | 92 |
|
| Non-associated companies | 18 |
| | 30 |
| | 10 |
| | 14 |
| | 24 |
|
| Other | 55 |
| | 59 |
| | 71 |
| | 69 |
| | 62 |
|
| Total |
| $1,198 |
| |
| $1,095 |
| |
| $1,397 |
| |
| $1,524 |
| |
| $1,335 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
|
| Residential | 5,308 |
| | 5,617 |
| | 5,661 |
| | 5,672 |
| | 5,629 |
|
| Commercial | 4,783 |
| | 4,894 |
| | 4,913 |
| | 4,821 |
| | 4,815 |
|
| Industrial | 2,536 |
| | 2,493 |
| | 2,283 |
| | 2,297 |
| | 2,265 |
|
| Governmental | 421 |
| | 439 |
| | 433 |
| | 414 |
| | 409 |
|
| Total retail | 13,048 |
| | 13,443 |
| | 13,290 |
| | 13,204 |
| | 13,118 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | — |
| | — |
| | 1,419 |
| | 2,657 |
| | 1,543 |
|
| Non-associated companies | 857 |
| | 1,021 |
| | 261 |
| | 193 |
| | 304 |
|
| Total | 13,905 |
| | 14,464 |
| | 14,970 |
| | 16,054 |
| | 14,965 |
|
ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Internal Restructuring
In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans, Inc. to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. The restructuring was subject to regulatory review and approval by the City Council and the FERC. In May 2017 the City Council adopted a resolution approving the proposed internal restructuring pursuant to an agreement in principle with the City Council advisors and certain intervenors. Pursuant to the agreement in principle, Entergy New Orleans would credit retail customers $10 million in 2017, $1.4 million in the first quarter of the year after the transaction closes, and $117,500 each month in the second year after the transaction closes until such time as new base rates go into effect as a result of the anticipated 2018 base rate case. Entergy New Orleans began crediting retail customers in June 2017. In June 2017 the FERC approved the transaction and, pursuant to the agreement in principle, Entergy New Orleans will provide additional credits to retail customers of $5 million in each of the years 2018, 2019, and 2020.
In November 2017, pursuant to the agreement in principle, Entergy New Orleans undertook a multi-step restructuring, including the following:
Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.
Results of Operations
Net Income
2017 Compared to 2016
Net income decreased $4.3 million primarily due to higher taxes other than income taxes, lower net revenue, and a higher effective income tax rate, partially offset by lower other operation and maintenance expenses and higher other income.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2016 Compared to 2015
Net income increased $3.9 million primarily due to higher net revenue, partially offset by higher depreciation and amortization expenses, higher interest expense, and lower other income.
Net Revenue
2017 Compared to 2016
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 2017 to 2016.
|
| | | |
| Amount |
| (In Millions) |
| |
| 2016 net revenue |
| $317.2 |
|
| Retail electric price | (6.4 | ) |
| Volume/weather | (4.3 | ) |
| Other | 5.4 |
|
| 2017 net revenue |
| $311.9 |
|
The retail electric price variance is primarily due to a net decrease in the purchased power and capacity acquisition cost recovery rider. There was an increase in the rider primarily due to credits to customers as part of the Entergy New Orleans internal restructuring agreement in principle, effective with the first billing cycle of June 2017, partially offset by lower credits to customers in 2017 related to the retirement of Michoud Units 2 and 3. See Note 2 to the financial statements for further discussion of the credits associated with Entergy New Orleans’s internal restructuring and the Michoud retirement.
The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales, partially offset by an increase in residential and commercial usage resulting from a 1% increase in the average number of residential and commercial electric customers.
2016 Compared to 2015
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
| 2015 net revenue |
| $293.9 |
|
| Retail electric price | 39.0 |
|
| Net gas revenue | (2.5 | ) |
| Volume/weather | (5.1 | ) |
| Other | (8.1 | ) |
| 2016 net revenue |
| $317.2 |
|
The retail electric price variance is primarily due to an increase in the purchased power and capacity acquisition cost recovery rider, as approved by the City Council, effective with the first billing cycle of March 2016, primarily
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
related to the purchase of Power Block 1 of the Union Power Station. See Note 14 to the financial statements for discussion of the Union Power Station purchase.
The net gas revenue variance is primarily due to the effect of less favorable weather on residential and commercial sales.
The volume/weather variance is primarily due to a decrease of 112 GWh, or 2%, in billed electricity usage, partially offset by the effect of favorable weather on commercial sales and a 2% increase in the average number of electric customers.
Other Income Statement Variances
2017 Compared to 2016
Other operation and maintenance expenses decreased primarily due to:
a decrease of $7.9 million in fossil-fueled generation expenses primarily due to lower outage costs at Power Block 1 of the Union Power Station in 2017 as compared to 2016, the deactivation of Michoud Units 2 and 3 effective May 2016, and asbestos loss provisions in 2016;
a decrease of $4.5 million in other loss provisions; and
a decrease of $2.8 million due to lower write-offs of uncollectible customer accounts.
The decrease was partially offset by:
an increase of $4 million in distribution expenses primarily due to higher labor costs, including contract labor, and higher vegetation maintenance costs; and
an increase of $1.3 million in energy efficiency costs.
Taxes other than income taxes increased primarily due to an increase in ad valorem taxes and higher local franchise taxes. Ad valorem taxes increased primarily due to higher assessments, including the assessment of Arkansas ad valorem taxes on the Union Power Station beginning in 2017. Local franchise taxes increased primarily due to higher electric retail revenues in 2017 as compared to 2016.
Other income increased primarily due to a decrease in charitable contributions made in 2017 as compared to 2016.
2016 Compared to 2015
Other operation and maintenance expenses decreased primarily due to:
a decrease of $6.1 million due to lower transmission equalization expenses, as allocated under the System Agreement as compared to the same period in 2015 primarily due to the termination of the System Agreement. See Note 2 to the financial statements for further discussion on the System Agreement termination;
a decrease of $4.4 million due to the cessation of storm damage provisions in August 2015. See Note 2 to the financial statements for further discussion of storm cost recovery; and
a decrease of $3.1 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The decrease was partially offset by:
an increase of $5.7 million in fossil-fueled generation expenses primarily due to an increase as a result of the purchase of Power Block 1 of the Union Power Station in March 2016, partially offset by a decrease as a result of the deactivation of Michoud Units 2 and 3 effective May 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;
an increase of $3.1 million in loss provisions; and
an increase of $2.8 million due to higher write-offs of uncollectible customer accounts in 2016 as compared to 2015.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the purchase of Power Block 1 of the Union Power Station in March 2016, partially offset by the retirement of Michoud Units 2 and 3 effective May 2016.
Interest expense increased primarily due to the issuance of $110 million of 5.50% Series first mortgage bonds in March 2016 and the issuance of $98.7 million of storm cost recovery bonds in July 2015. See Note 5 to the financial statements for details on long-term debt.
Other income decreased primarily due to an increase in charitable contributions made in 2016 as compared to 2015.
Income Taxes
The effective income tax rates for 2017, 2016, and 2015 were 42.8%, 37.0% and 35.9%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses proceedings commenced or other responses by Entergy’s regulators to the Act.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2017, 2016, and 2015 were as follows:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $103,068 |
| |
| $88,876 |
| |
| $42,389 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 127,797 |
| | 205,211 |
| | 105,068 |
|
| Investing activities | (109,500 | ) | | (322,681 | ) | | (173,460 | ) |
| Financing activities | (88,624 | ) | | 131,662 |
| | 114,879 |
|
| Net increase (decrease) in cash and cash equivalents | (70,327 | ) |
| 14,192 |
|
| 46,487 |
|
| | | | | | |
| Cash and cash equivalents at end of period |
| $32,741 |
|
|
| $103,068 |
|
|
| $88,876 |
|
Operating Activities
Net cash flow provided by operating activities decreased $77.4 million in 2017 primarily due to a decrease of $77.3 million in income tax refunds in 2017 compared to 2016 and the timing of collections from customers and payments to vendors. Entergy New Orleans had income tax refunds in 2017 and 2016 in accordance with an intercompany income tax allocation agreement. The 2016 income tax refunds resulted primarily from deductible temporary differences. The decrease was partially offset by an increase due to the timing of recovery of fuel and purchased power costs.
Net cash flow provided by operating activities increased $100.1 million in 2016 primarily due to income tax refunds of $86 million in 2016 as compared to income tax payments of $8.1 million in 2015. Entergy New Orleans had income tax refunds in 2016 and income tax payments in 2015 in accordance with an intercompany income tax allocation agreement. The 2016 income tax refunds resulted primarily from deductible temporary differences.
Investing Activities
Net cash flow used in investing activities decreased $213.2 million in 2017 primarily due to the purchase of Power Block 1 of the Union Power Station for approximately $237 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase. The decrease was partially offset by an increase of $16.7 million in distribution construction expenditures primarily due to a higher scope of work performed in 2017 as compared to 2016.
Net cash flow used in investing activities increased $149.2 million in 2016 primarily due to the purchase of Power Block 1 of the Union Power Station for approximately $237 million in March 2016. The increase was partially offset by a deposit of $63.9 million into the storm reserve escrow account in July 2015 and money pool activity. See Note 14 to the financial statements for discussion of the Union Power Station purchase. See Note 5 to the financial statements for a discussion of the issuance in July 2015 of securitization bonds to recover storm costs.
Decreases in Entergy New Orleans’s receivable from the money pool are a source of cash flow, and Entergy New Orleans’s receivable from the money pool decreased $1.6 million in 2016 compared to increasing $15.4 million in 2015. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Financing Activities
Entergy New Orleans’s financing activities used $88.6 million of cash in 2017 compared to providing $131.7 million in 2016 primarily due to the following activity:
the issuance of $110 million of 5.50% Series first mortgage bonds in March 2016;
an increase of $55.5 million in common equity distributions in 2017 as compared to 2016. Common equity distributions in 2017 increased primarily as a result of Entergy New Orleans’s cash position in excess of its working capital requirements. There were no common equity distributions in first quarter 2016 in anticipation of the purchase of Power Block 1 of the Union Power Station in March 2016;
a decrease of $27.8 million in capital contributions received from Entergy Corporation in 2017 compared to 2016. The 2017 contribution was made in consideration of Entergy New Orleans’s upcoming capital requirements. The 2016 contribution was made in anticipation of Entergy New Orleans’s purchase of Power Block 1 of the Union Power Station; and
the redemptions of $7.8 million of 4.75% Series preferred stock, $6 million of 5.56% Series preferred stock, and $6 million of 4.36% Series preferred stock in 2017 in connection with the internal restructuring, as discussed above.
See Note 14 to the financial statements for discussion of the Union Power Station purchase.
Net cash flow provided by financing activities increased $16.8 million in 2016 primarily due to:
the purchase of Entergy Louisiana’s Algiers assets in September 2015. The cash portion of the purchase is reflected as a repayment of a long-term payable due to Entergy Louisiana in the cash flow statement. See Note 2 to the financial statements and “Algiers Asset Transfer” below for further discussion of the Algiers asset transfer and accounting for the transaction;
the issuance of $110 million of 5.50% Series first mortgage bonds in March 2016; and
the issuance of $85 million of 4% Series first mortgage bonds in May 2016. Entergy New Orleans used the proceeds to pay, prior to maturity, its $33.271 million of 5.6% Series first mortgage bonds due September 2024 and to pay, prior to maturity, its $37.772 million of 5.65% Series first mortgage bonds due September 2029.
The increase was offset by:
the issuance of $98.7 million of storm costs recovery bonds in July 2015;
a $47.8 million capital contribution received from Entergy Corporation in 2016 as compared to an $87.5 million capital contribution received from Entergy Corporation in 2015, both in anticipation of Entergy New Orleans’s purchase of Power Block 1 of the Union Power Station; and
an increase of $11.5 million in common equity distributions in 2016. Common equity distributions were lower in 2015 in anticipation of the purchase of Power Block 1 of the Union Power Station.
See Note 5 to the financial statements for more details on long-term debt.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Capital Structure
Entergy New Orleans’s capitalization is balanced between equity and debt as shown in the following table. The increase in the debt to capital ratio is primarily due to the redemptions of preferred stock in 2017.
|
| | | | | |
| | December 31, 2017 | | December 31, 2016 |
| Debt to capital | 51.3 | % | | 50.1 | % |
| Effect of excluding securitization bonds | (4.7 | %) | | (5.2 | %) |
| Debt to capital, excluding securitization bonds (a) | 46.6 | % | | 44.9 | % |
| Effect of subtracting cash | (2.4 | %) | | (8.0 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 44.2 | % | | 36.9 | % |
(a) Calculation excludes the securitization bonds, which are non-recourse to Entergy New Orleans.
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, long-term debt, including the currently maturing portion, and the long-term payable to Entergy Louisiana. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy New Orleans uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because the securitization bonds are non-recourse to Entergy New Orleans, as more fully described in Note 5 to the financial statements. Entergy New Orleans also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because net debt indicates Entergy New Orleans’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy New Orleans seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy New Orleans may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy New Orleans may receive equity contributions to maintain the targeted capital structure.
Uses of Capital
Entergy New Orleans requires capital resources for:
construction and other capital investments;
working capital purposes, including the financing of fuel and purchased power costs;
debt maturities or retirements; and
distribution and interest payments.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.
|
| | | | | | | | | | | |
| | 2018 | | 2019 | | 2020 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $115 |
| |
| $80 |
| |
| $15 |
|
| Transmission | 15 |
| | 10 |
| | 5 |
|
| Distribution | 80 |
| | 85 |
| | 80 |
|
| Utility Support | 20 |
| | 15 |
| | 15 |
|
| Total |
| $230 |
| |
| $190 |
| |
| $115 |
|
Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2019-2020 | | 2021-2022 | | After 2022 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $31 |
| |
| $87 |
| |
| $59 |
| |
| $674 |
| |
| $851 |
|
| Operating leases |
| $2 |
| |
| $3 |
| |
| $1 |
| |
| $2 |
| |
| $8 |
|
| Purchase obligations (b) |
| $245 |
| |
| $480 |
| |
| $463 |
| |
| $3,669 |
| |
| $4,857 |
|
| |
| (a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
| (b) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy New Orleans, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements. |
In addition to the contractual obligations given above, Entergy New Orleans currently expects to contribute approximately $7.3 million to its qualified pension plan and approximately $3.7 million to other postretirement health care and life insurance plans in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy New Orleans has $238.2 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy New Orleans includes specific investments such as the New Orleans Power Station discussed below; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including investment to support advanced metering; system improvements; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy New Orleans pays distributions from its earnings at a percentage determined monthly.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
New Orleans Power Station
In June 2016, Entergy New Orleans filed an application with the City Council seeking a public interest determination and authorization to construct the New Orleans Power Station, a 226 MW advanced combustion turbine in New Orleans, Louisiana, at the site of the existing Michoud generating facility, which was retired effective May 31, 2016. In January 2017 several intervenors filed testimony opposing the construction of the New Orleans Power Station on various grounds. In July 2017, Entergy New Orleans submitted a supplemental and amending application to the City Council seeking approval to construct either the originally proposed 226 MW advanced combustion turbine, or alternatively, a 128 MW unit composed of natural gas-fired reciprocating engines and a related cost recovery plan. The application included an updated cost estimate of $232 million for the 226 MW advanced combustion turbine. The cost estimate for the alternative 128 MW unit is $210 million. In addition, the application renewed the commitment to pursue up to 100 MW of renewable resources to serve New Orleans. In testimony filed subsequent to Entergy New Orleans’s supplemental and amending application, several intervenors oppose City Council approval of either alternative, while the City Council advisors and one intervenor support the smaller alternative. A contested hearing was held in December 2017 and post-hearing briefs were filed in January 2018. In February 2018 the City Council Utility Committee adopted a resolution approving construction of the 128 MW unit. The full City Council is expected to vote on the resolution in March 2018. The commercial operation date is dependent on the alternative selected by the City Council and the receipt of other permits and approvals.
Gas Infrastructure Rebuild Plan
In September 2016, Entergy New Orleans submitted to the City Council a request for authorization for Entergy New Orleans to proceed with annual incremental capital funding of $12.5 million for its gas infrastructure rebuild plan, which would replace of all of Entergy New Orleans’s low pressure cast iron, steel, and vintage plastic pipe over a ten-year period commencing in 2017. Entergy New Orleans also proposed that recovery of the investment to fund its gas infrastructure replacement plan be determined in connection with its next base rate case, which is anticipated to be filed in 2018. The City Council has authorized Entergy New Orleans to proceed with its replacement plans at the requested pace until such time that rates resulting from the anticipated 2018 rate case are implemented (approximately 13 months after filing). As a result of the anticipated 2018 rate case, the City Council may establish new overall gas base rates to allow Entergy New Orleans to continue to recover these replacement costs. The City Council has established a schedule for proceedings in advance of the rate case intended to provide an opportunity for evaluation of the gas infrastructure replacement plan that would best serve the public interest and the effect on customers of the approval of any such plan.
Advanced Metering Infrastructure (AMI)
In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid. The filing included an estimate of implementation costs for AMI of $75 million. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million. Entergy New Orleans also sought to continue to include in rate base the remaining book value, approximately $21 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Deployment of the information technology infrastructure began in 2017 and deployment of the communications network is expected to begin in 2018. Entergy New Orleans proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. The City Council’s advisors filed testimony in May 2017 recommending the adoption of AMI subject to certain modifications, including the denial of Entergy New Orleans’s proposed customer charge as a cost recovery mechanism. In January 2018 a settlement was reached between
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
the City Council’s advisors and Entergy New Orleans. In February 2018 the City Council approved the settlement, which deferred cost recovery to the 2018 Entergy New Orleans rate case, but also stated that an adjustment for 2018-2019 AMI costs can be filed in the rate case and that, for all subsequent AMI costs, the mechanism to be approved in the 2018 rate case will allow for the timely recovery of such costs.
Sources of Capital
Entergy New Orleans’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt and preferred membership interest issuances; and
bank financing under new or existing facilities.
Entergy New Orleans may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
Entergy New Orleans’s receivables from the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2017 | | 2016 | | 2015 | | 2014 |
| (In Thousands) |
| $12,723 | | $14,215 | | $15,794 | | $442 |
See Note 4 to the financial statements for a description of the money pool.
Entergy New Orleans has a credit facility in the amount of $25 million scheduled to expire in November 2018. The credit facility allows Entergy New Orleans to issue letters of credit against $10 million of the borrowing capacity of the facility. As of December 31, 2017, there were no cash borrowings and a $0.8 million letter of credit was outstanding under the facility. In addition, Entergy New Orleans is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2017, a $1.4 million letter of credit was outstanding under Entergy New Orleans’s letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy New Orleans obtained authorization from the FERC through October 2019 for short-term borrowings not to exceed an aggregate amount of $150 million at any time outstanding and long-term borrowings and securities issuances. See Note 4 to the financial statements for further discussion of Entergy New Orleans’s short-term borrowing limits. The long-term securities issuances of Entergy New Orleans are limited to amounts authorized not only by the FERC, but also by the City Council, and the current City Council authorization extends through June 2018.
State and Local Rate Regulation
The rates that Entergy New Orleans charges for electricity and natural gas significantly influence its financial position, results of operations, and liquidity. Entergy New Orleans is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the City Council, is primarily responsible for approval of the rates charged to customers.
Retail Rates
See “Algiers Asset Transfer” below for discussion of the Algiers asset transfer. As a provision of the settlement agreement approved by the City Council in May 2015 providing for the Algiers asset transfer, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions included continued implementation of the then-remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allowed for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorized Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.
In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy from Ninemile 6 (Ninemile PPA), which commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed only to Entergy New Orleans customers outside of Algiers.
In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted (estimated to be June 2018) and when new rates from the anticipated 2018 combined rate case, which will include a cost recovery mechanism for Energy Smart funding, take effect (estimated to be August 2019). Entergy New Orleans requested that the City Council approve a cost recovery mechanism prior to June 2018. In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Fuel and Purchased Power Cost Recovery
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
Due to higher fuel costs associated in part with the extended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans to cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs associated in part with certain plant outages, Entergy New Orleans has proposed to cap the fuel adjustment charge to be billed in March 2018 to non-transmission Entergy New Orleans legacy customers and Entergy New Orleans Algiers customers at $0.035323 per kWh and $0.025446 per kWh, respectively. Entergy New Orleans has also proposed to cap the fuel adjustment charge to be billed in March 2018 for Entergy New Orleans legacy transmission customers at $0.034609 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Algiers Asset Transfer
In October 2014, Entergy Louisiana and Entergy New Orleans filed an application with the City Council seeking authorization to undertake a transaction that would result in the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that currently support the provision of service to Entergy Louisiana’s customers in Algiers. The transaction is expected to result in the transfer of net assets of approximately $60 million. The Algiers asset transfer is also subject to regulatory review and approval of the FERC. As discussed previously, Entergy Louisiana also filed an application with the City Council seeking authorization to undertake the Entergy Louisiana and Entergy Gulf States Louisiana business combination. The application provides that if the City Council approves the Algiers asset transfer before the business combination occurs, the City Council may not need to issue a public interest finding regarding the business combination. If the necessary approvals are obtained from the City Council and the FERC, Entergy Louisiana expects to transfer the Algiers assets to Entergy New Orleans in the second half of 2015. In November 2014 the City Council approved a resolution establishing a procedural schedule that provides for a hearing on the joint application in late-May 2015, with a decision to be rendered no later than June 2015.
Industrial and Commercial Customers
Entergy Louisiana’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Louisiana’s industrial customer base. Entergy Louisiana responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Entergy Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers. Entergy Louisiana does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Louisiana’s marketing efforts in retaining industrial customers.
Federal Regulation
See “Entergy’s Integration Into the MISO Regional Transmission Organization,” “System Agreement,” and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of these topics.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Nuclear Matters
Entergy Louisiana owns and, through an affiliate, operates the Waterford 3 nuclear power plant. Entergy Louisiana is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.
The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system. The issue is applicable to Waterford 3 and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators to undertake plant modifications and perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating nuclear plants. The NRC, with input from the industry, is continuing to determine the specific actions required by the orders. Entergy Louisiana’s estimated capital expenditures for 2015 through 2017 for complying with the NRC orders are included in the planned construction and other capital investments estimates given in “Liquidity and Capital Resources - Uses of Capital” above.
Environmental Risks
Entergy Louisiana’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Louisiana is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Louisiana’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Louisiana’s financial position or results of operations.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In the fourth quarter 2013, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $39.4 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement costs asset that will be depreciated over the remaining life of the unit.
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy Louisiana records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Qualified Pension and Other Postretirement Benefits
Entergy Louisiana’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
|
| | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2014 Qualified Pension Cost | | Impact on 2014 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $2,235 | | $35,324 |
| Rate of return on plan assets | | (0.25%) | | $1,346 | | $— |
| Rate of increase in compensation | | 0.25% | | $892 | | $5,860 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
|
| | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2014 Postretirement Benefit Cost | | Impact on 2014 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $465 | | $6,598 |
| Health care cost trend | | 0.25% | | $820 | | $5,691 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Costs and Funding
Total qualified pension cost for Entergy Louisiana in 2014 was $30.8 million. Entergy Louisiana anticipates 2015 qualified pension cost to be $45.4 million. Entergy Louisiana contributed $54.5 million to its pension plans in 2014 and estimates 2015 pension contributions to be approximately $57 million, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.
Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 2014 were $10.9 million. Entergy Louisiana expects 2015 postretirement health care and life insurance benefit costs of approximately $12.8 million. Entergy Louisiana contributed $11.2 million to its other postretirement plans in 2014 and expects to contribute approximately $9.9 million in 2015.
The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $70.3 million in the qualified pension benefit obligation and $9.7 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $10.5 million and other postretirement cost by approximately $1.2 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.
Federal Healthcare Legislation
See the “Qualified Pension and Other Postretirement Benefits -Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Members of
Entergy Louisiana, LLC and Subsidiaries
Jefferson, Louisiana
We have audited the accompanying consolidated balance sheets of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 2014 and 2013 and the related consolidated income statements, consolidated statements of comprehensive income, consolidated statements of cash flows, and consolidated statements of changes in equity (pages 371 through 376 and applicable items in pages 61 through 234) for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Louisiana, LLC and Subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2015
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $2,825,881 |
| |
| $2,626,935 |
| |
| $2,149,443 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 679,028 |
| | 570,956 |
| | 360,964 |
|
| Purchased power | | 895,242 |
| | 850,998 |
| | 728,170 |
|
| Nuclear refueling outage expenses | | 30,347 |
| | 34,566 |
| | 24,344 |
|
| Other operation and maintenance | | 514,910 |
| | 480,166 |
| | 449,172 |
|
| Decommissioning | | 24,649 |
| | 21,612 |
| | 23,406 |
|
| Taxes other than income taxes | | 75,416 |
| | 74,241 |
| | 69,186 |
|
| Depreciation and amortization | | 252,690 |
| | 242,787 |
| | 218,140 |
|
| Other regulatory charges (credits) - net | | (30,844 | ) | | (3,785 | ) | | 127,050 |
|
| TOTAL | | 2,441,438 |
| | 2,271,541 |
| | 2,000,432 |
|
| | | | | | | |
| OPERATING INCOME | | 384,443 |
| | 355,394 |
| | 149,011 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 38,807 |
| | 31,544 |
| | 39,610 |
|
| Interest and investment income | | 94,437 |
| | 91,599 |
| | 84,478 |
|
| Miscellaneous - net | | 8,458 |
| | (3,990 | ) | | (2,584 | ) |
| TOTAL | | 141,702 |
| | 119,153 |
| | 121,504 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 166,750 |
| | 153,529 |
| | 136,967 |
|
| Allowance for borrowed funds used during construction | | (20,406 | ) | | (13,323 | ) | | (18,611 | ) |
| TOTAL | | 146,344 |
| | 140,206 |
| | 118,356 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 379,801 |
| | 334,341 |
| | 152,159 |
|
| | | | | | | |
| Income taxes | | 96,270 |
| | 81,877 |
| | (128,922 | ) |
| | | | | | | |
| NET INCOME | | 283,531 |
| | 252,464 |
| | 281,081 |
|
| | | | | | | |
| Preferred distribution requirements and other | | 6,969 |
| | 6,950 |
| | 6,950 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | |
| $276,562 |
| |
| $245,514 |
| |
| $274,131 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | | |
| | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 |
| | | (In Thousands) |
| | | | | | | |
| Net Income | |
| $283,531 |
| |
| $252,464 |
| |
| $281,081 |
|
| | | | | | | |
| Other comprehensive income (loss) | | |
| | |
| | |
|
| Pension and other postretirement liabilities | | |
| | |
| | |
|
| (net of tax expense (benefit) of ($10,207), $30,591, and $5,095) | | (16,241 | ) | | 36,497 |
| | (6,625 | ) |
| Other comprehensive income (loss) | | (16,241 | ) | | 36,497 |
| | (6,625 | ) |
| | | | | | | |
| Comprehensive Income | |
| $267,290 |
| |
| $288,961 |
| |
| $274,456 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $283,531 |
| |
| $252,464 |
| |
| $281,081 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 349,947 |
| | 337,333 |
| | 293,774 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 149,282 |
| | 310,964 |
| | (59,069 | ) |
| Changes in working capital: | | |
| | |
| | |
|
| Receivables | | 60,747 |
| | (121,118 | ) | | 43,850 |
|
| Fuel inventory | | (7,640 | ) | | 272 |
| | 336 |
|
| Accounts payable | | (22,560 | ) | | (29,151 | ) | | 40,085 |
|
| Prepaid taxes and taxes accrued | | 185,363 |
| | (176,566 | ) | | (39,275 | ) |
| Interest accrued | | 2,300 |
| | 4,808 |
| | 729 |
|
| Deferred fuel costs | | 20,040 |
| | 56,960 |
| | (93,103 | ) |
| Other working capital accounts | | (4,562 | ) | | 41,693 |
| | (79,771 | ) |
| Changes in provisions for estimated losses | | 204,510 |
| | (188,741 | ) | | (16,586 | ) |
| Changes in other regulatory assets | | (213,664 | ) | | 111,049 |
| | (116,249 | ) |
| Changes in other regulatory liabilities | | 12,837 |
| | 156,446 |
| | 81,259 |
|
| Changes in pension and other postretirement liabilities | | 172,430 |
| | (180,601 | ) | | 80,027 |
|
| Other | | (66,521 | ) | | 86,960 |
| | 30,610 |
|
| Net cash flow provided by operating activities | | 1,126,040 |
| | 662,772 |
| | 447,698 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (484,638 | ) | | (711,470 | ) | | (787,075 | ) |
| Allowance for equity funds used during construction | | 38,807 |
| | 31,544 |
| | 39,610 |
|
| Nuclear fuel purchases | | (131,978 | ) | | (51,016 | ) | | (159,501 | ) |
| Proceeds from the sale of nuclear fuel | | 59,784 |
| | 23,438 |
| | 62,248 |
|
| Investment in affiliates | | (227,273 | ) | | — |
| | — |
|
| Payments to storm reserve escrow account | | (200,053 | ) | | — |
| | — |
|
| Receipts from storm reserve escrow account | | — |
| | 187,008 |
| | 14,478 |
|
| Changes in securitization account | | 1,480 |
| | (157 | ) | | 818 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 43,158 |
| | 109,856 |
| | 27,577 |
|
| Investment in nuclear decommissioning trust funds | | (54,044 | ) | | (121,773 | ) | | (39,374 | ) |
| Change in money pool receivable - net | | 15,999 |
| | (8,215 | ) | | (9,433 | ) |
| Other | | — |
| | (22 | ) | | (214 | ) |
| Net cash flow used in investing activities | | (938,758 | ) | | (540,807 | ) | | (850,866 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 642,835 |
| | 417,740 |
| | 663,975 |
|
| Retirement of long-term debt | | (512,180 | ) | | (30,846 | ) | | (50,899 | ) |
| Change in money pool payable - net | | — |
| | — |
| | (118,415 | ) |
| Changes in credit borrowings - net | | 43,110 |
| | (51,734 | ) | | (39,735 | ) |
| Distributions paid: | | |
| | |
| | |
|
| Common equity | | (320,601 | ) | | (356,254 | ) | | (15,600 | ) |
| Preferred membership interests | | (6,950 | ) | | (6,950 | ) | | (6,950 | ) |
| Other | | 50 |
| | — |
| | — |
|
| Net cash flow provided by (used in) financing activities | | (153,736 | ) | | (28,044 | ) | | 432,376 |
|
| Net increase in cash and cash equivalents | | 33,546 |
| | 93,921 |
| | 29,208 |
|
| Cash and cash equivalents at beginning of period | | 124,007 |
| | 30,086 |
| | 878 |
|
| Cash and cash equivalents at end of period | |
| $157,553 |
| |
| $124,007 |
| |
| $30,086 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $158,905 |
| |
| $143,257 |
| |
| $130,934 |
|
| Income taxes | |
| ($241,411 | ) | |
| ($33,622 | ) | |
| ($41,423 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2014 | | 2013 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $431 |
| |
| $427 |
|
| Temporary cash investments | | 157,122 |
| | 123,580 |
|
| Total cash and cash equivalents | | 157,553 |
| | 124,007 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 124,125 |
| | 144,836 |
|
| Allowance for doubtful accounts | | (984 | ) | | (965 | ) |
| Associated companies | | 48,474 |
| | 87,820 |
|
| Other | | 9,150 |
| | 21,420 |
|
| Accrued unbilled revenues | | 88,673 |
| | 93,073 |
|
| Total accounts receivable | | 269,438 |
| | 346,184 |
|
| Accumulated deferred income taxes | | 74,558 |
| | 100,022 |
|
| Fuel inventory | | 30,951 |
| | 23,311 |
|
| Materials and supplies - at average cost | | 154,295 |
| | 156,487 |
|
| Deferred nuclear refueling outage costs | | 23,067 |
| | 13,670 |
|
| Prepaid taxes | | — |
| | 184,503 |
|
| Prepayments and other | | 24,962 |
| | 22,651 |
|
| TOTAL | | 734,824 |
| | 970,835 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Investment in affiliate preferred membership interests | | 1,034,696 |
| | 807,423 |
|
| Decommissioning trust funds | | 383,615 |
| | 347,274 |
|
| Storm reserve escrow account | | 200,053 |
| | — |
|
| Non-utility property - at cost (less accumulated depreciation) | | 214 |
| | 396 |
|
| TOTAL | | 1,618,578 |
| | 1,155,093 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 9,627,495 |
| | 8,799,393 |
|
| Property under capital lease | | 334,716 |
| | 331,895 |
|
| Construction work in progress | | 241,923 |
| | 672,883 |
|
| Nuclear fuel | | 162,721 |
| | 147,385 |
|
| TOTAL UTILITY PLANT | | 10,366,855 |
| | 9,951,556 |
|
| Less - accumulated depreciation and amortization | | 3,942,916 |
| | 3,763,234 |
|
| UTILITY PLANT - NET | | 6,423,939 |
| | 6,188,322 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Regulatory asset for income taxes - net | | 324,555 |
| | 309,617 |
|
| Other regulatory assets (includes securitization property of $135,538 as of December 31, 2014 and $156,103 as of December 31, 2013) | | 914,229 |
| | 715,503 |
|
| Deferred fuel costs | | 67,998 |
| | 67,998 |
|
| Other | | 45,182 |
| | 43,025 |
|
| TOTAL | | 1,351,964 |
| | 1,136,143 |
|
| | | | | |
| TOTAL ASSETS | |
| $10,129,305 |
| |
| $9,450,393 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2014 | | 2013 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $19,525 |
| |
| $320,231 |
|
| Short-term borrowings | | 46,033 |
| | 2,923 |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 74,692 |
| | 83,655 |
|
| Other | | 164,329 |
| | 162,507 |
|
| Customer deposits | | 93,010 |
| | 90,393 |
|
| Taxes accrued | | 860 |
| | — |
|
| Accumulated deferred income taxes | | — |
| | 338 |
|
| Interest accrued | | 44,372 |
| | 42,072 |
|
| Deferred fuel costs | | 50,432 |
| | 30,392 |
|
| Other | | 48,250 |
| | 46,698 |
|
| TOTAL | | 541,503 |
| | 779,209 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 1,406,507 |
| | 1,275,584 |
|
| Accumulated deferred investment tax credits | | 64,771 |
| | 67,347 |
|
| Other regulatory liabilities | | 546,084 |
| | 533,247 |
|
| Decommissioning | | 503,734 |
| | 479,086 |
|
| Accumulated provisions | | 212,243 |
| | 7,733 |
|
| Pension and other postretirement liabilities | | 530,844 |
| | 358,017 |
|
| Long-term debt (includes securitization bonds of $143,039 as of December 31, 2014 and $164,965 as of December 31, 2013) | | 3,337,054 |
| | 2,899,285 |
|
| Other | | 70,141 |
| | 75,233 |
|
| TOTAL | | 6,671,378 |
| | 5,695,532 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| EQUITY | | |
| | |
|
| Preferred membership interests without sinking fund | | 100,000 |
| | 100,000 |
|
| Member’s equity | | 2,842,300 |
| | 2,885,287 |
|
| Accumulated other comprehensive loss | | (25,876 | ) | | (9,635 | ) |
| TOTAL | | 2,916,424 |
| | 2,975,652 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $10,129,305 |
| |
| $9,450,393 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2014, 2013, and 2012 |
| | | | | | |
| | | | Common Equity | | |
| | Preferred Membership Interests | | Member’s Equity | | Accumulated Other Comprehensive Income (Loss) | | Total |
| | (In Thousands) |
| | | | | | | | |
| Balance at December 31, 2011 |
| $100,000 |
| |
| $2,504,436 |
| |
| ($39,507 | ) | |
| $2,564,929 |
|
| Net income | — |
| | 281,081 |
| | — |
| | 281,081 |
|
| Additional contribution from parent | — |
| | 253,661 |
| | — |
| | 253,661 |
|
| Other comprehensive loss | — |
| | — |
| | (6,625 | ) | | (6,625 | ) |
| Distributions to parent | — |
| | (15,600 | ) | | — |
| | (15,600 | ) |
| Distributions declared on preferred membership interests | — |
| | (6,950 | ) | | — |
| | (6,950 | ) |
| Balance at December 31, 2012 |
| $100,000 |
| |
| $3,016,628 |
| |
| ($46,132 | ) | |
| $3,070,496 |
|
| Net income | — |
| | 252,464 |
| | — |
| | 252,464 |
|
| Other comprehensive income | — |
| | — |
| | 36,497 |
| | 36,497 |
|
| Distributions to parent | — |
| | (376,855 | ) | | — |
| | (376,855 | ) |
| Distributions declared on preferred membership interests | — |
| | (6,950 | ) | | — |
| | (6,950 | ) |
| Balance at December 31, 2013 |
| $100,000 |
| |
| $2,885,287 |
| |
| ($9,635 | ) | |
| $2,975,652 |
|
| Net income | — |
| | 283,531 |
| | — |
| | 283,531 |
|
| Other comprehensive loss | — |
| | — |
| | (16,241 | ) | | (16,241 | ) |
| Contributions from parent | — |
| | 1,052 |
| | — |
| | 1,052 |
|
| Distributions to parent | — |
| | (320,601 | ) | | — |
| | (320,601 | ) |
| Distributions declared on preferred membership interests | — |
| | (6,969 | ) | | — |
| | (6,969 | ) |
| Balance at December 31, 2014 |
| $100,000 |
| |
| $2,842,300 |
| |
| ($25,876 | ) | |
| $2,916,424 |
|
| | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2014 | | 2013 | | 2012 | | 2011 | | 2010 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $2,825,881 |
| |
| $2,626,935 |
| |
| $2,149,443 |
| |
| $2,508,915 |
| |
| $2,538,766 |
|
| Net Income |
| $283,531 |
| |
| $252,464 |
| |
| $281,081 |
| |
| $473,923 |
| |
| $231,435 |
|
| Total assets |
| $10,129,305 |
| |
| $9,450,393 |
| |
| $9,074,084 |
| |
| $8,063,867 |
| |
| $7,488,423 |
|
| Long-term obligations (a) |
| $3,337,054 |
| |
| $2,899,285 |
| |
| $2,811,859 |
| |
| $2,177,003 |
| |
| $1,771,566 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt). |
| | | | | | | | | | |
| | 2014 | | 2013 | | 2012 | | 2011 | | 2010 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $856 |
| |
| $839 |
| |
| $687 |
| |
| $830 |
| |
| $840 |
|
| Commercial | 596 |
| | 586 |
| | 482 |
| | 549 |
| | 543 |
|
| Industrial | 981 |
| | 955 |
| | 731 |
| | 867 |
| | 817 |
|
| Governmental | 47 |
| | 46 |
| | 38 |
| | 42 |
| | 42 |
|
| Total retail |
| $2,480 |
| |
| $2,426 |
| |
| $1,938 |
| |
| $2,288 |
| |
| $2,242 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 256 |
| | 114 |
| | 137 |
| | 137 |
| | 220 |
|
| Non-associated companies | 18 |
| | 3 |
| | 2 |
| | 8 |
| | 5 |
|
| Other | 72 |
| | 84 |
| | 72 |
| | 76 |
| | 72 |
|
| Total |
| $2,826 |
| |
| $2,627 |
| |
| $2,149 |
| |
| $2,509 |
| |
| $2,539 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | |
| | |
| | |
| | |
| | |
|
| Residential | 9,047 |
| | 8,820 |
| | 8,703 |
| | 9,303 |
| | 9,533 |
|
| Commercial | 6,257 |
| | 6,194 |
| | 6,112 |
| | 6,155 |
| | 6,164 |
|
| Industrial | 17,100 |
| | 16,713 |
| | 16,416 |
| | 15,813 |
| | 14,473 |
|
| Governmental | 500 |
| | 495 |
| | 479 |
| | 473 |
| | 479 |
|
| Total retail | 32,904 |
| | 32,222 |
| | 31,710 |
| | 31,744 |
| | 30,649 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 4,450 |
| | 1,844 |
| | 2,156 |
| | 2,145 |
| | 2,860 |
|
| Non-associated companies | 126 |
| | 92 |
| | 65 |
| | 185 |
| | 101 |
|
| Total | 37,480 |
| | 34,158 |
| | 33,931 |
| | 34,074 |
| | 33,610 |
|
ENTERGY MISSISSIPPI, INC.
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Net Income
2014 Compared to 2013
Net income decreased $7.3 million primarily due to the write-off in 2014 of the regulatory asset associated with new nuclear generation development costs as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, in which Entergy Mississippi agreed not to pursue recovery of the costs deferred by an MPSC order in the new nuclear generation docket. See Note 2 to the financial statements for discussion of the new nuclear generation development costs and the joint stipulation. Also contributing to the decrease were higher depreciation and amortization expenses and higher taxes other than income taxes. These decreases were significantly offset by higher net revenue and lower other operation and maintenance expenses.
2013 Compared to 2012
Net income increased $35.4 million primarily due to higher net revenue and a lower effective income tax rate, partially offset by higher other operation and maintenance expenses.
Net Revenue
2014 Compared to 2013
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2014 to 2013.
|
| | | |
| Amount |
| (In Millions) |
| |
2013 net revenue |
| $644.4 |
|
Retail electric price | 39.7 |
|
Reserve equalization | 11.2 |
|
Transmission equalization | 1.3 |
|
Volume/weather | 1.3 |
|
Other | 3.3 |
|
2014 net revenue |
| $701.2 |
|
The retail electric price variance is primarily due to a formula rate plan increase, as approved by the MPSC, effective September 2013 and an increase in the storm damage rider, as approved by the MPSC, effective October 2013. The increase in the storm damage rider is offset by other operation and maintenance expenses and has no effect on net income. See Note 2 to the financial statements for a discussion of the formula rate plan and storm damage rider.
The reserve equalization variance is primarily due to an increase in reserve equalization revenue primarily due to the changes in the Entergy System generation mix as a result of Entergy Arkansas’s exit from the System Agreement in December 2013.
Entergy Mississippi, Inc.
Management's Financial Discussion and Analysis
The transmission equalization variance is primarily due to changes in transmission investment equalization billings under the Entergy System Agreement compared to the same period in 2013 primarily as a result of Entergy Arkansas’s exit from the System Agreement in December 2013.
The volume/weather variance is primarily due to an increase of 86 GWh, or 1%, in billed electricity usage, including the effect of more favorable weather on residential sales as compared to the prior year and an increase in industrial. The increase in industrial usage is primarily in the primary metals and pipelines industries.
2013 Compared to 2012
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory credits. Following is an analysis of the change in net revenue comparing 2013 to 2012.
|
| | | |
| Amount |
| (In Millions) |
| |
2012 net revenue |
| $578.0 |
|
Retail electric price | 55.1 |
|
Reserve equalization | 8.0 |
|
Other | 3.3 |
|
2013 net revenue |
| $644.4 |
|
The retail electric price variance is primarily due to the recovery of Hinds plant costs through the power management rider, as approved by the MPSC, effective with the first billing cycle of 2013 and a formula rate plan increase effective September 2013. The net income effect of the Hinds plant cost recovery is limited to a portion representing an allowed return on equity on the net plant investment with the remainder offset by the Hinds plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes. The increase is partially offset by a temporary increase in 2012 in the storm cost recovery rider, as approved by the MPSC for a five-month period effective August 2012. This temporary increase in revenues in 2012 was offset by costs included in other operation and maintenance expenses and had no effect on net income. See Note 2 to the financial statements for discussion of the formula rate plan increase.
The reserve equalization variance is primarily due to increased reserve equalization revenue resulting from the acquisition of the Hinds plant in November 2012.
Other Income Statement Variances
2014 Compared to 2013
Other operation and maintenance expenses decreased primarily due to:
a decrease of $11.6 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
a decrease of $7.6 million in fossil-fueled generation expenses primarily due to a lower scope of work done during plant outages in 2014 as compared to the same period in 2013;
a decrease of $5.9 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business;
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
a decrease of $5.1 million in implementation costs, severance costs, and curtailment and special termination benefits related to the human capital management strategic imperative in 2014 as compared to the same period in 2013. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion; and
a net decrease of $3.8 million related to Baxter Wilson (Unit 1) repairs. The increase in repair costs incurred in 2014 compared to the prior year were offset by expected insurance proceeds and the deferral of repair costs, as approved by the MPSC. See “Baxter Wilson Plant Event” below for further discussion.
The decrease was partially offset by:
an increase of $10 million in storm damage accruals, as approved by the MPSC, effective October 2013;
an increase of $5.1 million in 2014 as compared to 2013 in administration fees related to participation in the MISO RTO;
an increase of $4 million in regulatory, consulting, and legal fees;
an increase of $2.3 million in distribution and transmission vegetation maintenance;
an increase of $1.3 million due to higher write-offs of uncollectible customer accounts in 2014 as compared to 2013; and
several individually insignificant items.
The asset write-off resulted from the $56.2 million ($36.7 million after-tax) write-off in 2014 of the regulatory asset associated with new nuclear generation development costs as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, in which Entergy Mississippi agreed not to pursue recovery of the costs deferred by an MPSC order in the new nuclear generation docket. See Note 2 to the financial statements for discussion of the new nuclear generation development costs and the joint stipulation.
Taxes other than income taxes increased primarily due to an increase in ad valorem taxes in 2014 as compared to prior year and an increase in local franchise taxes due to higher revenues.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
2013 Compared to 2012
Other operation and maintenance expenses increased primarily due to:
an increase of $30.6 million in fossil-fueled generation expenses resulting from a higher scope of work done during plant outages in 2013 as compared to 2012, the acquisition of the Hinds plant in November 2012, and the Baxter Wilson (Unit 1) unplanned outage in September 2013;
an increase of $7.1 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion; and
an increase of $5.9 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs.
The increase was partially offset by a temporary increase in 2012 of $17.8 million in storm damage accruals, as approved by the MPSC for a five-month period effective August 2012, and several individually insignificant items.
Also, other operation and maintenance expenses include $5.9 million in 2013 and $7.6 million in 2012 of costs incurred related to the now terminated plan to spin off and merge the transmission business.
Entergy Mississippi, Inc.
Management's Financial Discussion and Analysis
Taxes other than income taxes increased primarily due to an increase in ad valorem taxes as a result of a higher assessment in 2013 primarily due to the acquisition of the Hinds plant in November 2012.
Depreciation and amortization expenses increased primarily due to an increase in plant in service, including the acquisition of the Hinds plant in November 2012.
Income Taxes
The effective income tax rates for 2014, 2013, and 2012 were 42.7%, 37.7%, and 55.6%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
Baxter Wilson Plant Event
On September 11, 2013, Entergy Mississippi’s Baxter Wilson (Unit 1) power plant experienced a significant unplanned outage event. Entergy Mississippi completed the repairs to the unit in December 2014. As of December 31, 2014, Entergy Mississippi incurred $22.3 million of capital spending and $26.6 million of operation and maintenance expenses to return the unit to service. The damage was covered by Entergy Mississippi’s property insurance policy, subject to a $20 million deductible. As of December 31, 2014, Entergy Mississippi recorded an insurance receivable of $28.2 million for the amount expected to be received from its insurance policy, allocating $12.9 million of the expected insurance proceeds to capital spending and $15.3 million to operation and maintenance expenses. In June 2014, Entergy Mississippi filed a rate case with the MPSC, which includes recovery of the costs associated with Baxter Wilson (Unit 1) repair activities, net of applicable insurance proceeds. In December 2014 the MPSC issued an order that provided for a deferral of $6 million in other operation and maintenance expenses associated with the Baxter Wilson outage and that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset to occur over two years beginning in February 2015, and provided that the capital costs will be reflected in rate base. The final accounting of costs to return the unit to service and insurance proceeds will be addressed in Entergy Mississippi’s next formula rate plan filing.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2014, 2013, and 2012 were as follows:
|
| | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $31 |
| |
| $52,970 |
| |
| $16 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 303,463 |
| | 219,665 |
| | 202,406 |
|
| Investing activities | (177,765 | ) | | (149,410 | ) | | (391,127 | ) |
| Financing activities | (64,096 | ) | | (123,194 | ) | | 241,675 |
|
| Net increase (decrease) in cash and cash equivalents | 61,602 |
| | (52,939 | ) | | 52,954 |
|
| | | | | | |
| Cash and cash equivalents at end of period |
| $61,633 |
| |
| $31 |
| |
| $52,970 |
|
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Operating Activities
Net cash flow provided by operating activities increased $83.8 million in 2014 primarily due to:
increased recovery of fuel costs;
the timing of collections of receivables from customers; and
System Agreement bandwidth remedy payments of $11.3 million received in the second quarter 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period.
The increase was partially offset by:
System Agreement bandwidth remedy payments made in September 2014 of $16.4 million as a result of the compliance filing pursuant to the FERC’s orders related to the bandwidth payments/receipts for the 2007 - 2009 period;
an increase of $15 million in income tax payments in 2014. Entergy Mississippi had income tax payments in 2014 and 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2013 and 2014 payments resulted primarily from the reversal of temporary differences for which Entergy Mississippi had previously claimed a tax deduction; and
an increase of $13.7 million in pension contributions in 2014 as compared to 2013. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
See Note 2 to the financial statements for a discussion of the System Agreement proceedings.
Net cash flow provided by operating activities increased $17.3 million in 2013 primarily due to the timing of collections of receivables from customers and a $1.5 million decrease in pension contributions in 2013 as compared to 2012. The increase was partially offset by income tax payments of $4.7 million in 2013, as discussed above, as compared to income tax refunds of $0.7 million in 2012. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Investing Activities
Net cash flow used in investing activities increased $28.4 million in 2014 primarily due to money pool activity and an increase in fossil-fueled generation construction expenditures primarily due to a higher scope of work done during plant outages in 2014 and an increase in spending on Baxter Wilson (Unit 1) repairs in 2014. The increase was partially offset by a decrease in transmission construction expenditures as a result of a decrease in reliability work performed in 2014.
Increases in Entergy Mississippi’s receivable from the money pool are a use of cash flow, and Entergy Mississippi’s receivable from the money pool increased by $0.6 million in 2014 compared to decreasing by $16.9 million in 2013. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Net cash flow used in investing activities decreased $241.7 million in 2013 primarily due to the payment for the purchase of Hinds Energy Facility in November 2012 of approximately $203 million, including adjustments to the purchase price, and money pool activity. See Note 15 to the financial statements for a discussion of the purchase of Hinds Energy Facility.
Decreases in Entergy Mississippi’s receivable from the money pool are a source of cash flow, and Entergy Mississippi’s receivable from the money pool decreased by $16.9 million in 2013 compared to increasing by $16.9 million in 2012.
Entergy Mississippi, Inc.
Management's Financial Discussion and Analysis
Financing Activities
Net cash flow used in financing activities decreased $59.1 million in 2014 primarily due to the issuance of $100 million of 3.75% Series first mortgage bonds in March 2014 and the payment, at maturity, of $100 million of 5.15% Series first mortgage bonds in February 2013.
The decrease was partially offset by:
the payment, prior to maturity, of $95 million of 4.95% Series first mortgage bonds in April 2014;
an increase of $54 million in common stock dividends paid in 2014 as compared to 2013; and
money pool activity.
Decreases in Entergy Mississippi’s payable to the money pool are a use of cash flow, and Entergy Mississippi’s payable to the money pool decreased by $3.5 million in 2014 compared to increasing by $3.5 million in 2013.
Entergy Mississippi’s financing activities used $123.2 million of cash in 2013 as compared to providing $241.7 million of cash in 2012 primarily due to the payment, at maturity, of $100 million of 5.15% Series first mortgage bonds in February 2013 and the issuance of $250 million of 3.1% Series first mortgage bonds in December 2012.
See Note 5 to the financial statements for details on long-term debt.
Capital Structure
Entergy Mississippi’s capitalization is balanced between equity and debt, as shown in the following table.
|
| | | | | |
| | December 31,
2014 | | December 31,
2013 |
| Debt to capital | 51.2 | % | | 51.4 | % |
| Effect of subtracting cash | (1.5 | %) | | — | % |
| Net debt to net capital | 49.7 | % | | 51.4 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, capital lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Mississippi uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition. Entergy Mississippi uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition because net debt indicates Entergy Mississippi’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Uses of Capital
Entergy Mississippi requires capital resources for:
construction and other capital investments;
debt and preferred stock maturities or retirements;
working capital purposes, including the financing of fuel and purchased power costs; and
dividend and interest payments.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Mississippi’s planned construction and other capital investments.
|
| | | | | | | | | | | |
| | 2015 | | 2016 | | 2017 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $35 |
| |
| $15 |
| |
| $20 |
|
| Transmission | 70 |
| | 115 |
| | 180 |
|
| Distribution | 125 |
| | 115 |
| | 100 |
|
| Other | 25 |
| | 15 |
| | 15 |
|
| Total |
| $255 |
| |
| $260 |
| |
| $315 |
|
Following are the amounts of Entergy Mississippi’s existing debt obligations and lease obligations (includes estimated interest payments) and other purchase obligations.
|
| | | | | | | | | | | | | | | | | | | |
| | 2015 | | 2016-2017 | | 2018-2019 | | After 2019 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $52 |
| |
| $222 |
| |
| $240 |
| |
| $1,245 |
| |
| $1,759 |
|
| Capital lease payments |
| $2 |
| |
| $3 |
| |
| $1 |
| |
| $— |
| |
| $6 |
|
| Operating leases |
| $7 |
| |
| $9 |
| |
| $6 |
| |
| $4 |
| |
| $26 |
|
| Purchase obligations (b) |
| $318 |
| |
| $563 |
| |
| $496 |
| |
| $1,033 |
| |
| $2,410 |
|
| |
(a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
(b) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Mississippi, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements. |
In addition to the contractual obligations given above, Entergy Mississippi currently expects to contribute approximately $22.5 million to its pension plans and approximately $535 thousand to its other postretirement plans in 2015, although the 2015 required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy Mississippi has $13.2 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Mississippi includes amounts associated with specific investments such as environmental compliance spending; transmission projects to enhance reliability, reduce congestion, and enable economic growth; resource planning; generation projects; system improvements; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.
As a wholly-owned subsidiary, Entergy Mississippi dividends its earnings to Entergy Corporation at a percentage determined monthly. Entergy Mississippi’s long-term debt indenture restricts the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock. As of
Entergy Mississippi, Inc.
Management's Financial Discussion and Analysis
December 31, 2014, Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $68.5 million.
New Nuclear Generation Development Costs
Pursuant to the Mississippi Baseload Act and the Mississippi Public Utilities Act, Entergy Mississippi had been developing and preserving a project option for new nuclear generation at Grand Gulf Nuclear Station. In October 2010, Entergy Mississippi filed an application with the MPSC requesting that the MPSC determine that it was in the public interest to preserve the option to construct new nuclear generation at Grand Gulf and that the MPSC approve the deferral of Entergy Mississippi’s costs incurred to date and in the future related to this project, including the accrual of AFUDC or similar carrying charges. In October 2011, Entergy Mississippi and the Mississippi Public Utilities Staff filed with the MPSC a joint stipulation that the MPSC approved in November 2011. The stipulation stated that there should be a deferral of the $57 million of costs incurred through September 2011 in connection with planning, evaluating, monitoring, and other related generation resource development activities for new nuclear generation at Grand Gulf.
In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations in Entergy Mississippi’s general rate case proceeding, which are discussed below. In consideration of the comprehensive terms for settlement in that rate case proceeding, the Mississippi Public Utilities Staff and Entergy Mississippi agreed that Entergy Mississippi would request consolidation of the new nuclear generation development costs proceeding with the rate case proceeding for hearing purposes and will not further pursue, except as noted below, recovery of the costs deferred by MPSC order in the new nuclear generation development docket. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. After considering the progress of the new nuclear generation costs proceeding in light of the joint stipulation, Entergy Mississippi recorded in 2014 a $56.2 million pre-tax charge to recognize that the regulatory asset associated with new nuclear generation development is no longer probable of recovery. In December 2014 the MPSC issued an order accepting in their entirety the October 2014 stipulations, including the findings and terms of the stipulations regarding new nuclear generation development costs.
Sources of Capital
Entergy Mississippi’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt or preferred stock issuances; and
bank financing under new or existing facilities.
Entergy Mississippi may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred stock issuances by Entergy Mississippi require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in its corporate charter, bond indenture, and other agreements. Entergy Mississippi has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Entergy Mississippi’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2014 | | 2013 | | 2012 | | 2011 |
| (In Thousands) |
| $644 | | ($3,536) | | $16,878 | | ($1,999) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Mississippi has four separate credit facilities in the aggregate amount of $102.5 million scheduled to expire May 2015. No borrowings were outstanding under the credit facilities as of December 31, 2014. See Note 4 to the financial statements for additional discussion of the credit facilities. In addition, Entergy Mississippi entered into an uncommitted letter of credit facility in 2013 and an uncommitted letter of credit facility in 2014 as a means to post collateral to support its obligations under MISO. As of December 31, 2014, a $14.4 million letter of credit was outstanding under Entergy Mississippi’s letter of credit facility which was issued in 2014.
Entergy Mississippi obtained authorizations from the FERC through October 2015 for short-term borrowings not to exceed an aggregate amount of $175 million at any time outstanding and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Mississippi’s short-term borrowing limits. Entergy Mississippi has also obtained an order from the FERC authorizing long-term securities issuances through October 2015.
In March 2014, Entergy Mississippi issued $100 million of 3.75% Series first mortgage bonds due July 2024. Entergy Mississippi used the proceeds to pay, prior to maturity, its $95 million of 4.95% Series first mortgage bonds due June 2018 and for general corporate purposes.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Mississippi charges for electricity significantly influence its financial position, results of operations, and liquidity. Entergy Mississippi is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the MPSC, is primarily responsible for approval of the rates charged to customers.
Formula Rate Plan
In September 2009, Entergy Mississippi filed with the MPSC proposed modifications to its formula rate plan rider. In March 2010 the MPSC issued an order: (1) providing the opportunity for a reset of Entergy Mississippi’s return on common equity to a point within the formula rate plan bandwidth and eliminating the 50/50 sharing that had been in the plan, (2) modifying the performance measurement process, and (3) replacing the revenue change limit of two percent of revenues, which was subject to a $14.5 million revenue adjustment cap, with a limit of four percent of revenues, although any adjustment above two percent requires a hearing before the MPSC. The MPSC did not approve Entergy Mississippi’s request to use a projected test year for its annual scheduled formula rate plan filing and, therefore, Entergy Mississippi continued to use a historical test year for its annual evaluation reports under the plan.
In March 2012, Entergy Mississippi submitted its formula rate plan filing for the 2011 test year. The filing shows an earned return on common equity of 10.92% for the test year, which is within the earnings bandwidth and results in no change in rates. In February 2013 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provided for no change in rates.
In March 2013, Entergy Mississippi submitted its formula rate plan filing for the 2012 test year. The filing requested a $36.3 million revenue increase to reset Entergy Mississippi’s return on common equity to 10.55%, which is a point within the formula rate plan bandwidth. In June 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, in which both parties agreed that the MPSC should approve a $22.3 million rate
Entergy Mississippi, Inc.
Management's Financial Discussion and Analysis
increase for Entergy Mississippi which, with other adjustments reflected in the stipulation, would have the effect of resetting Entergy Mississippi’s return on common equity to 10.59% when adjusted for performance under the formula rate plan. In August 2013 the MPSC approved the joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff authorizing the rate increase effective with September 2013 bills. Additionally, the MPSC authorized Entergy Mississippi to defer approximately $1.2 million in MISO-related implementation costs incurred in 2012 along with other MISO-related implementation costs incurred in 2013.
In June 2014, Entergy Mississippi filed its first general rate case before the MPSC in almost 12 years. The rate filing laid out Entergy Mississippi’s plans for improving reliability, modernizing the grid, maintaining its workforce, stabilizing rates, utilizing new technologies, and attracting new industry to its service territory. Entergy Mississippi requested a net increase in revenue of $49 million for bills rendered during calendar year 2015, including $30 million resulting from new depreciation rates to update the estimated service life of assets. In addition, the filing proposed, among other things: 1) realigning cost recovery of the Attala and Hinds power plant acquisitions from the power management rider to base rates; 2) including certain MISO-related revenues and expenses in the power management rider; 3) power management rider changes that reflect the changes in costs and revenues that will accompany Entergy Mississippi’s withdrawal from participation in the System Agreement; and 4) a formula rate plan forward test year to allow for known changes in expenses and revenues for the rate effective period. Entergy Mississippi proposed maintaining the current authorized return on common equity of 10.59%.
In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations that addressed the majority of issues in the proceeding. The stipulations provided for:
an approximate $16 million net increase in revenues, which reflected an agreed upon 10.07% return on common equity;
revision of Entergy Mississippi’s formula rate plan by providing Entergy Mississippi with the ability to reflect known and measurable changes to historical rate base and certain expense amounts; resolving uncertainty around and obviating the need for an additional rate filing in connection with Entergy Mississippi’s withdrawal from participation in the System Agreement; updating depreciation rates; and moving costs associated with the Attala and Hinds generating plants from the power management rider to base rates;
recovery of non-fuel MISO-related costs through a separate rider for that purpose;
a deferral of $6 million in other operation and maintenance expenses associated with the Baxter Wilson outage and a determination that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset over two years beginning in February 2015, and a provision that the capital costs will be reflected in rate base. See "Baxter Wilson Plant Event" above for further discussion of the Baxter Wilson outage; and
consolidation of the new nuclear generation development costs proceeding with the general rate case proceeding for hearing purposes and a determination that Entergy Mississippi would not further pursue, except as noted below, recovery of the costs that were approved for deferral by the MPSC in November 2011. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. See "New Nuclear Generation Development Costs" above for further discussion of the new nuclear generation development costs proceeding and subsequent write-off in 2014 of the regulatory asset related to those costs.
In December 2014 the MPSC issued an order accepting the stipulations in their entirety and approving the revenue adjustments and rate changes effective with February 2015 bills.
In August 2012 the MPSC opened inquiries to review whether the current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan is still appropriate or can be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan docket. In March
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans.
In Entergy Mississippi’s 2014 general rate case, the Mississippi Public Utilities Staff conducted a review of Entergy Mississippi’s proposed changes to its formula rate plan and recommended changes in that proceeding that may be duplicative of the review being conducted simultaneously in the above-described formula rate plan docket. Consequently, the MPSC found in the general rate case order that the changes to Entergy Mississippi's formula rate plan schedule approved in that order are just and reasonable and should remain unchanged by any MPSC action in the above-described formula rate plan docket, but that any provisions of Entergy Mississippi's formula rate plan schedule not specifically addressed in the general rate case order may be reviewed and changed.
Fuel and Purchased Power Cost Recovery
Entergy Mississippi’s rate schedules include an energy cost recovery rider that, effective January 1, 2013, is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
Entergy Mississippi had a deferred fuel balance of $60.4 million as of March 31, 2014. In May 2014, Entergy Mississippi filed for an interim adjustment under its energy cost recovery rider. The interim adjustment proposed a net energy cost factor designed to collect over a six-month period the under-recovered deferred fuel balance as of March 31, 2014 and also reflected a natural gas price of $4.50 per MMBtu. In May 2014, Entergy Mississippi and the Public Utilities Staff entered into a joint stipulation in which Entergy Mississippi agreed to a revised net energy cost factor that reflected the proposed interim adjustment with a reduction in costs recovered through the energy cost recovery rider associated with the suspension of the DOE nuclear waste storage fee. In June 2014 the MPSC approved the joint stipulation and allowed Entergy Mississippi’s interim adjustment. In November 2014, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. Due to lower gas prices and a lower deferred fuel balance, the redetermined annual factor was a decrease from the revised interim net energy cost factor. In January 2015 the MPSC approved the redetermined annual factor effective January 30, 2015.
Mississippi Attorney General Complaint
The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. In December 2008 the defendant Entergy companies removed the attorney general’s lawsuit to U.S. District Court in Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.
Entergy Mississippi, Inc.
Management's Financial Discussion and Analysis
The defendant Entergy companies answered the complaint and filed a counterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. In May 2009 the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the attorney general’s complaint. In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings. The District Court’s ruling on the motion for judgment on the pleadings is pending.
In January 2014 the U.S. Supreme Court issued a decision in which it held that cases brought by attorneys general as the sole plaintiff to enforce state laws were not subject to the federal law that allowed federal courts to hear those cases as “mass action” lawsuits. One day later the Attorney General renewed its motion to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies have responded to that motion and the District Court held oral argument on the motion to remand in February 2014. Entergy also has asserted federal question jurisdiction as a basis for the district court having jurisdiction and also has pending the motion for judgment on the pleadings.
Storm Damage Accrual and Storm Cost Recovery
In two orders issued in July 2012 the MPSC temporarily increased Entergy Mississippi’s storm damage provision monthly accrual from $0.75 million to $2 million for bills rendered during the billing months of August 2012 through December 2012, and approved recovery of $14.9 million in prudently incurred storm costs to be amortized over five months, beginning with August 2012 bills.
In August 2012, Hurricane Isaac caused damage to Entergy Mississippi’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair and/or replacement of Entergy Mississippi’s electric facilities damaged by Hurricane Isaac were $22 million.
On July 1, 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, wherein both parties agreed that approximately $32 million in storm restoration costs incurred in 2011 and 2012 were prudently incurred and chargeable to the storm damage provision, while approximately $700,000 in prudently incurred costs were more properly recoverable through the formula rate plan. Entergy Mississippi and the Mississippi Public Utilities Staff also agreed that the storm damage accrual should be increased from $750,000 per month to $1.75 million per month. In September 2013 the MPSC approved the joint stipulation with the increase in the storm damage accrual effective with October 2013 bills. In February 2015, Entergy Mississippi provided notice to the Mississippi Public Utilities Staff that the storm damage accrual would be set to zero effective with the March 2015 billing cycle as a result of Entergy Mississippi's storm damage accrual balance exceeding $15 million as of January 31, 2015, but will return to its current level when the storm damage accrual balance becomes less than $10 million.
Federal Regulation
See “Entergy’s Integration Into the MISO Regional Transmission Organization,” “System Agreement,” and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of these topics.
Nuclear Matters
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Environmental Risks
Entergy Mississippi’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Mississippi is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Mississippi’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of Entergy Mississippi’s financial position or results of operations.
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy Mississippi records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Qualified Pension and Other Postretirement Benefits
Entergy Mississippi’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected qualified benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
|
| | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2014 Qualified Pension Cost | | Impact on 2014 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $906 | | $14,873 |
| Rate of return on plan assets | | (0.25%) | | $671 | | $— |
| Rate of increase in compensation | | 0.25% | | $361 | | $2,205 |
Entergy Mississippi, Inc.
Management's Financial Discussion and Analysis
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
|
| | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2014 Postretirement Benefit Cost | | Impact on 2014 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $225 | | $2,925 |
| Health care cost trend | | 0.25% | | $377 | | $2,531 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension cost for Entergy Mississippi in 2014 was $10 million. Entergy Mississippi anticipates 2015 qualified pension cost to be $16.4 million. Entergy Mississippi contributed $21.8 million to its qualified pension plans in 2014 and estimates 2015 pension contributions to be approximately $22.5 million, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.
Total postretirement health care and life insurance benefit income for Entergy Mississippi in 2014 was $982 thousand. Entergy Mississippi expects 2015 postretirement health care and life insurance benefit income of approximately $758 thousand. Entergy Mississippi contributed $8.5 million to its other postretirement plans in 2014 and expects to contribute $535 thousand in 2015.
The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $33.5 million in the qualified pension benefit obligation and $4.6 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $4.8 million and other postretirement cost by approximately $0.6 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.
Federal Healthcare Legislation
See the “Qualified Pension and Other Postretirement Benefits -Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
(Page left blank intentionally)
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Entergy Mississippi, Inc.
Jackson, Mississippi
We have audited the accompanying balance sheets of Entergy Mississippi, Inc. (the “Company”) as of December 31, 2014 and 2013, and the related income statements, statements of cash flows, and statements of changes in common equity (pages 394 through 398 and applicable items in pages 61 through 234) for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Mississippi, Inc. as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2015
|
| | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $1,524,193 |
| |
| $1,334,540 |
| |
| $1,120,366 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 325,643 |
| | 328,934 |
| | 227,133 |
|
| Purchased power | | 493,533 |
| | 375,745 |
| | 320,923 |
|
| Other operation and maintenance | | 256,339 |
| | 261,832 |
| | 244,722 |
|
| Asset write-off | | 56,225 |
| | — |
| | — |
|
| Taxes other than income taxes | | 87,936 |
| | 83,630 |
| | 75,006 |
|
| Depreciation and amortization | | 113,903 |
| | 108,714 |
| | 97,768 |
|
| Other regulatory charges (credits) - net | | 3,854 |
| | (14,545 | ) | | (5,701 | ) |
| TOTAL | | 1,337,433 |
| | 1,144,310 |
| | 959,851 |
|
| | | | | | | |
| OPERATING INCOME | | 186,760 |
| | 190,230 |
| | 160,515 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 2,380 |
| | 2,182 |
| | 3,955 |
|
| Interest and investment income | | 1,055 |
| | 817 |
| | 170 |
|
| Miscellaneous - net | | (3,905 | ) | | (3,821 | ) | | (3,951 | ) |
| TOTAL | | (470 | ) | | (822 | ) | | 174 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 57,002 |
| | 59,031 |
| | 57,345 |
|
| Allowance for borrowed funds used during construction | | (1,243 | ) | | (1,539 | ) | | (2,103 | ) |
| TOTAL | | 55,759 |
| | 57,492 |
| | 55,242 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 130,531 |
| | 131,916 |
| | 105,447 |
|
| | | | | | | |
| Income taxes | | 55,710 |
| | 49,757 |
| | 58,679 |
|
| | | | | | | |
| NET INCOME | | 74,821 |
| | 82,159 |
| | 46,768 |
|
| | | | | | | |
| Preferred dividend requirements and other | | 2,828 |
| | 2,828 |
| | 2,828 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | |
| $71,993 |
| |
| $79,331 |
| |
| $43,940 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $74,821 |
| |
| $82,159 |
| |
| $46,768 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 113,903 |
| | 108,714 |
| | 97,768 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 32,472 |
| | 47,878 |
| | 58,221 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | (27,444 | ) | | (31,647 | ) | | 42,222 |
|
| Fuel inventory | | 6,163 |
| | (121 | ) | | (6,202 | ) |
| Accounts payable | | (14,618 | ) | | 38,727 |
| | (3,796 | ) |
| Taxes accrued | | 318 |
| | 920 |
| | 6,791 |
|
| Interest accrued | | 2,789 |
| | 2,157 |
| | (3,324 | ) |
| Deferred fuel costs | | 40,251 |
| | (11,567 | ) | | (42,331 | ) |
| Other working capital accounts | | 17,567 |
| | (12,820 | ) | | (6,859 | ) |
| Provisions for estimated losses | | 14,468 |
| | (146 | ) | | (2,469 | ) |
| Other regulatory assets | | (36,875 | ) | | 87,907 |
| | (6,501 | ) |
| Pension and other postretirement liabilities | | 68,434 |
| | (94,143 | ) | | 16,782 |
|
| Other assets and liabilities | | 11,214 |
| | 1,647 |
| | 5,336 |
|
| Net cash flow provided by operating activities | | 303,463 |
| | 219,665 |
| | 202,406 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (179,544 | ) | | (168,510 | ) | | (175,544 | ) |
| Allowance for equity funds used during construction | | 2,380 |
| | 2,182 |
| | 3,955 |
|
| Payment for purchase of plant | | — |
| | — |
| | (202,668 | ) |
| Change in money pool receivable - net | | (644 | ) | | 16,878 |
| | (16,878 | ) |
| Other | | 43 |
| | 40 |
| | 8 |
|
| Net cash flow used in investing activities | | (177,765 | ) | | (149,410 | ) | | (391,127 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 98,668 |
| | — |
| | 246,502 |
|
| Retirement of long-term debt | | (95,000 | ) | | (116,030 | ) | | — |
|
| Change in money pool payable - net | | (3,536 | ) | | 3,536 |
| | (1,999 | ) |
| Dividends paid: | | |
| | |
| | |
|
| Common stock | | (61,400 | ) | | (7,400 | ) | | — |
|
| Preferred stock | | (2,828 | ) | | (2,828 | ) | | (2,828 | ) |
| Other | | — |
| | (472 | ) | | — |
|
| Net cash flow provided by (used in) financing activities | | (64,096 | ) | | (123,194 | ) | | 241,675 |
|
| Net increase (decrease) in cash and cash equivalents | | 61,602 |
| | (52,939 | ) | | 52,954 |
|
| Cash and cash equivalents at beginning of period | | 31 |
| | 52,970 |
| | 16 |
|
| Cash and cash equivalents at end of period | |
| $61,633 |
| |
| $31 |
| |
| $52,970 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $51,509 |
| |
| $54,120 |
| |
| $58,043 |
|
| Income taxes | |
| $19,650 |
| |
| $4,657 |
| |
| ($696 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| BALANCE SHEETS |
| ASSETS |
| �� | | |
| | | December 31, |
| | | 2014 | | 2013 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $1,223 |
| |
| $22 |
|
| Temporary cash investments | | 60,410 |
| | 9 |
|
| Total cash and cash equivalents | | 61,633 |
| | 31 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 78,593 |
| | 76,534 |
|
| Allowance for doubtful accounts | | (873 | ) | | (906 | ) |
| Associated companies | | 21,233 |
| | 13,794 |
|
| Other | | 42,009 |
| | 9,117 |
|
| Accrued unbilled revenues | | 43,374 |
| | 44,777 |
|
| Total accounts receivable | | 184,336 |
| | 143,316 |
|
| Deferred fuel costs | | — |
| | 38,057 |
|
| Accumulated deferred income taxes | | 5,198 |
| | — |
|
| Fuel inventory - at average cost | | 42,736 |
| | 48,899 |
|
| Materials and supplies - at average cost | | 37,741 |
| | 40,849 |
|
| Prepayments and other | | 7,315 |
| | 19,813 |
|
| TOTAL | | 338,959 |
| | 290,965 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Non-utility property - at cost (less accumulated depreciation) | | 4,642 |
| | 4,670 |
|
| Escrow accounts | | 41,752 |
| | 51,795 |
|
| TOTAL | | 46,394 |
| | 56,465 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 3,999,918 |
| | 3,875,737 |
|
| Property under capital lease | | 4,185 |
| | 5,329 |
|
| Construction work in progress | | 67,514 |
| | 37,316 |
|
| TOTAL UTILITY PLANT | | 4,071,617 |
| | 3,918,382 |
|
| Less - accumulated depreciation and amortization | | 1,516,540 |
| | 1,413,484 |
|
| UTILITY PLANT - NET | | 2,555,077 |
| | 2,504,898 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Regulatory asset for income taxes - net | | 49,306 |
| | 58,716 |
|
| Other regulatory assets | | 364,747 |
| | 318,462 |
|
| Other | | 19,121 |
| | 20,819 |
|
| TOTAL | | 433,174 |
| | 397,997 |
|
| | | | | |
| TOTAL ASSETS | |
| $3,373,604 |
| |
| $3,250,325 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2014 | | 2013 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Accounts payable: | | |
| | |
|
| Associated companies | |
| $49,832 |
| |
| $74,144 |
|
| Other | | 63,300 |
| | 52,129 |
|
| Customer deposits | | 77,753 |
| | 74,211 |
|
| Taxes accrued | | 53,565 |
| | 53,247 |
|
| Accumulated deferred income taxes | | — |
| | 15,413 |
|
| Interest accrued | | 23,172 |
| | 20,383 |
|
| Deferred fuel costs | | 2,194 |
| | — |
|
| Other | | 17,533 |
| | 19,021 |
|
| TOTAL | | 287,349 |
| | 308,548 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 800,374 |
| | 746,939 |
|
| Accumulated deferred investment tax credits | | 6,370 |
| | 8,530 |
|
| Asset retirement cost liabilities | | 6,786 |
| | 6,401 |
|
| Accumulated provisions | | 50,142 |
| | 35,674 |
|
| Pension and other postretirement liabilities | | 135,156 |
| | 66,722 |
|
| Long-term debt | | 1,058,838 |
| | 1,053,670 |
|
| Other | | 16,038 |
| | 21,883 |
|
| TOTAL | | 2,073,704 |
| | 1,939,819 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| Preferred stock without sinking fund | | 50,381 |
| | 50,381 |
|
| | | | | |
| COMMON EQUITY | | |
| | |
|
| Common stock, no par value, authorized 12,000,000 shares; issued and outstanding 8,666,357 shares in 2014 and 2013 | | 199,326 |
| | 199,326 |
|
| Capital stock expense and other | | (690 | ) | | (690 | ) |
| Retained earnings | | 763,534 |
| | 752,941 |
|
| TOTAL | | 962,170 |
| | 951,577 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $3,373,604 |
| |
| $3,250,325 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| STATEMENTS OF CHANGES IN COMMON EQUITY |
| For the Years Ended December 31, 2014, 2013, and 2012 |
| | | | |
| | Common Equity | | |
| | Common Stock | | Capital Stock Expense and Other | | Retained Earnings | | Total |
| | (In Thousands) |
| | | | | | | | |
| Balance at December 31, 2011 |
| $199,326 |
| |
| ($690 | ) | |
| $637,070 |
| |
| $835,706 |
|
| Net income | — |
| | — |
| | 46,768 |
| | 46,768 |
|
| Preferred stock dividends | — |
| | — |
| | (2,828 | ) | | (2,828 | ) |
| Balance at December 31, 2012 |
| $199,326 |
| |
| ($690 | ) | |
| $681,010 |
| |
| $879,646 |
|
| Net income | — |
| | — |
| | 82,159 |
| | 82,159 |
|
| Common stock dividends | — |
| | — |
| | (7,400 | ) | | (7,400 | ) |
| Preferred stock dividends | — |
| | — |
| | (2,828 | ) | | (2,828 | ) |
| Balance at December 31, 2013 |
| $199,326 |
| |
| ($690 | ) | |
| $752,941 |
| |
| $951,577 |
|
| Net income | — |
| | — |
| | 74,821 |
| | 74,821 |
|
| Common stock dividends | — |
| | — |
| | (61,400 | ) | | (61,400 | ) |
| Preferred stock dividends | — |
| | — |
| | (2,828 | ) | | (2,828 | ) |
| Balance at December 31, 2014 |
| $199,326 |
| |
| ($690 | ) | |
| $763,534 |
| |
| $962,170 |
|
| | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2014 | | 2013 | | 2012 | | 2011 | | 2010 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $1,524,193 |
| |
| $1,334,540 |
| |
| $1,120,366 |
| |
| $1,266,470 |
| |
| $1,232,922 |
|
| Net Income |
| $74,821 |
| |
| $82,159 |
| |
| $46,768 |
| |
| $108,729 |
| |
| $85,377 |
|
| Total assets |
| $3,373,604 |
| |
| $3,250,325 |
| |
| $3,354,027 |
| |
| $2,943,394 |
| |
| $2,772,778 |
|
| Long-term obligations (a) |
| $1,112,161 |
| |
| $1,108,236 |
| |
| $1,125,229 |
| |
| $978,932 |
| |
| $806,506 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and preferred stock without sinking fund. |
| | | | | | | | | | |
| | 2014 | | 2013 | | 2012 | | 2011 | | 2010 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $585 |
| |
| $527 |
| |
| $454 |
| |
| $490 |
| |
| $509 |
|
| Commercial | 481 |
| | 432 |
| | 381 |
| | 401 |
| | 406 |
|
| Industrial | 175 |
| | 156 |
| | 140 |
| | 146 |
| | 145 |
|
| Governmental | 47 |
| | 42 |
| | 37 |
| | 37 |
| | 38 |
|
| Total retail | 1,288 |
| | 1,157 |
| | 1,012 |
| | 1,074 |
| | 1,098 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 153 |
| | 92 |
| | 23 |
| | 104 |
| | 55 |
|
| Non-associated companies | 14 |
| | 24 |
| | 24 |
| | 27 |
| | 33 |
|
| Other | 69 |
| | 62 |
| | 61 |
| | 61 |
| | 47 |
|
| Total |
| $1,524 |
| |
| $1,335 |
| |
| $1,120 |
| |
| $1,266 |
| |
| $1,233 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
|
| Residential | 5,672 |
| | 5,629 |
| | 5,550 |
| | 5,848 |
| | 6,077 |
|
| Commercial | 4,821 |
| | 4,815 |
| | 4,915 |
| | 4,985 |
| | 5,000 |
|
| Industrial | 2,297 |
| | 2,265 |
| | 2,400 |
| | 2,326 |
| | 2,250 |
|
| Governmental | 414 |
| | 409 |
| | 408 |
| | 415 |
| | 416 |
|
| Total retail | 13,204 |
| | 13,118 |
| | 13,273 |
| | 13,574 |
| | 13,743 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 2,657 |
| | 1,543 |
| | 232 |
| | 431 |
| | 268 |
|
| Non-associated companies | 193 |
| | 304 |
| | 265 |
| | 332 |
| | 402 |
|
| Total | 16,054 |
| | 14,965 |
| | 13,770 |
| | 14,337 |
| | 14,413 |
|
ENTERGY NEW ORLEANS, INC.
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
State and Local Rate Regulation
The rates that Entergy New Orleans charges for electricity and natural gas significantly influence its financial position, results of operations, and liquidity. Entergy New Orleans is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the City Council, is primarily responsible for approval of the rates charged to customers.
Retail Rates
See “Algiers Asset Transfer” below for discussion of the Algiers asset transfer. As a provision of the settlement agreement approved by the City Council in May 2015 providing for the Algiers asset transfer, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions included continued implementation of the then-remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allowed for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorized Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.
In October 2014,addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy from Ninemile 6 (Ninemile PPA), which commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed only to Entergy New Orleans customers outside of Algiers.
In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a transaction that would resultproceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in the transfer from Entergy Louisiana toprinciple between Entergy New Orleans of certain assets that currently support the provision of service to Entergy Louisiana’s customers in Algiers. The transaction is expected to result in the transfer of net assets of approximately $60 million. The Algiers asset transfer is also subject to regulatory review and approval of the FERC. Entergy Louisiana also filed an application with the City Council seeking authorization to undertakeadvisors providing that the Entergy Louisianapurchase of Union Power Block 1 and Entergy Gulf States Louisiana business combination. The application provides that if the City Council approves the Algiers asset transfer before the business combination occurs, the City Council may not need to issue a public interest finding regarding the business combination. If the necessary approvals are obtained from the City Council and the FERC, Entergy Louisiana expects to transfer the Algiersrelated assets toby Entergy New Orleans is prudent and in the second half of 2015. In November 2014 thepublic interest. The City Council approvedauthorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a resolution establishing a procedural schedule that provides for a hearing oncredit to customers of $400 thousand monthly beginning June 2016 in recognition of the joint applicationdecrease in late-May 2015, with a decision to be rendered no later than June 2015.
Results of Operations
Net Income
2014 Compared to 2013
Net income increased $17 million primarily due to higher net revenue and lower other operation and maintenance expenses partially offset bythat would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a higher effective income tax rate.temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.
2013 ComparedA 2008 rate case settlement included $3.1 million per year in electric rates to 2012fund the Energy Smart energy efficiency programs. The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted (estimated to be June 2018) and when new rates from the anticipated 2018 combined rate case, which will include a cost recovery mechanism for Energy Smart funding, take effect (estimated to be August 2019). Entergy New Orleans requested that the City Council approve a cost recovery mechanism prior to June 2018. In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist.
Net income decreased $5.4 million primarily due to higher other operation and maintenance expenses, higher taxes other than income taxes, and higher interest expense, partially offset by higher net revenue and a lower effective income tax rate.
Net Revenue
2014 Compared to 2013
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 2014 to 2013.
|
| | | |
| Amount |
| (In Millions) |
| |
2013 net revenue |
| $249.2 |
|
Volume/weather | 4.5 |
|
Net gas revenue | 3.5 |
|
Transmission revenue | 1.4 |
|
Other | 1.5 |
|
2014 net revenue |
| $260.1 |
|
Entergy New Orleans, Inc.LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The volume/weather variance is primarily due to an increase of 125 GWh, or 2%, in billed electricity usage, primarily in the residential and commercial sectors, including the effect of favorable weather on residential sales in 2014 as compared to the prior year and a 2% increase in the average number of electric customers.
The net gas revenue variance is primarily due to the effect of favorable weather, primarily in the residentialFuel and commercial sectors, in 2014 as compared to the prior year.Purchased Power Cost Recovery
The transmission revenue variance is primarily due to changes as a result of participation in the MISO RTO in 2014.
2013 Compared to 2012
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 2013 to 2012.
|
| | | |
| Amount |
| (In Millions) |
| |
2012 net revenue |
| $237.9 |
|
Volume/weather | 6.6 |
|
Rider revenue | 2.7 |
|
Net gas revenue | 2.6 |
|
Retail electric price | (1.9 | ) |
Other | 1.3 |
|
2013 net revenue |
| $249.2 |
|
The volume/weather variance is primarily due to an increase of 125 GWh, or 3%, in billed electricity usage in the residential and commercial sectors primarily due to the effects of Hurricane Isaac, which decreased sales volume in 2012, and in part to a 2% increase in the average number of both residential and commercial customers.
The rider revenue variance is primarily due to an increase in franchise tax rider revenue as a result of higher retail revenues. There is a corresponding increase in taxes other than income taxes, resulting in no effect on net income.
The net gas revenue variance is primarily due to the effect of more favorable weather, primarily in the residential and commercial sectors, in 2013 as compared to prior year.
The retail electric price variance is primarily due to a formula rate plan decrease effective September 2013. See Note 2 to the financial statements for a discussion of the formula rate plan filing.
Other Income Statement Variances
2014 Compared to 2013
Other operation and maintenance expenses decreased primarily due to:
a decrease of $7.7 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
Entergy New Orleans, Inc.
Management’s Financial DiscussionOrleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and Analysis
a decrease of $6.7 million in fossil-fueled generation expenses due to an overall lower scope of work done during plant outages as compared to prior year; and
a decrease of $2.4 million in outside regulatory consultant fees.
2013 Compared to 2012
Other operation and maintenance expenses increased primarily due to:
an increase of $9 million in fossil-fueled generation expenses due to an overall higher scope of work done during plant outages as compared to prior year;
an increase of $4.4 million resulting from implementationpurchased power costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion; and
an increase of $3.1 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs.
The increase was partially offsetadjusted by a decrease of $3 million in loss reserves and a decrease of $1.5 million due to expenses recorded in 2012 related tosurcharge or credit for deferred fuel expense arising from the Energy Smart Program.
Taxes other than income taxes increased primarily due to an increase in local franchise taxes resulting from higher electric and gas retail revenues as compared to prior year and an increase in ad valorem taxes resulting from higher assessments. Franchise taxes have no effect on net income as these taxes are recovered through the franchise tax rider.
Interest expense increased primarily due to the issuance of $100 million of 3.90% Series first mortgage bonds in June 2013 and the issuance of $30 million of 5.00% Series first mortgage bonds in November 2012, partially offset by the retirement, at maturity, of $70 million of 5.25% Series first mortgage bonds in August 2013.
Income Taxes
The effective income tax rates for 2014, 2013, and 2012 were 30%, 12.2%, and 29.8%, respectively. See Note 3 to the financial statements for amonthly reconciliation of the federal statutory rate of 35%actual fuel and purchased power costs incurred with fuel cost revenues billed to the effective income tax rates.
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2014, 2013, and 2012 were as follows:
|
| | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $33,489 |
| |
| $9,391 |
| |
| $9,834 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 81,064 |
| | 86,326 |
| | 52,089 |
|
| Investing activities | (64,514 | ) | | (89,666 | ) | | (78,040 | ) |
| Financing activities | (7,650 | ) | | 27,438 |
| | 25,508 |
|
| Net increase (decrease) in cash and cash equivalents | 8,900 |
| | 24,098 |
| | (443 | ) |
| | | | | | |
| Cash and cash equivalents at end of period |
| $42,389 |
| |
| $33,489 |
| |
| $9,391 |
|
Operating Activities
Net cash flow provided by operating activities decreased $5.3 million in 2014 primarily due to the payment of calendar year 2012 System Agreement bandwidth remedy payments of $15 million to the City of New Orleans in June 2014 for use in the streetlight conversion program, as directed by the City Council, an increase of $6.3 million in pension contributions, and income tax payments of $4.9 million in 2014 compared to income tax refunds of $1.4 million in 2013. The decrease in cash flow was offset by the timing of collections from customers. See “Critical Accountings Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Net cash provided by operating activities increased $34.2 million in 2013 primarily due to the increased recovery of fuel costs and decreased Hurricane Isaac storm spending in 2013, partially offset by a decrease of $11.5 million in income tax refunds. The income tax refunds of $13 million in 2012 resulted primarily from a decrease of previously estimated 2011 taxable income due to the recognition of additional bonus depreciation.
Investing Activities
Net cash flow used in investing activities decreased $25.2 million in 2014 primarily due to:
a decrease in fossil-fueled generation construction expenditures primarily due to spending on the Michoud turbine blade replacement projects in 2013;
a decrease in transmission construction expenditures as a result of decreased scope of work in 2014; and
money pool activity.
The decrease was partially offset by receipts from the storm reserve escrow account of $7.8 million in 2013.
Decreases in Entergy New Orleans’s receivable from the money pool are a source of cash flow, and Entergy New Orleans’s receivable from the money pool decreased $4.3 million in 2014 compared to increasing $1.8 million in 2013. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis
Net cash flow used in investing activities increased $11.6 million in 2013 primarily due to:
money pool activity;
an increase in transmission construction expenditures as a result of additional reliability work performed in 2013; and
an increase in fossil-fueled generation construction expenditures as a result of increased scope of work in 2013.
The increase was partially offset by a decrease in distribution construction expenditures due to higher spending related to Hurricane Isaac in 2012.
Increases in Entergy New Orleans’s receivable from the money pool are a use of cash flow, and Entergy New Orleans’s receivable from the money pool increased $1.8 million in 2013 compared to decreasing $6.2 million in 2012.
Financing Activitiescustomers, including carrying charges.
Entergy New Orleans’s financing activities used $7.7 million of cashgas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in 2014 compared to providing $27.4 million of cash in 2013 primarily due to the issuance of $100 million of 3.9% Series first mortgage bonds in June 2013 and $6 million in common stock dividends paid in 2014, partially offset by the retirement of $70 million of 5.25% Series first mortgage bonds in August 2013.
Net cash provided by financing activities increased $1.9 million in 2013 primarily due to the issuance of $100 million of 3.90% Series first mortgage bonds in June 2013 compared to the issuance of $30 million of 5.0% Series first mortgage bonds in November 2012. The increase was substantially offset by the retirement of $70 million of 5.25% Series first mortgage bonds in August 2013.electric fuel adjustment clause, including carrying charges.
See Note 5Due to higher fuel costs associated in part with the financial statementsextended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for more details on long-term debt.the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans to cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Capital Structure
Entergy New Orleans’s capitalization is balanced between equityDue to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and debt as shown in the following table. The decrease in debt to capital ratio is due to an increase in retained earnings.
|
| | | | | |
| | December 31,
2014 | | December 31,
2013 |
| Debt to capital | 47.7 | % | | 50.0 | % |
| Effect of subtracting cash | (5.2 | %) | | (4.0 | %) |
| Net debt to net capital | 42.5 | % | | 46.0 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy New Orleans uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition. Entergy New Orleans uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluation Entergy New Orleans’s financial condition because net debt indicates Entergy New Orleans’s outstanding debt position that could not be readily satisfied by cash and cash equivalents.
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis
Uses of Capital
Entergy New Orleans requires capital resources for:
construction and other capital investments;
working capital purposes, including the financing oftotal fuel and purchased power costs;
debt and preferred stock maturities or retirements; and
dividend payments.
Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.
|
| | | | | | | | | | | |
| | 2015 | | 2016 | | 2017 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $— |
| |
| $— |
| |
| $40 |
|
| Transmission | 15 |
| | 10 |
| | 5 |
|
| Distribution | 35 |
| | 25 |
| | 25 |
|
| Other | 25 |
| | 30 |
| | 25 |
|
| Total |
| $75 |
| |
| $65 |
| |
| $95 |
|
Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
|
| | | | | | | | | | | | | | | | | | | |
| | 2015 | | 2016-2017 | | 2018-2019 | | After 2019 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $11 |
| |
| $21 |
| |
| $21 |
| |
| $320 |
| |
| $373 |
|
| Operating leases |
| $2 |
| |
| $4 |
| |
| $2 |
| |
| $2 |
| |
| $10 |
|
| Purchase obligations (b) |
| $215 |
| |
| $425 |
| |
| $397 |
| |
| $579 |
| |
| $1,616 |
|
| |
(a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
(b) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy New Orleans, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements. |
In addition to the contractual obligations given above, Entergy New Orleans currently expects to contribute approximately $10.9 million to its pension plancosts associated in 2015, and approximately $3.7 million to other postretirement plans in 2015, although the required pension contributions will not be knownpart with more certainty until the January 1, 2015 valuations are completed by April 1, 2015. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations,certain plant outages, Entergy New Orleans has $33 million of unrecognized tax benefitsproposed to cap the fuel adjustment charge to be billed in March 2018 to non-transmission Entergy New Orleans legacy customers and interest net of unused tax attributesEntergy New Orleans Algiers customers at $0.035323 per kWh and payments for which$0.025446 per kWh, respectively. Entergy New Orleans has also proposed to cap the timing of payments beyond 12 months cannotfuel adjustment charge to be reasonably estimated due to uncertaintiesbilled in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimateMarch 2018 for Entergy New Orleans includes specific investmentslegacy transmission customers at $0.034609 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such as environmental compliance spending; transmission projects to enhance reliability, reduce congestion, and enable economic growth; resource planning; generation projects; system improvements; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based oncosts in the ongoing effects of regulatory constraints and requirements, environmental compliance,
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysisover- or under-recovery account.
business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.
As a wholly-owned subsidiary of Entergy Corporation, Entergy New Orleans pays dividends from its earnings at a percentage determined monthly. Entergy New Orleans’s long-term debt indenture contains restrictions on the payment of cash dividends or other distributions on its common and preferred stock.
Sources of Capital
Entergy New Orleans’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt and preferred stock issuances; and
bank financing under new or existing facilities.
Entergy New Orleans may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
Entergy New Orleans’s receivables from the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2014 | | 2013 | | 2012 | | 2011 |
| (In Thousands) |
| $442 | | $4,737 | | $2,923 | | $9,074 |
See Note 4 to the financial statements for a description of the money pool.
Entergy New Orleans has a credit facility in the amount of $25 million scheduled to expire in November 2015. No borrowings were outstanding under the facility as of December 31, 2014. See Note 4 to the financial statements for additional discussion of the credit facility. In addition, Entergy New Orleans entered into an uncommitted letter of credit facility as a means to post collateral to support its obligations under MISO. As of December 31, 2014, an $8.1 million letter of credit was outstanding under Entergy New Orleans’s letter of credit facility.
Entergy New Orleans obtained authorization from the FERC through October 2015 for short-term borrowings not to exceed an aggregate amount of $100 million at any time outstanding. See Note 4 to the financial statements for further discussion of Entergy New Orleans’s short-term borrowing limits. The long-term securities issuances of Entergy New Orleans are limited to amounts authorized by the City Council, and the current authorization extends through July 2016.
Entergy Louisiana’s Ninemile Point Unit 6 Self-Build Project
In June 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station. Ninemile 6 is a nominally-sized 560 MW unit that is expected to cost approximately $655 million to construct when spending is complete, excluding interconnection and transmission upgrades. Entergy Gulf States Louisiana joined in the application, seeking certification of its purchase under a life-of-unit power purchase agreement of up to 25% of the capacity and energy generated by Ninemile 6. The Ninemile 6 capacity and energy is allocated 55% to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20% to Entergy New Orleans. In February 2012 the City Council passed a resolution authorizing Entergy New Orleans to purchase 20% of the Ninemile 6 energy and capacity. In March 2012 the LPSC
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis
unanimously voted to grant the certifications requested by Entergy Gulf States Louisiana and Entergy Louisiana. Following approval by the LPSC, Entergy Louisiana issued full notice to proceed to the project’s engineering, procurement, and construction contractor. Under terms approved by the City Council, non-fuel costs associated with Ninemile 6 may be recovered through a special rider for that purpose. The unit was placed in service in December 2014.
State and Local Rate Regulation
The rates that Entergy New Orleans charges for electricity and natural gas significantly influence its financial position, results of operations, and liquidity. Entergy New Orleans is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the City Council, is primarily responsible for approval of the rates charged to customers.
Rate Cases and Formula Rate PlansRetail Rates
In April 2009See “Algiers Asset Transfer” below for discussion of the Algiers asset transfer. As a provision of the settlement agreement approved by the City Council approved a three-year formula rate planin May 2015 providing for the Algiers asset transfer, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented
Entergy New Orleans, with terms including an 11.1% benchmark electric return on common equity (ROE) with a +/-40 basis point bandwidthLLC and a 10.75% benchmark gas ROE with a +/-50 basis point bandwidth. Earnings outside the bandwidth reset to the midpoint benchmark ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans was over- or under-earning. The formula rate plan also included a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changesSubsidiaries
Management’s Financial Discussion and force majeure events.Analysis
In May 2012, Entergy New Orleansfrom a base rate case that must be filed for its electric and gas formula rate plan evaluation reports for the 2011 test year. Subsequent adjustments agreed upon with the City Council Advisors indicate a $4.9 million electric base revenue increase and a $0.05 million gas base revenue increase as necessary under the formula rate plan. As part of the original filing, Entergy New Orleans also requested to increase annual funding for its storm reserve by approximately $5.7 million for five years. On September 26, 2012, Entergy New Orleans made a filing with the City Council that implemented the $4.9 million electric formula rate plan rate increase and the $0.05 million gas formula rate plan rate increase. The new rates were effective with the first billing cycleoperations in October 2012. In August 2013 the City Council unanimously approved a settlement of all issues in2018. This provision eliminated the formula rate plan proceeding. Pursuantapplicable to Algiers operations. The limited exceptions included continued implementation of the termsthen-remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allowed for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans implemented an approximately $1.625 million net decrease to the electric rates that were in effect prior to the electric rate increase implemented in October 2012,under a power purchase agreement with no change in gas rates.Entergy Louisiana (Algiers PPA). The settlement authorized Entergy New Orleans refunded to customers approximately $6 million overrecover the four-month period from September 2013remaining revenue requirement related to the Algiers PPA through December 2013base rates charged to make the electric rate decrease effective asAlgiers customers. The settlement also provided for continued implementation of the first billing cycle of October 2012.Algiers MISO recovery rider.
In addition to the Algiers PPA, Entergy New Orleans had previously recorded provisions for the majority of the refund to customers, but recorded an additional $1.1 million provision in second quarter 2013 ashas a result of the settlement. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not been extended. Entergy New Orleans is recovering the costs of itsseparate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy of thefrom Ninemile Unit 6 generating station,(Ninemile PPA), which commenced operation in December 2014,2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile Unit 6 rider.rider billed only to Entergy New Orleans customers outside of Algiers.
In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans. The rate settlement providesprovided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and providesprovided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In October 2013 the City Council approved the extension of the current Energy Smart program through December 2014. The City Council approved the use of $3.5 million of rough production cost equalization funds for program costs. In addition, Entergy New Orleans will be allowed to recover its lost contribution to fixed costs and to earn an incentive for meeting program goals. In January 2015 the City Council approved extending the Energy Smart program through March 2015 and using $1.2 million of rough production cost equalization funds to cover program costs for the extended period. Additionally, the City Council approved funding for the Energy Smart 2 programsprogram from April 2015 through March 2017 using the
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis
remainder of the approximately $12.4$12.8 million of 2014 rough production cost equalization funds, and with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted (estimated to be June 2018) and when new rates from the anticipated 2018 combined rate case, which will include a cost recovery mechanism for Energy Smart funding, take effect (estimated to be August 2019). Entergy New Orleans requested that the City Council approve a cost recovery mechanism prior to June 2018. In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist.
Storm
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Fuel and Purchased Power Cost Recovery
In October 2006, the City Council approved a rate filing settlement agreement that, among other things, authorized a $75 million storm reserve for damage from future storms, which will be created over a ten-year period through a storm reserve rider that began in March 2007. These storm reserve funds are held in a restricted escrow account until needed in response to a storm.
In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair and/or replacement of Entergy New Orleans’s electric facilities damagedrate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by Hurricane Isaac were $47.3 million.a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
Due to higher fuel costs associated in part with the extended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans withdrew $17.4 millionto cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Due to higher fuel costs for the operating month of January 2018 resulting in part from the storm reserve escrow account to partially offset these costs. In February 2014,recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs associated in part with certain plant outages, Entergy New Orleans made a filinghas proposed to cap the fuel adjustment charge to be billed in March 2018 to non-transmission Entergy New Orleans legacy customers and Entergy New Orleans Algiers customers at $0.035323 per kWh and $0.025446 per kWh, respectively. Entergy New Orleans has also proposed to cap the fuel adjustment charge to be billed in March 2018 for Entergy New Orleans legacy transmission customers at $0.034609 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Algiers Asset Transfer
In October 2014, Entergy Louisiana and Entergy New Orleans filed an application with the City Council seeking certificationauthorization to undertake a transaction that would result in the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the Hurricane Isaac costs.provision of service to Entergy Louisiana’s customers in Algiers. In JanuaryApril 2015 the FERC issued an order approving the Algiers assets transfer. In May 2015 the parties filed a settlement agreement authorizing the Algiers assets transfer and the settlement agreement was approved by a City Council resolution in May 2015. On September 1, 2015, Entergy Louisiana transferred its Algiers assets to Entergy New Orleans for a purchase price of approximately $85 million. Entergy New Orleans paid Entergy Louisiana $59.6 million, including final true-ups, from available cash and issued a note payable to Entergy Louisiana in the amount of $25.5 million.
Show Cause Order
In July 2016 the City Council issued a resolution approvingapproved the termsissuance of a joint agreement in principle filed by Entergy New Orleans, Entergy Louisiana, and the City Council Advisors determining, among other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, ofshow cause order, which $31.7 million, net of reimbursements from the storm reserve escrow account, remains recoverable from Entergy New Orleans’s electric customers. The resolution also directsdirected Entergy New Orleans to file an applicationmake a filing on or before September 29, 2016 to securitizedemonstrate the unrecovered Council-approvedreasonableness of its actions or positions with regard to certain issues in four existing dockets that relate to Entergy New Orleans’s: (i) storm recovery costshardening proposal; (ii) 2015 integrated resource plan; (iii) gas infrastructure rebuild proposal; and (iv) proposed sizing of $31.7 million pursuantthe New Orleans Power Station and its community outreach prior to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64).filing. In addition, the resolution found that it is reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achieves the Council-approved funding level of $75 million. In January 2015, in compliance with that directive,September 2016, Entergy New Orleans filed withits response to the City Council an application requesting that theCouncil’s show cause order. The City Council grant a financing order authorizing the financing of Entergy New Orleans’s storm costs, storm reserves, and issuance costs pursuanthas not established any further procedural schedule with regard to Louisiana Act 64.this proceeding.
Federal Regulation
See “Entergy’s Integration Into the MISO Regional Transmission Organization,” “System Agreement,” and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of these topics.federal regulation.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Nuclear Matters
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
Environmental Risks
Entergy New Orleans’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous solid wastes, and other environmental matters. Management believes that Entergy New Orleans is in substantial compliance with environmental regulations currently applicable to its facilities and operations.operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis
Critical Accounting Estimates
The preparation of Entergy New Orleans’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of Entergy New Orleans’s financial position or results of operations.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Unbilled Revenue
As discussedSee “Unbilled Revenue” in Note 1 to the financial statements,“Critical Accounting Estimates” section of Entergy New Orleans records an estimateCorporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the revenues earned for energy delivered sinceestimates associated with the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenueamounts.
Impairment of Long-lived Assets and a receivable,Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the prior month’s estimate is reversed. The difference between the estimate“Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the unbilled receivable atestimates associated with the beginningimpairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the period“Critical Accounting Estimates” section of Entergy Corporation and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled periodSubsidiaries Management’s Financial Discussion and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each, in addition to changes in certain components of the calculation.Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy New Orleans’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | Actuarial Assumption | | Change in Assumption | | Impact on 2014 Qualified Pension Cost | | Impact on 2014 Projected Qualified Benefit Obligation | | Change in Assumption | | Impact on 2018 Qualified Pension Cost | | Impact on 2017 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $451 | | $7,348 | | (0.25%) | | $348 | |
| $6,153 |
|
| Rate of return on plan assets | | (0.25%) | | $295 | | $— | | (0.25%) | | $399 | |
| $— |
|
| Rate of increase in compensation | | 0.25% | | $175 | | $1,092 | | 0.25% | | $159 | |
| $729 |
|
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | Actuarial Assumption | | Change in Assumption | | Impact on 2014 Postretirement Benefit Cost | | Impact on 2014 Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2018 Postretirement Benefit Cost | | Impact on 2017 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $79 | | $1,813 | | (0.25%) | |
| ($12 | ) | | $1,406 |
| Health care cost trend | | 0.25% | | $210 | | $1,537 | | 0.25% | |
| $54 |
| | $1,074 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension cost for Entergy New Orleans in 20142017 was $6.6$5.1 million. Entergy New Orleans anticipates 20152018 qualified pension cost to be $9$5.8 million. In 2016, Entergy New Orleans refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $1.7 million. Entergy New Orleans contributed $10.5$9.9 million to its pension plans in 20142017 and estimates 20152018 pension contributions towill be approximately $10.9$7.3 million, although the 2018 required pension contributions will not be known with more certainty untilwhen the January 1, 20152018 valuations are completed, which is expected by April 1, 2015.2018.
Total postretirement health care and life insurance benefit income for Entergy New Orleans in 20142017 was $1.5$2.5 million. Entergy New Orleans expects 20152018 postretirement health care and life insurance benefit income of approximately $1.6$3.7 million. In 2016, Entergy New Orleans refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $548 thousand. Entergy New Orleans contributed $4.3$3.7 million to its other postretirement plans in 20142017 and expects to contributeestimates 2018 contributions will be approximately $3.7 million in 2015.million.
The retirement
Entergy New Orleans, LLC and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pensionSubsidiaries
Management’s Financial Discussion and other postretirement plans. The 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $15 million in the qualified pension benefit obligation and $3.6 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $2.2 million and other postretirement cost by approximately $0.4 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.Analysis
Federal Healthcare Legislation
See the “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the members and Board of Directors and Shareholders of
Entergy New Orleans, Inc.
New Orleans, LouisianaLLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy New Orleans, Inc.LLC and Subsidiaries (the “Company”) as of December 31, 20142017 and 2013, and2016, the related income statements,consolidated statements of income, cash flows, and statements of changes in common equity (pages 412392 through 416396 and applicable items in pages 6155 through 234)230), for each of the three years in the period ended December 31, 2014. 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on thesethe Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Anmisstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit includesof its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements. An auditOur audits also includes assessingincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy New Orleans, Inc. as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 20152018
We have served as the Company’s auditor since 2001.
411
| | | ENTERGY NEW ORLEANS, INC. | |
| INCOME STATEMENTS | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES | | ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS | | CONSOLIDATED INCOME STATEMENTS |
| | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | | | | |
| Electric | |
| $579,981 |
| |
| $525,041 |
| |
| $487,633 |
| |
| $631,744 |
| |
| $586,820 |
| |
| $584,322 |
|
| Natural gas | | 110,104 |
| | 95,115 |
| | 82,107 |
| | 84,326 |
| | 78,643 |
| | 87,124 |
|
| TOTAL | | 690,085 |
| | 620,156 |
| | 569,740 |
| | 716,070 |
| | 665,463 |
| | 671,446 |
|
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
| | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 169,605 |
| | 116,715 |
| | 107,616 |
| | 111,082 |
| | 40,489 |
| | 96,307 |
|
| Purchased power | | 259,680 |
| | 253,202 |
| | 222,193 |
| | 282,178 |
| | 299,551 |
| | 277,851 |
|
| Other operation and maintenance | | 120,610 |
| | 136,003 |
| | 122,143 |
| | 109,270 |
| | 117,471 |
| | 119,087 |
|
| Taxes other than income taxes | | 48,142 |
| | 48,659 |
| | 43,189 |
| | 54,590 |
| | 48,078 |
| | 46,660 |
|
| Depreciation and amortization | | 38,884 |
| | 37,717 |
| | 36,726 |
| | 52,945 |
| | 51,737 |
| | 43,205 |
|
| Other regulatory charges - net | | 694 |
| | 996 |
| | 1,983 |
| | 10,889 |
| | 8,258 |
| | 3,366 |
|
| TOTAL | | 637,615 |
| | 593,292 |
| | 533,850 |
| | 620,954 |
| | 565,584 |
| | 586,476 |
|
| | | | | | | | | | | | | |
| OPERATING INCOME | | 52,470 |
| | 26,864 |
| | 35,890 |
| | 95,116 |
| | 99,879 |
| | 84,970 |
|
| | | | | | | | | | | | | |
| OTHER INCOME | | |
| | |
| | |
| | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 915 |
| | 920 |
| | 791 |
| | 2,418 |
| | 1,178 |
| | 1,404 |
|
| Interest and investment income | | 79 |
| | 89 |
| | 47 |
| | 707 |
| | 256 |
| | 73 |
|
| Miscellaneous - net | | 430 |
| | (1,401 | ) | | (1,453 | ) | | 24 |
| | (3,144 | ) | | 339 |
|
| TOTAL | | 1,424 |
| | (392 | ) | | (615 | ) | | 3,149 |
| | (1,710 | ) | | 1,816 |
|
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest expense | | 13,310 |
| | 13,675 |
| | 11,344 |
| | 21,281 |
| | 21,061 |
| | 17,312 |
|
| Allowance for borrowed funds used during construction | | (447 | ) | | (505 | ) | | (374 | ) | | (847 | ) | | (446 | ) | | (641 | ) |
| TOTAL | | 12,863 |
| | 13,170 |
| | 10,970 |
| | 20,434 |
| | 20,615 |
| | 16,671 |
|
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 41,031 |
| | 13,302 |
| | 24,305 |
| | 77,831 |
| | 77,554 |
| | 70,115 |
|
| | | | | | | | | | | | | |
| Income taxes | | 12,324 |
| | 1,619 |
| | 7,240 |
| | 33,278 |
| | 28,705 |
| | 25,190 |
|
| | | | | | | | | | | | | |
| NET INCOME | | 28,707 |
| | 11,683 |
| | 17,065 |
| | 44,553 |
| | 48,849 |
| | 44,925 |
|
| | | | | | | | | | | | | |
| Preferred dividend requirements and other | | 965 |
| | 965 |
| | 965 |
| | 841 |
| | 965 |
| | 965 |
|
| | | | | | | | | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | |
| $27,742 |
| |
| $10,718 |
| |
| $16,100 |
| |
| EARNINGS APPLICABLE TO COMMON EQUITY | | |
| $43,712 |
| |
| $47,884 |
| |
| $43,960 |
|
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | | ENTERGY NEW ORLEANS, INC. | |
| STATEMENTS OF CASH FLOWS | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES | | ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | | CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | | | | | | | |
| Net income | |
| $28,707 |
| |
| $11,683 |
| |
| $17,065 |
| |
| $44,553 |
| |
| $48,849 |
| |
| $44,925 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | | | | |
| Depreciation and amortization | | 38,884 |
| | 37,717 |
| | 36,726 |
| | 52,945 |
| | 51,737 |
| | 43,205 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 24,388 |
| | (7,427 | ) | | 15,016 |
| | 64,036 |
| | 140,283 |
| | 22,180 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
| | |
| | |
| | |
|
| Receivables | | 20,506 |
| | (6,508 | ) | | (29,046 | ) | | (18,058 | ) | | (3,888 | ) | | 7,878 |
|
| Fuel inventory | | (17 | ) | | (1,222 | ) | | 2,029 |
| | (49 | ) | | 71 |
| | 1,104 |
|
| Accounts payable | | (7,702 | ) | | 5,987 |
| | 4,828 |
| | 1,874 |
| | 15,434 |
| | 2,738 |
|
| Prepaid taxes and taxes accrued | | | (22,100 | ) | | (1,685 | ) | | (1,050 | ) |
| Interest accrued | | (60 | ) | | 578 |
| | 180 |
| | 44 |
| | 534 |
| | 1,270 |
|
| Deferred fuel costs | | 5,252 |
| | 20,988 |
| | (9,464 | ) | | 12,592 |
| | (33,839 | ) | | (182 | ) |
| Other working capital accounts | | (18,050 | ) | | 3,155 |
| | 12,862 |
| | (2,711 | ) | | 4,165 |
| | (1,945 | ) |
| Provisions for estimated losses | | 10,877 |
| | (31 | ) | | (812 | ) | | (3,430 | ) | | 4,326 |
| | 58,310 |
|
| Other regulatory assets | | (38,405 | ) | | 64,810 |
| | (23,188 | ) | | 16,673 |
| | (2,784 | ) | | (70,471 | ) |
| Other regulatory liabilities | | | 110,147 |
| | (3,997 | ) | | (7,359 | ) |
Deferred tax rate change recognized as regulatory liability/asset
| | | (111,170 | ) | | — |
| | — |
|
| Pension and other postretirement liabilities | | 29,942 |
| | (51,293 | ) | | 9,773 |
| | (15,994 | ) | | (6,859 | ) | | (18,831 | ) |
| Other assets and liabilities | | (13,258 | ) | | 7,889 |
| | 16,120 |
| | (1,555 | ) | | (7,136 | ) | | 23,296 |
|
| Net cash flow provided by operating activities | | 81,064 |
| | 86,326 |
| | 52,089 |
| | 127,797 |
| | 205,211 |
| | 105,068 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Construction expenditures | | (62,199 | ) | | (88,864 | ) | | (86,373 | ) | | (115,584 | ) | | (90,512 | ) | | (91,928 | ) |
| Allowance for equity funds used during construction | | 915 |
| | 920 |
| | 791 |
| | 2,418 |
| | 1,178 |
| | 1,404 |
|
| Change in money pool receivable - net | | 4,295 |
| | (1,814 | ) | | 6,151 |
| |
| Payment for purchase of plant | | | — |
| | (237,335 | ) | | — |
|
| Investments in affiliates | | | — |
| | (38 | ) | | — |
|
| Changes in money pool receivable - net | | | 1,492 |
| | 1,579 |
| | (15,352 | ) |
| Payments to storm reserve escrow account | | (7,525 | ) | | (7,663 | ) | | (8,609 | ) | | (597 | ) | | (438 | ) | | (68,886 | ) |
| Receipts from storm reserve escrow account | | — |
| | 7,755 |
| | 10,000 |
| | 2,488 |
| | 3 |
| | 5,922 |
|
| Changes in securitization account | | | 283 |
| | 2,882 |
| | (4,620 | ) |
| Net cash flow used in investing activities | | (64,514 | ) | | (89,666 | ) | | (78,040 | ) | | (109,500 | ) | | (322,681 | ) | | (173,460 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | — |
| | 98,471 |
| | 28,422 |
| | — |
| | 240,604 |
| | 95,367 |
|
| Retirement of long-term debt | | — |
| | (70,068 | ) | | — |
| | (10,600 | ) | | (132,526 | ) | | — |
|
| Dividends paid: | | |
| | |
| | |
| |
| Common stock | | (6,000 | ) | | — |
| | (1,700 | ) | |
| Repayment of long-term payable due to Entergy Louisiana | | | (2,104 | ) | | (4,973 | ) | | (59,610 | ) |
Redemption of preferred stock
| | | (20,599 | ) | | — |
| | — |
|
| Capital contributions from parent | | | 20,000 |
| | 47,750 |
| | 87,500 |
|
| Distributions/dividends paid: | | | |
| | |
| | |
|
| Common equity | | | (74,250 | ) | | (18,720 | ) | | (7,250 | ) |
| Preferred stock | | (965 | ) | | (965 | ) | | (965 | ) | | (1,083 | ) | | (965 | ) | | (965 | ) |
| Other | | (685 | ) | | — |
| | (249 | ) | | 12 |
| | 492 |
| | (163 | ) |
| Net cash flow provided by (used in) financing activities | | (7,650 | ) | | 27,438 |
| | 25,508 |
| | (88,624 | ) | | 131,662 |
| | 114,879 |
|
| Net increase (decrease) in cash and cash equivalents | | 8,900 |
| | 24,098 |
| | (443 | ) | | (70,327 | ) | | 14,192 |
| | 46,487 |
|
| Cash and cash equivalents at beginning of period | | 33,489 |
| | 9,391 |
| | 9,834 |
| | 103,068 |
| | 88,876 |
| | 42,389 |
|
| Cash and cash equivalents at end of period | |
| $42,389 |
| |
| $33,489 |
| |
| $9,391 |
| |
| $32,741 |
| |
| $103,068 |
| |
| $88,876 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
| | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $12,477 |
| |
| $12,050 |
| |
| $10,183 |
| |
| $20,180 |
| |
| $19,317 |
| |
| $14,951 |
|
| Income taxes | |
| $4,871 |
| |
| ($1,448 | ) | |
| ($12,952 | ) | |
| ($8,660 | ) | |
| ($85,962 | ) | |
| $8,110 |
|
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | | ENTERGY NEW ORLEANS, INC. | |
| BALANCE SHEETS | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES | | ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS | | CONSOLIDATED BALANCE SHEETS |
ASSETS | | | | | | |
| | | December 31, | | December 31, |
| | | 2014 | | 2013 | | 2017 | | 2016 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT ASSETS | | | | | | | | |
| Cash and cash equivalents | | | | | | | | |
| Cash | |
| $1,006 |
| |
| $317 |
| |
| $30 |
| |
| $28 |
|
| Temporary cash investments | | 41,383 |
| | 33,172 |
| | 32,711 |
| | 103,040 |
|
| Total cash and cash equivalents | | 42,389 |
| | 33,489 |
| | 32,741 |
| | 103,068 |
|
| Securitization recovery trust account | | | 1,455 |
| | 1,738 |
|
| Accounts receivable: | | |
| | |
| | |
| | |
|
| Customer | | 35,663 |
| | 38,872 |
| | 51,006 |
| | 43,536 |
|
| Allowance for doubtful accounts | | (262 | ) | | (974 | ) | | (3,057 | ) | | (3,059 | ) |
| Associated companies | | 11,693 |
| | 32,273 |
| | 22,976 |
| | 16,811 |
|
| Other | | 3,223 |
| | 2,667 |
| | 6,471 |
| | 5,926 |
|
| Accrued unbilled revenues | | 16,465 |
| | 18,745 |
| | 20,638 |
| | 18,254 |
|
| Total accounts receivable | | 66,782 |
| | 91,583 |
| | 98,034 |
| | 81,468 |
|
| Accumulated deferred income taxes | | 8,562 |
| | 12,018 |
| |
| Deferred fuel costs | | | — |
| | 4,818 |
|
| Fuel inventory - at average cost | | 3,016 |
| | 2,999 |
| | 1,890 |
| | 1,841 |
|
| Materials and supplies - at average cost | | 12,650 |
| | 11,696 |
| | 10,381 |
| | 8,416 |
|
| Prepaid taxes | | | 26,479 |
| | 4,379 |
|
| Prepayments and other | | 6,887 |
| | 4,178 |
| | 8,030 |
| | 6,587 |
|
| TOTAL | | 140,286 |
| | 155,963 |
| | 179,010 |
|
| 212,315 |
|
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
| | |
| | |
|
| Non-utility property at cost (less accumulated depreciation) | | 1,016 |
| | 1,016 |
| | 1,016 |
| | 1,016 |
|
| Storm reserve escrow account | | 18,038 |
| | 10,513 |
| | 79,546 |
| | 81,437 |
|
| Other | | | 2,373 |
| | 7,160 |
|
| TOTAL | | 19,054 |
| | 11,529 |
| | 82,935 |
| | 89,613 |
|
| | | | | | | | | |
| UTILITY PLANT | | |
| | |
| | |
| | |
|
| Electric | | 936,862 |
| | 889,629 |
| | 1,302,235 |
| | 1,258,934 |
|
| Natural gas | | 228,979 |
| | 222,463 |
| | 261,263 |
| | 240,408 |
|
| Construction work in progress | | 18,866 |
| | 29,312 |
| | 46,993 |
| | 24,975 |
|
| TOTAL UTILITY PLANT | | 1,184,707 |
| | 1,141,404 |
| | 1,610,491 |
| | 1,524,317 |
|
| Less - accumulated depreciation and amortization | | 594,945 |
| | 566,948 |
| | 631,178 |
| | 604,825 |
|
| UTILITY PLANT - NET | | 589,762 |
| | 574,456 |
| | 979,313 |
| | 919,492 |
|
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
| | |
| | |
|
| Regulatory assets: | | |
| | |
| | |
| | |
|
| Deferred fuel costs | | 4,080 |
| | 4,080 |
| | 4,080 |
| | 4,080 |
|
| Other regulatory assets | | 175,596 |
| | 137,191 |
| |
| Other regulatory assets (includes securitization property of $72,095 as of December 31, 2017 and $82,272 as of December 31, 2016) | | | 251,433 |
| | 268,106 |
|
| Other | | 5,345 |
| | 5,577 |
| | 1,065 |
| | 963 |
|
| TOTAL | | 185,021 |
| | 146,848 |
| | 256,578 |
| | 273,149 |
|
| | | | | | | | | |
| TOTAL ASSETS | |
| $934,123 |
| |
| $888,796 |
| |
| $1,497,836 |
| |
| $1,494,569 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | | ENTERGY NEW ORLEANS, INC. | |
| BALANCE SHEETS | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES | | ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS | | CONSOLIDATED BALANCE SHEETS |
LIABILITIES AND EQUITY | | | | December 31, | | December 31, |
| | | 2014 | | 2013 | | 2017 | | 2016 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
Payable due to Entergy Louisiana
| | |
| $2,077 |
| |
| $2,104 |
|
| Accounts payable: | | |
| | |
| | |
| | |
|
| Associated companies | |
| $33,170 |
| |
| $36,193 |
| | 47,472 |
| | 39,260 |
|
| Other | | 22,435 |
| | 27,840 |
| | 29,777 |
| | 35,920 |
|
| Customer deposits | | 24,681 |
| | 22,959 |
| | 28,442 |
| | 28,667 |
|
| Interest accrued | | 3,538 |
| | 3,598 |
| | 5,487 |
| | 5,443 |
|
| Deferred fuel costs | | 28,397 |
| | 23,145 |
| | 7,774 |
| | — |
|
| System agreement cost equalization | | — |
| | 17,040 |
| |
| Other | | 6,830 |
| | 5,896 |
| | 7,351 |
| | 11,415 |
|
| TOTAL CURRENT LIABILITIES | | 119,051 |
| | 136,671 |
| | 128,380 |
| | 122,809 |
|
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
| | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 199,241 |
| | 183,636 |
| | 283,302 |
| | 334,953 |
|
| Accumulated deferred investment tax credits | | 864 |
| | 1,082 |
| | 2,323 |
| | 622 |
|
| Regulatory liability for income taxes - net | | 20,640 |
| | 28,711 |
| | 119,259 |
| | 9,074 |
|
| Asset retirement cost liabilities | | 2,511 |
| | 2,347 |
| | 3,076 |
| | 2,875 |
|
| Accumulated provisions | | 25,877 |
| | 15,000 |
| | 85,083 |
| | 88,513 |
|
| Pension and other postretirement liabilities | | 62,440 |
| | 32,497 |
| | 20,755 |
| | 36,750 |
|
| Long-term debt | | 225,866 |
| | 225,944 |
| |
| Gas system rebuild insurance proceeds | | 23,218 |
| | 32,760 |
| |
| Long-term debt (includes securitization bonds of $74,419 as of December 31, 2017 and $84,776 as of December 31, 2016) | | | 418,447 |
| | 428,467 |
|
Long-term payable due to Entergy Louisiana
| | | 16,346 |
| | 18,423 |
|
| Other | | 6,610 |
| | 4,085 |
| | 5,317 |
| | 5,357 |
|
| TOTAL NON-CURRENT LIABILITIES | | 567,267 |
| | 526,062 |
| | 953,908 |
| | 925,034 |
|
| | | | | | | | | |
| Commitments and Contingencies | |
|
| |
|
| |
|
| |
|
|
| | | | | | | | | |
| Preferred stock without sinking fund | | 19,780 |
| | 19,780 |
| | — |
| | 19,780 |
|
| | | | | | | | | |
| COMMON EQUITY | | |
| | |
| |
| Common stock, $4 par value, authorized 10,000,000 shares; issued and outstanding 8,435,900 shares in 2014 and 2013 | | 33,744 |
| | 33,744 |
| |
| Paid-in capital | | 36,294 |
| | 36,294 |
| |
| Retained earnings | | 157,987 |
| | 136,245 |
| |
| EQUITY | | | |
| | |
|
| Member's equity | | | 415,548 |
| | 426,946 |
|
| TOTAL | | 228,025 |
| | 206,283 |
| | 415,548 |
| | 426,946 |
|
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $934,123 |
| |
| $888,796 |
| |
| $1,497,836 |
| |
| $1,494,569 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. |
| STATEMENTS OF CHANGES IN COMMON EQUITY |
| For the Years Ended December 31, 2014, 2013, and 2012 |
| | | | |
| | Common Equity | | |
| | Common Stock | | Paid-in Capital | | Retained Earnings | | Total |
| | (In Thousands) |
| | | | | | | | |
| Balance at December 31, 2011 |
| $33,744 |
| |
| $36,294 |
| |
| $111,127 |
| |
| $181,165 |
|
| Net income | — |
| | — |
| | 17,065 |
| | 17,065 |
|
| Common stock dividends | — |
| | — |
| | (1,700 | ) | | (1,700 | ) |
| Preferred stock dividends | — |
| | — |
| | (965 | ) | | (965 | ) |
| Balance at December 31, 2012 |
| $33,744 |
| |
| $36,294 |
| |
| $125,527 |
| |
| $195,565 |
|
| Net income | — |
| | — |
| | 11,683 |
| | 11,683 |
|
| Preferred stock dividends | — |
| | — |
| | (965 | ) | | (965 | ) |
| Balance at December 31, 2013 |
| $33,744 |
| |
| $36,294 |
| |
| $136,245 |
| |
| $206,283 |
|
| Net income | — |
| | — |
| | 28,707 |
| | 28,707 |
|
| Common stock dividends | — |
| | — |
| | (6,000 | ) | | (6,000 | ) |
| Preferred stock dividends | — |
| | — |
| | (965 | ) | | (965 | ) |
| Balance at December 31, 2014 |
| $33,744 |
| |
| $36,294 |
| |
| $157,987 |
| |
| $228,025 |
|
| | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| | |
|
|
| | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY |
| For the Years Ended December 31, 2017, 2016, and 2015 |
| | |
| | |
| | Member’s Equity
|
| | (In Thousands) |
| | |
| Balance at December 31, 2014 | |
| $228,025 |
|
| Net income | | 44,925 |
|
Net income attributable to Entergy Louisiana
| | (2,203 | ) |
| Capital contributions from parent | | 87,500 |
|
| Common equity distributions | | (7,250 | ) |
| Preferred stock dividends | | (965 | ) |
| Balance at December 31, 2015 | |
| $350,032 |
|
| Net income | | 48,849 |
|
| Capital contributions from parent | | 47,750 |
|
| Common equity distributions | | (18,720 | ) |
| Preferred stock dividends | | (965 | ) |
| Balance at December 31, 2016 | |
| $426,946 |
|
| Net income | | 44,553 |
|
| Capital contributions from parent | | 20,000 |
|
| Common equity distributions | | (74,250 | ) |
| Preferred stock dividends | | (841 | ) |
| Other | | (860 | ) |
| Balance at December 31, 2017 | |
| $415,548 |
|
| | |
| See Notes to Financial Statements. | | |
|
| | | ENTERGY NEW ORLEANS, INC. | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES | | ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | | | | | | | | | | | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 | | 2011 | | 2010 | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (In Thousands) | (In Thousands) |
| | | | | | | | | | | | | | | | | | | |
| Operating revenues |
| $690,085 |
| |
| $620,156 |
| |
| $569,740 |
| |
| $630,185 |
| |
| $659,449 |
|
| $716,070 |
| |
| $665,463 |
| |
| $671,446 |
| |
| $735,192 |
| |
| $659,746 |
|
| Net Income |
| $28,707 |
| |
| $11,683 |
| |
| $17,065 |
| |
| $35,976 |
| |
| $31,114 |
| |
| Net income | |
| $44,553 |
| |
| $48,849 |
| |
| $44,925 |
| |
| $31,030 |
| |
| $12,608 |
|
| Total assets |
| $934,123 |
| |
| $888,796 |
| |
| $881,789 |
| |
| $806,035 |
| |
| $850,076 |
|
| $1,497,836 |
| |
| $1,494,569 |
| |
| $1,215,144 |
| |
| $1,014,916 |
| |
| $964,482 |
|
| Long-term obligations (a) |
| $245,646 |
| |
| $245,724 |
| |
| $146,080 |
| |
| $186,317 |
| |
| $186,995 |
|
| $434,793 |
| |
| $466,670 |
| |
| $357,687 |
| |
| $323,280 |
| |
| $318,034 |
|
| | | | | | | | | | | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund. | |
(a) Includes long-term debt (including the long-term payable to Entergy Louisiana and excluding currently maturing debt) and preferred stock without sinking fund.
| | (a) Includes long-term debt (including the long-term payable to Entergy Louisiana and excluding currently maturing debt) and preferred stock without sinking fund.
|
| | | | | | | | | | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 | | 2011 | | 2010 | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (Dollars In Millions) | (Dollars In Millions) |
| | | | | | | | | | | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Residential |
| $202 |
| |
| $197 |
| |
| $174 |
| |
| $176 |
| |
| $196 |
|
| $250 |
| |
| $231 |
| |
| $220 |
| |
| $230 |
| |
| $221 |
|
| Commercial | 184 |
| | 183 |
| | 164 |
| | 154 |
| | 174 |
| 228 |
| | 206 |
| | 186 |
| | 196 |
| | 194 |
|
| Industrial | 33 |
| | 35 |
| | 31 |
| | 30 |
| | 36 |
| 36 |
| | 33 |
| | 30 |
| | 33 |
| | 35 |
|
| Governmental | 66 |
| | 67 |
| | 63 |
| | 59 |
| | 70 |
| 77 |
| | 69 |
| | 64 |
| | 67 |
| | 69 |
|
| Total retail | 485 |
| | 482 |
| | 432 |
| | 419 |
| | 476 |
| 591 |
| | 539 |
| | 500 |
| | 526 |
| | 519 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Associated companies | 77 |
| | 27 |
| | 44 |
| | 95 |
| | 56 |
| — |
| | 30 |
| | 66 |
| | 78 |
| | 27 |
|
| Non-associated companies | 4 |
| | — |
| | — |
| | 1 |
| | 1 |
| 29 |
| | 3 |
| | — |
| | 4 |
| | — |
|
| Other | 14 |
| | 16 |
| | 12 |
| | 14 |
| | 10 |
| 12 |
| | 15 |
| | 18 |
| | 17 |
| | 19 |
|
| Total |
| $580 |
| |
| $525 |
| |
| $488 |
| |
| $529 |
| |
| $543 |
|
| $632 |
| |
| $587 |
| |
| $584 |
| |
| $625 |
| |
| $565 |
|
| | | | | | | | | | | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
| | | |
| | |
| | |
| | |
|
| Residential | 1,963 |
| | 1,867 |
| | 1,772 |
| | 1,888 |
| | 1,858 |
| 2,155 |
| | 2,231 |
| | 2,301 |
| | 2,262 |
| | 2,152 |
|
| Commercial | 2,046 |
| | 1,998 |
| | 1,968 |
| | 1,939 |
| | 1,899 |
| 2,248 |
| | 2,268 |
| | 2,257 |
| | 2,181 |
| | 2,130 |
|
| Industrial | 452 |
| | 481 |
| | 484 |
| | 498 |
| | 503 |
| 429 |
| | 441 |
| | 463 |
| | 455 |
| | 484 |
|
| Governmental | 768 |
| | 758 |
| | 785 |
| | 795 |
| | 809 |
| 790 |
| | 794 |
| | 825 |
| | 783 |
| | 778 |
|
| Total retail | 5,229 |
| | 5,104 |
| | 5,009 |
| | 5,120 |
| | 5,069 |
| 5,622 |
| | 5,734 |
| | 5,846 |
| | 5,681 |
| | 5,544 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Associated companies | 1,322 |
| | 495 |
| | 978 |
| | 1,167 |
| | 906 |
| — |
| | 1,071 |
| | 1,644 |
| | 1,379 |
| | 517 |
|
| Non-associated companies | 16 |
| | 13 |
| | 8 |
| | 19 |
| | 13 |
| 1,703 |
| | 141 |
| | 11 |
| | 18 |
| | 14 |
|
| Total | 6,567 |
| | 5,612 |
| | 5,995 |
| | 6,306 |
| | 5,988 |
| 7,325 |
| | 6,946 |
| | 7,501 |
| | 7,078 |
| | 6,075 |
|
| | | | | | | | | | | |
| | | | | | | | | | | |
| |
|
ENTERGY TEXAS, INC. AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Net Income
20142017 Compared to 20132016
Net income increased $16.9decreased $31.4 million primarily due to higherlower net revenue, and lower other operation and maintenance expenses, partially offset by a higher effective income tax rate, higher taxes other than income taxes, and higher depreciation and amortization expenses.
2013 Compared to 2012
Net income increased $15.9 million primarily due to higher net revenue and a lower effective income tax rate, partially offset byexpenses, higher other operation and maintenance expenses, and higher depreciationtaxes other than income taxes.
2016 Compared to 2015
Net income increased $37.9 million primarily due to lower other operation and amortization expenses.maintenance expenses, the asset write-off of its receivable associated with the Spindletop gas storage facility in 2015, and higher net revenue.
Net Revenue
20142017 Compared to 20132016
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 20142017 to 2013.2016.
|
| | | |
| | Amount |
| | (In Millions) |
| | |
|
20132016 net revenue |
| $586.5644.2 |
|
| Net wholesale revenue | (35.1 | ) |
| Purchased power capacity | 37.5(5.9 | ) |
| Transmission revenue | (5.4 | ) |
| Reserve equalization | 5.6 |
|
| Retail electric price | 17.319.0 |
|
Volume/weatherOther | 11.64.4 |
|
Transmission revenue | (7.6 | ) |
Reserve equalization | (18.0 | ) |
Net wholesale revenue | (21.0 | ) |
Other | 5.4 |
|
20142017 net revenue |
| $611.7626.8 |
|
The net wholesale revenue variance is primarily due to lower net capacity revenues resulting from the termination of the purchased power agreements between Entergy Louisiana and Entergy Texas in August 2016.
The purchased power capacity variance is primarily due to a decrease inincreased expenses due to contract changes.capacity cost changes
for ongoing purchased power capacity contracts.
The retail electric pricetransmission revenue variance is primarily due to an annual base rate increasea decrease in the amount of $18.5 million, effective April 2014,transmission revenues allocated by MISO.
The reserve equalization variance is due to the absence of reserve equalization expenses in 2017 as a result of Entergy Texas’s exit from the PUCT’s orderSystem Agreement in the September 2013 rate case.August 2016. See Note 2 to the financial statements for furthera discussion of the PUCT rate order.System Agreement.
The volume/weather variance is primarily due to an increase of 884 GWh, or 5%, in billed electricity usage, including the effect of more favorable weather on residential sales and increased industrial usage primarily in the petroleum industry as a result of expansions.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The transmission revenueretail electric price variance is primarily due to changes as a resultthe implementation of the participationtransmission cost recovery factor rider in the MISO RTO in 2014.
The reserve equalization variance is primarily due toSeptember 2016 and an increase in reserve equalization expensethe transmission cost recovery factor rider rate in March 2017, each as comparedapproved by the PUCT. See Note 2 to the same period in 2013 primarily due to the changes in the Entergy System generation mix compared to the same period in 2013 as a resultfinancial statements for further discussion of the Entergy Arkansas’s exit from the System Agreement in December 2013.
The net wholesale revenue variance is primarily due to a wholesale customer contract termination in December 2013.transmission cost recovery factor rider filing.
20132016 Compared to 20122015
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 20132016 to 2012.2015.
|
| | | |
| | Amount |
| | (In Millions) |
| | |
|
20122015 net revenue |
| $551.0637.2 |
|
Volume/weatherReserve equalization | 13.914.3 |
|
| Purchased power capacity | 12.4 |
|
| Transmission revenue | 7.0 |
|
| Retail electric price | 13.3 |
|
Fuel recovery | 6.5 |
|
Hurricane Rita regulatory asset adjustment | 6.45.4 |
|
| Net wholesale revenue | 4.7 |
|
Purchased power capacity | (10.527.8 | ) |
| Other | 1.2(4.3 |
) |
20132016 net revenue |
| $586.5644.2 |
|
The volume/weatherreserve equalization variance is primarily due to a reduction in reserve equalization expense primarily due to changes in the Entergy System generation mix compared to the same period in 2015 as a result of the execution of a new purchased power agreement and Entergy Mississippi’s exit from the System Agreement, each in November 2015, and Entergy Texas’s exit from the System Agreement in August 2016. See Note 2 to the financial statements for a discussion of the System Agreement.
The purchased power capacity variance is primarily due to decreased expenses due to the termination of the purchased power agreements between Entergy Louisiana and Entergy Texas in August 2016, as well as capacity cost changes for ongoing purchased power capacity contracts.
The transmission revenue variance is primarily due to an increase in Attachment O rates charged by MISO to transmission customers and a settlement of 470 GWh, or 3%, inAttachment O rates previously billed electricity usage, including the effect of more favorable weather compared to last year on residential sales and increased usage in the industrial sector compared to prior year as a result of an unplanned outage in the refining industry in 2012.transmission customers by MISO.
The retail electric price variance is primarily due to an annual base rate increase of $28 million, effective July 2012, as a resultthe implementation of the PUCT’s ordertransmission cost recovery factor rider, as approved by the PUCT and implemented in September 2016, and the increase in the November 2011 rate case.distribution cost recovery rider, as approved by the PUCT and implemented in January 2016. This increase was partially offset by a decrease in energy efficiency revenues. See Note 2 to the financial statements for further discussion of the PUCT rate order.
The fueltransmission cost recovery variance is primarily the result of a $6 million adjustment to deferred fuel costs recorded in third quarter 2012 in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT order issued in Entergy Texas’s 2011 rate case.
The Hurricane Rita regulatory asset adjustment of $6.4 million was recorded in third quarter 2012 in accordance with the rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order.factor rider and distribution cost recovery factor rider filings.
The net wholesale revenue variance is primarily due to contract changes for municipalslower capacity revenues resulting from the termination of the purchased power agreements between Entergy Louisiana and co-op customers.Entergy Texas in August 2016.
The purchased power capacity variance is primarily due to additional capacity purchases as well as price increases for ongoing purchased power capacity.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Other Income Statement Variances
20142017 Compared to 20132016
Other operation and maintenance expenses decreasedincreased primarily due to:
an decreaseincrease of $14.9$5.1 million in transmission and distribution expenses primarily due to higher vegetation maintenance costs;
an increase of $4.3 million in fossil-fueled generation expenses primarily due to a higher scope of work performed during plant outages in 2017 as compared to 2016; and
an increase of $2.8 million in compensation and benefitbenefits costs primarily due to an increasehigher incentive-based compensation accruals in the discount rates used2017 as compared to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge in 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates”belowand Note 11 to the financial statements for further discussion of benefits costs;
a decrease of $7.4 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business; and
a decrease of $7.1 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
2016.
The decreaseincrease was partially offset by an increasea decrease of $5.9$4.5 million primarily due to administration feesthe absence of transmission equalization expenses, as allocated under the System Agreement, as a result of Entergy Texas’s exit from the System Agreement in 2014 related to participation in the MISO RTO.August 2016.
Taxes other than income taxes increased primarily due to a reduction in the provision recorded for sales and use taxes in 2013, an increase in local franchise taxes, and an increase in ad valorem taxes. Franchise taxes have no effect on net income as these taxes are recovered throughresulting from higher assessments and a true-up to the franchisesales and use tax rider.accruals recorded in 2016 resulting from an audit settlement.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
20132016 Compared to 20122015
Other operation and maintenance expenses increaseddecreased primarily due to:
a decrease of $11.2 million in fossil-fueled generation expenses primarily due to an overall lower scope of work performed in 2016 as compared to 2015;
a decrease of $7 million in transmission expenses primarily due to lower transmission equalization expenses, as allocated under the System Agreement, as compared to the same period in 2015 as a result of Entergy Mississippi’s exit from the System Agreement in November 2015 and Entergy Texas’s exit from the System Agreement in August 2016;
an increasea decrease of $9$5.7 million in compensation and benefitbenefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit costsliabilities and a settlement charge, recognizedrefinement in September 2013, relatedthe approach used to estimate the paymentservice cost and interest cost components of lump sum benefits out of the non-qualified pension plan.and other postretirement costs. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits”belowand Note 11 to the financial statements for further discussion of benefitspension and other postretirement benefit costs;
an increasethe write-off in the third quarter 2015 of $8.8$4.3 million resulting from implementationof rate case expenses and acquisition costs severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative. See the “Human Capital Management Strategic Imperative” sectionproposed Union Power Station acquisition upon Entergy Texas’s withdrawal of Entergy Corporationits 2015 rate case and Subsidiaries Management’s Financial Discussiondismissal of its certificate of convenience and Analysis for further discussion;
necessity filing; andan increasea decrease of $2.3$4.2 million primarilyin energy efficiency costs.
The asset write-off variance is due to storm damage accrualsthe $23.5 million ($15.3 million net-of-tax) write-off recorded in accordance2015 of the receivable associated with a rate order from PUCT issued in September 2012.the Spindletop gas storage facility. See Note 2 to the financial statements for further discussion of the PUCT rate order;
an increase of $1.7 million in distribution contract work relating primarily to vegetation maintenance; and
an increase of $1.4 million in insurance expenses primarily due to increases in premiums.write-off.
The increase was partially offset by:
the amortization of $4.3 million of Hurricane Rita storm costs in prior year in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order; and
a decrease of $2.7 million in fossil-fueled expenses due to a reduced scope of work and fewer outages compared to 2012.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Also, other operation and maintenance expenses include $7.4 million in 2013 and $4.8 million in 2012 of costs incurred related to the now-terminated plan to spin off and merge the transmission business.
Taxes other than income taxes increased primarily due to a reduction in the provision recorded for sales and use taxes in 2012.
Depreciation and amortization expenses increased primarily due to additions to plant in service and an increase in depreciation rates as a result of the 2011 rate case order issued by the PUCT in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order.
Other income increased primarily due to the reversal in 2012 of $6.7 million of disallowed carrying charges on Hurricane Rita storm restoration costs in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order.
Income Taxes
The effective income tax rates for 2017, 2016, and 2015 were 39.9%38.9%, 34.2%37.0%, and 44.1% for 2014, 2013, and 2012,34.9%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses proceedings commenced or other responses by Entergy’s regulators to the Act.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2014, 2013,2017, 2016, and 20122015 were as follows:
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| | (In Thousands) | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $46,488 |
| |
| $60,236 |
| |
| $65,289 |
|
| $6,181 |
| |
| $2,182 |
| |
| $30,441 |
|
| | | | | | | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
| |
| | |
| | |
|
| Operating activities | 315,164 |
| | 237,054 |
| | 271,081 |
| 301,396 |
| | 306,601 |
| | 284,268 |
|
| Investing activities | (186,540 | ) | | (164,309 | ) | | (128,904 | ) | (383,176 | ) | | (330,191 | ) | | (315,293 | ) |
| Financing activities | (144,671 | ) | | (86,493 | ) | | (147,230 | ) | 191,112 |
| | 27,589 |
| | 2,766 |
|
| Net decrease in cash and cash equivalents | (16,047 | ) | | (13,748 | ) | | (5,053 | ) | |
| Net increase (decrease) in cash and cash equivalents | | 109,332 |
| | 3,999 |
| | (28,259 | ) |
| | | | | | | | | | | |
| Cash and cash equivalents at end of period |
| $30,441 |
| |
| $46,488 |
| |
| $60,236 |
|
| $115,513 |
| |
| $6,181 |
| |
| $2,182 |
|
Operating Activities
Net cash flow provided by operating activities decreased $5.2 million in 2017 primarily due to lower net income, the timing of recovery of fuel and purchased power costs, and an increase of $13.7 million in storm spending primarily as a result of Hurricane Harvey. The decrease was partially offset by income tax refunds of $21.1 million in 2017 compared to income tax payments of $28.5 million in 2016. Entergy Texas had income tax refunds in 2017 and income tax payments in 2016 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2017 primarily resulted from deductible temporary differences. The income tax payments in 2016 resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audit.
Net cash flow provided by operating activities increased $78.1$22.3 million in 20142016 primarily due to:
$86.1to increased net income and a decrease of $31.8 million in income tax payments in 2016. Entergy Texas had income tax payments in 2016 and 2015 in accordance with an intercompany income tax allocation agreement. The income tax payments in 2016 resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit. The income tax payments in 2015 resulted primarily from the results of operations and the reversal of taxable temporary differences. See Note 3 to the financial statements for a discussion of the income tax audit. The increase was partially offset by an increase of $5.2 million in interest paid in 2016 due to the issuance of $125 million of fuel cost refunds2.55% Series first mortgage bonds in 2013;
System Agreement bandwidth remedy payments of $48.6 million received in the second quarter 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. Entergy Texas received approval to apply a portion of the payments to the under-collected fuel balance. The remaining balance of $24.6 million was refunded to Entergy Texas customers as of December 31, 2014;March 2016 and
the timing of collections from customers.
See Note 2 to the financial statements for a discussion of fuel cost refunds and the System Agreement proceedings.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The increase was partially offset by:
a decrease of $54.8 million in income tax refunds in 2014 compared to 2013. Entergy Texas had income tax refunds in 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds in 2013 resulted from the utilization of Entergy Texas’s taxable losses against taxable income of other members of the Entergy consolidated group; and
an increase of $10.2 million in pension contributions in 2014. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Net cash flow provided by operating activities decreased $34 million in 2013 primarily due to:
the receipt, in January 2012, of $43 million in System Agreement bandwidth remedy payments required to implement the FERC’s remedy in an October 2011 order for the period June-December 2005. As of March 31, 2013, all of the $43 million, plus interest, had been credited to Entergy Texas customers, with the final $9.5 million being credited in the first quarter 2013. See Note 2 to the financial statements for a discussion of the System Agreement proceedings;
$86.1 million of fuel cost refunds in 2013, compared to $67.2 million of fuel cost refunds in 2012. See Note 2 to the financial statements for discussion of the fuel cost refunds; and
the timing of collections of receivables from customers.
The decrease was partially offset by an increase of $55.3 million in income tax refunds. Entergy Texas had income tax refunds in 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds resulted from the utilization of Entergy Texas’s taxable losses against taxable income of other members of the Entergy consolidated group.
Investing Activities
Net cash flow used in investing activities increased $22.2$53 million in 20142017 primarily due to:
money pool activity;
an increase of $34.9 million in distribution construction expenditures primarily due to increased storm spending primarily as a result of Hurricane Harvey and spending on digital technology improvements within the customer contact centers;
an increase in transmission construction expenditures and an increaseof $24.4 million in fossil-fueled generation construction expenditures primarily due to a greaterhigher scope of projectswork performed in 20142017 as compared to 2016; and money pool activity.
an increase of $8.5 million in spending on advanced metering infrastructure.
DecreasesThe increase was partially offset by a decrease of $51.7 million in transmission construction expenditures primarily due to a lower scope of work performed in 2017 as compared to 2016.
Increases in Entergy Texas’s receivable from the money pool are a sourceuse of cash flow, and Entergy Texas’s receivable from the money pool decreasedincreased by $6$44.2 million in 20142017 compared to decreasingincreasing by $12.9$0.7 million in 2013.2016. The money pool is an inter-company borrowing arrangement designed to reduce Entergy’sthe Utility subsidiaries’ need for external short-term borrowings.
Net cash flow used in investing activities increased $35.4$14.9 million in 20132016 primarily due to:
money pool activity;
an increaseto increases of $27.7 million in transmission construction expenditures due to reliability work performed in 2013; and
an increase $11.7 million in distribution construction expenditures due to an increased scope of work in 2013.
The increase was partially offset by lower fossil-fueled generation construction expendituresprimarily due to a greater scope of projects in 2012.2016 as compared to the same period in 2015. The increase was partially offset by a $21.4 million decrease in fossil-fueled generation construction expenditures primarily due to a decreased scope of work performed during plant outages in 2016 as compared to the same period in 2015.
Financing Activities
Net cash flow provided by financing activities increased $163.5 million in 2017 primarily due to:
a $115 million capital contribution received from Entergy Corporation in December 2017 in anticipation of upcoming construction expenditures;
the issuance of $150 million of 2.55% Series first mortgage bonds in December 2017 compared to the issuance of $125 million of 2.55% Series first mortgage bonds in March 2016; and
money pool activity.
Decreases in Entergy Texas’s receivable frompayable to the money pool are a sourceuse of cash flow, and Entergy Texas’s receivable frompayable to the money pool decreased by $12.9$22.1 million in 2013 compared to decreasing by $44 million in 2012.2016.
Financing Activities
Net cash flow used inprovided by financing activities increased $58.2$24.8 million in 20142016 primarily due to the retirement of $150$200 million of 7.875%3.6% Series first mortgage bonds in June 20142015 and an increasethe issuance of $45$125 million of 2.55% Series first mortgage bonds in March 2016, partially offset by the issuance of $250 million of 5.15% Series first mortgage bonds in May 2015 and money pool activity.
Decreases in Entergy Texas’s payable to the money pool are a use of cash flow, and Entergy Texas’s payable to the money pool decreased by $22.1 million in common stock2016 compared to increasing by $22.1 million in 2015.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
dividends paid, partially offset by the issuance of $135 million of 5.625% Series first mortgage bonds in May 2014. See Note 5 to the financial statements for more details on long-term debt.
Net cash flow used in financing activities decreased $60.7 million in 2013 primarily due to a decrease of $62.2 million in common stock dividends paid.
Capital Structure
Entergy Texas’s capitalization is balanced between equity and debt, as shown in the following table. The decrease in the debt to capital ratio for Entergy Texas is primarily due to the capital contribution received from Entergy Corporation and an increase in retained earnings.
| | | | December 31,
2014 | | December 31,
2013 | December 31,
2017 | | December 31,
2016 |
| Debt to capital | 62.4 | % | | 63.7 | % | 55.7 | % | | 58.5 | % |
| Effect of excluding the securitization bonds | (11.8 | %) | | (12.6 | %) | (6.3 | %) | | (8.3 | %) |
| Debt to capital, excluding securitization bonds (a) | 50.6 | % | | 51.1 | % | 49.4 | % | | 50.2 | % |
| Effect of subtracting cash | (0.9 | %) | | (1.3 | %) | (2.5 | %) | | (0.1 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 49.7 | % | | 49.8 | % | 46.9 | % | | 50.1 | % |
|
| |
| (a) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Texas. |
Net debt consists of debt less cash and cash equivalents. Debt consists of long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Texas uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Texas’s financial condition because the securitization bonds are non-recourse to Entergy Texas, as more fully described in Note 5 to the financial statements. Entergy Texas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Texas’s financial condition because net debt indicates Entergy Texas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Texas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Texas may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, Entergy Texas may receive equity contributions to maintain the targeted capital structure for certain circumstances such as large transactions that would materially alter the capital structure if financed entirely with debt and reduced dividends.
Uses of Capital
Entergy Texas requires capital resources for:
construction and other capital investments;
debt maturities or retirements;
working capital purposes, including the financing of fuel and purchased power costs; and
dividend and interest payments.
Following are the amounts of Entergy Texas’s planned construction and other capital investments.
|
| | | | | | | | | | | |
| | 2015 | | 2016 | | 2017 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $275 |
| |
| $45 |
| |
| $100 |
|
| Transmission | 140 |
| | 165 |
| | 85 |
|
| Distribution | 105 |
| | 95 |
| | 95 |
|
| Other | 35 |
| | 35 |
| | 10 |
|
| Total |
| $555 |
| |
| $340 |
| |
| $290 |
|
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Texas’s planned construction and other capital investments.
|
| | | | | | | | | | | |
| | 2018 | | 2019 | | 2020 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $175 |
| |
| $385 |
| |
| $265 |
|
| Transmission | 195 |
| | 240 |
| | 165 |
|
| Distribution | 105 |
| | 165 |
| | 145 |
|
| Utility Support | 55 |
| | 30 |
| | 30 |
|
| Total |
| $530 |
| |
| $820 |
| |
| $605 |
|
Following are the amounts of Entergy Texas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | 2015 | | 2016-2017 | | 2018-2019 | | After 2019 | | Total | 2018 | | 2019-2020 | | 2021-2022 | | After 2022 | | Total |
| | (In Millions) | (In Millions) |
| Long-term debt (a) |
| $276 |
| |
| $158 |
| |
| $356 |
| |
| $1,444 |
| |
| $2,234 |
|
| $159 |
| |
| $749 |
| |
| $385 |
| |
| $1,168 |
| |
| $2,461 |
|
| Operating leases (b) |
| $6 |
| |
| $9 |
| |
| $6 |
| |
| $4 |
| |
| $25 |
|
| $4 |
| |
| $5 |
| |
| $2 |
| |
| $2 |
| |
| $13 |
|
| Purchase obligations (c) |
| $244 |
| |
| $494 |
| |
| $492 |
| |
| $213 |
| |
| $1,443 |
|
| $279 |
| |
| $555 |
| |
| $527 |
| |
| $1,188 |
| |
| $2,549 |
|
| |
| (a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
| (b) | Does not include power purchase agreements that are accounted for as leases that are included in purchase obligations. |
| |
| (c) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Texas, it primarily includes unconditional fuel and purchased power obligations. |
In addition to the contractual obligations given above, Entergy Texas expects to contribute approximately $17.2$10.9 million to its qualified pension plans and approximately $3.2 million to other postretirement health care and life insurance plans in 2015,2018, although the 2018 required pension contributions will not be known with more certainty untilwhen the January 1, 20152018 valuations are completed, which is expected by April 1, 2015.2018. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy Texas has $17$15.8 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Texas amounts associated withincludes specific investments such as the UnionMontgomery County Power Station, acquisition discussed below; NRC post-Fukushima requirements; environmental compliance spending; transmission projects to enhance reliability, reduce congestion, and enable economic growth; resource planning; generation projects;distribution spending to enhance reliability and improve service to customers, including investment to support advanced metering; system improvements; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt in Note 5 to the financial statements.
As a wholly-owned subsidiary,discussed above in “Capital Structure,” Entergy Texas paysroutinely evaluates its ability to pay dividends to Entergy Corporation from its earnings at a percentage determined monthly.earnings.
Union Power Station Purchase Agreement
In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire the Union Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Pursuant to the agreement, Entergy Gulf States Louisiana will acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas will each acquire one power block and a 25% undivided ownership interest in such related assets. (If Entergy Arkansas or Entergy Texas do not obtain approval for the purchase of their power blocks, Entergy Gulf States Louisiana will seek to purchase the power blocks not approved.) The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments. In addition, Entergy Gulf States Louisiana anticipates selling 20% of the capacity and energy associated with its two power blocks to Entergy New Orleans through a cost-based, life-of-unit power purchase
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
agreement. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. These include regulatory approvals from the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino anti-trust law. Montgomery County Power Station
In December 2014,October 2016, Entergy Texas filed itsan application with the PUCT seeking certification that the public convenience and necessity would be served by the construction of the Montgomery County Power Station, a nominal 993 MW combined-cycle generating unit in Montgomery County, Texas on land adjacent to the existing Lewis Creek plant. The current estimated cost of the Montgomery County Power Station is $937 million, including approximately $111 million of transmission interconnection and network upgrades and other related costs. The independent monitor, who oversaw the request for proposal process, filed testimony and a report affirming that the Montgomery County Power Station was selected through an objective and fair request for proposal process that showed no undue preference to any proposal. In June 2017 parties to the proceeding filed an unopposed stipulation and settlement agreement. The stipulation contemplates that Entergy Texas’s level of cost-recovery for generation construction costs for Montgomery County Power Station is capped at $831 million, subject to certain exclusions such as force majeure events. Transmission interconnection and network upgrades and other related costs are not subject to the $831 million cap. In July 2017 the PUCT approved the stipulation. Subject to the timely receipt of other permits and approvals, commercial operation is estimated to occur by mid-2021.
Advanced Metering Infrastructure (AMI)
In April 2017 the Texas legislature enacted legislation that extends statutory support for AMI deployment to Entergy Texas and directs that if Entergy Texas elects to deploy AMI, it shall do so as rapidly as practicable. In July 2017, Entergy Texas filed an application seeking an order from the PUCT approving Entergy Texas’s deployment of AMI. Entergy Texas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Texas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, with Entergy Texas showing that its AMI deployment is expected to produce nominal net operational cost savings to customers of $33 million. Entergy Texas also sought to continue to include in rate base the remaining book value, approximately $41 million at December 31, 2016, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Texas proposed a seven-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Entergy Texas also proposed a surcharge tariff to recover the reasonable and necessary costs it has and will incur under the deployment plan for the full deployment of advanced meters. Further, Entergy Texas sought approval of the acquisition.fees that would be charged to customers who choose to opt out of receiving service through an advanced meter and instead receive electric service with a non-standard meter. In October 2017, Entergy Texas and other parties entered into and filed an unopposed stipulation and settlement agreement, permitting deployment of AMI with limited modifications. The PUCT has indicated that it will conveneapproved the hearing onstipulation and settlement agreement in December 2017. Consistent with the meritsapproval, deployment of this casethe communications network is expected to begin in June 2015.2018. Entergy Texas intendsexpects to filerecover the remaining net book value of its existing meters through a rate applicationregulatory asset to seek cost recovery later in 2015. In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC and Entergy Arkansas filed its application with the APSC, each for approval of the acquisition and cost recovery. Closing is targeted to occur in late-2015.be amortized at current depreciation rates.
Sources of Capital
Entergy Texas’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt or preferred stock issuances; and
bank financing under new or existing facilities.
Entergy Texas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
All debt and common and preferred stock issuances by Entergy Texas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indenture and other agreements. Entergy Texas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Texas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2014 | | 2013 | | 2012 | | 2011 |
| (In Thousands) |
| $306 | | $6,287 | | $19,175 | | $63,191 |
|
| | | | | | |
| 2017 | | 2016 | | 2015 | | 2014 |
| (In Thousands) |
| $44,903 | | $681 | | ($22,068) | | $306 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Texas has a credit facility in the amount of $150 million scheduled to expire in March 2019.August 2022. The credit facility allows Entergy Texas to issue letters of credit against 50%$30 million of the borrowing capacity of the facility. As of December 31, 2014,2017, there were no cash borrowings and $1.3$25.6 million of letters of credit outstanding under the credit facility. In addition, Entergy Texas entered intois a party to an uncommitted letter of credit facility in 2014 as a means to post collateral to support its obligations underto MISO. As of December 31, 2014,2017, a $24.5$22.8 million letter of credit was outstanding under Entergy Texas’s letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy Texas obtained authorizations from the FERC through October 20152019 for short-term borrowings, not to exceed an aggregate amount of $200 million at any time outstanding, and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Texas’s short-term borrowing limits.
In May 2014, Entergy Texas issued $135 million of 5.625% Series first mortgage bonds due June 2064. Entergy Texas used the proceeds to pay, prior to maturity, a portion of its $150 million of 7.875% Series first mortgage bonds due June 2039.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Texas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Texas is regulated and the rates charged to its customers are determined in regulatory proceedings. The PUCT, a governmental agency, is primarily responsible for approval of the rates charged to customers.
Filings with the PUCT
2011 Rate Case
In November 2011, Entergy Texas filed a rate case requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year. The rate case also proposed a purchased power recovery rider. On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the current rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased power capacity rider is approved in a separate proceeding. In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity. The PUCT Staff, however, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas’s recovery of purchased power capacity costs and Entergy Texas’s proposal to defer its MISO transition expenses. In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase. A hearing was held in late-April through early-May 2012.
In September 2012 the PUCT issued an order approving a $28 million rate increase, effective July 2012. The order includesincluded a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.” The order also providesprovided for increases in depreciation rates and the annual storm reserve accrual. The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measureable;measurable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates,rates; and reduced Entergy’s Texas’s fuel reconciliation recovery by $4
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
million because itthe PUCT disagreed with the line-loss factor used in the calculation. After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believebelieved that it iswas entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties have also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, have appealed various aspects of the PUCT’s order to the Travis County District Court. A hearing was held in July 2014. In October 2014 the Travis County District Court issued an order upholding the PUCT’s decision except as to the line-loss factor issue referenced above, which was found in favor of Entergy Texas. In November 2014, Entergy Texas and other parties, including the PUCT, appealed the Travis County District Court decision andto the PUCT appealedThird Court of Appeals. Oral argument before the court panel was held in September 2015. In April 2016 the Third Court of Appeals issued its opinion affirming the District Court’s decision on the line-loss factor issue.all points. Entergy Texas expectspetitioned the Texas Supreme Court to file briefs duringhear its appeal of the first halfThird Court’s ruling. In September 2017 the Texas Supreme Court denied the petitions for review. Entergy Texas filed a motion for rehearing of 2015.the Texas Supreme Court’s denial of the petition for review. In January 2018 the Texas Supreme Court denied Entergy Texas’s motion for rehearing.
2013 Rate CaseDistribution cost recovery factor (DCRF) rider
In September 2013,2015, Entergy Texas filed to amend its DCRF rider. Entergy Texas requested an increase in recovery under the rider of $6.5 million, for a rate case requesting a $38.6total collection of $10.1 million base rate increase reflecting a 10.4% return on common equity based on an adjusted test year ending March 31, 2013. The rate case also proposed (1) a rough production cost equalization adjustment rider recovering Entergy Texas’s payment to Entergy New Orleans to achieve rough production cost equalization based on calendar year 2012 production costsannually from retail customers. In October 2015 intervenors and (2) a rate case expense rider recovering the cost of the 2013 rate case and certain costs associated with previous rate cases. The rate case filing also included a request to reconcile $0.9 billion of fuel and purchased power costs and fuel revenues covering the period July 2011 through March 2013. The fuel reconciliation also reflects special circumstances fuel cost recovery of approximately $22 million of purchased power capacity costs. In January 2014 the PUCT staff filed direct testimony recommending a retail rate reductionopposing, in part, Entergy Texas’s request. In November 2015, Entergy Texas and the parties filed an unopposed settlement agreement and supporting documents. The settlement established an annual revenue requirement of $0.3$8.65 million for the amended DCRF rider, with the resulting rates effective for usage on and a 9.2% return on common equity. after January 1, 2016. The PUCT approved the settlement agreement in February 2016.
In March 2014,June 2017, Entergy Texas filed an Agreed Motionapplication to amend its DCRF rider by increasing the total collection from $8.65 million to approximately $19 million. In July 2017, Entergy Texas, the PUCT, and the two other parties in the proceeding entered into an unopposed stipulation and settlement agreement resulting in an amended DCRF annual revenue requirement of $18.3 million, with the resulting rates effective for Interim Rates.usage no later than October 1, 2017. In September 2017 the PUCT issued its final order approving the unopposed stipulation and settlement agreement. The motion explainedamended DCRF rider rates became effective for usage on and after September 1, 2017.
Transmission cost recovery factor (TCRF) rider
In September 2015, Entergy Texas filed for a TCRF rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances involving, among other things, MISO charges, vegetation management costs, and bad debt expenses that would reduce the requested increase by approximately $2 million. In addition to those recommended disallowances, a number of parties recommended that Entergy Texas’s request be reduced by an additional $3.4 million to account for load growth since base rates were last set. A hearing on the merits was held in December 2015. In February 2016 a State Office of Administrative Hearings ALJ issued a proposal for decision recommending that the partiesPUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In June 2016 the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to this proceeding have agreeda TCRF. In July 2016 the PUCT issued an order generally accepting the proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider is designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount includes the approximately $10.5 million annually that Entergy Texas should be allowedis currently authorized to implement new rates reflecting an $18.5 million base rate increase, effective forcollect through the TCRF rider, as discussed above. In December 2016, concurrent with the 2016 fuel reconciliation stipulation and settlement agreement discussed above, Entergy Texas and the PUCT reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. As discussed below, the terms of the two settlements are interdependent. The PUCT approved the settlement and issued a final order in March 2017. Entergy Texas implemented the amended TCRF rider beginning with bills covering usage on and after April 1, 2014, as well as recovery of charges for rough production cost equalization and rate case expenses. In March 2014 the State Office of Administrative Hearings, the body assigned to hear the case, approved the motion. In April 2014, Entergy Texas filed a unanimous stipulation in this case. Among other things, the stipulation provides for an $18.5 million base rate increase, recovery over three years of the calendar year 2012 rough production cost equalization charges and rate case expenses, and states a 9.8% return on common equity. In addition, the stipulation finalizes the fuel and purchased power reconciliation covering the period July 2011 through March 2013, with the parties stipulating an immaterial fuel disallowance. No special circumstances recovery of purchased power capacity costs was allowed. In April 2014 the State Office of Administrative Hearings remanded the case back to the PUCT for final processing. In May 2014 the PUCT approved the stipulation. No motions for rehearing were filed during the statutory rehearing period.
In September 2014, Entergy Texas filed for a distribution cost recovery factor rider based on a law that was passed in 2011 allowing for the recovery of increases in capital costs associated with distribution plant. Entergy Texas requested collection of approximately $7 million annually from retail customers. The parties reached a unanimous settlement authorizing recovery of $3.6 million annually commencing with usage on and after January 1, 2015. A State Office of Administrative Hearings ALJ issued an order in December 2014 authorizing this recovery on an interim basis and remanded the case to the PUCT. In February 2015 the PUCT entered a final order, making the settlement final and the interim rates permanent.20, 2017.
Fuel and Purchased Power Cost Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT.
In December 2011, Entergy Texas filed with the PUCT a request to refund approximately $43 million, including interest, of fuel cost recovery over-collections through October 2011. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $67 million, including interest and additional over-recoveries through December 2011, over a three-month period. Entergy Texas and the parties requested that interim rates consistent with the settlement be approved effective with the March 2012 billing month, and the PUCT approved the application in March 2012. Entergy Texas completed this refund to customers in May 2012.
In October 2012, Entergy Texas filed with the PUCT a request to refund approximately $78 million, including interest, of fuel cost recovery over-collections through September 2012. Entergy Texas requested that the refund be implemented over a six-month period effective with the January 2013 billing month. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $84 million, including interest and additional over-recoveries through October 2012, to most customers over a three-month period beginning January 2013. The PUCT approved the stipulation in January 2013. Entergy Texas completed this refund to customers in March 2013.
In July 2012, Entergy Texas filed with the PUCT an application to credit its customers approximately $37.5 million, including interest, resulting from the FERC’s October 2011 order in the System Agreement rough production cost equalization proceeding. See Note 2 to the financial statements for a discussion of the FERC’s October 2011 order. In September 2012 the parties submitted a stipulation resolving the proceeding. The stipulation provided that most Entergy Texas customers would be credited over a four-month period beginning October 2012. The credits were initiated with the October 2012 billing month on an interim basis, and the PUCT subsequently approved the stipulation, also in October 2012.
In August 2014, Entergy Texas filed an application seeking PUCT approval to implement an interim fuel refund of approximately $24.6 million for over-collected fuel costs incurred during the months of November 2012 through April 2014. This refund resulted from (i) applying $48.6 million in bandwidth remedy payments that Entergy Texas
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
received in May 2014 related to the June - December 2005 period to Entergy Texas’s $8.7 million under-recovered fuel balance as of April 30, 2014 and (ii) netting that fuel balance against the $15.3 million bandwidth remedy payment that Entergy Texas made related to calendar year 2013 production costs. Also in August 2014, Entergy Texas filed an unopposed motion for interim rates to implement these refunds for most customers over a two-month period commencing with September 2014. The PUCT issued its order approving the interim relief in August 2014 and Entergy Texas completed the refunds in October 2014. Parties intervened in this matter. Allmatter, and all parties agreed that this casethe proceeding should be bifurcated such that the proposed interim refundsrefund would become final in a separate docket. The current docket would remainproceeding, which refund was approved by the PUCT in placeMarch 2015. In July 2015 certain parties filed briefs in the open proceeding asserting that Entergy Texas should refund to potentially addressretail customers an additional rough$10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production cost equalization-related matterscosts. In October 2015 an ALJ issued a proposal for decision recommending that are not part of the interim refunds discussed above.additional $10.9 million in bandwidth remedy payments be refunded to retail customers. In January 2015,2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a requestmotion for this severance and final approvalrehearing of the interim refund. Both applications are pending.
AtPUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The pending appeals did not stay the PUCT’s decision. In April 2013 open meeting,2016, Entergy Texas filed with the PUCT Commissionersan application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments, discussed their viewabove, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a purchased power capacity rider was good public policy.$68 million refund. The ALJ approved the refund on an interim basis to be made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund. The federal appeal of the PUCT’s January 2016 decision was heard in May 2013 adoptingDecember 2016, and the rule allowingFederal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal to the U.S. Court of Appeals for the Fifth Circuit of the Federal District Court ruling. Oral argument was held before the U.S. Court of Appeals for the Fifth Circuit in February 2018, and a decision is pending. The State District Court appeal of the PUCT’s January 2016 decision also remains pending.
In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power capacity rider, subjectcosts for the period April 1, 2013 through March 31, 2016. Under a recent PUCT rule change, a fuel reconciliation is required to be filed at least once every three years and outside of a base rate case filing. During the reconciliation period, Entergy Texas incurred approximately $1.77 billion in Texas jurisdictional eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. Entergy Texas estimated an offsetting adjustmentover-recovery balance of
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for load growth. The rule,the subsequent reconciliation period beginning Apri1 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as adopted,a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also includesrequested a processprudence finding for obtaining pre-approvaleach of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT of purchased power agreements.in a prior proceeding. In December 2016, Entergy Texas hasentered into a stipulation and settlement agreement resulting in a $6 million disallowance not exercisedassociated with any particular issue raised and a refund of the optionover-recovery balance of $21 million as of November 30, 2016, to recover its capacity costs undermost customers beginning April 2017 through June 2017. This settlement was developed concurrently with the newstipulation and settlement agreement in the 2016 transmission cost recovery factor rider mechanism, butamendment discussed above, and the terms and conditions in both settlements are interdependent. The fuel reconciliation settlement was approved by the PUCT in March 2017 and the refunds were made.
In June 2017, Entergy Texas filed an application for a fuel refund of approximately $30.7 million for the months of December 2016 through April 2017. For most customers, the refunds flowed through bills for the months of July 2017 through September 2017. The fuel refund was approved by the PUCT in August 2017.
In December 2017, Entergy Texas filed an application for a fuel refund of approximately $30.5 million for the months of May 2017 through October 2017. Also in December 2017, the PUCT’s ALJ approved the refund on an interim basis. For most customers, the refunds flowed through bills beginning January 2018 and will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.through March 2018. A final decision in this matter remains pending.
Federal Regulation
See “Entergy’s Integration Into the MISO Regional Transmission Organization,” “System Agreement,” and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of these topics.federal regulation.
Nuclear Matters
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
Industrial and Commercial Customers
Entergy Texas’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Texas’s industrial customer base. Entergy Texas responds by working with industrial and commercial customers and negotiating electric service contracts to provide, under existing rate schedules, competitive rates that match specific customer needs and load profiles. Entergy Texas actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers. Entergy Texas does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Texas’s marketing efforts in retaining industrial customers.
Environmental Risks
Entergy Texas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Texas is in substantial compliance with environmental regulations currently applicable to its facilities and operations.operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Critical Accounting Estimates
The preparation of Entergy Texas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Texas’s financial position or results of operations.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Unbilled Revenue
As discussedSee “Unbilled Revenue” in Note 1 to the financial statements,“Critical Accounting Estimates” section of Entergy Texas records an estimateCorporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the revenues earned for energy delivered sinceestimates associated with the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenueamounts.
Impairment of Long-lived Assets and a receivable,Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the prior month’s estimate is reversed. The difference between the estimate“Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the unbilled receivable atestimates associated with the beginningimpairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the period“Critical Accounting Estimates” section of Entergy Corporation and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled periodSubsidiaries Management’s Financial Discussion and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period and fuel price fluctuations, in addition to changes in certain components of the calculation.Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Texas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries’ Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension and qualified projected benefit obligation cost to changes in certain actuarial assumptions (dollars in thousands).
| | Actuarial Assumption | | Change in Assumption | | Impact on 2014 Qualified Pension Cost | | Impact on 2014 Qualified Projected Benefit Obligation | | Change in Assumption | | Impact on 2018 Qualified Pension Cost | | Impact on 2017 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $842 | | $13,906 | | (0.25%) | | $701 | |
| $11,425 |
|
| Rate of return on plan assets | | (0.25%) | | $697 | | $— | | (0.25%) | | $868 | |
| $— |
|
| Rate of increase in compensation | | 0.25% | | $322 | | $1,769 | | 0.25% | | $301 | |
| $1,488 |
|
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation changes in certain actuarial assumptions (dollars in thousands).
| | Actuarial Assumption | | Change in Assumption | | Impact on 2014 Postretirement Benefit Cost | | Impact on 2014 Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2018 Postretirement Benefit Cost | | Impact on 2017 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $230 | | $4,221 | | (0.25%) | | $231 | | $3,481 |
| Health care cost trend | | 0.25% | | $536 | | $3,884 | | 0.25% | | $413 | | $2,907 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Costs and Funding
Total qualified pension cost for Entergy Texas in 20142017 was $8.5$3.5 million. Entergy Texas anticipates 20152018 qualified pension costincome to be $12.1$4.2 million. In 2016, Entergy Texas refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $3.6 million. Entergy Texas contributed $17.1$17 million to its qualified pension plans in 20142017 and estimates 20152018 pension contributions towill be approximately $17.2$10.9 million, although the 2018 required pension contributions will not be known with more certainty untilwhen the January 1, 20152018 valuations are completed, which is expected by April 1, 2015.2018.
Total postretirement health care and life insurance benefit income for Entergy Texas in 20142017 was $2.8$1.8 million. Entergy Texas expects 20152018 postretirement health care and life insurance benefit income to approximate $3.0$6.2 million. In 2016, Entergy Texas refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $1.1 million. Entergy Texas contributed $3.4$3.1 million to its other postretirement plans in 20142017 and expects to contributeestimates 2018 contributions will be approximately $3.2 million in 2015.
The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $30.8 million in the qualified pension benefit obligation and $8.2 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $4.3 million and other postretirement cost by approximately $1 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.
Federal Healthcare Legislation
See the “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and Board of Directors and Shareholder of
Entergy Texas, Inc. and Subsidiaries
The Woodlands, Texas
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Texas, Inc. and Subsidiaries (the “Company”) as of December 31, 20142017 and 2013, and2016, the related consolidated income statements, consolidated statements of income, cash flows, and consolidated statements of changes in common equity (pages 432414 through 436418 and applicable items in pages 6155 through 234)230), for each of the three years in the period ended December 31, 2014. 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on thesethe Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Anmisstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit includesof its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements. An auditOur audits also includes assessingincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Texas, Inc. and Subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 20152018
We have served as the Company’s auditor since 2001.
431
| | ENTERGY TEXAS, INC. AND SUBSIDIARIES | CONSOLIDATED INCOME STATEMENTS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | | | | |
| Electric | |
| $1,851,982 |
| |
| $1,728,799 |
| |
| $1,581,496 |
| |
| $1,544,893 |
| |
| $1,615,619 |
| |
| $1,707,203 |
|
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
| | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 282,809 |
| | 207,310 |
| | 243,877 |
| | 225,517 |
| | 271,968 |
| | 277,810 |
|
| Purchased power | | 881,438 |
| | 857,512 |
| | 717,876 |
| | 610,279 |
| | 616,597 |
| | 709,947 |
|
| Other operation and maintenance | | 232,955 |
| | 253,786 |
| | 233,503 |
| | 230,616 |
| | 220,566 |
| | 254,731 |
|
| Asset write-off | | | — |
| | — |
| | 23,472 |
|
| Taxes other than income taxes | | 70,439 |
| | 63,823 |
| | 59,348 |
| | 79,254 |
| | 70,973 |
| | 72,945 |
|
| Depreciation and amortization | | 99,609 |
| | 94,744 |
| | 88,307 |
| | 117,520 |
| | 107,026 |
| | 102,410 |
|
| Other regulatory charges - net | | 76,017 |
| | 77,491 |
| | 68,772 |
| | 82,328 |
| | 82,879 |
| | 82,243 |
|
| TOTAL | | 1,643,267 |
| | 1,554,666 |
| | 1,411,683 |
| | 1,345,514 |
| | 1,370,009 |
| | 1,523,558 |
|
| | | | | | | | | | | | | |
| OPERATING INCOME | | 208,715 |
| | 174,133 |
| | 169,813 |
| | 199,379 |
| | 245,610 |
| | 183,645 |
|
| | | | | | | | | | | | | |
| OTHER INCOME | | |
| | |
| | |
| | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 2,959 |
| | 4,647 |
| | 4,537 |
| | 6,722 |
| | 7,617 |
| | 5,678 |
|
| Interest and investment income (loss) | | 1,106 |
| | 1,369 |
| | (2,220 | ) | |
| Interest and investment income | | | 981 |
| | 987 |
| | 684 |
|
| Miscellaneous - net | | (2,345 | ) | | (3,328 | ) | | (4,264 | ) | | 193 |
| | (746 | ) | | (798 | ) |
| TOTAL | | 1,720 |
| | 2,688 |
| | (1,947 | ) | | 7,896 |
| | 7,858 |
| | 5,564 |
|
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest expense | | 88,049 |
| | 92,156 |
| | 96,035 |
| | 86,719 |
| | 87,776 |
| | 86,024 |
|
| Allowance for borrowed funds used during construction | | (2,062 | ) | | (3,324 | ) | | (3,258 | ) | | (4,098 | ) | | (4,943 | ) | | (3,690 | ) |
| TOTAL | | 85,987 |
| | 88,832 |
| | 92,777 |
| | 82,621 |
| | 82,833 |
| | 82,334 |
|
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 124,448 |
| | 87,989 |
| | 75,089 |
| | 124,654 |
| | 170,635 |
| | 106,875 |
|
| | | | | | | | | | | | | |
| Income taxes | | 49,644 |
| | 30,108 |
| | 33,118 |
| | 48,481 |
| | 63,097 |
| | 37,250 |
|
| | | | | | | | | | | | | |
| NET INCOME | |
| $74,804 |
| |
| $57,881 |
| |
| $41,971 |
| |
| $76,173 |
| |
| $107,538 |
| |
| $69,625 |
|
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | ENTERGY TEXAS, INC. AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | | | | | | | |
| Net income | |
| $74,804 |
| |
| $57,881 |
| |
| $41,971 |
| |
| $76,173 |
| |
| $107,538 |
| |
| $69,625 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | | | | |
| Depreciation and amortization | | 99,609 |
| | 94,744 |
| | 88,307 |
| | 117,520 |
| | 107,026 |
| | 102,410 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 2,829 |
| | 86,152 |
| | 123,167 |
| | 42,119 |
| | 20,794 |
| | (23,292 | ) |
| Changes in assets and liabilities: | | |
| | |
| | |
| | |
| | |
| | |
|
| Receivables | | 24,318 |
| | (49,252 | ) | | 32,912 |
| | (15,934 | ) | | (9,300 | ) | | 21,443 |
|
| Fuel inventory | | 5,433 |
| | 53 |
| | (1,504 | ) | | (25,054 | ) | | 9,765 |
| | 2,960 |
|
| Accounts payable | | (19,854 | ) | | 29,718 |
| | 19,980 |
| | 32,842 |
| | (22,462 | ) | | (16,913 | ) |
| Prepaid taxes and taxes accrued | | 57,484 |
| | (1,967 | ) | | (93,979 | ) | | 30,308 |
| | 10,018 |
| | 3,484 |
|
| Interest accrued | | (1,489 | ) | | (920 | ) | | (929 | ) | | (421 | ) | | (3,229 | ) | | (551 | ) |
| Deferred fuel costs | | (15,954 | ) | | (89,241 | ) | | 28,670 |
| | 12,758 |
| | 29,419 |
| | 36,985 |
|
| Other working capital accounts | | 9,045 |
| | 6,918 |
| | (58,691 | ) | | (7,852 | ) | | (3,354 | ) | | 2,468 |
|
| Provisions for estimated losses | | 3,139 |
| | 2,470 |
| | 1,585 |
| | 2,531 |
| | (1,735 | ) | | (2,899 | ) |
| Other regulatory assets | | 2,809 |
| | 197,520 |
| | 62,166 |
| | 184,574 |
| | 74,389 |
| | 125,133 |
|
| Other regulatory liabilities | | | 410,968 |
| | 2,106 |
| | 1,271 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | | (520,547 | ) | | — |
| | — |
|
| Pension and other postretirement liabilities | | 59,725 |
| | (104,055 | ) | | 17,330 |
| | (49,445 | ) | | (10,204 | ) | | (33,474 | ) |
| Other assets and liabilities | | 13,266 |
| | 7,033 |
| | 10,096 |
| | 10,856 |
| | (4,170 | ) | | (4,382 | ) |
| Net cash flow provided by operating activities | | 315,164 |
| | 237,054 |
| | 271,081 |
| | 301,396 |
| | 306,601 |
| | 284,268 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Construction expenditures | | (195,794 | ) | | (181,546 | ) | | (181,404 | ) | | (348,027 | ) | | (337,963 | ) | | (320,408 | ) |
| Allowance for equity funds used during construction | | 2,981 |
| | 4,647 |
| | 4,537 |
| | 6,874 |
| | 7,743 |
| | 5,751 |
|
| Insurance proceeds | | | 2,431 |
| | — |
| | — |
|
| Changes in money pool receivable - net | | 5,981 |
| | 12,888 |
| | 44,016 |
| | (44,222 | ) | | (681 | ) | | 306 |
|
| Changes in securitization account | | 292 |
| | (256 | ) | | 3,960 |
| | (232 | ) | | 710 |
| | (942 | ) |
| Other | | — |
| | (42 | ) | | (13 | ) | |
| Net cash flow used in investing activities | | (186,540 | ) | | (164,309 | ) | | (128,904 | ) | | (383,176 | ) | | (330,191 | ) | | (315,293 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 131,163 |
| | — |
| | — |
| | 148,277 |
| | 123,502 |
| | 246,607 |
|
| Retirement of long-term debt | | (213,450 | ) | | (61,316 | ) | | (59,322 | ) | | (71,683 | ) |
| (68,593 | ) |
| (265,734 | ) |
| Dividends paid: | | |
| | |
| | |
| |
| Common stock | | (70,000 | ) | | (25,000 | ) | | (87,180 | ) | |
| Capital contributions from parent | | | 115,000 |
| | — |
| | — |
|
| Change in money pool payable - net | | | — |
| | (22,068 | ) | | 22,068 |
|
| Other | | 7,616 |
| | (177 | ) | | (728 | ) | | (482 | ) | | (5,252 | ) | | (175 | ) |
| Net cash flow used in financing activities | | (144,671 | ) | | (86,493 | ) | | (147,230 | ) | |
| Net decrease in cash and cash equivalents | | (16,047 | ) | | (13,748 | ) | | (5,053 | ) | |
| Net cash flow provided by financing activities | | | 191,112 |
| | 27,589 |
| | 2,766 |
|
| Net increase (decrease) in cash and cash equivalents | | | 109,332 |
| | 3,999 |
| | (28,259 | ) |
| Cash and cash equivalents at beginning of period | | 46,488 |
| | 60,236 |
| | 65,289 |
| | 6,181 |
| | 2,182 |
| | 30,441 |
|
| Cash and cash equivalents at end of period | |
| $30,441 |
| |
| $46,488 |
| |
| $60,236 |
| |
| $115,513 |
| |
| $6,181 |
| |
| $2,182 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
| | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $85,695 |
| |
| $89,021 |
| |
| $92,632 |
| |
| $84,556 |
| |
| $88,489 |
| |
| $83,290 |
|
| Income taxes | |
| ($2,653 | ) | |
| ($57,473 | ) | |
| ($2,207 | ) | |
| ($21,107 | ) | |
| $28,523 |
| |
| $60,359 |
|
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | ENTERGY TEXAS, INC. AND SUBSIDIARIES | CONSOLIDATED BALANCE SHEETS | ASSETS | | | | | | |
| | | December 31, | | December 31, |
| | | 2014 | | 2013 | | 2017 | | 2016 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT ASSETS | | | | | | | | |
| Cash and cash equivalents: | | | | | | | | |
| Cash | |
| $1,733 |
| |
| $2,432 |
| |
| $32 |
| |
| $1,216 |
|
| Temporary cash investments | | 28,708 |
| | 44,056 |
| | 115,481 |
| | 4,965 |
|
| Total cash and cash equivalents | | 30,441 |
| | 46,488 |
| | 115,513 |
| | 6,181 |
|
| Securitization recovery trust account | | 37,219 |
| | 37,511 |
| | 37,683 |
| | 37,451 |
|
| Accounts receivable: | | |
| | |
| | |
| | |
|
| Customer | | 70,993 |
| | 76,957 |
| | 74,382 |
| | 71,803 |
|
| Allowance for doubtful accounts | | (672 | ) | | (443 | ) | | (463 | ) | | (828 | ) |
| Associated companies | | 57,004 |
| | 76,494 |
| | 90,629 |
| | 39,447 |
|
| Other | | 10,985 |
| | 10,897 |
| | 9,831 |
| | 14,756 |
|
| Accrued unbilled revenues | | 38,363 |
| | 43,067 |
| | 50,682 |
| | 39,727 |
|
| Total accounts receivable | | 176,673 |
| | 206,972 |
| | 225,061 |
| | 164,905 |
|
| Deferred fuel costs | | 11,861 |
| | — |
| |
| Accumulated deferred income taxes | | 669 |
| | — |
| |
| Fuel inventory - at average cost | | 49,902 |
| | 55,335 |
| | 42,731 |
| | 37,177 |
|
| Materials and supplies - at average cost | | 33,892 |
| | 34,068 |
| | 38,605 |
| | 36,631 |
|
| Prepaid taxes | | — |
| | 55,635 |
| |
| Prepayments and other | | 29,211 |
| | 50,498 |
| | 19,710 |
| | 18,599 |
|
| TOTAL | | 369,868 |
| | 486,507 |
| | 479,303 |
| | 300,944 |
|
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
| | |
| | |
|
| Investments in affiliates - at equity | | 655 |
| | 687 |
| | 457 |
| | 600 |
|
| Non-utility property - at cost (less accumulated depreciation) | | 376 |
| | 376 |
| | 376 |
| | 376 |
|
| Other | | 19,085 |
| | 18,161 |
| | 19,235 |
| | 18,801 |
|
| TOTAL | | 20,116 |
| | 19,224 |
| | 20,068 |
| | 19,777 |
|
| | | | | | | | | |
| UTILITY PLANT | | |
| | |
| | |
| | |
|
| Electric | | 3,761,847 |
| | 3,616,061 |
| | 4,569,295 |
| | 4,274,069 |
|
| Construction work in progress | | 125,425 |
| | 94,743 |
| | 102,088 |
| | 111,227 |
|
| TOTAL UTILITY PLANT | | 3,887,272 |
| | 3,710,804 |
| | 4,671,383 |
| | 4,385,296 |
|
| Less - accumulated depreciation and amortization | | 1,454,701 |
| | 1,387,303 |
| | 1,579,387 |
| | 1,526,057 |
|
| UTILITY PLANT - NET | | 2,432,571 |
| | 2,323,501 |
| | 3,091,996 |
| | 2,859,239 |
|
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
| | |
| | |
|
| Regulatory assets: | | |
| | |
| | |
| | |
|
| Regulatory asset for income taxes - net | | 123,407 |
| | 129,069 |
| | — |
| | 105,816 |
|
Other regulatory assets (includes securitization property of $521,424 as of
December 31, 2014 and $585,152 as of December 31, 2013) | | 922,087 |
| | 919,234 |
| |
| Long-term receivables - associated companies | | 26,156 |
| | 27,900 |
| |
| Other regulatory assets (includes securitization property of $313,123 as of December 31, 2017 and $384,609 as of December 31, 2016) | | | 661,398 |
| | 740,156 |
|
| Other | | 13,880 |
| | 16,425 |
| | 26,973 |
| | 7,149 |
|
| TOTAL | | 1,085,530 |
| | 1,092,628 |
| | 688,371 |
| | 853,121 |
|
| | | | | | | | | |
| TOTAL ASSETS | |
| $3,908,085 |
| |
| $3,921,860 |
| |
| $4,279,738 |
| |
| $4,033,081 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | ENTERGY TEXAS, INC. AND SUBSIDIARIES | CONSOLIDATED BALANCE SHEETS | LIABILITIES AND EQUITY | | | | | | |
| | | December 31, | | December 31, |
| | | 2014 | | 2013 | | 2017 | | 2016 |
| | | (In Thousands) | | (In Thousands) |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing long-term debt | |
| $200,000 |
| |
| $— |
| |
| Accounts payable: | | | | | | | | |
| Associated companies | | 91,481 |
| | 112,309 |
| |
| $59,347 |
| |
| $47,867 |
|
| Other | | 87,910 |
| | 73,682 |
| | 126,095 |
| | 77,342 |
|
| Customer deposits | | 44,308 |
| | 38,721 |
| | 40,925 |
| | 44,419 |
|
| Taxes accrued | | 1,849 |
| | — |
| | 45,659 |
| | 15,351 |
|
| Accumulated deferred income taxes | | — |
| | 33,847 |
| |
| Interest accrued | | 29,757 |
| | 31,246 |
| | 25,556 |
| | 25,977 |
|
| Deferred fuel costs | | — |
| | 4,093 |
| | 67,301 |
| | 54,543 |
|
| Other | | 18,238 |
| | 36,276 |
| | 8,132 |
| | 9,388 |
|
| TOTAL | | 473,543 |
| | 330,174 |
| | 373,015 |
| | 274,887 |
|
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
| | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 1,046,618 |
| | 1,022,955 |
| | 544,642 |
| | 1,027,647 |
|
| Accumulated deferred investment tax credits | | 14,735 |
| | 16,147 |
| | 11,983 |
| | 12,934 |
|
| Regulatory liability for income taxes - net | | | 412,620 |
| | — |
|
| Other regulatory liabilities | | 5,125 |
| | 5,194 |
| | 6,850 |
| | 8,502 |
|
| Asset retirement cost liabilities | | 4,610 |
| | 4,349 |
| | 6,835 |
| | 6,470 |
|
| Accumulated provisions | | 12,218 |
| | 9,079 |
| | 10,115 |
| | 7,584 |
|
| Pension and other postretirement liabilities | | 111,011 |
| | 51,253 |
| | 17,853 |
| | 67,313 |
|
| Long-term debt (includes securitization bonds of $565,659 as of December 31, 2014 and $629,087 as of December 31, 2013) | | 1,278,931 |
| | 1,556,939 |
| |
| Long-term debt (includes securitization bonds of $358,104 as of December 31, 2017 and $429,043 as of December 31, 2016) | | | 1,587,150 |
| | 1,508,407 |
|
| Other | | 69,463 |
| | 38,743 |
| | 48,508 |
| | 50,343 |
|
| TOTAL | | 2,542,711 |
| | 2,704,659 |
| | 2,646,556 |
| | 2,689,200 |
|
| | | | | | | | | |
| Commitments and Contingencies | |
|
| |
|
| |
|
| |
|
|
| | | | | | | | | |
| COMMON EQUITY | | |
| | |
| | |
| | |
|
| Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2014 and 2013 | | 49,452 |
| | 49,452 |
| |
| Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2017 and 2016 | | | 49,452 |
| | 49,452 |
|
| Paid-in capital | | 481,994 |
| | 481,994 |
| | 596,994 |
| | 481,994 |
|
| Retained earnings | | 360,385 |
| | 355,581 |
| | 613,721 |
| | 537,548 |
|
| TOTAL | | 891,831 |
| | 887,027 |
| | 1,260,167 |
| | 1,068,994 |
|
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $3,908,085 |
| |
| $3,921,860 |
| |
| $4,279,738 |
| |
| $4,033,081 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | ENTERGY TEXAS, INC. AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY | | For the Years Ended December 31, 2014, 2013, and 2012 | |
| For the Years Ended December 31, 2017, 2016, and 2015 | | For the Years Ended December 31, 2017, 2016, and 2015 |
| | | | | | | |
| | Common Equity | | | Common Equity | | |
| | Common Stock | | Paid-in Capital | | Retained Earnings | | Total | Common Stock | | Paid-in Capital | | Retained Earnings | | Total |
| | (In Thousands) | (In Thousands) |
| | | | | | | | | | | | | | | |
| Balance at December 31, 2011 |
| $49,452 |
| |
| $481,994 |
| |
| $367,909 |
| |
| $899,355 |
| |
| Balance at December 31, 2014 | |
| $49,452 |
| |
| $481,994 |
| |
| $360,385 |
| |
| $891,831 |
|
| Net income | — |
| | — |
| | 41,971 |
| | 41,971 |
| — |
| | — |
| | 69,625 |
| | 69,625 |
|
| Common stock dividends | — |
| | — |
| | (87,180 | ) | | (87,180 | ) | |
| Balance at December 31, 2012 |
| $49,452 |
| |
| $481,994 |
| |
| $322,700 |
| |
| $854,146 |
| |
| Balance at December 31, 2015 | |
| $49,452 |
| |
| $481,994 |
| |
| $430,010 |
| |
| $961,456 |
|
| Net income | — |
| | — |
| | 57,881 |
| | 57,881 |
| — |
| | — |
| | 107,538 |
| | 107,538 |
|
| Common stock dividends | — |
| | — |
| | (25,000 | ) | | (25,000 | ) | |
| Balance at December 31, 2013 |
| $49,452 |
| |
| $481,994 |
| |
| $355,581 |
| |
| $887,027 |
| |
| Balance at December 31, 2016 | |
| $49,452 |
| |
| $481,994 |
| |
| $537,548 |
| |
| $1,068,994 |
|
| Net income | — |
| | — |
| | 74,804 |
| | 74,804 |
| — |
| | — |
| | 76,173 |
| | 76,173 |
|
| Common stock dividends | — |
| | — |
| | (70,000 | ) | | (70,000 | ) | |
| Balance at December 31, 2014 |
| $49,452 |
| |
| $481,994 |
| |
| $360,385 |
| |
| $891,831 |
| |
| Capital contributions from parent | | — |
| | 115,000 |
| | — |
| | 115,000 |
|
| Balance at December 31, 2017 | |
| $49,452 |
| |
| $596,994 |
| |
| $613,721 |
| |
| $1,260,167 |
|
| | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | See Notes to Financial Statements. | | |
| | |
| | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | ENTERGY TEXAS, INC. AND SUBSIDIARIES | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | | | | | | | | | | | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 | | 2011 | | 2010 | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (In Thousands) | (In Thousands) |
| | | | | | | | | | | | | | | | | | | |
| Operating revenues |
| $1,851,982 |
| |
| $1,728,799 |
| |
| $1,581,496 |
| |
| $1,757,199 |
| |
| $1,690,431 |
|
| $1,544,893 |
| |
| $1,615,619 |
| |
| $1,707,203 |
| |
| $1,851,982 |
| |
| $1,728,799 |
|
| Net Income |
| $74,804 |
| |
| $57,881 |
| |
| $41,971 |
| |
| $80,845 |
| |
| $66,200 |
| |
| Net income | |
| $76,173 |
| |
| $107,538 |
| |
| $69,625 |
| |
| $74,804 |
| |
| $57,881 |
|
| Total assets |
| $3,908,085 |
| |
| $3,921,860 |
| |
| $4,025,781 |
| |
| $4,059,006 |
| |
| $3,783,864 |
|
| $4,279,738 |
| |
| $4,033,081 |
| |
| $3,898,582 |
| |
| $3,897,989 |
| |
| $3,909,470 |
|
| Long-term obligations (a) |
| $1,278,931 |
| |
| $1,556,939 |
| |
| $1,617,813 |
| |
| $1,677,127 |
| |
| $1,659,230 |
|
| $1,587,150 |
| |
| $1,508,407 |
| |
| $1,451,967 |
| |
| $1,268,835 |
| |
| $1,544,549 |
|
| | | | | | | | | | | | | | | | | | | |
(a) Includes long-term debt (excluding currently maturing debt). | | | | | | | | | | | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 | | 2011 | | 2010 | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (Dollars In Millions) | (Dollars In Millions) |
| | | | | | | | | | | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Residential |
| $654 |
| |
| $596 |
| |
| $553 |
| |
| $638 |
| |
| $559 |
|
| $636 |
| |
| $613 |
| |
| $633 |
| |
| $654 |
| |
| $596 |
|
| Commercial | 384 |
| | 327 |
| | 325 |
| | 369 |
| | 321 |
| 378 |
| | 356 |
| | 369 |
| | 384 |
| | 327 |
|
| Industrial | 422 |
| | 325 |
| | 299 |
| | 352 |
| | 305 |
| 384 |
| | 365 |
| | 372 |
| | 422 |
| | 325 |
|
| Governmental | 26 |
| | 24 |
| | 24 |
| | 26 |
| | 23 |
| 25 |
| | 24 |
| | 25 |
| | 26 |
| | 24 |
|
| Total retail | 1,486 |
| | 1,272 |
| | 1,201 |
| | 1,385 |
| | 1,208 |
| 1,423 |
| | 1,358 |
| | 1,399 |
| | 1,486 |
| | 1,272 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Associated companies | 316 |
| | 369 |
| | 313 |
| | 262 |
| | 373 |
| 58 |
| | 178 |
| | 259 |
| | 316 |
| | 369 |
|
| Non-associated companies | 23 |
| | 47 |
| | 36 |
| | 74 |
| | 76 |
| 22 |
| | 40 |
| | 14 |
| | 23 |
| | 47 |
|
| Other | 27 |
| | 41 |
| | 31 |
| | 36 |
| | 33 |
| 42 |
| | 40 |
| | 35 |
| | 27 |
| | 41 |
|
| Total |
| $1,852 |
| |
| $1,729 |
| |
| $1,581 |
| |
| $1,757 |
| |
| $1,690 |
|
| $1,545 |
| |
| $1,616 |
| |
| $1,707 |
| |
| $1,852 |
| |
| $1,729 |
|
| | | | | | | | | | | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
| | | |
| | |
| | |
| | |
|
| Residential | 5,810 |
| | 5,726 |
| | 5,604 |
| | 6,034 |
| | 5,958 |
| 5,716 |
| | 5,836 |
| | 5,889 |
| | 5,810 |
| | 5,726 |
|
| Commercial | 4,471 |
| | 4,402 |
| | 4,396 |
| | 4,433 |
| | 4,271 |
| 4,548 |
| | 4,570 |
| | 4,548 |
| | 4,471 |
| | 4,402 |
|
| Industrial | 7,140 |
| | 6,404 |
| | 6,066 |
| | 6,102 |
| | 5,642 |
| 7,521 |
| | 7,493 |
| | 7,036 |
| | 7,140 |
| | 6,404 |
|
| Governmental | 277 |
| | 282 |
| | 278 |
| | 294 |
| | 271 |
| 273 |
| | 283 |
| | 276 |
| | 277 |
| | 282 |
|
| Total retail | 17,698 |
| | 16,814 |
| | 16,344 |
| | 16,863 |
| | 16,142 |
| 18,058 |
| | 18,182 |
| | 17,749 |
| | 17,698 |
| | 16,814 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Associated companies | 4,763 |
| | 6,287 |
| | 5,702 |
| | 4,158 |
| | 3,758 |
| 1,534 |
| | 4,625 |
| | 5,853 |
| | 4,763 |
| | 6,287 |
|
| Non-associated companies | 200 |
| | 712 |
| | 827 |
| | 1,258 |
| | 1,300 |
| 729 |
| | 1,086 |
| | 254 |
| | 200 |
| | 712 |
|
| Total | 22,661 |
| | 23,813 |
| | 22,873 |
| | 22,279 |
| | 21,200 |
| 20,321 |
| | 23,893 |
| | 23,856 |
| | 22,661 |
| | 23,813 |
|
SYSTEM ENERGY RESOURCES, INC.
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
System Energy’s principal asset currently consists of an ownership interest and a leasehold interest in Grand Gulf. The capacity and energy from its 90% interest is sold under the Unit Power Sales Agreement to its only four customers, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% interest in Grand Gulf pursuant to the Unit Power Sales Agreement. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenues.
Results of Operations
Net Income
20142017 Compared to 20132016
Net income decreased $18.1 million primarily due to provisions against revenue recorded in 2017 in connection with the complaint against System Energy’s return on equity and a higher effective income tax rate in 2017. See “Federal Regulation - Complaint Against System Energy” below for further discussion of the complaint against System Energy.
2016 Compared to 2015
Net income decreased $17.3$14.6 million primarily due to a higher effective income tax rate and lower operating revenues resulting from lower rate base as compared with the same period in the prior year, partially offset by higher other regulatory credits. System Energy records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The increase in regulatory credits for 2014 compared to 2013 is primarily caused by increases in depreciation and accretion expenses and regulatory credits recorded in 2014 to realign the asset retirement obligation regulatory asset with regulatory treatment.
2013 Compared to 2012
Net income increased $1.8 million primarily due to higher operating income and a lower effective income tax rate, partially offset by lower other income. Operating income was higher because of higher rate base compared to 2012 resulting from capital spending at Grand Gulf, including the uprate project. The lower effective income tax rate was primarily due to the reversal of a portion of the provision for uncertain tax positions. Other income was lower due to AFUDC accrued on the Grand Gulf uprate project in 2012. Grand Gulf’s Spring 2012 refueling outage was completed in June 2012, and the majority of uprate-related capital improvements were completed during this outage.2016.
Income Taxes
The effective income tax rates for 2014, 2013,2017, 2016, and 20122015 were 46.4%47.1%, 37.7%42.3%, and 40.8%32.3%, respectively. The difference in the effective income tax rate of 47.1% for 2017 versus the statutory rate of 35% for 2017 was primarily due to certain book and tax differences related to utility plant items and state income taxes. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses proceedings commenced or other responses by Entergy’s regulators to the Act.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2014, 2013,2017, 2016, and 20122015 were as follows:
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| | (In Thousands) | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $127,142 |
| |
| $83,622 |
| |
| $185,157 |
|
| $245,863 |
| |
| $230,661 |
| |
| $223,179 |
|
| | | | | | | | | | | |
| Net cash provided by (used in): | | | |
| | |
| | | |
| | |
|
| Operating activities | 428,265 |
| | 279,638 |
| | 412,000 |
| 371,278 |
| | 341,939 |
| | 502,536 |
|
| Investing activities | (203,930 | ) | | (96,852 | ) | | (502,637 | ) | (174,250 | ) | | (232,602 | ) | | (137,562 | ) |
| Financing activities | (128,298 | ) | | (139,266 | ) | | (10,898 | ) | (155,704 | ) | | (94,135 | ) | | (357,492 | ) |
| Net increase (decrease) in cash and cash equivalents | 96,037 |
| | 43,520 |
| | (101,535 | ) | |
| Net increase in cash and cash equivalents | | 41,324 |
| | 15,202 |
| | 7,482 |
|
| | | | | | | | | | | |
| Cash and cash equivalents at end of period |
| $223,179 |
| |
| $127,142 |
| |
| $83,622 |
|
| $287,187 |
| |
| $245,863 |
| |
| $230,661 |
|
Operating Activities
Net cash flow provided by operating activities increased $148.6$29.3 million in 20142017 primarily due to:
a decrease in spending of $35.7 million on nuclear refueling outages in 2017 as compared to income tax refundsthe prior year;
the timing of $10.1collection of receivables; and
a decrease of $9.9 million in 2014 compared to income tax payments of $211.2 millioninterest paid in 2013. 2017.
The increase was partially offset by spending on the Grand Gulf refueling outageby:
proceeds of $28.4 million received in 2014 and an increase of $12.9 million in pension contributions in 2014. System Energy made income tax payments in 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2013 resulted primarilyAugust 2016 from the reversal of temporary differences for which System Energy hadDOE resulting from litigation regarding spent nuclear fuel storage costs that were previously claimed a tax deduction.expensed. See “Critical Accounting Estimates”below and Note 118 to the financial statements for a discussion of qualified pensionthe spent nuclear fuel litigation; and other postretirement benefits funding.
Net cash provided by operating activities decreased $132.4a decrease of $21.3 million in 2013 primarily due to income tax payments of $211.2 million in 2013, as discussed above, compared to income tax refunds of $56.8 million in 2012, partially offset by spending on the Grand Gulf refueling outage in 2012.2017. System Energy received income tax refunds in 20122017 and 2016 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement.an intercompany income tax allocation agreement. The income tax refunds of $56.8 million in 20122017 and 2016 resulted primarily from the adoption of a new accounting method for income tax purposes in which System Energy will treat its nuclear decommissioning costs as production costs of electricity includable in cost of goods sold. See Note 3 to the financial statements for further discussion of the adoption of the new accounting method.
Net cash flow provided by operating activities decreased $160.6 million in 2016 primarily due to:
a decrease of previously estimated 2011 taxable$90.5 million in income duetax refunds in 2016. System Energy received income tax refunds in 2016 and 2015 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2016 and 2015 resulted primarily from the adoption of a new accounting method for income tax purposes in which System Energy will treat its nuclear decommissioning costs as production costs of electricity includable in cost of goods sold. See Note 3 to the recognitionfinancial statements for further discussion of additional bonus depreciation.the adoption of the new accounting method; and
an increase in spending of $35.1 million on nuclear refueling outages in 2016 as compared to 2015.
The decrease was partially offset by proceeds of $28.4 million received in August 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Investing Activities
Net cash flow used in investing activities increased $107.1decreased $58.4 million in 20142017 primarily due to a decrease of $159.4 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle. The decrease was partially offset by money pool activity and proceeds of $15.8 million received in August 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Increases in System Energy’s receivable from the money pool are a use of cash flow and System Energy’s receivable from the money pool increased by $77.9 million in 2017 compared to decreasing by $6.1 million in 2016. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Net cash flow used in investing activities increased $95 million in 2016 primarily due to:
fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and
an increase in nuclear construction expenditures primarily as a result of spendinga higher scope of work performed in 2016 on nuclear projects during the Grand Gulf refueling outage projects, partially offset by decreased spending in 2014; and
money pool activity.2016 on compliance with NRC post-Fukushima requirements.
Decreases in System Energy’s receivable from the money pool are a source of cash flow and System Energy’s
receivable from the money pool decreased by $6.9 million in 2014 compared to decreasing by $17.7 million in 2013. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Net cash used in investing activities decreased $405.8 million in 2013 primarily due to a decrease in construction expenditures resulting from spending on the uprate project at Grand Gulf completed during the refueling outage in 2012 and a decrease in nuclear fuel activity primarily due to the Grand Gulf refueling outage in 2012. The decreaseincrease was partially offset by money pool activity.activity and proceeds of $15.8 million received in August 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Decreases in System Energy’s receivable from the money pool are a source of cash flow and System Energy’s receivable from the money pool decreased $17.7by $6.1 million in 20132016 compared to decreasingincreasing by $93.5$37.6 million in 2012.2015.
Financing Activities
Net cash flow used in financing activities decreased $11increased $61.6 million in 20142017 primarily due to:
the redemptionnet repayments of $70short-term borrowings of $49.1 million of 6.29% Series F notes byon the nuclear fuel company variable interest entityentity’s credit facility in September 2013;2017 as compared to net short-term borrowings of $66.9 million on the nuclear fuel variable interest entity’s credit facility in 2016; and
the payment in February 2017, at maturity, of $50 million of the System Energy nuclear fuel company variable interest entity’s 4.02% Series H notes.
The increase was partially offset by:
net long-term borrowings of $50 million in 2017 on the nuclear fuel company variable interest entity’s credit facility;
a decrease of $32.4 million in common stock dividends and distributions in 2017 in order to maintain System Energy’s targeted capital structure; and
the repayment in May 2016 of $22 million of 5.875% pollution control revenue bonds due 2022 issued on behalf of System Energy.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Net cash flow used in financing activities decreased $263.4 million in 2016 primarily due to:
net borrowings of $66.9 million on the nuclear fuel company variable interest entity’s credit facility in 2016 compared to net repayments of $20.4 million on the nuclear fuel company variable interest entity’s credit facility in 20142015;
a decrease of $61.8 million in common stock dividends and distributions as a result of lower operating cash flows and higher nuclear fuel purchases in 2016 as compared to net repaymentsthe prior year;
the redemption in April 2015, at maturity, of $40$60 million on theof System Energy nuclear fuel company variable interest entity’s credit facility5.33% Series G notes; and
redemption in 2013.May 2015 of $35 million and in November 2015 of $25 million of System Energy’s 5.875% Series governmental bonds due 2022.
The decrease was partially offset by the issuancerepayment in May 2016 of $85$22 million of 3.78% Series I notes by the nuclear fuel company variable interest entity in October 2013 and an increase of $31.6 million in common stock dividends paid in 2014.
Net cash used in financing activities increased $128.4 million in 2013 primarily due to:
the issuance of $250 million of 4.10% Series first mortgage bonds in September 2012;
the issuance of $50 million of 4.02% Series H notes by the nuclear fuel company variable interest entity in February 2012; and
the redemption of $70 million of 6.29% Series F notes by the nuclear fuel company variable interest entity in September 2013.
The increase was partially offset by:
the redemption of $152.975 million of5.875% pollution control revenue bonds in 2012;
the redemptiondue 2022 issued on behalf of $70 million of 6.2% Series first mortgage bonds in October 2012;
an increase in borrowings of $40 million on the nuclear fuel company variable interest entity’s credit facility in 2013 compared to the repayment of borrowings of $40 million on the nuclear fuel company variable interest entity’s credit facility in 2012; and
a decrease of $9.4 million in common stock dividends paid in 2013.System Energy.
See Note 5 to the financial statements for details of long-term debt.
Capital Structure
System Energy’s capitalization is balanced between equity and debt, as shown in the following table. The decrease in the debt to capital ratio for System Energy is primarily due to the payment in February 2017, at maturity, of $50 million of the System Energy nuclear fuel company variable interest entity’s 4.02% Series H notes.
| | | | December 31,
2014 | | December 31,
2013 | December 31,
2017 | | December 31,
2016 |
| Debt to capital | 45.7 | % | | 46.4 | % | 44.5 | % | | 45.5 | % |
| Effect of subtracting cash | (8.8 | %) | | (4.6 | %) | (16.0 | %) | | (12.0 | %) |
| Net debt to net capital | 36.9 | % | | 41.8 | % | 28.5 | % | | 33.5 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
capital less cash and cash equivalents. System Energy uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating System Energy’s financial condition. System Energy uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating System Energy’s financial condition because net debt indicates System Energy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
System Energy seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, System Energy may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure.
Uses of Capital
System Energy requires capital resources for:
construction and other capital investments;
debt maturities or retirements;
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
working capital purposes, including the financing of fuel costs; and
dividend, distribution, and interest payments.
Following are the amounts of System Energy’s planned construction and other capital investments.
| | | | 2015 | | 2016 | | 2017 | 2018 | | 2019 | | 2020 |
| | (In Millions) | (In Millions) |
| Planned construction and capital investment: | | | | | | | | | | |
| Generation |
| $70 |
| |
| $65 |
| |
| $35 |
|
| $180 |
| |
| $130 |
| |
| $150 |
|
| Other | 5 |
| | 5 |
| | 5 |
| |
| Utility Support | | 15 |
| | 15 |
| | 10 |
|
| Total |
| $75 |
| |
| $70 |
| |
| $40 |
|
| $195 |
| |
| $145 |
| |
| $160 |
|
Following are the amounts of System Energy’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | 2015 | | 2016-2017 | | 2018-2019 | | After 2019 | | Total | 2018 | | 2019-2020 | | 2021-2022 | | After 2022 | | Total |
| | (In Millions) | (In Millions) |
| Long-term debt (a) |
| $141 |
| |
| $132 |
| |
| $161 |
| |
| $762 |
| |
| $1,196 |
|
| $124 |
| |
| $121 |
| |
| $199 |
| |
| $493 |
| |
| $937 |
|
| Purchase obligations (b) |
| $5 |
| |
| $28 |
| |
| $30 |
| |
| $53 |
| |
| $116 |
|
| $38 |
| |
| $39 |
| |
| $34 |
| |
| $— |
| |
| $111 |
|
| |
| (a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
| (b) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For System Energy, it includes nuclear fuel purchase obligations. |
In addition to the contractual obligations given above, System Energy expects to contribute approximately $20.8$13.8 million to its qualified pension plans and approximately $475$16 thousand to its other postretirement health care and life insurance plans in 2015,2018, although the 2018 required pension contributions will not be known with more certainty untilwhen the January 1, 20152018 valuations are completed, which is expected by April 1, 2015.2018. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, System Energy has $95.1$433 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine spending to maintain operations, the planned capital investment estimate includes specific Grand Gulf investments and initiatives such as NRC post-Fukushima requirements and plant improvements.initiatives.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly. Currently, all of System Energy’s retained earnings are available for distribution.
Sources of Capital
System Energy’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt issuances; and
bank financing under new or existing facilities.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
System Energy may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common stock issuances by System Energy require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. System Energy has sufficient capacity under these tests to meet its foreseeable capital needs.
System Energy’s receivables from the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2014 | | 2013 | | 2012 | | 2011 |
| (In Thousands) |
| $2,373 | | $9,223 | | $26,915 | | $120,424 |
|
| | | | | | |
| 2017 | | 2016 | | 2015 | | 2014 |
| (In Thousands) |
| $111,667 | | $33,809 | | $39,926 | | $2,373 |
See Note 4 to the financial statements for a description of the money pool.
The System Energy nuclear fuel company variable interest entity has a credit facility in the amount of $125$120 million scheduled to expire in June 2016.May 2019. As of December 31, 2014, $20.42017, $17.8 million wasin letters of credit to support a like amount of commercial paper issued and $50 million in loans were outstanding onunder the System Energy nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facilities.facility.
System Energy obtained authorizations from the FERC through October 20152019 for the following:
short-term borrowings not to exceed an aggregate amount of $200 million at any time outstanding;
long-term borrowings and security issuances; and
long-term borrowings by its nuclear fuel company variable interest entity.
See Note 4 to the financial statements for further discussion of System Energy’s short-term borrowing limits.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Complaint Against System Energy
In January 2017 the APSC and MPSC filed a complaint with the FERC against System Energy. The complaint seeks a reduction in the return on equity component of the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Entergy Arkansas also sells some of its Grand Gulf capacity and energy to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under separate agreements. The current return on equity under the Unit Power Sales Agreement is 10.94%. The complaint alleges that the return on equity is unjust and unreasonable because current capital market and other considerations indicate that it is excessive. The complaint requests the FERC to institute proceedings to investigate the return on equity and establish a lower return on equity, and also requests that the FERC establish January 23, 2017 as a refund effective date. The complaint includes return on equity analysis that purports to establish that the range of reasonable return on equity for System Energy is between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputes that a return on equity of 8.37% to 8.67% is just and reasonable. The LPSC and the City Council intervened in the proceeding expressing support for the complaint. System Energy is recording a provision against revenue for the potential outcome of this proceeding. In September 2017 the FERC established a refund effective date of January 23, 2017, consolidated the return on equity complaint with the proceeding described in Unit Power Sales Agreement below, and directed the parties to engage in settlement
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
proceedings before an ALJ. If the parties fail to come to an agreement during settlement proceedings, a prehearing conference will be held to establish a procedural schedule for hearing proceedings.
Unit Power Sales Agreement
In August 2017, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The filing proposes limited amendments to the Unit Power Sales Agreement to adopt (1) updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses and (2) updated nuclear decommissioning cost annual revenue requirements, both of which are recovered through the Unit Power Sales Agreement rate formula. The proposed amendments would result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The proposed changes are based on updated depreciation and nuclear decommissioning studies that take into account the renewal of Grand Gulf’s operating license for a term through November 1, 2044. System Energy requested that the FERC accept the amendments effective October 1, 2017.
In September 2017 the FERC accepted System Energy’s proposed Unit Power Sales Agreement amendments, subject to further proceedings to consider the justness and reasonableness of the amendments. Because the amendments propose a rate decrease, the FERC also initiated an investigation under Section 206 of the Federal Power Act to determine if the rate decrease should be lower than proposed. The FERC accepted the proposed amendments effective October 1, 2017, subject to refund pending the outcome of the further settlement and/or hearing proceedings, and established a refund effective date of October 11, 2017 with respect to the rate decrease. The FERC also consolidated the Unit Power Sales Agreement amendment proceeding with the proceeding described in Complaint Against System Energy above, and directed the parties to engage in settlement proceedings before an ALJ. If the parties fail to come to an agreement during settlement proceedings, a prehearing conference will be held to establish a procedural schedule for hearing proceedings.
Nuclear Matters
System Energy owns and, through an affiliate, operates Grand Gulf. System Energy is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks fromrelated to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, to position Entergy’s nuclear fleet to meet its operational goals, including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems and the Fukushima event; regulatory requirementrequirements and potential future regulatory changes, including changes resulting from events at other plants,affecting the regulations governing nuclear plant ownership, operations, license renewal and amendments, and decommissioning; the performance and capacity factors of these nuclear plants; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts and types of insurance commercially available for losses in connection with nuclear plant operations and technological and financial uncertainties related to decommissioningcatastrophic events such as a nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts.accident. In the event of an unanticipated early shutdown of Grand Gulf, System Energy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. In December 2016, the NRC granted the extension of Grand Gulf’s operating license is currently due to expire2044.
Grand Gulf Outage and NRC review
Grand Gulf began a maintenance outage on September 8, 2016 to replace a residual heat removal pump. Although the pump had been replaced, on September 27, 2016 management decided to keep the plant in Novemberan outage for additional training and other steps to support management’s operational goals. Grand Gulf returned to service on January 31, 2017.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
2024. In October 2011, System Energy filed an application withBased on the plant’s performance indicators, in November 2016 the NRC for an extensionplaced Grand Gulf in the “regulatory response column,” or Column 2, of its Reactor Oversight Process Action Matrix. Entergy is implementing a plan to restore Grand Gulf’s operating licenseGulf to 2044, which application is pending.
In June 2012Column 1, including addressing the U.S. Court of Appeals forissues related to the D.C. Circuit vacatedthree very low safety significance non-cited violations identified in the NRC’s 2010 update toreport on the results of its Waste Confidence Decision, which had found genericallyOctober 2016 special inspection. Depending on the success of implementing that a permanent geologic repository to store spent nuclear fuel would be available when necessaryplan and that spent nuclear fuel could be stored at nuclear reactor sites in the interim without significant environmental effects, and remanded the case for further proceedings. The court concludedplant’s performance indicators, there is risk that the NRC had not satisfiedcould move Grand Gulf into the requirements“degraded cornerstone column,” or Column 3, of the National Environmental Policy Act (NEPA) when it considered environmental effects in reaching these conclusions. The Waste Confidence Decision has been relied upon by NRC license renewal applicants to address some of the issues that the NEPA requires the NRC to address before it issues a renewed license. Certain nuclear opponents filed requests with the NRC asking it to address the issues raised by the court’s decision in the license renewal proceedings for a number of nuclear plants including Grand Gulf. In August 2012 the NRC issued an order stating that it will not issue final licenses dependent upon the Waste Confidence Decision until the D.C. Circuit’s remand is addressed, but also stating that licensing reviews and proceedings should continue to move forward. In September 2014 the NRC published a new final Waste Confidence rule, named Continued Storage of Spent Nuclear Fuel, that for licensing purposes adopts non-site specific findings concerning the environmental impacts of the continued storage of spent nuclear fuel at reactor sites - for 60 years, 100 years and indefinitely - after the reactor’s licensed period of operations. The NRC also issued an order lifting its suspension of licensing proceedings after the final rule’s effective date in October 2014. After the final rule became effective, New York, Connecticut, and Vermont filed a challenge to the rule in the U.S. Court of Appeals. The final rule remains in effect while that challenge is pending unless the court orders otherwise.
The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system. The issue is applicable to Grand Gulf and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.NRC’s Reactor Oversight Process Action Matrix.
After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators to undertake plant modifications and perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating nuclear plants. The NRC, with input from the industry, is continuing to determine the specific actions required by the orders. System Energy’s estimated capital expenditures for 2015 through 2017 for complying with the NRC orders are included in the planned construction and other capital investments estimates given in “Liquidity and Capital Resources - Uses of Capital” above.
Environmental Risks
System Energy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that System Energy is in substantial compliance with environmental regulations currently applicable to its facilities and operations.operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of System Energy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of System Energy’s financial position or results of operations.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
In the fourthsecond quarter 2014,2017, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $99.9$35.9 million increasereduction in its decommissioning cost liability, along with a corresponding increasereduction in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.
InUtility Regulatory Accounting
See “Utility Regulatory Accounting” in the fourth quarter 2013, “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets and trust fund investments.
System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $102.3 million increase in its decommissioning liability, along with a corresponding increaseResources, Inc.
Management’s Financial Discussion and Analysis
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the related asset retirement cost asset that will be depreciated over the remaining life“Critical Accounting Estimates” section of the unit.Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
System Energy’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | Actuarial Assumption | | Change in Assumption | | Impact on 2014 Qualified Pension Cost | | Impact on 2014 Projected Qualified Benefit Obligation | | Change in Assumption | | Impact on 2018 Qualified Pension Cost | | Impact on 2017 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $858 | | $12,797 | | (0.25%) | | $820 | |
| $11,922 |
|
| Rate of return on plan assets | | (0.25%) | | $489 | | $— | | (0.25%) | | $664 | |
| $— |
|
| Rate of increase in compensation | | 0.25% | | $330 | | $1,934 | | 0.25% | | $329 | |
| $1,473 |
|
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | Actuarial Assumption | | Change in Assumption | | Impact on 2014 Postretirement Benefit Cost | | Impact on 2014 Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2018 Postretirement Benefit Cost | | Impact on 2017 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $191 | | $2,252 | | (0.25%) | | $154 | | $2,042 |
| Health care cost trend | | 0.25% | | $318 | | $2,071 | | 0.25% | | $239 | | $1,704 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension cost for System Energy in 20142017 was $12.2$11.7 million. System Energy anticipates 20152018 qualified pension cost to be $16.6$14.9 million. In 2016, System Energy refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $2.8 million. System Energy contributed $21.2$18.2 million to its pension plans in 20142017 and estimates 20152018 pension contributions to be approximately $20.8will approximate $13.8 million, although the 2018 required pension contributions will not be known with more certainty untilwhen the January 1, 20152018 valuations are completed, which is expected by April 1, 2015.2018.
Total postretirement health care and life insurance benefit costscost for System Energy in 2014 were $5612017 was $692 thousand. System Energy expects 20152018 postretirement health care and life insurance benefit costsincome to approximate $481$490 thousand.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
In 2016, System Energy refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $555 thousand. System Energy contributed $334$570 thousand to its other postretirement plans in 20142017 and expects 2018 contributions to contribute $475 thousand in 2015.
The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $17.7 million in the qualified pension benefit obligation and $3.1 million in the accumulated postretirement obligation. The new mortality assumptions increasedanticipated 2015 qualified pension cost by approximately $2.7 million and other postretirement cost by approximately $0.4 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.approximate $16 thousand.
Federal Healthcare Legislation
See the “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
new accounting pronouncements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and Board of Directors and Shareholder of
System Energy Resources, Inc.
Jackson, Mississippi
Opinion on the Financial Statements
We have audited the accompanying balance sheets of System Energy Resources, Inc. (the “Company”) as of December 31, 20142017 and 2013, and2016, the related income statements, statements of income, cash flows, and statements of changes in common equity (pages 448431 through 452436 and applicable items in pages 6155 through 234)230), for each of the three years in the period ended December 31, 2014. 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on thesethe Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Anmisstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit includesof its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements. An auditOur audits also includes assessingincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of System Energy Resources, Inc. as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 20152018
We have served as the Company’s auditor since 2001.
447
| | SYSTEM ENERGY RESOURCES, INC. | INCOME STATEMENTS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | | | | |
| Electric | |
| $664,364 |
| |
| $735,089 |
| |
| $622,118 |
| |
| $633,458 |
| |
| $548,291 |
| |
| $632,405 |
|
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
| | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 84,658 |
| | 103,358 |
| | 62,918 |
| | 71,700 |
| | 27,416 |
| | 89,598 |
|
| Nuclear refueling outage expenses | | 23,309 |
| | 29,551 |
| | 21,824 |
| | 17,968 |
| | 19,512 |
| | 21,654 |
|
| Other operation and maintenance | | 156,502 |
| | 174,772 |
| | 149,346 |
| | 213,534 |
| | 153,064 |
| | 156,552 |
|
| Decommissioning | | 41,835 |
| | 35,472 |
| | 33,019 |
| | 43,347 |
| | 50,797 |
| | 47,993 |
|
| Taxes other than income taxes | | 25,160 |
| | 25,537 |
| | 19,468 |
| | 26,180 |
| | 25,195 |
| | 27,281 |
|
| Depreciation and amortization | | 142,583 |
| | 176,387 |
| | 154,561 |
| | 137,767 |
| | 136,195 |
| | 143,133 |
|
| Other regulatory credits - net | | (30,799 | ) | | (13,068 | ) | | (10,429 | ) | | (37,831 | ) | | (45,041 | ) | | (39,434 | ) |
| TOTAL | | 443,248 |
| | 532,009 |
| | 430,707 |
| | 472,665 |
| | 367,138 |
| | 446,777 |
|
| | | | | | | | | | | | | |
| OPERATING INCOME | | 221,116 |
| | 203,080 |
| | 191,411 |
| | 160,793 |
| | 181,153 |
| | 185,628 |
|
| | | | | | | | | | | | | |
| OTHER INCOME | | |
| | |
| | |
| | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 5,069 |
| | 7,784 |
| | 26,102 |
| | 6,345 |
| | 7,944 |
| | 8,494 |
|
| Interest and investment income | | 11,037 |
| | 9,844 |
| | 10,134 |
| | 17,538 |
| | 14,793 |
| | 14,437 |
|
| Miscellaneous - net | | (529 | ) | | (804 | ) | | (617 | ) | | (521 | ) | | (556 | ) | | (876 | ) |
| TOTAL | | 15,577 |
| | 16,824 |
| | 35,619 |
| | 23,362 |
| | 22,181 |
| | 22,055 |
|
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest expense | | 58,384 |
| | 38,173 |
| | 45,214 |
| | 37,141 |
| | 37,529 |
| | 45,532 |
|
| Allowance for borrowed funds used during construction | | (1,335 | ) | | (786 | ) | | (7,165 | ) | | (1,551 | ) | | (2,000 | ) | | (2,244 | ) |
| TOTAL | | 57,049 |
| | 37,387 |
| | 38,049 |
| | 35,590 |
| | 35,529 |
| | 43,288 |
|
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 179,644 |
| | 182,517 |
| | 188,981 |
| | 148,565 |
| | 167,805 |
| | 164,395 |
|
| | | | | | | | | | | | | |
| Income taxes | | 83,310 |
| | 68,853 |
| | 77,115 |
| | 69,969 |
| | 71,061 |
| | 53,077 |
|
| | | | | | | | | | | | | |
| NET INCOME | |
| $96,334 |
| |
| $113,664 |
| |
| $111,866 |
| |
| $78,596 |
| |
| $96,744 |
| |
| $111,318 |
|
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
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| | SYSTEM ENERGY RESOURCES, INC. | STATEMENTS OF CASH FLOWS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2014 | | 2013 | | 2012 | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | | | | | | | |
| Net income | |
| $96,334 |
| |
| $113,664 |
| |
| $111,866 |
| |
| $78,596 |
| |
| $96,744 |
| |
| $111,318 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 254,199 |
| | 293,537 |
| | 235,881 |
| | 240,962 |
| | 224,879 |
| | 270,514 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 79,835 |
| | 29,996 |
| | 43,651 |
| | 7,827 |
| | 99,531 |
| | 200,797 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
| | |
| | |
| | |
|
| Receivables | | 37,345 |
| | (29,226 | ) | | (12,557 | ) | | 9,210 |
| | (15,846 | ) | | 5,879 |
|
| Accounts payable | | (6,372 | ) | | 6,685 |
| | (10,511 | ) | | 15,969 |
| | 2,720 |
| | (352 | ) |
| Prepaid taxes and taxes accrued | | 12,146 |
| | (170,356 | ) | | 89,022 |
| | 62,466 |
| | (6,555 | ) | | (32,594 | ) |
| Interest accrued | | 21,371 |
| | (3,794 | ) | | (2,157 | ) | | (660 | ) | | (134 | ) | | (19,013 | ) |
| Other working capital accounts | | (11,688 | ) | | 24,863 |
| | (22,917 | ) | | 12,083 |
| | (15,470 | ) | | 13,576 |
|
| Other regulatory assets | | (64,262 | ) | | 79,345 |
| | (44,004 | ) | | 60,012 |
| | (58,279 | ) | | (4,565 | ) |
| Other regulatory liabilities | | | 331,251 |
| | 33,438 |
| | (33,686 | ) |
| Deferred tax rate change recognized as regulatory liability/asset | | | (325,707 | ) | | — |
| | — |
|
| Pension and other postretirement liabilities | | 49,741 |
| | (63,206 | ) | | 2,898 |
| | 4,024 |
| | 5,586 |
| | (16,888 | ) |
| Other assets and liabilities | | (40,384 | ) | | (1,870 | ) | | 20,828 |
| | (124,755 | ) | | (24,675 | ) | | 7,550 |
|
| Net cash flow provided by operating activities | | 428,265 |
| | 279,638 |
| | 412,000 |
| | 371,278 |
| | 341,939 |
| | 502,536 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Construction expenditures | | (63,774 | ) | | (51,584 | ) | | (450,236 | ) | | (91,705 | ) | | (88,037 | ) | | (70,358 | ) |
| Allowance for equity funds used during construction | | 5,069 |
| | 7,784 |
| | 26,102 |
| | 6,345 |
| | 7,944 |
| | 8,494 |
|
| Nuclear fuel purchases | | (181,209 | ) | | (65,691 | ) | | (194,314 | ) | | (49,728 | ) | | (151,068 | ) | | (64,977 | ) |
| Proceeds from sale of nuclear fuel | | 61,076 |
| | 26,522 |
| | 52,708 |
| |
| Proceeds from the sale of nuclear fuel | | | 69,516 |
| | 11,467 |
| | 57,681 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 392,872 |
| | 215,467 |
| | 349,427 |
| | 565,416 |
| | 499,252 |
| | 390,371 |
|
| Investment in nuclear decommissioning trust funds | | (424,814 | ) | | (247,042 | ) | | (379,833 | ) | | (596,236 | ) | | (534,083 | ) | | (421,220 | ) |
| Change in money pool receivable - net | | 6,850 |
| | 17,692 |
| | 93,509 |
| |
| Changes in money pool receivable - net | | | (77,858 | ) | | 6,117 |
| | (37,553 | ) |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | | — |
| | 15,806 |
| | — |
|
| Net cash flow used in investing activities | | (203,930 | ) | | (96,852 | ) | | (502,637 | ) | | (174,250 | ) | | (232,602 | ) | | (137,562 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | — |
| | 85,000 |
| | 297,908 |
| | 150,100 |
| | — |
| | — |
|
| Retirement of long-term debt | | (46,743 | ) | | (111,479 | ) | | (262,867 | ) | | (150,103 | ) | | (22,002 | ) | | (136,310 | ) |
| Changes in credit borrowings - net | | 20,404 |
| | (39,986 | ) | | 39,986 |
| | (49,063 | ) | | 66,893 |
| | (20,404 | ) |
| Dividends paid: | | |
| | |
| | |
| |
| Common stock | | (101,930 | ) | | (70,286 | ) | | (79,700 | ) | |
| Common stock dividends and distributions | | | (106,610 | ) | | (139,000 | ) | | (200,750 | ) |
| Other | | (29 | ) | | (2,515 | ) | | (6,225 | ) | | (28 | ) | | (26 | ) | | (28 | ) |
| Net cash flow used in financing activities | | (128,298 | ) | | (139,266 | ) | | (10,898 | ) | | (155,704 | ) | | (94,135 | ) | | (357,492 | ) |
| Net increase (decrease) in cash and cash equivalents | | 96,037 |
| | 43,520 |
| | (101,535 | ) | |
| Net increase in cash and cash equivalents | | | 41,324 |
| | 15,202 |
| | 7,482 |
|
| Cash and cash equivalents at beginning of period | | 127,142 |
| | 83,622 |
| | 185,157 |
| | 245,863 |
| | 230,661 |
| | 223,179 |
|
| Cash and cash equivalents at end of period | |
| $223,179 |
| |
| $127,142 |
| |
| $83,622 |
| |
| $287,187 |
| |
| $245,863 |
| |
| $230,661 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
| | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $27,834 |
| |
| $32,178 |
| |
| $34,012 |
| |
| $26,251 |
| |
| $36,152 |
| |
| $47,864 |
|
| Income taxes | |
| ($10,065 | ) | |
| $211,210 |
| |
| ($56,808 | ) | |
| ($2,227 | ) | |
| ($23,565 | ) | |
| ($114,092 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | SYSTEM ENERGY RESOURCES, INC. | BALANCE SHEETS | ASSETS | | | | | | |
| | | December 31, | | December 31, |
| | | 2014 | | 2013 | | 2017 | | 2016 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT ASSETS | | | | | | | | |
| Cash and cash equivalents: | | | | | | | | |
| Cash | |
| $789 |
| |
| $62,561 |
| |
| $78 |
| |
| $786 |
|
| Temporary cash investments | | 222,390 |
| | 64,581 |
| | 287,109 |
| | 245,077 |
|
| Total cash and cash equivalents | | 223,179 |
| | 127,142 |
| | 287,187 |
| | 245,863 |
|
| Accounts receivable: | | |
| | |
| | |
| | |
|
| Associated companies | | 60,907 |
| | 104,419 |
| | 170,149 |
| | 104,390 |
|
| Other | | 5,717 |
| | 6,400 |
| | 6,526 |
| | 3,637 |
|
| Total accounts receivable | | 66,624 |
| | 110,819 |
| | 176,675 |
| | 108,027 |
|
| Materials and supplies - at average cost | | 80,049 |
| | 85,118 |
| | 88,424 |
| | 82,469 |
|
| Deferred nuclear refueling outage costs | | 26,580 |
| | 7,853 |
| | 7,908 |
| | 24,729 |
|
| Prepayments and other | | 2,312 |
| | 1,727 |
| | 2,489 |
| | 20,111 |
|
| TOTAL | | 398,744 |
| | 332,659 |
| | 562,683 |
| | 481,199 |
|
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
| | |
| | |
|
| Decommissioning trust funds | | 679,840 |
| | 603,896 |
| | 905,686 |
| | 780,496 |
|
| TOTAL | | 679,840 |
| | 603,896 |
| | 905,686 |
| | 780,496 |
|
| | | | | | | | | |
| UTILITY PLANT | | |
| | |
| | |
| | |
|
| Electric | | 4,244,902 |
| | 4,124,647 |
| | 4,327,849 |
| | 4,331,668 |
|
| Property under capital lease | | 573,784 |
| | 570,872 |
| | 588,281 |
| | 585,084 |
|
| Construction work in progress | | 50,382 |
| | 29,061 |
| | 69,937 |
| | 43,888 |
|
| Nuclear fuel | | 251,376 |
| | 188,824 |
| | 207,513 |
| | 259,635 |
|
| TOTAL UTILITY PLANT | | 5,120,444 |
| | 4,913,404 |
| | 5,193,580 |
| | 5,220,275 |
|
| Less - accumulated depreciation and amortization | | 2,819,688 |
| | 2,699,263 |
| | 3,175,018 |
| | 3,063,249 |
|
| UTILITY PLANT - NET | | 2,300,756 |
| | 2,214,141 |
| | 2,018,562 |
| | 2,157,026 |
|
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
| | |
| | |
|
| Regulatory assets: | | |
| | |
| | |
| | |
|
| Regulatory asset for income taxes - net | | 105,882 |
| | 115,492 |
| | — |
| | 93,127 |
|
| Other regulatory assets | | 335,613 |
| | 261,740 |
| | 444,327 |
| | 411,212 |
|
| Other | | 9,251 |
| | 15,996 |
| | 7,629 |
| | 4,652 |
|
| TOTAL | | 450,746 |
| | 393,228 |
| | 451,956 |
| | 508,991 |
|
| | | | | | | | | |
| TOTAL ASSETS | |
| $3,830,086 |
| |
| $3,543,924 |
| |
| $3,938,887 |
| |
| $3,927,712 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | SYSTEM ENERGY RESOURCES, INC. | BALANCE SHEETS | LIABILITIES AND EQUITY | | | | | | |
| | | December 31, | | December 31, |
| | | 2014 | | 2013 | | 2017 | | 2016 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing long-term debt | |
| $76,310 |
| |
| $48,653 |
| |
| $85,004 |
| |
| $50,003 |
|
| Short-term borrowings | | 20,404 |
| | — |
| | 17,830 |
| | 66,893 |
|
| Accounts payable: | | |
| | |
| | |
| | |
|
| Associated companies | | 6,252 |
| | 12,778 |
| | 16,878 |
| | 5,843 |
|
| Other | | 33,096 |
| | 31,862 |
| | 62,868 |
| | 50,558 |
|
| Taxes accrued | | 23,267 |
| | 11,121 |
| | 46,584 |
| | — |
|
| Accumulated deferred income taxes | | 14,175 |
| | 2,310 |
| |
| Interest accrued | | 33,196 |
| | 11,825 |
| | 13,389 |
| | 14,049 |
|
| Other | | 2,365 |
| | 2,312 |
| | 2,434 |
| | 2,957 |
|
| TOTAL | | 209,065 |
| | 120,861 |
| | 244,987 |
| | 190,303 |
|
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
| | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 808,171 |
| | 737,973 |
| | 776,420 |
| | 1,112,865 |
|
| Accumulated deferred investment tax credits | | 49,313 |
| | 54,786 |
| | 39,406 |
| | 41,663 |
|
| Regulatory liability for income taxes - net | | | 246,122 |
| | — |
|
| Other regulatory liabilities | | 371,110 |
| | 349,846 |
| | 455,991 |
| | 370,862 |
|
| Decommissioning | | 757,918 |
| | 616,157 |
| | 861,664 |
| | 854,202 |
|
| Pension and other postretirement liabilities | | 129,152 |
| | 79,411 |
| | 121,874 |
| | 117,850 |
|
| Long-term debt | | 634,496 |
| | 708,783 |
| | 466,484 |
| | 501,129 |
|
| Other | | 350 |
| | — |
| | 15,130 |
| | 15 |
|
| TOTAL | | 2,750,510 |
| | 2,546,956 |
| | 2,983,091 |
| | 2,998,586 |
|
| | | | | | | | | |
| Commitments and Contingencies | |
|
| |
|
| |
|
| |
|
|
| | | | | | | | | |
| COMMON EQUITY | | |
| | |
| | |
| | |
|
| Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2014 and 2013 | | 789,350 |
| | 789,350 |
| |
| Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2017 and 2016 | | | 658,350 |
| | 679,350 |
|
| Retained earnings | | 81,161 |
| | 86,757 |
| | 52,459 |
| | 59,473 |
|
| TOTAL | | 870,511 |
| | 876,107 |
| | 710,809 |
| | 738,823 |
|
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $3,830,086 |
| |
| $3,543,924 |
| |
| $3,938,887 |
| |
| $3,927,712 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | SYSTEM ENERGY RESOURCES, INC. | STATEMENTS OF CHANGES IN COMMON EQUITY | | For the Years Ended December 31, 2014, 2013, and 2012 | |
| For the Years Ended December 31, 2017, 2016, and 2015 | | For the Years Ended December 31, 2017, 2016, and 2015 |
| | | | | | | |
| | Common Equity | | | Common Equity | | |
| | Common Stock | | Retained Earnings | | Total | Common Stock | | Retained Earnings | | Total |
| | (In Thousands) | (In Thousands) |
| | | | | | | | | | | |
| Balance at December 31, 2011 |
| $789,350 |
| |
| $11,213 |
| |
| $800,563 |
| |
| Balance at December 31, 2014 | |
| $789,350 |
| |
| $81,161 |
| |
| $870,511 |
|
| Net income | — |
| | 111,866 |
| | 111,866 |
| — |
| | 111,318 |
| | 111,318 |
|
| Common stock dividends | — |
| | (79,700 | ) | | (79,700 | ) | |
| Balance at December 31, 2012 |
| $789,350 |
| |
| $43,379 |
| |
| $832,729 |
| |
| Common stock dividends and distributions | | (70,000 | ) | | (130,750 | ) | | (200,750 | ) |
| Balance at December 31, 2015 | |
| $719,350 |
| |
| $61,729 |
| |
| $781,079 |
|
| Net income | — |
| | 113,664 |
| | 113,664 |
| — |
| | 96,744 |
| | 96,744 |
|
| Common stock dividends | — |
| | (70,286 | ) | | (70,286 | ) | |
| Balance at December 31, 2013 |
| $789,350 |
| |
| $86,757 |
| |
| $876,107 |
| |
| Common stock dividends and distributions | | (40,000 | ) | | (99,000 | ) | | (139,000 | ) |
| Balance at December 31, 2016 | |
| $679,350 |
| |
| $59,473 |
| |
| $738,823 |
|
| Net income | — |
| | 96,334 |
| | 96,334 |
| — |
| | 78,596 |
| | 78,596 |
|
| Common stock dividends | — |
| | (101,930 | ) | | (101,930 | ) | |
| Balance at December 31, 2014 |
| $789,350 |
| |
| $81,161 |
| |
| $870,511 |
| |
| Common stock dividends and distributions | | (21,000 | ) | | (85,610 | ) | | (106,610 | ) |
| Balance at December 31, 2017 | |
| $658,350 |
| |
| $52,459 |
| |
| $710,809 |
|
| | | | | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| |
| | |
| | |
|
| | SYSTEM ENERGY RESOURCES, INC. | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | | | | | | | | | | | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 | | 2011 | | 2010 | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (Dollars In Thousands) | (Dollars In Thousands) |
| | | | | | | | | | | | | | | | | | | |
| Operating revenues |
| $664,364 |
| |
| $735,089 |
| |
| $622,118 |
| |
| $563,411 |
| |
| $558,584 |
|
| $633,458 |
| |
| $548,291 |
| |
| $632,405 |
| |
| $664,364 |
| |
| $735,089 |
|
| Net Income |
| $96,334 |
| |
| $113,664 |
| |
| $111,866 |
| |
| $64,197 |
| |
| $82,624 |
| |
| Net income | |
| $78,596 |
| |
| $96,744 |
| |
| $111,318 |
| |
| $96,334 |
| |
| $113,664 |
|
| Total assets |
| $3,830,086 |
| |
| $3,543,924 |
| |
| $3,623,516 |
| |
| $3,245,365 |
| |
| $3,224,070 |
|
| $3,938,887 |
| |
| $3,927,712 |
| |
| $3,728,875 |
| |
| $3,826,193 |
| |
| $3,537,414 |
|
| Long-term obligations (a) |
| $634,496 |
| |
| $708,783 |
| |
| $671,945 |
| |
| $636,885 |
| |
| $796,728 |
|
| $466,484 |
| |
| $501,129 |
| |
| $572,665 |
| |
| $630,603 |
| |
| $702,273 |
|
| Electric energy sales (GWh) | 9,219 |
| | 9,794 |
| | 6,602 |
| | 9,293 |
| | 8,692 |
| 6,675 |
| | 5,384 |
| | 10,547 |
| | 9,219 |
| | 9,794 |
|
| | | | | | | | | | | | | | | | | | | |
(a) Includes long-term debt (excluding currently maturing debt). |
Item 2. Properties
Information regarding the registrant’s properties is included in Part I. Item 1. - Entergy’s Business under the sections titled “Utility - Property and Other Generation Resources” and “Entergy Wholesale Commodities - Property” in this report.
Item 3. Legal Proceedings
Details of the registrant’s material environmental regulation and proceedings and other regulatory proceedings and litigation that are pending or those terminated in the fourth quarter of 20142017 are discussed in Part I. Item 1. - Entergy’s Business under the sections titled “Retail Rate Regulation,”, “Environmental Regulation,”, and “Litigation” and “Impairment of Long-LivedLong-lived Assets” in Note 1 14to the financial statements in this report.statements.
Item 4. Mine Safety Disclosures
Not applicable.
EXECUTIVE OFFICERS OF ENTERGY CORPORATION
Executive Officers
|
| | | | | | |
| Name | | Age | | Position | | Period |
| Leo P. Denault (a) | | 5558 | | Chairman of the Board and Chief Executive Officer of Entergy Corporation | | 2013-Present |
| | | | | Executive Vice President and Chief Financial Officer of Entergy Corporation | | 2004-2013 |
| | | | | Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and System Energy | | 2004-2013 |
| | | | | Director of Entergy Texas | | 2007-2013 |
| | | | | Director of Entergy New Orleans | | 2011-2013 |
| | | | | | | |
William M. MohlA. Christopher Bakken, III (a) | | 5556 | | Executive Vice President and Chief Nuclear Officer of Entergy Wholesale CommoditiesCorporation, Entergy Arkansas, Entergy Louisiana, and System Energy | | 2013-Present2016-Present |
| | | | | President and Chief Executive OfficerProject Director, Hinkley Point C of Entergy Gulf States Louisiana and Entergy LouisianaEDF Energy | | 2010-2013 |
| | | | Director of Entergy Gulf States Louisiana and Entergy Louisiana | | 2010-2013 |
| | | | Vice President, System Planning of Entergy Services, Inc. | | 2007-20102009-2016 |
| | | | | | | |
Theodore H. Bunting, Jr. (a) | | 56 | | Group President Utility Operations of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas | | 2012-Present |
| | | | President, Chief Executive Officer, and Director of System Energy | | 2014-Present |
| | | | Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | | 2012-Present |
| | | | Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2007-2012 |
|
| | | | | | |
Name | | Age | | Position | | Period |
| Marcus V. Brown (a) | | 5356 | | Executive Vice President and General Counsel of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2013-Present |
| | | | | Senior Vice President and General Counsel of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2012-2013 |
| | | | | Vice President and Deputy General Counsel of Entergy Services, Inc. | | 2009-2012 |
| | | | | Associate General Counsel of Entergy Services, Inc. | | 2007-2009 |
|
| | | | | | |
| Name | | Age | | Position | | Period |
| Andrew S. Marsh (a) | | 4346 | | Executive Vice President and Chief Financial Officer of Entergy Corporation | | 2013-Present |
| | | | | Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2013-Present |
| | | | | Chief Financial Officer of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2014-Present |
| | | | | Vice President, System Planning of Entergy Services, Inc. | | 2010-2013 |
| | | | | Vice President, Planning and Financial Communications of Entergy Services, Inc. | | 2007-2010 |
| | | | | | | |
Mark T. SavoffRoderick K. West (a) | | 5849 | | Executive ViceGroup President and Chief Operating OfficerUtility Operations of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas | | 2010-Present2017-Present |
| | | | | President, Chief Executive Officer, and Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and Entergy MississippiSystem Energy | | 2004-Present |
| | | | Director of Entergy Texas | | 2007-Present |
| | | | Director of Entergy New Orleans | | 2011-Present2017-Present |
| | | | | Executive Vice President Operations of Entergy Corporation | | 2004-20102010-2017 |
| | | | | | | |
Roderick K. West (a) | | 46 | | Executive Vice President and Chief Administrative Officer of Entergy Corporation | | 2010-Present2010-2016 |
| | | | | President and Chief Executive Officer of Entergy New Orleans | | 2007-2010 |
| | | | | Director of Entergy New Orleans | | 2005-2011 |
| | | | | | | |
Jeffrey S. ForbesPaul D. Hinnenkamp (a) | | 58 | | Executive Vice President, Nuclear Operations/Chief Nuclear Officer of Entergy Corporation | | 2013-Present |
| | 56 | | Executive Vice President and Chief NuclearOperating Officer of Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy LouisianaCorporation | | 2013-Present |
| | | | Executive Vice President and Chief Nuclear Officer of System Entergy | | 2014-Present2017-Present |
| | | | | Director of System EnergyEntergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | | 2013-Present |
| | | | President and Chief Executive Officer of System Energy | | 2013-2014 |
| | | | Senior Vice President, Nuclear Operations of Entergy Services, Inc. | | 2011-20132015-Present |
| | | | | Senior Vice President and Chief Operating Officer of Entergy Operations,Corporation | | 2015-2017 |
| | | | Senior Vice President, Capital Project Management and Technology of Entergy Services, Inc. | | 2003-2011 |
| 2015 |
| | | | | | |
Name | | Age | | PositionVice President, Capital Project Management and Technology of Entergy Services, Inc. | | Period2013-2015 |
| | | | Vice President of Fossil Generation Development and Support of Entergy Services, Inc. | | 2010-2013 |
| | | | | | |
| Alyson M. Mount (a) | | 4447 | | Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2012-Present |
| | | | | Vice President Corporate Controller of Entergy Services, Inc. | | 2010-2012 |
| | | | | Director, Corporate Reporting and Accounting Policy of Entergy Services, Inc. | | 2002-2010 |
| | | | | | | |
| Andrea Coughlin Rowley (a) | | 52 | | Senior Vice President, Human Resources of Entergy Corporation | | 2016-Present |
| | | | President and Chief Executive Officer of Advance/Evolve LLC | | 2013-2016 |
| | | | Vice President, Human Resources of Dover Corporation | | 2012-2013 |
|
| | | | | | |
| Name | | Age | | Position | | Period |
| Donald W. Vinci (a) | | 5659 | | Executive Vice President and Chief Administrative Officer of Entergy Corporation | | 2016-Present |
| | | | Senior Vice President, Human Resources and Chief Diversity Officer of Entergy Corporation | | 2013-Present2013-2016 |
| | | | | Vice President, Human Capital Management of Entergy Services, Inc. | | 2013 |
| | | | | Vice President, Gas Distribution Business of Entergy Services, Inc. | | 2010-2013 |
| | | | | Vice President, Business Development of Entergy Services, Inc. | | 2008-2010 |
| |
| (a) | In addition, this officer is an executive officer and/or director of various other wholly owned subsidiaries of Entergy Corporation and its operating companies. |
Each officer of Entergy Corporation is elected yearly by the Board of Directors. Each officer’s age and title is provided as of December 31, 2014.2017.
PART II
Item 5. Market for Registrants’ Common Equity and Related Stockholder Matters
Entergy Corporation
The shares of Entergy Corporation’s common stock are listed on the New York Stock and Chicago Stock Exchanges under the ticker symbol ETR.
The high and low prices of Entergy Corporation’s common stock for each quarterly period in 20142017 and 20132016 were as follows:
| | | | 2014 | | 2013 | 2017 | | 2016 |
| | High | | Low | | High | | Low | High | | Low | | High | | Low |
| | (In Dollars) | (In Dollars) |
| First | 67.02 | | 60.40 | | 65.39 | | 61.09 | 77.51 | | 69.63 | | 79.72 | | 65.38 |
| Second | 82.30 | | 66.41 | | 72.10 | | 63.12 | 80.61 | | 74.88 | | 81.36 | | 72.67 |
| Third | 82.48 | | 70.70 | | 72.60 | | 61.66 | 80.49 | | 74.83 | | 82.09 | | 75.99 |
| Fourth | 92.02 | | 76.51 | | 68.63 | | 60.22 | 87.95 | | 75.01 | | 76.56 | | 66.71 |
Consecutive quarterly cash dividends on common stock were paid to stockholders of Entergy Corporation in 20142017 and 2013.2016. Quarterly dividends of $0.83$0.85 per share were paid in 2014through third quarter 2016. In fourth quarter 2016 and 2013.through third quarter 2017, dividends of $0.87 per share were paid. In fourth quarter 2017, dividends of $0.89 per share were paid.
As of January 31, 2015,2018, there were 30,76226,213 stockholders of record of Entergy Corporation.
Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities (1)
|
| | | | | | | | | | | | | | | |
| Period | | Total Number of Shares Purchased | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of a Publicly Announced Plan | | Maximum $ Amount of Shares that May Yet be Purchased Under a Plan (2) |
| | | | | | | | | | |
| 10/01/2014 | -10/31/2014 | | — |
| |
| $— |
| | — |
| |
| $350,052,918 |
|
| 11/01/2014 | -11/30/2014 | | — |
| |
| $— |
| | — |
| |
| $350,052,918 |
|
| 12/01/2014 | -12/31/2014 | | 1,906,300 |
| |
| $86.56 |
| | 1,906,300 |
| |
| $350,052,918 |
|
| Total | | | 1,906,300 |
| |
| $86.56 |
| | 1,906,300 |
| | |
|
| | | | | | | | | | | | | | | |
| Period | | Total Number of Shares Purchased | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of a Publicly Announced Plan | | Maximum $ Amount of Shares that May Yet be Purchased Under a Plan (2) |
| | | | | | | | | |
| 10/01/2017 | -10/31/2017 | | — |
| |
| $— |
| | — |
| |
| $350,052,918 |
|
| 11/01/2017 | -11/30/2017 | | — |
| |
| $— |
| | — |
| |
| $350,052,918 |
|
| 12/01/2017 | -12/31/2017 | | — |
| |
| $— |
| | — |
| |
| $350,052,918 |
|
| Total | | | — |
| |
| $— |
| | — |
| | |
In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options to key employees, which may be exercised to obtain shares of Entergy’s common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans. In addition to this authority, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. The amount of share repurchases under these programs may vary as a result of material changes in business results or capital spending or new investment opportunities. In addition, in the first quarter 2014,2017, Entergy withheld 55,0761,054 shares of its common stock at $61.29$70.58 per share, and 43,246122,148 shares of its common stock at $63.03$70.61 per share, and 31,243 shares of its common stock at $71.89 per share to pay income taxes due upon vesting of restricted stock granted and payout of performance units as part of its long-term incentive program.
| |
| (1) | See Note 12 to the financial statements for additional discussion of the stock-based compensation plans. |
| |
| (2) | Maximum amount of shares that may yet be repurchased relates only to the $500 million plan does not include an estimate of the amount of shares that may be purchased to fund the exercise of grants under the stock-based compensation plans. |
Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
There is no market for the common stockequity of Entergy Corporation’s wholly owned subsidiaries.the Registrant Subsidiaries. Cash dividends and distributions on common stockequity paid by the Registrant Subsidiaries during 20142017 and 2013,2016, were as follows:
| | | | 2014 | | 2013 | 2017 | | 2016 |
| | (In Millions) | (In Millions) |
| Entergy Arkansas |
| $10.0 |
| |
| $15.0 |
|
| $15.0 |
| |
| $— |
|
| Entergy Gulf States Louisiana |
| $166.9 |
| |
| $119.9 |
| |
| Entergy Louisiana |
| $320.6 |
| |
| $356.3 |
|
| $91.3 |
| |
| $285.5 |
|
| Entergy Mississippi |
| $61.4 |
| |
| $7.4 |
|
| $26.0 |
| |
| $24.0 |
|
| Entergy New Orleans |
| $6.0 |
| |
| $— |
|
| $74.3 |
| |
| $18.7 |
|
| Entergy Texas |
| $70.0 |
| |
| $25.0 |
|
| $— |
| |
| $— |
|
| System Energy |
| $101.9 |
| |
| $70.3 |
|
| $106.6 |
| |
| $139.0 |
|
Information with respect to restrictions that limit the ability of the Registrant Subsidiaries to pay dividends or distributions is presented in Note 7 to the financial statements.
Item 6. Selected Financial Data
Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC. AND SUBSIDIARIES, ENTERGY GULF STATES LOUISIANA, L.L.C.,ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC.,LLC AND SUBSIDIARIES, ENTERGY TEXAS, INC. AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC.” which follow each company’s financial statements in this report, for information with respect to selected financial data and certain operating statistics.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC. AND SUBSIDIARIES, ENTERGY GULF STATES, LOUISIANA,L.L.C., ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC.,LLC AND SUBSIDIARIES, ENTERGY TEXAS, INC. AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC.”
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES - Market and Credit Risk Sensitive Instruments.”
Item 8. Financial Statements and Supplementary Data
Refer to “TABLE OF CONTENTS - Entergy Corporation, Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc.,LLC, Entergy Texas, Inc., and System Energy Resources, Inc.”
Item 9. Changes In and Disagreements With Accountants On Accounting and Financial Disclosure
No event that would be described in response to this item has occurred with respect to Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, or System Energy.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
As of December 31, 2014,2017, evaluations were performed under the supervision and with the participation of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (individually “Registrant” and collectively the “Registrants”) management, including their respective Principal Executive Officers (PEO) and Principal Financial Officers (PFO). The evaluations assessed the effectiveness of the Registrants’ disclosure controls and procedures. Based on the evaluations, each PEO and PFO has concluded that, as to the Registrant or Registrants for which they serve as PEO or PFO, the Registrant’s or Registrants’ disclosure controls and procedures are effective to ensure that information required to be disclosed by each Registrant in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms; and that the Registrant’s or Registrants’ disclosure controls and procedures are also effective in reasonably assuring that such information is accumulated and communicated to the Registrant’s or Registrants’ management, including their respective PEOs and PFOs, as appropriate to allow timely decisions regarding required disclosure.
Internal Control over Financial Reporting
(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The managements of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (individually “Registrant” and collectively the “Registrants”) are responsible for establishing and maintaining adequate internal control over financial reporting for the Registrants. Each Registrant’s internal control system is designed to provide reasonable assurance regarding the preparation and fair presentation of each Registrant’s financial statements presented in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Each Registrant’s management assessed the effectiveness of each Registrant’s internal control over financial reporting as of December 31, 2014.2017. In making this assessment, each Registrant’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. The 2013 COSO Framework was utilized for management’s assessment.
Based on each management’s assessment and the criteria set forth by the 2013 COSO Framework, each Registrant’s management believes that each Registrant maintained effective internal control over financial reporting as of December 31, 2014.2017.
The report of Deloitte & Touche LLP, Entergy Corporation’s independent registered public accounting firm, regarding Entergy Corporation’s internal control over financial reporting is included herein on page 529.herein. The report of Deloitte & Touche LLP is not applicable to Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy because these Registrants are non-accelerated filers.
Changes in Internal Controls over Financial Reporting
Under the supervision and with the participation of each Registrant’s management, including its respective PEO and PFO, each Registrant evaluated changes in internal control over financial reporting that occurred during the quarter ended December 31, 20142017 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
Attestation Report of Registered Public Accounting Firm
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors and Shareholders of
Entergy Corporation and Subsidiaries
New Orleans, Louisiana
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2014,2017, based on criteria established in Internal Control -Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Commission (COSO). In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2017 of the Corporation and our report dated February 26, 2018 expressed an unqualified opinion of those consolidated financial statements.
Basis for Opinion
The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Item 9A, Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of theits inherent limitations, of internal control over financial reporting including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be preventedprevent or detected on a timely basis.detect misstatements. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control -Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014 of the Corporation and our report dated February 26, 2015 expressed an unqualified opinion on those consolidated financial statements.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 20152018
PART III
Item 10. Directors and Executive Officers of the Registrants (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Information required by this item concerning directors of Entergy Corporation is set forth under the heading “Item 1 – Election of Directors” contained in the Proxy Statement of Entergy Corporation, to be filed in connection with its Annual Meeting of Stockholders to be held May 8, 2015,4, 2018, and is incorporated herein by reference.
All officers and directors listed below held the specified positions with their respective companies as of the date of filing this report, unless otherwise noted.
|
| | | | | | |
| Name | | Age | | Position | | Period |
| ENTERGY ARKANSAS, INC. |
| | | | | | | |
| Directors | | | | | | |
Hugh T. McDonaldRichard C. Riley | | 5655 | | President and Chief Executive Officer of Entergy Arkansas | | 2000-Present2016-Present |
| | | | | Director of Entergy Arkansas | | 2000-Present2016-Present |
| | | | Group Vice President, Customer Service and Operations of Entergy Arkansas | | 2015-2016 |
| | | | Vice President, Transmission of Entergy Services, Inc. | | 2010-2015 |
| | | | | | | |
Theodore H. Bunting, Jr.Paul D. Hinnenkamp | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Andrew S. Marsh | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
Mark T. SavoffRoderick K. West | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| | | | | | |
| Officers | | | | | | |
| A. Christopher Bakken, III | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Marcus V. Brown | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Leo P. Denault | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Paul D. Hinnenkamp | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Andrew S. Marsh | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Alyson M. Mount | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Richard C. Riley | | | | See information under the Entergy Arkansas Directors Section above. | | |
| Andrea Coughlin Rowley | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Donald W. Vinci | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Roderick K. West | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
|
| | | | | | |
| ENTERGY LOUISIANA, LLC |
| Directors | | | | | | |
| Phillip R. May, Jr. | | 55 | | President and Chief Executive Officer of Entergy Louisiana | | 2013-Present |
| | | | Director of Entergy Louisiana | | 2013-Present |
| | | | Vice President, Regulatory Services of Entergy Services, Inc. | | 2002-2013 |
| | | | | | |
| Paul D. Hinnenkamp | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Andrew S. Marsh | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Roderick K. West | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| | | | | | |
| Officers | | | | | | |
| A. Christopher Bakken, III | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Marcus V. Brown | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Leo P. Denault | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Paul D. Hinnenkamp | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Andrew S. Marsh | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Phillip R. May, Jr. | | | | See information under the Entergy Louisiana Directors Section above. | | |
| Alyson M. Mount | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Andrea Coughlin Rowley | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Donald W. Vinci | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Roderick K. West | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
|
| | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| Directors | | | | | | |
| Haley R. Fisackerly | | 52 | | President and Chief Executive Officer of Entergy Mississippi | | 2008-Present |
| | | | Director of Entergy Mississippi | | 2008-Present |
| | | | | | |
| Paul D. Hinnenkamp | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Andrew S. Marsh | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Roderick K. West | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
|
| | | | | | |
| Officers | | | | | | |
| Marcus V. Brown | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Leo P. Denault | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Haley R. Fisackerly | | | | See information under the Entergy Mississippi Directors Section above. | | |
| Paul D. Hinnenkamp | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Andrew S. Marsh | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Alyson M. Mount | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Andrea Coughlin Rowley | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Donald W. Vinci | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Roderick K. West | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
|
| | | | | | |
| ENTERGY NEW ORLEANS, LLC |
| Directors | | | | | | |
| Charles L. Rice, Jr. | | 53 | | President and Chief Executive Officer of Entergy New Orleans | | 2010-Present |
| | | | Director of Entergy New Orleans | | 2010-Present |
| | | | Director, Utility Strategy of Entergy Services, Inc. | | 2009-2010 |
| | | | Partner, Barrasso, Usdin, Kupperman, Freeman & Sarver, LLC | | 2005-2009 |
| | | | | | |
| Paul D. Hinnenkamp | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Andrew S. Marsh | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Roderick K. West | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
|
| | | | | | |
| Officers | | | | | | |
| Marcus V. Brown | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Leo P. Denault | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Paul D. Hinnenkamp | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Andrew S. Marsh | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Alyson M. Mount | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Charles L. Rice, Jr. | | | | See information under the Entergy New Orleans Directors Section above. | | |
| Andrea Coughlin Rowley | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Donald W. Vinci | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Roderick K. West | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
|
| | | | |
Officers | | | | |
| | | | |
Marcus V. Brown | | See information under the Entergy Corporation Officers Section in Part I. | | |
Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | |
Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | |
Jeffrey S. Forbes | | See information under the Entergy Corporation Officers Section in Part I. | | |
Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | |
Hugh T. McDonald | | See information under the Entergy Arkansas Directors Section above. | | |
Alyson M. Mount | | See information under the Entergy Corporation Officers Section in Part I. | | |
Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | |
Donald W. Vinci | | See information under the Entergy Corporation Officers Section in Part I. | | |
Roderick K. West | | See information under the Entergy Corporation Officers Section in Part I. | | |
|
| | | | |
ENTERGY GULF STATES LOUISIANA, L.L.C. |
Directors | | | | |
Phillip R. May, Jr. | 52 | Director of Entergy Gulf States Louisiana and Entergy Louisiana | | 2013-Present |
| | President and Chief Executive Officer of Entergy Gulf States Louisiana and Entergy Louisiana | | 2013-Present |
| | Vice President, Regulatory Services of Entergy Services, Inc. | | 2002-2013 |
| | | | |
Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | |
Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | |
Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | |
|
| | | | |
Officers | | | | |
| | | | |
Marcus V. Brown | | See information under the Entergy Corporation Officers Section in Part I. | | |
Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | |
Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | |
Jeffrey S. Forbes | | See information under the Entergy Corporation Officers Section in Part I. | | |
Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | |
Phillip R. May, Jr. | | See information under the Entergy Gulf States Louisiana Directors Section above. | | |
Alyson M. Mount | | See information under the Entergy Corporation Officers Section in Part I. | | |
Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | |
Donald W. Vinci | | See information under the Entergy Corporation Officers Section in Part I. | | |
Roderick K. West | | See information under the Entergy Corporation Officers Section in Part I. | | |
|
| | | | |
ENTERGY LOUISIANA, LLC |
Directors | | | | |
| | | | |
Phillip R. May, Jr. | | See information under the Entergy Gulf States Louisiana Directors Section above. | | |
Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | |
Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | |
Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | |
|
| | | | |
Officers | | | | |
| | | | |
Marcus V. Brown | | See information under the Entergy Corporation Officers Section in Part I. | | |
Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | |
Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | |
Jeffrey S. Forbes | | See information under the Entergy Corporation Officers Section in Part I. | | |
Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | |
Phillip R. May, Jr. | | See information under the Entergy Gulf States Louisiana Directors Section above. | | |
Alyson M. Mount | | See information under the Entergy Corporation Officers Section in Part I. | | |
Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | |
Donald W. Vinci | | See information under the Entergy Corporation Officers Section in Part I. | | |
Roderick K. West | | See information under the Entergy Corporation Officers Section in Part I. | | |
|
| | | | |
ENTERGY MISSISSIPPI, INC. |
Directors | | | | |
Haley R. Fisackerly | 49 | President and Chief Executive Officer of Entergy Mississippi | | 2008-Present |
| | Director of Entergy Mississippi | | 2008-Present |
| | | | |
Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | |
Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | |
Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | |
|
| | | | |
Officers | | | | |
| | | | |
Marcus V. Brown | | See information under the Entergy Corporation Officers Section in Part I. | | |
Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | |
Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | |
Haley R. Fisackerly | | See information under the Entergy Mississippi Directors Section above. | | |
Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | |
Alyson M. Mount | | See information under the Entergy Corporation Officers Section in Part I. | | |
Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | |
Donald W. Vinci | | See information under the Entergy Corporation Officers Section in Part I. | | |
Roderick K. West | | See information under the Entergy Corporation Officers Section in Part I. | | |
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| | | | |
ENTERGY NEW ORLEANS, INC. |
Directors | | | | |
Charles L. Rice, Jr. | 50 | President and Chief Executive Officer of Entergy New Orleans | | 2010-Present |
| | Director of Entergy New Orleans | | 2010-Present |
| | Director, Utility Strategy of Entergy Services, Inc. | | 2009-2010 |
| | Partner, Barrasso, Usdin, Kupperman, Freeman & Sarver, L.L.C. | | 2005-2009 |
| | | | |
Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | |
Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | |
Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | |
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| | | | |
Officers | | | | |
| | | | |
Marcus V. Brown | | See information under the Entergy Corporation Officers Section in Part I. | | |
Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | |
Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | |
Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | |
Alyson M. Mount | | See information under the Entergy Corporation Officers Section in Part I. | | |
Charles L. Rice, Jr. | | See information under the Entergy New Orleans Directors Section above. | | |
Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | |
Donald W. Vinci | | See information under the Entergy Corporation Officers Section in Part I. | | |
Roderick K. West | | See information under the Entergy Corporation Officers Section in Part I. | | |
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| | | | |
| ENTERGY TEXAS, INC. |
| Directors | | | | | | |
| Sallie T. Rainer | 53 | Director of Entergy Texas | | 2012-Present |
| 56 | | President and Chief Executive Officer of Entergy Texas | | 2012-Present |
| | | | | Director of Entergy Texas | | 2012-Present |
| | | | Vice President, Federal Policy of Entergy Services, Inc. | | 2011-2012 |
| | | | Director, Regulatory Affairs and Energy Settlements of Entergy Services, Inc. | | 2006-2011 |
| | | | | | | |
Theodore H. Bunting, Jr.Paul D. Hinnenkamp | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Andrew S. Marsh | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
Mark T. SavoffRoderick K. West | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
|
| | | | | | |
| Officers | | | | |
| | | | | |
| Marcus V. Brown | | See information under the Entergy Corporation Officers Section in Part I. | | |
Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Leo P. Denault | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Paul D. Hinnenkamp | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Andrew S. Marsh | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Alyson M. Mount | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Sallie T. Rainer | | | | See information under the Entergy Texas Directors Section above. | | |
Mark T. SavoffAndrea Coughlin Rowley | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Donald W. Vinci | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Roderick K. West | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
Each director and officer of the applicable Entergy company is elected yearly to serve by the unanimous consent of the sole common stockholder with the exception of the directors and officers of Entergy Gulf States Louisiana, L.L.C.LLC and Entergy Louisiana,New Orleans, LLC, who are elected yearly to serve by the unanimous consent of the sole common membership owners, EGS Holdings, Inc. andowner, Entergy Louisiana Holdings, respectively.Utility Holding Company, LLC. Entergy Corporation’s directors are elected annually at the annual meeting of shareholders. Entergy Corporation’s officers are elected at the annual organizational meeting of the Board of Directors.
Corporate Governance Guidelines and Committee Charters
Each of the Audit, Corporate Governance, and Personnel Committees of Entergy Corporation’s Board of Directors operates under a written charter. In addition, the full Board has adopted Corporate Governance Guidelines. Each charter and the guidelines are available through Entergy’s website (www.entergy.com) or upon written request.
Audit Committee of the Entergy Corporation Board
The following directors are members of the Audit Committee of Entergy Corporation’s Board of Directors:
Steven V. WilkinsonPatrick J. Condon (Chairman)
Maureen S. Bateman
StuartPhilip L. LevenickFrederickson
Blanche L. Lincoln
Karen A. Puckett
All Audit Committee members are independent. In addition to the general independence requirements, all Audit Committee members must meet the heightened independence standards imposed by the SEC and NYSE. All Audit Committee members possess the level of financial literacy and accounting or related financial management expertise required by the NYSE rules. Steven V. Wilkinson qualifies asThe Board has determined that each of Patrick J. Condon and Philip L. Frederickson is an “audit committee financial expert,”expert” as thatsuch term is defined inby the SEC rules.rules of the SEC.
Code of Ethics
The Board of Directors has adopted a Code of Business Conduct and Ethics for Members of the Board of Directors. The code is available through Entergy’s website (www.entergy.com) or upon written request. The Board has also adopted a Code of Business Conduct and Ethics for Employees that includes Special ProvisionProvisions Relating to Principal Executive Officer and Senior Financial Officers. The Code of Business Conduct and Ethics for Employees is to be read in conjunction with Entergy’s omnibus code of integrity under which Entergy operates called the Code of Entegrity as well as system policies. All employees are requiredexpected to abide by the Codes. Non-bargaining employees are required to acknowledge annually that they understand and abide by the Code of Entegrity. The Code of Business Conduct and Ethics for Employees, including any amendments or any waivers thereto, and the Code of Entegrity are available through Entergy’s website (www.entergy.com) or upon written request.
Source of Nominations to the Board of Directors; Nominating Procedure
The Corporate Governance Committee does not have any single method for identifying director candidates but will consider candidates suggestedidentified by a wide range of sources including director candidates recommendedcurrent directors, management, third-party search firms engaged by the Corporate Governance Committee and Entergy Corporation’s shareholders. Shareholders wishing to recommend a candidate to the Corporate Governance Committee should do so by submitting the recommendation in writing to Entergy Corporation’s Secretary at 639 Loyola Avenue, P.O. Box 61000, New Orleans, LA 70161, and it will be forwarded to the Corporate Governance Committee members for their consideration. Any recommendation should include:
the number of shares of Entergy Corporation stock held by the shareholder;
the name and address of the candidate;
a brief biographical description of the candidate, including his or her occupation for at least the last five years, and a statement of the qualifications of the candidate, taking into account the qualification requirements set forth above;discussed in the Proxy Statement under “Corporate Governance at Entergy - Our Board Structure - Identifying Director Candidates”; and
the candidate’s signed consent to be named in the Proxy Statement and to serve as a director if elected and to be named in the Proxy Statement.elected.
Once the Corporate Governance Committee receives the recommendation, it may request additional information from the candidate about the candidate’s independence, qualifications, and other information that would assist the Corporate Governance Committee in evaluating the candidate, as well as certain information that must be disclosed about the candidate in the Proxy Statement, if nominated. The Corporate Governance Committee will apply the same standards in considering director candidates recommended by shareholders as it applies to other candidates.
Section 16(a) Beneficial Ownership Reporting Compliance
Information called for by this item concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held on May 8, 2015,4, 2018, under the heading “Section 16(a) Beneficial Ownership Reporting Compliance”,Compliance,” which information is incorporated herein by reference.
Item 11. Executive Compensation
ENTERGY CORPORATION
Information concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement under the headings “Compensation Discussion and Analysis,” “Executive Compensation Tables,” “Nominees for the Board of Directors,” and “Non-Employee Director Compensation,” all of which information is incorporated herein by reference.
ENTERGY ARKANSAS, ENTERGY GULF STATES LOUISIANA, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND ENTERGY TEXAS
COMPENSATION DISCUSSION AND ANALYSIS
In this section, the compensation earned by the following Named Executive Officers in 20142017 is discussed. Each officer’s title is provided as of December 31, 2014.2017.
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| |
Name(1) | Title |
| A. Christopher Bakken, III | Executive Vice President and Chief Nuclear Officer |
| Marcus V. Brown | Executive Vice President and General Counsel |
| Leo P. Denault | Chairman of the Board and Chief Executive Officer |
| Haley R. Fisackerly | President and Chief Executive Officer, Entergy Mississippi |
| Andrew S. Marsh | Executive Vice President and Chief Financial Officer Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas |
| Phillip R. May, Jr. | President Entergy Gulf States Louisiana and Chief Executive Officer, Entergy Louisiana |
Hugh T. McDonald | President, Entergy Arkansas |
Alyson M. Mount | Senior Vice President and Chief Accounting Officer Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans and Entergy Texas |
| Sallie T. Rainer | President and Chief Executive Officer, Entergy Texas |
| Charles L. Rice, Jr. | President and Chief Executive Officer, Entergy New Orleans |
Mark T. SavoffRichard C. Riley | Executive Vice President and Chief OperatingExecutive Officer, Entergy Arkansas |
| Roderick K. West | Executive ViceGroup President and Chief Administrative OfficerUtility Operations |
| |
| (1) | Messrs. Bakken, Brown, Denault, Marsh, and West hold the positions referenced above as executive officers |
Mr. Denault, Mr. Marsh, Ms. Mount, Mr. Savoff, and Mr. West serve as executive officers of Entergy Corporation.Corporation and are members of Entergy Corporation’s Office of the Chief Executive. No additional compensation was paid in 20142017 to Mr. Denault, Mr. Marsh, Ms. Mount, Mr. Savoff, or Mr. Westany of these officers for their service as Named Executive Officers of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas (the “Subsidiaries”). Ms. Mount is included in the Executive Compensation section of this Form 10-K because she served as the principal financial officer of the Subsidiaries for a portion of 2014.Utility operating companies.
CD&A Highlights
Executive Compensation Programs and Practices
Entergy Corporation regularly reviews its executive compensation programs to align them with commonly viewed best practices in the market. Following are some highlights of market and to reflect feedback from discussions with investors on executive compensation.
Sound Program Design
Entergy Corporation’s executive compensation practices:programs are designed to:
ThingsPay for performance
Attract, retain, and motivate key executive officers who drive Entergy Corporation DoesCorporation’s success and industry leadership
Provide market compensation payout opportunities
Align with the interests of Entergy Corporation’s long-term shareholders
Reflect best practices in the market
Require a “double trigger” for severance payments or equity acceleration in the event of a change in control
Maintain a “clawback” policy that goes beyond Sarbanes-Oxley requirements
Cap the maximum payout at 200% of target under the Long-Term Performance Unit Program and under the Annual Incentive Plan for members of the Office of the Chief Executive
Require minimum vesting periods for equity based awards
Target the long-term compensation mix to give more weight to performance units than to time-based restricted stock and stock options combined
Settle 100% of long-term performance unit payouts in shares of Entergy stock
Require executives to hold substantially all equity compensation received from Entergy Corporation until stock ownership guidelines are met
Prohibit directors and officers from pledging or entering into hedging or other derivative transactions with respect to their Entergy Corporation shares Compensation Best Practices:
|
| | |
| Changes Since 2017 Annual Meeting | * | To align with compensation best practices, and in response to investor feedback, beginning with the 2018-2020 performance period, added a cumulative utility earnings performance measure to the Long-Term Performance Incentive Program supplementing the relative total shareholder return measure historically used in this program |
| What Entergy Corporation Does | * | Double trigger for severance payments or equity acceleration in the event of a change in control |
| * | Clawback policy that goes beyond Sarbanes-Oxley requirements |
| * | Maximum payout capped at 200% of target under the Long-Term Performance Unit Program and under the Annual Incentive Plan for members of the Office of the Chief Executive |
| * | Minimum vesting periods for equity-based awards |
| * | Long-term compensation mix weighted more toward performance units than service-based equity awards |
| * | All long-term performance units settled in shares of Entergy Corporation common stock |
| * | Rigorous stock ownership requirements |
| * | Executives required to hold substantially all equity compensation received by Entergy Corporation until stock ownership guidelines are met |
| * | Annual Say on Pay vote |
| What Entergy Corporation Doesn’t Do | * | No 280G tax “gross up” payments in the event of a change in control
|
| * | No tax “gross up” payments on any executive perquisites, other than relocation benefits available to all eligible employees, and club dues for some of the Named Executive Officers. |
| * | No option repricing or cash buy-outs for underwater options |
| * | No agreements providing for severance payments to executive officers that exceed 2.99 times annual base salary and annual incentive awards without shareholder approval |
| * | No hedging or pledging of Entergy Corporation common stock |
| * | No unusual or excessive perquisites |
| * | New officers are excluded from participation in the System Executive Retirement Plan |
| * | No grants of supplemental service credit to newly-hired officers under any of Entergy Corporation’s non-qualified retirement plans |
No 280(G) tax “gross up” payments in the event of a change in control
No option repricing or cash buy-outs for underwater options under the equity plans
No agreements providing for severance payments to executive officers that exceed 2.99 times annual base salary and annual incentive awards without shareholder approval
No unusual or excessive perquisites
New officers are excluded from participation in the System Executive Retirement Plan
No grants of supplemental service credit for newly-hired officers under any of Entergy Corporation's non-qualified retirement plans
Corporation’s Pay for Performance Philosophy
Entergy Corporation’s executive compensation programs are based on a philosophy of pay-for-performancepay for performance that is embodied in the design of its annual and long-term incentive plans. In keepingIt believes the executive pay programs described in this section and in the accompanying tables have played a significant role in its ability to drive strong financial and operational results and to attract and retain a highly experienced and successful management team. The Annual Incentive Plan incentivizes and rewards the achievement of financial metrics that are deemed by the Personnel Committee to be consistent with this philosophy approximately 80% of the annual target compensationoverall goals and strategic direction that the Entergy Corporation Board has approved for Entergy Corporation. The long-term incentive programs further align the interests of Entergy Corporation’s Chief Executive Officer is “at risk,”executives and its shareholders by directly tying the value of the equity or performance-based compensation.awards granted to executives under these programs to Entergy Corporation’s stock price performance and total shareholder return. By incentivizing officers to achieve important financial and operational objectives and create long-term shareholder value, these programs play a key role in creating sustainable value for the benefit of all of Entergy Corporation’s stakeholders, including owners, customers, employees, and communities.
2014Incentive Programs and 2017 Incentive Pay Outcomes
PayEntergy Corporation believes that the 2017 incentive pay outcomes for the Named Executive Officers during 2014 demonstrated the application of this pay-for-performanceits pay for performance philosophy.
Annual Incentive Plan Awards
Awards under Entergy Corporation’sthe Executive Annual Incentive Plan, or Annual Incentive Plan, are tied to itsEntergy Corporation’s financial and operational performance through the Entergy Achievement Multiplier (EAM), which is the performance metric used to determine the maximum funding ofavailable for awards under the plan. For 2014, the Entergy Achievement MultiplierThe 2017 EAM was determined based in equal part on Entergy Corporation’s success in achieving its consolidated operational earnings per share and consolidated operational operating cash flow goals.goals set at the beginning of the year. These goals were approved by the Personnel Committee at the beginning of the year based on Entergy Corporation’s financial plan and the Board’s overall goals for Entergy Corporation and were consistent with its published earnings guidance.
2017 Annual Incentive Plan Payout.For 2014,2017, the Personnel Committee, based on thea recommendation of the Finance Committee, determined that management exceeded its consolidated operational earnings per share goal of $5.00$5.05 per share by $0.83 per share and exceeded$2.17, but fell short of its consolidated operational operating cash flow goal of $3.43$3.000 billion by approximately $517$227 million. Based on the targets and ranges previously determinedestablished by the Committee, Entergy Corporation’s outstanding financial performance in 2014 would havethese results resulted in an Entergy Achievement Multipliera calculated EAM of 200% of target. From a qualitative standpoint,129%. This determined the Committee also took into account management’s strong performance executing on Entergy Corporation’s strategies in 2014maximum funding level for the plan and various accomplishments and challenges in 2014. Included in those challenges was a decline in Entergy Corporation’s employee safety performance,the maximum award, as a resultpercentage of whichtarget, that could be received by any of the Committee decidedexecutive officers, subject to exercise its discretion to reducedownward adjustment based on individual performance. After considering individual performance, including the calculated Entergy Achievement Multiplier to 195%. This resulted in payouts under the Annual Incentive Plan torole played by each of the Named Executive Officers, who are members of the Office of the Chief Executive, includingin advancing Entergy Corporation’s strategies and delivering the strong financial results in 2017, the Personnel Committee approved payouts of 129% of target for each of the Named Executive Officers, who are members of the Office of the Chief Executive.
After the EAM was established to determine overall funding for the Annual Incentive Plan, Entergy Corporation’s Chief Executive Officer at 195%allocated incentive award funding to individual business units based on business unit results. Individual awards were determined for the Named Executive Officers who are not members of eachthe Office of the Chief Executive by their immediate supervisor based on the individual officer’s key accountabilities, accomplishments, and performance. This resulted in payouts that ranged from 79% of target award, whichto 204% of target for the Personnel Committee considered to be appropriate in lightNamed Executive Officers who are not members of management’s performance andEntergy Corporation’s Office of the outstanding results achieved in 2014.Chief Executive.
Long-Term Incentives
Long-TermLong term incentives consist of three components to incentivize long-term value creation - performance units, stock options, and restricted stock. Performance Unit Program Payouts
Underunder the Long-Term Performance Unit Program a substantial portion of targeted executive officer pay is tied directly to Entergy Corporation’s relative total shareholder return. Under this program, Entergy Corporation measures performancemeasured over
a three-year period by assessing Entergy’sEntergy Corporation’s total shareholder return in relation to the total shareholder return of the companies included in the Philadelphia Utility Index, with payouts based solely on Entergy Corporation’s performance relative to the other companies in the index. Entergy Corporation measures performanceIndex. Payouts, if any, are based on relative total shareholder return because it encourages the executives to deliver superior shareholder value in relation to Entergy Corporation’s peers and rewards not just stock price appreciation, but also the ability to deliver significant dividends to shareholders, and takes into account market fluctuations in the utility sector.
Entergy Corporation’s total shareholder return performance in relation to its peers and are not subject to adjustment by the Personnel Committee. Beginning with the 2018-2020 performance period, Entergy Corporation will be using a cumulative utility earnings measure, as well as relative total shareholder return to assess performance under the Long-Term Performance Unit Program. Entergy Corporation also uses stock options, which had substantially laggedreward increases in the returnsmarket value of its peer groupcommon stock, and restricted stock, which is an effective retention mechanism.
Long-Term Performance Unit Program Payout. For the three-year performance period ending in 2012, improved significantly in 2013 and, for 2014, was near the top of the Philadelphia Utility Index. As a result, following a review by the Finance Committee and the Personnel Committee of2017, Entergy Corporation’s total shareholder return was in relation to the total shareholder return of the companies in the Philadelphia Utility Index, the Personnel Committee determined that Entergy Corporation’s relative total shareholder return fell within the third quartile, of the Philadelphia Utility Index for the 2012-2014 performance period, resulting in payoutsa payout of 64.64%31% of target. Such payoutstarget for its executive officers. Payouts were made 100% in shares of Entergy Corporation common stock thatwhich are required to be held by the executivesexecutive officers until they satisfy the executive stock ownership guidelines.
What Entergy Corporation Pays and Why
Pay for Performance Philosophy
Entergy Corporation’s executive compensation programs are based on a philosophy of pay-for-performance that is embodied in the design of its annual and long-term incentive plans. Entergy Corporation believes the executive pay programs described in this section and in the accompanying tables have played a material role in its ability to drive strong financial and operational results and to attract and retain a highly experienced and successful management team. The Annual Incentive Plan incentivizes and rewards the achievement of operational financial metrics that are deemed by the Personnel Committee to be consistent with the overall goals and strategic direction that the Board has approved for Entergy Corporation. Entergy Corporation’s long-term incentive programs further align the interests of its executives and its shareholders by directly tying the value of the equity awards granted to executives under these programs to the performance of Entergy Corporation’s stock price and its total shareholder return. By incentivizing officers to achieve important financial and operational objectives and create long-term shareholder value, these programs play a key role in creating sustainable value for the benefit of all of Entergy Corporation's stakeholders, including its owners, customers, employees, and communities.
How Entergy Corporation Sets Target Pay
To develop a competitive compensation program, the Personnel Committee annually reviews compensation data from two sources:
SurveyUse of Competitive Data
The Personnel Committee uses published and private compensation survey data to develop marketplace compensation levels for theEntergy Corporation’s executive officers. The data which are compiled by Pay Governance, LLC, the Committee’s independent compensation consultant, Pay Governance LLC, compare the current compensation opportunities provided to each of the executive officers against the compensation opportunities provided to executives holding similar positions at companies with corporate revenues similar to Entergy Corporation’s. The Committee reviews:
For non-industry specific positions, such as a chief financial officer, the Committee reviews general industry data for total cash compensation (base salary and annual incentive) since the market for talent is broader than the utility sector.
For management positions that are industry-specific, such as Group President, Utility Operations, the Committee reviews data from utility companies for total cash compensation. However,
For all positions, utility market data for long-term incentives, all positions are reviewed relative to utility market data. incentives.
The survey data reviewed by the Committee cover hundreds of companies across a broad range of industries and overapproximately 60 investor-owned utility companies in the utility sector.companies. In evaluating compensation levels against the survey data, the Committee considers only the aggregated survey data. The identities of the companies participating in the compensation survey data are not disclosed to, or considered by, the Committee in its decision-making process and, thus, are not considered material by the Committee.
The Committee uses this survey data to develop compensation opportunities that are designed to deliver total target compensation at approximately the 50th50th percentile of the surveyed companies.companies in the aggregate. The survey data are the primary data used for purposes of assessing target compensation. As a result, Mr. Denault, Entergy Corporation’s Chief Executive Officer, is compensated at a higher level than the other Named Executive Officers, reflecting market practices that compensate chief executive officers at greater potential compensation levels with more pay “at risk” than other named executive officers,Named Executive Officers, due to the greater responsibilities and accountability required of a Chief Executive Officer. In most cases, the Committee considers its objectives to have been met if Entergy Corporation’s Chief Executive Officer and the eight (8)7 other executive officers who constitute what Entergy Corporation refersis referred to as itsthe Office of the Chief Executive each havehas a target compensation opportunity that falls within the range of 85%-115% - 115% of the 50th percentile of the survey data. Promoted officers or officers who are new to their roles may be transitioned into the targeted market range over time. Actual compensation received by an individual officer may be above or below the targeted range based on an individual officer’s skills, performance, experience, and responsibilities, corporateEntergy Corporation performance, and internal pay equity. For 2014, the total target compensation of each of the Named Executive Officers fell within the targeted range except for three officers whose total target compensation fell below the targeted range.
Proxy Analysis
Although the survey data described above are the primary data used in determiningbenchmarking compensation, the Committee reviews data derived from the proxy statements of companies included in the Philadelphia Utility Index as an additional point of comparison. The Personnel Committee identified the Philadelphia Utility Index as the appropriate industry peer group because the companies included in this index, in the aggregate, are comparable to Entergy Corporation in terms of business and scale. The proxy data are used to compare the compensation levels of the Named Executive Officers with the compensation levels of the corresponding top five highest paid executive officers of the companies included in the Philadelphia Utility Index, as reported in their proxy statements, based on pay rank and without regard to roles and responsibilities, except with respect to the Chief Executive Officer and Chief Financial Officer, for whom comparable roles are used.statements. The Personnel Committee uses this analysis to evaluate the overall reasonableness of the Entergy Corporation’s compensation programs. The following companies were included in the Philadelphia Utility Index at the time the proxy data from the 20142016 filings of the Index were compiled:
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| | | | |
| Ÿ | AES Corporation | Ÿ | El Paso InternationalElectric |
| Ÿ | Ameren Corporation | Ÿ | Exelon CorporationEversource Energy |
| Ÿ | American Electric Power Co. Inc. | Ÿ | Exelon Corporation |
| Ÿ | American Water Works | Ÿ | FirstEnergy Corporation |
| Ÿ | CenterPoint Energy Inc. | Ÿ | NextEra Energy |
| Ÿ | Consolidated Edison Inc. | Ÿ | Northeast Utilities |
| Ÿ | Covanta Holding Corporation | Ÿ | PGEPG&E Corporation |
| Ÿ | Dominion Resources Inc. | Ÿ | Public Service Enterprise Group, Inc. |
| Ÿ | DTE Energy Company | Ÿ | Southern Company |
| Ÿ | Duke Energy Corporation | Ÿ | Xcel Energy |
| Ÿ | Edison International | | |
Executive Compensation Elements
The following table summarizes the elements of targettotal direct compensation (TDC) granted or paid to the executive officers under the 2014Entergy Corporation’s 2017 executive compensation program. The program uses a mix of fixed and variable compensation elements and provides alignment with both short- and long-term business goals through annual and long-term incentives. Incentives are designed to drive overall corporate performance, specific business unit strategies, and individual performance using performance and operational measures the Committee believes correlate to shareholder value and align with Entergy Corporation’s strategic vision and operating priorities. The Personnel Committee establishes the performance measures and ranges of performance for the variable compensation elements. An individual’s award is based primarily on corporate performance, market-based compensation levels, and individual performance.
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| | | | |
| Element | Key Characteristics | Why This Element Is Paid | How This Amount Is Determined | 20142017 Decisions |
| Base Salary | Fixed compensation component payable in cash. Reviewed annually and adjusted when appropriate. | Provides a base level of competitive cash compensation for executive talent. | Experience, job scope, market data, individual performance, and internal pay equity. | All of the Named Executive Officers received increases in their base salaries ranging from 2%-5%1.5% to 7.3%. |
| Annual Incentive Awards | Variable compensation component payable in cash based on performance against goals established annually. | Motivate and reward executives for performance on key financial and operational measures during the year. | Target opportunity is determined based on job scope, market data, and internal pay equity. For 2014,2017, awards were determined based on success in meeting consolidated operational earnings per share and consolidated operational operating cash flow targets, subject to downward adjustment at the Personnel Committee’s discretion.discretion for members of the Office of the Chief Executive. | The CEO’sMr. Denault's target annual incentive award for 20142017 was 120%135% of base salary, and target awards were in the range of 40%-70% to 70% of base salary for the other Named Executive Officers.
Strong operational and financial performance and a review of individual performance resulted in awards in the range of 130%-195%an award at 129% of target for eachEntergy Corporation’s Chief Executive Officer, and awards that ranged from 79% to 204% of target for the other Named Executive Officers. |
Long-Term Performance Unit Program | Each performance unit equals one share of Entergy Corporation’s common stock. Performance is measured at the end of a three-year performance period. Each unit also earns the equivalent of the dividends paid during the performance period. Performance units granted under the Long-Term Performance Unit Program along with accrued dividend equivalents are settled in shares of Entergy Corporation common stock. | Focuses executive officers on building long-term shareholder value and increases executive officers’ ownership of Entergy Corporation common stock. | Formulaic. payout based on Entergy Corporation’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index.
Beginning with the 2018-2020 performance period, payouts will be based on a cumulative utility earnings metric, as well as total shareholder return. | Performance unit grants for the 2017-2019 performance period represented approximately 39% of target TDC for Entergy Corporation’s Chief Executive Officer and approximately 21% to 31% of target for the other Named Executive Officers.
Unfavorable relative total shareholder return in 2015 and 2016, partially offset by strong relative total shareholder return in 2017, resulted in performance in the third quartile with a 6.7% TSR for the 2015-2017 performance period, yielding a payout of 31% of target for the Named Executive Officers, after downward adjustment for failure to meet Board expectations as to safety performance.Officers. |
Stock Options | Non-qualified stock options are granted at fair market value, have a ten yearten-year term, and vest over 3 years - 33 1/3% on each anniversary of the grant date.
| Reward executives for absolute value creation and coupled with restricted stock provide competitive compensation, retain executive talent, and increase the executive officers’ ownership in Entergy Corporation’s common stock. | Job scope, market data, individual performance, and Entergy Corporation performance. | Stock options granted in 20142017 represented approximately 12%13% of total target compensationTDC for Entergy Corporation’s Chief Executive Officer and approximately 7%-10% to 10% for the other Named Executive Officers. |
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| | | | |
ElementRestricted Stock Awards | Key Characteristics | Why This Element Is Paid | How This Amount Is Determined | 2014 Decisions |
Restricted Stock Awards | Restricted stock awards vest over 3 years - 33 1/3% on each anniversary of the grant date, have voting rights, and accrue dividends during the vesting period.
| Coupled with stock options, align interests of executives with long-term shareholder value, provide competitive compensation, retain executive talent, and increase the executive officers’ ownership of Entergy Corporation’sCorporation common stock. | Job scope, market data, individual performance, and Entergy Corporation performance.
| Restricted stock granted in 20142017 represented approximately 12%13% of total target compensationTDC for Entergy Corporation’s Chief Executive Officer and approximately 7%-10% - 10% for the other Named Executive Officers.
|
Long-Term Performance Unit Program | Each performance unit equals the value of one share of Entergy Corporation’s common stock. Performance is measured at the end of a three-year performance period. Each unit also earns the equivalent of the dividends paid during the performance period. Performance units granted under the Long-Term Performance Unit Program are settled in shares of Entergy common stock rather than in cash. | Focuses the executive officers on building long-term shareholder value and increases the executive officers’ ownership of Entergy Corporation’s common stock.
| Payout based on Entergy Corporation’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index.
| Performance unit grants for the 2014 to 2016 performance cycle represented approximately 34% of total target compensation for Entergy Corporation’s Chief Executive Officer and approximately 22%-31% for the other Named Executive Officers.
Strong relative total shareholder return for 2014 resulted in third quartile performance for the 2012 to 2014 performance period, yielding a payout of 64.64% of target for the Named Executive Officers.
|
Short-TermFixed Compensation
Base Salary
The Personnel Committee determines the base salaries for all of the Named Executive Officers who are members of the Office of the Chief Executive based on competitive compensation data, performance considerations, and advice provided by the Committee’s independent compensation consultant. For the other Named Executive Officers, their salaries are established by their immediate supervisors using the same criteria. The Committee also considers internal pay equity; however, the Committee has not established any predetermined formula against which the base salary of one Named Executive Officer is measured against another officer or employee.
In 2014,2017, all of the Named Executive Officers received merit increases in their base salaries ranging from 2approximately 1.5% to 5 percent.7.3%. The increases in base salary were made in light of current economic conditions and the projected growth in executive salaries in 2014 based on the market data previously discussed in this CD&A under “What Entergy Corporation Pays and Why - How Entergy Corporation Sets Target Pay,” as well as an internal pay equity comparison.
The following table sets forth the 20132016 and 20142017 base salaries for the Named Executive Officers. Changes in base salaries for 20142017 were effective in April.
April 2017.
| | | Named Executive Officer | | 2013 Base Salary | | 2014 Base Salary | | 2016 Base Salary | | 2017 Base Salary |
| A. Christopher Bakken, III | | | $605,000 | | $620,125 |
| Marcus V. Brown | | | $605,000 | | $630,000 |
| Leo P. Denault | | $1,085,000 | | $1,110,000 | | $1,200,000 | | $1,230,000 |
| Haley R. Fisackerly | | $296,174 | | $302,934 | | $350,000 | | $355,300 |
| Andrew S. Marsh | | $500,000 | | $517,500 | | $559,408 | | $600,000 |
| Phillip R. May, Jr. | | $330,000 | | $338,250 | | $356,650 | | $366,150 |
| Hugh T. McDonald | | $345,220 | | $352,121 | |
| Alyson M. Mount | | $286,700 | | $301,100 | |
| Sallie T. Rainer | | $291,000 | | $298,275 | | $319,475 | | $328,275 |
| Charles L. Rice, Jr. | | $257,144 | | $262,287 | | $280,424 | | $286,424 |
| Mark T. Savoff | | $632,251 | | $644,896 | |
| Richard C. Riley | | | $335,000 | | $344,200 |
| Roderick K. West | | $612,726 | | $628,044 | | $659,120 | | $675,598 |
Variable Compensation
Short-Term Incentive Compensation
Annual Incentive Plan
Entergy Corporation includes performance-based incentives in the Named Executive Officers’ compensation packages because it believes performance-based incentives encourage the Named Executive Officers to pursue objectives consistent with the overall goals and strategic direction that the Board has approved for Entergy Corporation.
Under The EAM is the Annual Incentive Plan, Entergy Corporation uses a performance metric known as the Entergy Achievement Multiplierused to determine the maximum percentage of target annual plan opportunities that will be paid each year to each Named Executive Officer subject to adjustmentwho are members of the Office of the Chief Executive under the Annual Incentive Plan. Once the EAM has been determined, individual awards for the Office of the Chief
Executive members may be adjusted downward, but not upward, from the EAM at the Personnel Committee’s discretion, based on individual performance. For 2014,performance and other factors deemed relevant by the Personnel Committee maintainedCommittee. For 2017, the following target award levelsAnnual Incentive Plan opportunities for each of base salary for the Named Executive Officers:Officers, expressed as a percentage of the officer’s base salary, were:
120%135% for Mr. Denault;
70% for Mr. Marsh,Bakken, Mr. Savoff,Brown, Mr. Marsh, and Mr. West;
60% for Mr. May and Ms. Mount;
50% for Mr. McDonald;May; and
40% for Mr. Fisackerly, Ms. Rainer, Mr. Rice, and Mr. Rice.Riley.
The target opportunities established for these officers were comparable to the target opportunities historically set for these positions and levels of responsibility. TheTarget opportunities for the Named Executive Officers who are members of the Office of the Chief Executive are established by the Personnel Committee, and these Named Executive Officers may earn a maximum payout ranging from 0% to 200% of their target opportunity, calculated as described in the table below. The target awards for the Named Executive Officers (other than the Entergy Corporation Named Executive Officers) were set by their respective supervisors (subject to ultimate approval of Entergy Corporation’s Chief Executive Officer) who allocated a potential incentive pool established by the Personnel Committee among various of their direct and indirect reports.
Target awardsaward opportunities are set based on an executive officer’s position and executive management level within the Entergy organization. Executive management levels at Entergy Corporation range from Level 1 through Level 4. At December 31, 2014,2017, Mr. Denault held a Level 1 position, Messrs. Bakken, Brown, Marsh, Savoff, and West held positions in Level 2, Ms. Mount and Mr. May held a Level 3 positionsposition, and the remaining Named Executive Officers held positions in Level 4. Accordingly, their respective incentive targetsaward opportunities differ from one from another based on their management level and the external market data developed by the Committee’s independent compensation consultant and the other factors noted above.consultant.
Each year the Personnel Committee reviews the performance measures used to determine the Entergy Achievement Multiplier.EAM pool. In December 2013,2016, the Personnel Committee decided to retain for 2014 the performance measures used for determining the 2013 Entergy Achievement Multiplier. These measures wereconsolidated operational earnings per share and consolidated operational operating cash flow, with each measure weighted equally.equally, as the performance measures for determining the EAM pool. The Committee considered a variety of other potential measures, but determined that consolidated operational earnings per share and consolidated operational operating cash flow continued to be the
best metrics to use because, among other things, they are objective measures that Entergy Corporation’s investors consider to be important in evaluating its financial performance and because Entergy Corporation’s goals in that regard are broadly communicated both internally and externally. This provides both discipline and transparency that the Committee believes are important objectives of any well designed incentive compensation plan.
The Personnel Committee also engages in a rigorous process each year to establish the targetstarget achievement levels for each of the Annual Incentive PlanEAM performance measures with a goal of establishing target achievement levels that are consistent with Entergy Corporation’s strategy and business objectives for the upcoming year, as reflected in its financial plan, and sufficient to drive results that represent a high level of achievement, for Entergy Corporation, taking into consideration the applicable business environment and specific challenges facing it. These targets are approved based on a comprehensive review by the full Board of Entergy Corporation’s financial plan, includingconducted in December of the preceding year and updated in January to reflect the most current information concerning changes in commodity market conditions and other key drivers of anticipated changes in performance from the preceding year. The Committee also reviews the effects on plan results of various risks and opportunities that are recognized at the time the plan is set, to assure that targets that are determined based on the plan reflect an appropriate balance of risks and opportunities. The Committee further confirms that the targetsearnings target it approves areis aligned with the earnings guidance that will be communicated to the financial markets, which assuresthus ensuring that the internal targets approvedearnings target set for purposes of Entergy Corporation’s incentive compensation plans areis aligned with the external expectations set and communicated to itsEntergy Corporation’s shareholders.
In December 2013,January 2017, after full Board review of management’s 20142017 financial plan for Entergy Corporation and engaging in the process discussed above, the Committee determined the Annual Incentive Plan targets to be used for purposes of determining annual bonusesAnnual Incentive Plan awards for 2014.2017. In keeping with its past practice, the Committee also determined that for purposes of measuring performance against such targets, the Committee would exclude the effect on as-reportedreported results of activities related to special items that would be excluded in determining operational results, and the effect of any major storms that may occur during the year. This exclusion was viewed by the Committee
as appropriate because although Entergy Corporation includes estimates for storm costs in its financial plan, it does not include estimates for a major storm event, such as a hurricane. The Committee also approved exclusions from reported results, for purposes of calculating achievement levels, for the impact of certain longstanding unresolved litigation relating to the System Agreement among the Utility operating companies, and for the potential effects of changes in tax laws, given the possibility that significant unanticipated changes in tax laws might be enacted during the year that could impact reported results. The Committee believed that each of these adjustments was appropriate because of the significant uncertainty around each such item and management’s inability to influence any of the related outcomes.
In determining the targets to set for 2017, the Committee reviewed anticipated drivers for consolidated operational earnings per share and consolidated operational operating cash flow for 2017 as set forth in Entergy Corporation’s financial plan and as reflected in its published earnings guidance. Under the plan, consolidated operational earnings per share were expected to decline from 2016 results due primarily to the significant impact on 2016 operational results of certain tax benefits and, to a lesser extent, favorable weather, which were not anticipated to recur in 2017. Together, these factors accounted for $2.06 of consolidated operational earnings per share for 2016. Under the plan, consolidated operational operating cash flow was expected to increase slightly in 2017 from 2016 results.
In evaluating the proposed targets, the Committee considered the potential impact on consolidated operational earnings per share and consolidated operational operating cash flow of certain risks and opportunities, including differences in wholesale energy prices and capacity factors at Entergy Wholesale Commodities, utility sales, operations and maintenance costs, interest expense, and certain tax and regulatory risks. This evaluation indicated that there was significantly more downside risk than upside opportunity in the targets and, as a result, that there was a reasonable degree of challenge embedded in the targets.
After adjusting to eliminate the impact of weather and tax benefits, the 2017 plan targets required management to achieve (i) slight growth in utility operational earnings despite higher nuclear and pension costs and the absence of certain favorable items from 2016 and (ii) modest growth in Entergy Wholesale Commodities operational earnings, despite an expectation for further declines in wholesale energy and capacity revenues due in part to the sale of FitzPatrick in the first quarter of 2017. While the resulting earnings target represented a decline from 2016 operational results, the Committee recognized that in addition to the favorable weather and tax items that were not expected to recur in 2017, management would be challenged in 2017 by significantly higher nuclear costs as they executed on its nuclear strategic plan. Thus, the Committee concluded, based on a careful review of the overall plan, that the targets derived from the plan challenged management appropriately to deliver growth in Entergy Corporation’s core business while continuing to manage the significant risks at Entergy Wholesale Commodities and represented an appropriate balancing of Entergy Corporation’s business risks and opportunities for 2017.
The following table shows the resulting Annual Incentive Plan targets established by the Personnel Committee in December 2013,January 2017, and 20142017 results:
Annual Incentive Plan Targets and Results
|
| | | | |
| | Performance Goals(1) | |
| | Minimum | Target | Maximum | 2014 Results |
| Operational Earnings Per Share ($) | $4.50 | $5.00 | $5.50 | $5.83 |
| Operational Operating Cash Flow ($ billion) | $3.02 | $3.43 | $3.84 | $3.947 |
| Payout as % of Target | 25% | 100% | 200% | 195%(2) |
|
| | | | |
| | Performance Goals(1) | |
| | Minimum | Target | Maximum | 2017 Results |
| Consolidated Operational Earnings Per Share | $4.55 | $5.05 | $5.55 | $7.22 |
| Consolidated Operational Operating Cash Flow ($ billion) | $2.600 | $3.000 | $3.400 | $2.773 |
| EAM as % of Target | 25% | 100% | 200% | 129% |
| |
| (1) | Payouts for performance between minimum and target achievement levels and between target and maximum levels are calculated using straight-line interpolation. There is no payout for performance below minimum. |
| |
(2) | Reflects downward adjustment by Personnel Committee, as further described below. |
In January 2015,2018, the Finance and Personnel Committees jointly reviewed Entergy Corporation’s financial results against the performance objectives reflected in the table above. Based onManagement discussed with the Finance Committee’s recommendation,Committees the Personnel Committee determined that managementconsolidated operational earnings per share and consolidated operational operating cash flow results for 2017, including primary factors explaining how those results compared to the 2017 business plan and Annual Incentive Plan targets. Consolidated operational earnings per share exceeded itsthe operational earnings per share goal of $5.00$5.05 per share set at the beginning of the year by $0.83 per share and exceeded$2.17, due in large part to a non-cash restructuring tax benefit, but management fell short of achieving its consolidated operational operating cash flow goal of $3.43$3.000 billion by approximately $517 million.$227 million, leading to a calculated EAM of 129%. Operational results excluded the impact of certain special items that were excluded from as-reported results special items recorded for (i) expenses(GAAP) earnings per share and operating cash flow to determine consolidated operational earnings per share and consolidated operational operating cash flow, including asset impairments and related write-offs at Entergy Wholesale Commodities related to Entergy Corporation’s 2016 decision to close two nuclear generating plants, and certain costs associated with nuclear plant closings, and charges recorded at the shutdown in December 2014end of 2017 relating to the impact of recently enacted federal income tax law changes. Consistent with determinations made by the Personnel Committee when the targets were set, adjustments were made to the reported results to exclude the impact of Hurricane Harvey and the resolution of certain longstanding System Agreement litigation, but these adjustments had only a negligible impact on the calculated EAM.
The Committee reviewed certain sensitivities as part of its review of the Vermont Yankee Nuclear Power Station and the related settlement agreement reached with the State of Vermont in 2014, and (ii) expenses for the implementationcalculation of the Human Capital Management strategic imperativeEAM and noted that Entergy Corporation far exceeded its consolidated operational earnings per share goal in 2014. The exclusion2017, as noted, due in large part to a restructuring tax benefit, partially offset by unfavorable weather at the utility, and that unfavorable weather at the utility also accounted for approximately $128 million of thesethe $227 million shortfall in consolidated operational operating cash flow. Had the EAM been calculated to exclude both the impact of the restructuring tax benefit and unfavorable weather, the calculated EAM would have been 140%. This indicated that the underlying performance of the core business, without regard to the impact of tax items and weather, was significantly stronger than implied by the calculated EAM. However, consistent with the Committee’s decisionplan design, the Personnel Committee did not make any adjustments for these factors to approve the annual incentive plan targetsconsolidated operational earnings per share and consolidated operational operating cash flow results to determine the EAM for 2014 on2017. The Committee also noted that its utility, parent, and other adjusted earnings of $4.57 per share for 2017 were slightly above the basishigh end of the guidance range Entergy Corporation’s operational financial results, because such results formCorporation had provided to investors at the basisbeginning of the year for this extremely important measure of its core utility earnings.
In determining individual executive officer awards under the Annual Incentive Plan, for Entergy Corporation’s financial planChief Executive Officers and guidancethe Named Executive Officers, who are members of the Office of the Chief Executive, the Committee considered individual performance and, in particular, whether there were additional factors beyond those captured by the EAM measures that should be taken into account in determining whether to investors and areexercise negative discretion to reduce awards below the primary basis on which its financial performance is evaluated by investors.
Based on the targets previouslylevels determined by the Committee, Entergy Corporation’s outstanding financial performance in 2014 exceededEAM. In determining the maximum target achievement approved byextent of negative discretion, if any, that it would exercise with respect to each executive officer, the Committee considered the executive’s key accountabilities and would have resulted
in an Entergy Achievement Multiplier of 200%. However, in determining the Entergy Achievement Multiplier, the Committee also took into account management’s strongaccomplishments, and individual performance executing on Entergy Corporation’s strategies in 2014 and various accomplishments and challenges in 2014. Included in those challenges was2017. Based on these considerations, the Committee decided to award a decline inpayout equal to the EAM, or 129% of target, for Entergy Corporation’s employee safety performance from 2013, which included an increase in OSHA recordable accidents from the preceding year and two electrical contact incidents involving critical safety rule violations. The Committee concluded that despite management’s outstanding performance overall and Entergy Corporation’s strong financial performance for the year, this decline in safety performance warranted a downward adjustment in the Entergy Achievement Multiplier to 195%.
Based on the foregoing evaluation of management performanceChief Executive Officer and the recommendation of the Finance Committee, the Personnel Committee certified an Entergy Achievement Multiplier of 195% for 2014 for theother Named Executive Officers who are members of the Office of the Chief Executive.
After the Entergy Achievement MultiplierEAM was established to determine overall funding for the Annual Incentive Plan, Entergy Corporation’s Chief Executive Officer allocated incentive award funding to theindividual business units based on their business unit results (referred to as the “line of business multiplier).results. Individual awards were determined for the remaining Named Executive Officers who are not members of the Office of the Chief Executive by their immediate supervisor based on the lineindividual officer’s key accountabilities, accomplishments, and performance. This resulted in payouts that ranged from 79% of business multiplier as well as individual officer performance taking into account customer, operational, and safety measures.target to 204% of target for the Named Executive Officers who are not members of the Office of the Chief Executive.
The
Based on the foregoing evaluation of management performance, the Personnel Committee approved the following table shows the Annual Incentive Plan payouts to each Named Executive Officer for 2014.
2017:
| | | Named Executive Officer | Base Salary | Target as Percentage of Base Salary | Payout as Percentage of Base Salary | 2014 Annual Incentive Award | Base Salary | Target as Percentage of Base Salary | Payout as Percentage of Target | 2017 Annual Incentive Award |
| A. Christopher Bakken, III | | $620,125 | 70% | 129% | $559,973 |
| Marcus V. Brown | | $630,000 | 70% | 129% | $568,890 |
| Leo P. Denault | $1,110,000 | 120% | 234% | $2,597,400 | $1,230,000 | 135% | 129% | $2,142,045 |
| Haley R. Fisackerly | $302,934 | 40% | 64% | $193,878 | $355,300 | 40% | 119% | $169,123 |
| Andrew S. Marsh | $517,500 | 70% | 137% | $706,388 | $600,000 | 70% | 129% | $541,800 |
| Phillip R. May, Jr. | $338,250 | 60% | 78% | $263,835 | $366,150 | 60% | 137% | $300,000 |
| Hugh T. McDonald | $352,121 | 50% | 65% | $228,879 | |
| Alyson M. Mount | $301,100 | 60% | 108% | $325,188 | |
| Sallie T. Rainer | $298,275 | 40% | 58% | $171,500 | $328,275 | 40% | 119% | $156,259 |
| Charles L. Rice, Jr. | $262,275 | 40% | 64% | $167,864 | $286,424 | 40% | 79% | $91,000 |
| Mark T. Savoff | $644,896 | 70% | 137% | $880,283 | |
| Richard C. Riley | | $344,200 | 40% | 204% | $280,661 |
| Roderick K. West | $628,044 | 70% | 137% | $857,280 | $675,598 | 70% | 129% | $610,065 |
Nuclear Retention Plan
Mr. Bakken participates in the Nuclear Retention Plan, a retention plan for officers and other leaders with expertise in the nuclear industry. The Personnel Committee authorized this plan to attract and retain key management and employee talent in the nuclear power field, a field that requires unique technical and other expertise that is in great demand in the utility industry. The plan provides for bonuses to be paid annually over a three-year employment period with the bonus opportunity dependent on the participant’s management level and continued employment. Each annual payment is equal to an amount ranging from 15% to 30% of the employee’s base salary as of their date of enrollment in the plan. Mr. Bakken’s participation in the plan commenced in May 2016 and in accordance with the terms and conditions of the plan, in May 2017, 2018, and 2019, subject to his continued employment, Mr. Bakken will receive a cash bonus equal to 30% of his base salary as of May 1, 2016. This plan does not allow for accelerated or prorated payout upon termination of any kind. The three-year coverage period and percentage of base salary payable under the plan are consistent with the terms of participation of other senior nuclear officers who participate in this plan. In May 2017, Mr. Bakken received a cash bonus of $181,500 which equaled 30% of his May 1, 2016, base salary of $605,000.
Long-Term Incentive Compensation
Entergy Corporation’s goal for its long-term incentive compensation is to focus the executive officers on building shareholder value and to increase the executive officers’ ownership of Entergy Corporation’s common stock in order to more closely align their interest with those of itsEntergy Corporation’s shareholders. In its long-term incentive compensation program,programs, Entergy Corporation uses a mix of performance units, restricted stock, and stock options. Performance units are used to deliver more than a majority of the total target long-term incentive awards. For periods through the end of 2017, performance units reward the Named Executive Officers on the basis of total shareholder return, which is a measure of stock price appreciation and dividend payments, in relation to the companies in the Philadelphia Utility Index. Beginning with the 2018-2020 performance period, a cumulative utility earnings metric has been added to the Long-Term Performance Unit Program to supplement the relative total shareholder return measure that historically has been used in this program with each measure equally weighted. Restricted stock ties the executive officers’ long-term financial interest to the long-term financial interests of Entergy Corporation’s shareholders. Stock options provide a direct incentive to increase the value of Entergy Corporation’s common stock. In general, Entergy Corporation seeks to allocate the total value of long-term incentive compensation 60% to performance units and 40% to a combination of stock options and restricted stock, equally divided in value, all based on their grant date fair values.the value the compensation model seeks to deliver. Awards for individual Named Executive Officers may vary from this target as a result of individual performance, promotions, and internal pay equity.
All ofThe performance units for the 2015-2017 performance period were awarded under the 2011 Equity Ownership Plan and Long-Term Cash Incentive Plan (the “2011 Equity Ownership Plan”) and the performance units for the
2016-2018 and 2017-2019 performance periods and all of the shares of restricted stock and stock options granted to the Named Executive Officers in 20142017 were awarded under Entergy Corporation’sgranted pursuant to the 2015 Equity Ownership Plan (the “2015 Equity Ownership Plan,” and together with the 2011 Equity Ownership Plan and Long-Term Cash
Incentive Plan (“2011(the “Equity Ownership Plans”). The Equity Ownership Plan”), which requiresPlans require both a change in control and an involuntary job loss or substantial diminution of duties (a “double trigger”) for the acceleration of these awards upon a change in control.
Performance Unit Program
Entergy Corporation issues performance unit awards to the Named Executive Officers under its Long-Term Performance Unit Program. Each performance unit represents the value of one share of Entergy Corporation’sCorporation common stock at the end of the three-year performance period, plus dividends accrued during the performance period. The Personnel Committee approvessets payout opportunities for the program at the outset of each performance period, and the program is structured to reward Named Executive Officers only if performance goals approved by the Personnel Committee are met. The Personnel Committee has no discretion to make awards if minimum performance goals are not achieved.
The performance units granted under the Long-Term Performance Unit Program and accrued dividends on any shares earned during the performance period are settled in shares of Entergy Corporation common stock rather than cash. No shares are issued, including shares attributable to accrued dividends, unless performance goals are achieved. All shares paid out under the Long-Term Performance Unit Program are required to be retained by the officers until applicable executive stock ownership requirements are met.
The Long-Term Performance Unit Program specifies a minimum, target, and maximum achievement level, the achievement of which will determine the number of performance units that may be earned by each participant. Entergy Corporation measures performance by assessing Entergy Corporation’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index.Index, which Entergy Corporation refers to as it peer companies. The Personnel Committee identified the Philadelphia Utility Index as the appropriate industry peer group for this purpose because the companies included in this index, in the aggregate, approximateare comparable to Entergy Corporation in terms of business and scale. The Personnel Committee chose relative total shareholder return as a measure of performance because it reflects Entergy Corporation’s creation of shareholder value relative to other electric utilities over the performance period. It also takes into account dividends paid by the companies in this index and normalizes certain events that affect the industry as a whole. Minimum, target, and maximum performance levels are determined by reference to the ranking of Entergy Corporation’s total shareholder return against the total shareholder return of the companies in the Philadelphia Utility Index. The range of potential payouts under the program is shown below.
|
| | | |
Performance Level | Minimum | Target | Maximum |
Total Shareholder Return | Bottom of Third Quartile | 50th percentile
| Top Quartile |
Payout | 25% of target | 100% of target | 200% of Target |
There is no payout for performance below the 25th percentile. Payouts between minimum and target and between target and maximum are calculated by interpolating between the bottom position of the third quartile and the median or between the median and the bottom position of the top quartile, respectively. For top quartile performance, a maximum payout of 200% of target is earned.Performance Unit Program Grants. At any given time, a participant in the Long-Term Performance Unit Program may be participating in up to three performance periods. Currently,During 2017, eligible participants arewere participating in the 2013-2015, the 2014-2016,2015-2017, 2016-2018, and the 2015-20172017-2019 performance periods.
Performance Unit Program Grants. Subject to achievement of the applicable performance levels as described below, the Personnel Committee established the following target performance unit payout opportunities for each of the 2012-2014, 2013-2015,2015-2017, 2016-2018, and 2014-20162017-2019 performance periods. Each Named Executive Officer received a larger number of performance units in 2013 and 2014 than were granted to officers at their respective levels in the preceding years to reflect the lower stock price at the time of the award as compared to the preceding year and a slight increase in targeted long-term value required to result in awards approximating the 50th percentile of the utility market data.
|
| | | |
| Named Executive Officer | 2012-2014 Target Opportunity | 2013-2015 Target Opportunity | 2014-2016 Target Opportunity |
Leo P. Denault(1) | 19,136 | 37,156 | 40,000 |
| Haley R. Fisackerly | 1,500 | 1,900 | 2,200 |
Andrew S. Marsh(1) | 3,992 | 7,442 | 9,400 |
Phillip R. May, Jr.(1) | 2,075 | 2,969 | 3,100 |
| Hugh T. McDonald | 1,500 | 1,900 | 2,200 |
| Alyson M. Mount | 2,067 | 3,000 | 3,100 |
| Sallie T. Rainer | 1,292 | 1,900 | 2,200 |
| Charles L. Rice, Jr. | 1,500 | 1,900 | 2,200 |
| Mark T. Savoff | 5,400 | 7,600 | 9,400 |
| Roderick K. West | 5,400 | 7,600 | 9,400 |
|
| | | |
| Named Executive Officer | 2015-2017 Target | 2016-2018 Target | 2017-2019 Target |
A. Christopher Bakken, III (1) | 3,639 | 7,289 | 8,300 |
| Marcus V. Brown | 6,550 | 8,200 | 8,300 |
| Leo P. Denault | 33,100 | 41,700 | 48,700 |
| Haley R. Fisackerly | 1,450 | 1,800 | 1,850 |
| Andrew S. Marsh | 6,550 | 8,200 | 8,300 |
| Phillip R. May, Jr. | 2,050 | 2,700 | 3,150 |
| Sallie T. Rainer | 1,450 | 1,800 | 1,850 |
| Charles L. Rice, Jr. | 1,450 | 1,800 | 1,850 |
| Richard C. Riley | 1,450 | 1,800 | 1,850 |
| Roderick K. West | 6,550 | 8,200 | 8,300 |
| |
| (1) | Messrs. Denault, Marsh, and MayAs a new hire in 2016, Mr. Bakken received pro-rated awardstarget award opportunities for the 2012-20142015-2017 and 2013-20152016-2018 performance cycles as a result of their promotions in 2013.periods. |
The range of potential payouts for the 2015-2017, 2016-2018, and 2017-2019 performance periods under the program is shown below.
|
| | | | |
| Performance Level | Zero | Minimum | Target | Maximum |
| Total Shareholder Return | Fourth Quartile | Bottom of Third Quartile | Median percentile | Top Quartile |
| Payout | No Payout | Minimum Payout of 25% of target | 100% of target | 200% of Target |
For all performance periods, there is no payout for performance that falls within the lowest quartile of performance of the peer companies, and for top quartile performance a maximum payout of 200% of target is earned. Payouts between minimum and target and between target and maximum are calculated by interpolating between the performance of the company at the top of the fourth quartile of performance of the peer companies and the median or between the median and the performance of the company at the bottom position of the top quartile of performance of the peer companies, respectively.
Payout for the 2012-20142015-2017 Performance Period. In January 2015,2018, the Committee reviewed the Entergy Corporation’s total shareholder return for the 2012-20142015-2017 performance period in order to determine the payout to participants for the 2012-2014 performance period.participants. The Committee compared Entergy Corporation’s total shareholder return against the total shareholder return of the companies that comprise the Philadelphia Utility Index, with the performance measures and range of potential payouts for the 2012-20142015-2017 performance period similar to the range of payoutsthat discussed above for the 2014-2016 performance period.above. As recommended by the Finance Committee, the Personnel Committee determinedconcluded that Entergy Corporation’s relative total shareholder return for the 2015-2017 performance period fell withinin the bottom of the third quartile, yielding a payout of the Philadelphia Utility Index31% of target for the 2012-2014 performance period, resulting in payouts to the Named Executive Officers of 64.64% of target. Beginning with the 2012-2014 performance period, payouts under the performance unit program are made in shares of Entergy common stock. For the 2012-2014 performance period, the following numbers of shares of Entergy common stock were issued:Officers.
Mr. Denault - 13,777 shares;
Mr. Marsh - 2,874 shares;Mr. Savoff and Mr. West - 3,888 shares;
Mr. May - 1,494 shares;
Ms. Mount - 1,462 shares;
Mr. Fisackerly, Mr. McDonald, and Mr. Rice - 1,080 shares; and
Ms. Rainer - 914 shares. |
| | | | |
| Named Executive Officer | 2015-2017 Target | Number of Shares Issued | Value of Shares Actually Issued(1) | Grant Date Fair Value |
A. Christopher Bakken, III(2) | 3,639 | 1,212 | $95,154 | $360,334 |
| Marcus V. Brown | 6,550 | 2,287 | $179,552 | $648,581 |
| Leo P. Denault | 33,100 | 11,554 | $907,105 | $3,277,562 |
| Haley R. Fisackerly | 1,450 | 506 | $39,726 | $143,579 |
| Andrew S. Marsh | 6,550 | 2,287 | $179,552 | $648,581 |
| Phillip R. May, Jr. | 2,050 | 716 | $56,213 | $202,991 |
| Sallie T. Rainer | 1,450 | 506 | $39,726 | $143,579 |
| Charles L. Rice, Jr. | 1,450 | 506 | $39,726 | $143,579 |
| Richard C. Riley | 1,450 | 506 | $39,726 | $143,579 |
| Roderick K. West | 6,550 | 2,287 | $179,552 | $648,581 |
| |
| (1) | Value determined based on the closing price of Entergy Corporation’s common stock on January 17, 2018 ($78.51), the date the Personnel Committee certified the 2015-2017 performance period results. |
| |
| (2) | As a new hire in 2016, Mr. Bakken received pro-rated target award opportunities for the 2015-2017 performance period. |
Stock Options and Restricted Stock
Entergy Corporation grants stock options and restricted stock as part of thea long-term incentive program to its executive officers. As previously discussed, the Personnel Committee considers several factors in determining the number of stock options and shares of restricted stock it will grant to the Named Executive Officers, including Entergy Corporation and individual performance, internal pay equity, prevailing market practice, targeted long-term value created by the use of stock options and restricted stock, and the potential dilutive effect of stock option and restricted stock grants. TheOf these factors, the Committee’s assessment of individual performance of each Named Executive Officer is the most important factor in determining the number of shares of restricted stock and stock options awarded, except with respect to the Chief Executive Officer for whom comparative market data is the most important factor. Mr. Denault's 2014 awards are comparable to historical awards granted to Entergy Corporation's Chief Executive Officer and reflects the decreased stock price at the time of grant. The Committee, in consultation with Entergy Corporation’s Chief Executive Officer, reviews each of the other Named Executive Officer’s performance, role and responsibilities, strengths, and developmental opportunities. Stock option and restricted stock awards for Entergy Corporation’s Chief Executive Officer are determined solely by the Personnel Committee on the basis of the same considerations. For all equity awards, the Committee also considers Entergy Corporation’s significant achievements for the prior year.
The following table sets forth the number of stock options and shares of restricted stock granted to each Named Executive Officer in 2014.2017. The exercise price for each option was $63.17,$70.53, which was the closing price of Entergy’sEntergy Corporation’s common stock on the date of grant.
| | | Named Executive Officer | Stock Options | Shares of Restricted Stock | Stock Options | Shares of Restricted Stock |
| A. Christopher Bakken, III | | 37,600 | 5,200 |
| Marcus V. Brown | | 44,000 | 6,100 |
| Leo P. Denault | 106,000 | 13,900 | 179,400 | 17,000 |
| Haley R. Fisackerly | 5,800 | 1,400 | 7,600 | 850 |
| Andrew S. Marsh | 35,000 | 4,900 | 44,000 | 6,100 |
| Phillip R. May, Jr. | 8,000 | 1,800 | 10,500 | 1,100 |
| Hugh T. McDonald | 5,500 | 1,300 | |
| Alyson M. Mount | 8,500 | 1,800 | |
| Sallie T. Rainer | 5,800 | 1,400 | 7,800 | 900 |
| Charles L. Rice, Jr. | 5,200 | 1,150 | 3,900 | 550 |
| Mark T. Savoff | 27,500 | 4,200 | |
| Richard C. Riley | | 8,000 | 1,000 |
| Roderick K. West | 36,000 | 6,000 | 29,200 | 3,200 |
Benefits Perquisites, Agreements and Post-Termination Plans
Retirement Plans
The Named Executive Officers participate in an Entergy Corporation-sponsored tax qualified final average pay defined benefit pension plan that covers a broad group of employees. In addition, each Named Executive Officer participates in the Pension Equalization Plan, a non-qualified restoration plan, and the System Executive Retirement Plan, a non-qualified supplemental retirement plan. Both plans are sponsored by Entergy Corporation. Under the terms of the Pension Equalization Plan and System Executive Retirement Plan, an employee participating in both plans is eligible to receive only the greater of the two benefits computed in accordance with the terms of, and conditions of each plan.Perquisites
Effective July 1, 2014, the Pension Equalization Plan was amended to provide that employees who participate in Entergy Corporation’s new cash balance pension plan are not eligible to participate in the Pension Equalization Plan. These employees instead will participate in a new cash balance restoration plan. In addition, the Pension Equalization Plan and all other non-qualified plans sponsored by Entergy Corporation were amended, as necessary, to eliminate the grant of supplemental credited service to new executive officers under any of those plans. The plan amendments were authorized by the Personnel Committee after reviewing comparative market data to better align Entergy Corporation’s retirement plans with emerging market practice. Also to better align with emerging market practice, effective July 1, 2014, the System Executive Retirement Plan and the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries were closed to new participants.
See the 2014 Pension Benefits Table for additional information regarding the operation of the plans described under this caption.
Savings Plan
The Named Executive Officers are eligible to participate in or receive the following benefits:
|
| |
| Plan Type | Description |
| Retirement Plans | Entergy Corporation-sponsored:
Entergy Retirement Plan - a tax-qualified final average pay defined benefit pension plan that covers a broad group of employees hired before July 1, 2014. Cash Balance Plan - a tax-qualified cash balance defined benefit pension plan that covers a broad group of employees hired on or after July 1, 2014. Pension Equalization Plan - a non-qualified pension restoration plan for a select group of management or highly compensated employees who participate in the Entergy Retirement Plan. Cash Balance Equalization Plan - a non-qualified restoration plan for a select group of management or highly compensated employees who participate in the Cash Balance Plan. System Executive Retirement Plan - a non-qualified supplemental retirement plan for individuals who became executive officers before July 1, 2014.
See the 2017 Pension Benefits Table for additional information regarding the operation of the plans described above. |
| Savings Plan | Entergy Corporation-sponsored 401(k) Savings Plan that covers a broad group of employees. |
| Health & Welfare Benefits | Medical, dental, and vision coverage, life and accidental death and dismemberment insurance, business travel accident insurance, and long-term disability insurance.
Eligibility, coverage levels, potential employee contributions, and other plan design features are the same for the Named Executive Officers as for the broad employee population. |
| 2017 Perquisites | Corporate aircraft usage, annual physical exams, relocation assistance, and event tickets. The Office of the Chief Executive members do not receive tax gross ups on any benefits, except for relocation assistance.
Named Executive Officers who are not members of the Office of the Chief Executive also were provided in 2017 with club dues and tax gross up payments on some perquisites.
For additional information regarding perquisites, see the “All Other Compensation” column in the 2017 Summary Compensation Table. |
| Deferred Compensation | The Named Executive Officers are eligible to defer up to 100% of their base salary and Annual Incentive Plan awards into an Entergy Corporation-sponsored Executive Deferred Compensation Plan. |
| Executive Disability Plan | Eligible individuals who become disabled under the terms of the plan are eligible for 65% of the difference between their annual base salary and $276,923 (i.e. the annual base salary that produces the maximum $15,000 monthly disability payment under the general long-term disability plan). |
Entergy Corporation-sponsored Savings Plan that covers a broad group of employees. The Savings Plan is a tax-qualified 401(k) retirement savings plan, wherein total combined before-tax and after-tax contributions may not exceed 30% of a participant’s base salary upCorporation provides these benefits to certain contribution limits defined by law. In addition, under the Savings Plan, the employer of Savings Plan participants, who participate in the final average pay defined benefit pension plan, matches an amount equal to seventy cents for each dollar contributed by participating employees, including theits Named Executive Officers with respect to the first six percentas part of their eligible earnings under the plan for that pay period.
Executive Deferred Compensation Plan
The Named Executive Officers are eligible to defer up to 100% of their Annual Incentive Plan awards into either or both of the Entergy Corporation-sponsored Executive Deferred Compensation Planproviding a competitive executive compensation program and the 2011 Equity Plan. In addition, they are eligible to defer up to 100% of their base salary into the Executive Deferred Compensation Plan. Entergy Corporationbecause it believes that providing this benefit isthese benefits are important as a retention and recruitment tool becausetools since many if not all, of the companies with which it competes for executive talent provide a similar arrangementarrangements to their senior executive officers. See the 2014 Non-qualified Deferred Compensation discussion for additional information regarding the operation of the Executive Deferred Compensation Plan.
Health & Welfare Benefits
The Named Executive Officers are eligible to participate in various health and welfare benefits available to a broad group of employees. These benefits include medical, dental, and vision coverage, life and accidental death and dismemberment insurance, business travel accident insurance, and long-term disability insurance. Eligibility, coverage levels, potential employee contributions, and other plan design features are the same for the Named Executive Officers as for the broad employee population.
Executive Disability Plan
All of the executive officers, including the Named Executive Officers, are eligible to participate in the Executive Disability Plan of Entergy Corporation and Subsidiaries. Individuals who elect to participate in this plan and become disabled under the terms of the plan are eligible for 65% of the difference between their base salary and $276,923 (i.e. the base salary that produces the maximum $15,000 monthly disability payment under the general long-term disability plan).
Perquisites
Entergy Corporation provides the Named Executive Officers with a limited number of perquisites and other personal benefits as part of providing a competitive executive compensation program and for employee retention. The Personnel Committee reviews all perquisites, including the personal use of corporate aircraft, on an annual basis. In 2014, the Named Executive Officers were offered corporate aircraft usage, relocation assistance, annual physical exams, and event tickets. Named Executive Officers who are not members of the Office of Chief Executive were provided in 2014 with club dues and tax gross up payment on some perquisites. For security and business convenience reasons, Entergy Corporation’s Chief Executive Officer is allowed to use corporate aircraft at Entergy Corporation’s expense for personal use. The other Named Executive Officers may use corporate aircraft for personal travel subject to the approval of Entergy Corporation’s Chief Executive Officer. From time to time, tickets to cultural and sporting events are made available to employees, including the Named Executive Officers, for business purposes. If not utilized for business purposes, the tickets are made available to employees, including the Named Executive Officers, for personal use. Entergy Corporation does not provide personal financial counseling. Relocation benefits to executive officers, including tax gross-up payments, are similar to those provided to all eligible employees. For additional information regarding perquisites, see the “All Other Compensation” column in the Summary Compensation Table.
Post-Termination Agreements and other Compensation Arrangements
The Personnel Committee believes that retention and transitional compensation arrangements are an important part of overall compensation. The Committee believes that these arrangements help to secure the continued employment and dedication of the Named Executive Officers, notwithstanding any concern that they might have at the time of a change in control regarding their own continued employment. In addition, the Committee believes that these arrangements are important as recruitment and retention devices, as all or nearly allmany of the companies with which Entergy Corporation competes for executive talent have similar arrangements in place for itstheir senior employees.
To achieve these objectives, Entergy Corporation has established a System Executive Continuity Plan under which each of the Named Executive Officers is entitled to receive “change in control” payments and benefits if such
officer’s employment is involuntarily terminated in connection with a change in control of Entergy Corporation.Corporation and its subsidiaries. Severance payments under the System Executive Continuity Plan generally are based on a multiple of the sum of an executive officer’s annual base salary plus his or her average Annual Incentive Plan award for the two fiscalcalendar years immediately preceding the fiscalcalendar year in which the termination of employment occurs. Under Entergy Corporation’s policy, under no circumstances can this multiple exceed 2.99 times the sum of (a) the executive officer’s annual base salary as in effect at any time within one year prior to the commencement of a change in control period or if higher, immediately prior to a circumstance constituting good reason plus (b)and his or her annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the officer’s termination occurs, or if higher the annual incentive award actually received under the Annual Incentive Plan for the fiscal year immediately preceding the fiscal year in which the termination of employment occurs.accordance with this policy. Entergy Corporation strives to ensure that the benefits and payment levels under the System Executive Continuity Plan are consistent with market practices. ExecutiveEntergy Corporation’s executive officers, including the Named Executive Officers, will not receive any tax gross-upgross up payments on any severance benefits received under this plan. For more information regarding the System Executive Continuity Plan, see “System“2017 Potential Payments Upon Termination or Change in Control-System Executive Continuity Plan."”
In certain cases, the Committee may approve the execution of a retention agreement with an individual executive officer. These decisions are made on a case by case basis to reflect specific retention needs or other factors, including market practice. If a retention agreement is entered into with an individual officer, the Committee considers the economic value associated with that agreement in making overall compensation decisions for that officer. Entergy Corporation has voluntarily adopted a policy that any employment or severance agreements providing severance benefits in excess of 2.99 times the sum of an officer’s annual base salary and annual incentive award (other than the value of the vesting or payment of an outstanding equity-based award or the pro rata vesting or payment of an outstanding long-term incentive award) must be approved by Entergy Corporation’s shareholders.
Entergy Corporation currently has a retention agreement with Mr. Denault. In general, Mr. Denault’s retention agreement provides for severancecertain payments and other benefits in the event of his termination of employment by his Entergy employer other than for cause, by Mr. Denault for good reason or on account of his death or disabilitydisability. See “2017 Potential Payments Upon Termination or Change in lieu of those provided under the System Executive Continuity Plan. As with anyControl - Mr. Denault’s 2006 Retention Agreement.” Because Mr. Denault has reached age 55, certain severance benefits paid under the System Executive Continuity Plan,payment provisions in his retention agreement no longer apply. Mr. Denault will not receive tax gross-upgross up payments on any severancepayments or benefits he may receive under his agreement. Mr. Denault’s retention agreement was entered into in 2006 when he was Entergy Corporation’s Chief Financial Officer and was designed to reflect the competition for chief financial officer talent in the marketplace at that time and the Committee’s assessment of the critical role this position playsplayed in executing Entergy Corporation’s long-term financial and other strategic objectives. Based on the market data provided by its former independent compensation consultant, the Committee, believesat the time the agreement was entered into, believed the benefits and payment levels under Mr. Denault’s retention agreement arewere consistent with market practices.
For additional information regarding the System Executive Continuity Plan and Mr. Denault’s retention agreement described above, see “2014 Potential Payments Upon Termination or Change in Control."
Compensation Policies and Practices
Entergy Corporation strives to ensure that its compensation philosophy and practices are in line with the best practices of companies in the utilityits industry as well as other companies in the S&P 500. Some of these practices include the following:
Clawback Provisions
Entergy Corporation has adopted a clawback policy that covers all individuals subject to Section 16 of the Securities Exchange Act of 1934 (the Exchange Act), including all of the members of the Office of the Chief Executive. Under the policy, which goes beyond the requirements of Sarbanes-Oxley Act of 2002 (Sarbanes-Oxley), the Committee will require reimbursement of incentives paid to these executive officers where:
(i) the payment was predicated upon the achievement of certain financial results with respect to the applicable performance period that were subsequently determined to be the subject of a material restatement other than a restatement due to changes in accounting policy; or (ii) a material miscalculation of a performance award
occurs, whether or not the financial statements were restated and, in either such case, a lower payment would have been made to the executive officer based upon the restated financial results or correct calculation; or
in the Board of Directors’ view, the executive officer engaged in fraud that caused or partially caused the need for a restatement or caused a material miscalculation of a performance award, in each case, whether or not the financial statements were restated.
The amount the Committee requires to be reimbursed is equal to the excess of the gross incentive payment made over the gross payment that would have been made if the original payment had been determined based on the restated financial results or correct calculation. Further, following a material restatement of theEntergy Corporation’s financial statements, Entergy Corporationit will seek to recover any compensation received by its Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under Section 304 of the Sarbanes-Oxley Act of 2002.Sarbanes-Oxley.
Stock Ownership Guidelines and Share Retention Requirements
For many years, Entergy Corporation has had stock ownership guidelines for executives, including the Named Executive Officers. These guidelines are designed to align the executives’ long-term financial interests with those of shareholders. Annually, the Personnel Committee monitors the executive officers’ compliance with these guidelines. The
Entergy Corporation’s ownership guidelines are as follows:
|
| |
| Role | Value of Common Stock to be Owned |
| Chief Executive Officer | 6 times base salary |
| Executive Vice Presidents | 3 times base salary |
| Senior Vice Presidents | 2 times base salary |
| Vice Presidents | 1 time base salary |
Further, to ensure compliance with the guidelines, until an executive officer satisfies the stock ownership guidelines, the officer must retain:
all net after-tax shares paid out under the Long-Term Performance Unit Program;
all net after-tax shares of Entergy Corporation’s restricted stock and restricted stock units received upon vesting; and
at least 75% of the after-tax net shares received upon the exercise of Entergy Corporation stock options, except for stock options granted before January 1, 2014, as to which the executive officer must retain at least 75% of the after-tax net shares until the earlier of achievement of the stock ownership guidelines or five years from the date of exercise.
Trading Controls and Anti-Pledging and Anti-Hedging Policies
Executive officers, including the Named Executive Officers, are required to receive the permission of Entergy Corporation’s General Counsel prior to entering into any transaction involving Entergy Corporation securities, including gifts, other than the exercise of employee stock options. Trading is generally permitted only during specified open trading windows occurringbeginning immediately following the release of earnings. Employees, who are subject to trading restrictions, including the Named Executive Officers, may enter into trading plans under Rule 10b5-1 of the Exchange Act, but these trading plans may be entered into only during an open trading window and must be approved by Entergy Corporation. The Named Executive Officer bears full responsibility if he or she violates companythe policy by permitting shares to be bought or sold without pre-approval or when trading is restricted.
Entergy Corporation also prohibits its directors and executive officers, including the Named Executive Officers, from pledging any Entergy Corporation’sCorporation securities or entering into margin accounts involving Entergy Corporation securities. It prohibits theseThese transactions are prohibited because of the potential that sales of Entergy Corporation’sCorporation securities could occur outside trading periods and without the required approval of the General Counsel.
Entergy Corporation has also has adopted an anti-hedging policy that prohibits officers, directors, and employees from entering into hedging or monetization transactions involving itsEntergy Corporation common stock. Prohibited transactions include,
without limitation, zero-cost collars, forward sale contracts, purchase or sale of options, puts, calls, straddles or equity swaps or other derivatives that are directly linked to the Entergy Corporation’s common stock or transactions involving “short-sales” of itsEntergy Corporation’s common stock. Entergy Corporation'sThe Board of Directors adopted this policy to require officers, directors, and employees to continue to own Entergy CorporationCorporation’s common stock with the full risks and rewards of ownership, thereby ensuring continued alignment of their objectives with those of Entergy Corporation’s other shareholders.
Roles and ResponsibilitiesHow Entergy Corporation Makes Compensation Decisions
Role of the Personnel Committee
The Personnel Committee has overall responsibility for approving the compensation program for the Named Executive Officers and makes all final compensation decisions regarding theEntergy Corporation’s Named Executive Officers. The Committee works with Entergy Corporation’s executive management to ensure that the compensation policies and practices are consistent with Entergy Corporation’sits values and support the successful recruitment, development, and retention of executive talent so that Entergy Corporation can achieve its business objectives and optimize its long-term financial returns. Each year, Entergy Corporation’s Senior Vice President, Human Resources and Chief Diversity OfficerAnnually, management presents the Personnel Committee with the proposed compensation model for the following year, including the compensation elements, mix of elements, and measures for each element, and consults with Entergy Corporation’s Chief Executive Officer on recommended compensation for senior executives. The Committee evaluates executive pay each year to ensure that theEntergy Corporation’s compensation policies and practices are consistent with Entergy Corporation’sits philosophy. The Personnel Committee is responsible for, among its other duties, the following actions related to the Named Executive Officers:
developing and implementing compensation policies and programs for hiring, evaluating, and setting compensation for the executive officers, including any employment agreement with an executive officer;
evaluating the performance of Entergy Corporation’s Chairman and Chief Executive Officer; and
reporting, at least annually, to the Board on succession planning, including succession planning for the Chief Executive Officer.
Role of the Chief Executive Officer
The Personnel Committee solicits recommendations from Entergy Corporation’s Chief Executive Officer with respect to compensation decisions for the other Named Executive Officers.Officers who are members of Entergy Corporation’s Office of the Chief Executive. Entergy Corporation’s Chief Executive Officer provides the Personnel Committee with an assessment of the performance of each of the otherthese Named Executive Officers and recommends compensation levels to be awarded to each of them. In addition, the Committee may request that the Chief Executive
Officer provide management feedback and recommendations on changes in the design of compensation programs, such as special retention plans or changes in the structure of bonus programs.incentive program structure. However, Entergy Corporation’sthe Chief Executive Officer does not play any role with respect to any matter affecting his own compensation, nor does he have any role determining or recommending the amount or form of director compensation. The Personnel Committee also relies on the recommendations of senior human resources executivesEntergy Corporation’s Senior Vice President, Human Resources with respect to compensation decisions, policies, and practices.
Entergy Corporation’sThe Chief Executive Officer may attend meetings of the Personnel Committee only at the invitation of the chair of the Personnel Committee and cannot call a meeting of the Committee. In addition, he is not in attendance at the portion of any meeting when the Committee approves the compensation to be paid to the Named Executive Officers. Since he is not a member of the Committee, he has no vote on matters submitted to the Committee. During 2014,2017, Mr. Denault attended 69 meetings of the Personnel Committee.
Role of the Compensation Consultant
Entergy Corporation’s Personnel Committee has the sole authority for the appointment, compensation, and oversight of its outside compensation consultant. In 2014,The Committee conducts an annual review of the Personnel Committeecompensation consultant, and in 2017, it retained Pay Governance LLC as its independent compensation consultant to assist it in, among other things, evaluating different compensation programs and developing market data to assess theEntergy Corporation’s compensation programs.
During 2014,2017, Pay Governance assisted the Committee with its responsibilities related to Entergy Corporation’s compensation programs for its executives. The Committee directed Pay Governance to: (i) regularly attend meetings of the Committee; (ii) conduct studies of competitive compensation practices; (iii) identify Entergy Corporation’s market surveys and proxy peer group; (iv) review base salary, annual incentives, and long-term incentive compensation opportunities relative to competitive practices; and (v) develop conclusions and recommendations related to the executive compensation planprograms for consideration by the Committee. A senior consultant from Pay Governance attended all Personnel Committee meetings to which he was invited in 2014.2017.
Compensation Consultant Independence
To maintain the independence of the Personnel Committee’s compensation consultant, the Board has adopted a policy that any consultant (including its affiliates) retained by the Board of Directors or any Committee of the Board of Directors to provide advice or recommendations on the amount or form of executive andor director compensation should not be retained by Entergy Corporation or any of its affiliates to provide other services in an aggregate amount that exceeds $120,000 in any year. In 2014,2017, the Personnel Committee’s independent compensation consultant, Pay Governance, LLC, did not provide any services to Entergy Corporation other than its services to the Personnel Committee.Committee and the Corporate Governance Committee in connection with Entergy Corporation’s non-employee director compensation program. Annually, the Committee reviews the relationship with its compensation consultant, including services provided, quality of those services, and fees associated with services in its evaluation of the executive compensation consultant’s independence. The Committee also assesses Pay Governance’s independence under NYSE rules and has concluded that no conflict of interests exists that would prevent Pay Governance from independently advising the Personnel Committee.
Tax and Accounting Considerations
Section 162(m) of the Internal Revenue Code (the Code) limits the tax deductibility by a publicly heldpublicly-held corporation of compensation in excess of $1 million paid to the Chief Executive Officer orand any of its other Named Executive Officers who may be Section 162(m) covered employees, unlessemployees. Historically, an exception was provided for compensation that compensation iswas “performance-based compensation” within the meaning of Section 162(m). The Personnel Committee considers deductibility under Section 162(m)Effective as it structures the compensation packages that are providedof January 1, 2018, this exception no longer applies, other than with respect to its Named Executive Officers. Likewise, the Personnel Committee considers financial accounting consequences as it structurescertain grandfathered arrangements. In structuring the compensation packages that are provided to the Named Executive Officers.Officers, the Personnel Committee takes into account the tax effects of Section 162(m) and considers the financial accounting consequences. However, the Personnel Committee and the Board believe that it is in the best interest of Entergy Corporation that the Personnel Committee retains the flexibility and discretion
to make compensation awards, whether or not deductible. This flexibility is necessary to foster achievement of performance goals established by the Personnel Committee, as well as other corporate goals that the Committee deems important to Entergy Corporation’s success, such as encouraging employee retention and rewarding achievement of key corporate goals.
PERSONNEL COMMITTEE REPORT
The Personnel Committee Report included in the Entergy Corporation Proxy Statement is incorporated by reference, but will not be deemed to be “filed” in this Annual Report on Form 10-K. None of the Subsidiaries has a compensation committee or other board committee performing equivalent functions. The board of directors of each of the Subsidiaries is comprised of individuals who are officers or employees of Entergy Corporation or one of the Subsidiaries. These boards do not make determinations regarding the compensation paid to executive officers of the Subsidiaries.
EXECUTIVE COMPENSATION TABLES
20142017 Summary Compensation Tables
The following table summarizes the total compensation paid or earned by each of the Named Executive Officers for the fiscal year ended December 31, 2014,2017, and to the extent required by SEC executive compensation disclosure rules, for the fiscal years ended 2013December 31, 2016 and 2012.2015. For information on the principal positions held by each of the Named Executive Officers, see Item 10, “Directors and Executive Officers of the Registrants.”
The compensation set forth in the table represents the aggregate compensation paid by all Entergy System companies. None of the Entergy System companies has entered into any employment agreements with any of the Named Executive Officers (other than the retention agreements described in “2014 Potential Payments upon Termination or Change in Control”). For additional information regarding the material terms of the awards reported in the following tables, including a general description of the formula or criteria to be applied in determining the amounts payable, see “Compensation Discussion and Analysis.”
| | | (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
Name and
Principal Position | | Year | | Salary (1)(2) | | Bonus (3) | | Stock Awards (4) | | Option Awards (5) | | Non-Equity Incentive Plan Compensation (6) | | Change in Pension Value and Non-qualified Deferred Compensation Earnings (7) | |
All
Other
Compensation (8) | | Total | |
Name and Principal Position (1) | | | Year | | Salary (2) | | Bonus (3) | | Stock Awards (4) | | Option Awards (5) | | Non-Equity Incentive Plan Compen-sation (6) | | Change in Pension Value and Non-qualified Deferred Compen-sation Earnings (7) | |
All
Other
Compens-ation (8) | | Total |
| A. Christopher Bakken, III | | | 2017 | |
| $615,791 |
| |
| $181,500 |
| |
| $959,376 |
| |
| $245,904 |
| |
| $559,973 |
| |
| $33,000 |
| |
| $114,494 |
| |
| $2,710,038 |
|
| Chief Nuclear Officer of Entergy Corp. | | | 2016 | |
| $426,990 |
| |
| $650,000 |
| |
| $3,292,700 |
| |
| $— |
| |
| $529,375 |
| |
| $27,900 |
| |
| $140,601 |
| |
| $5,067,566 |
|
| | | | | | | | | | | | | | | | | | |
| Marcus V. Brown | | | 2017 | |
| $622,788 |
| |
| $— |
| |
| $1,022,853 |
| |
| $287,760 |
| |
| $568,890 |
| |
| $1,217,200 |
| |
| $43,269 |
| |
| $3,762,760 |
|
| General Counsel of Entergy Corp. | | | 2016 | |
| $563,208 |
| |
| $— |
| |
| $1,144,648 |
| |
| $333,000 |
| |
| $550,550 |
| |
| $934,600 |
| |
| $34,381 |
| |
| $3,560,387 |
|
| | | | | | | | | | | | | | | | | | |
| Leo P. Denault | | 2014 | |
| $1,103,173 |
| |
| $— |
| |
| $3,564,463 |
| |
| $923,260 |
| |
| $2,597,400 |
| |
| $3,578,200 |
| |
| $57,538 |
| |
| $11,824,034 |
| | 2017 | |
| $1,221,346 |
| |
| $— |
| |
| $4,676,190 |
| |
| $1,173,276 |
| |
| $2,142,045 |
| |
| $3,819,500 |
| |
| $125,863 |
| |
| $13,158,220 |
|
| Chairman of the | | 2013 | |
| $1,039,253 |
| |
| $— |
| |
| $3,780,189 |
| |
| $400,000 |
| |
| $1,770,720 |
| |
| $630,800 |
| |
| $44,690 |
| |
| $7,665,652 |
| | 2016 | |
| $1,191,462 |
| |
| $— |
| |
| $4,632,276 |
| |
| $1,235,800 |
| |
| $2,154,600 |
| |
| $4,166,800 |
| |
| $97,786 |
| |
| $13,478,724 |
|
| Board and CEO - | | 2012 | |
| $669,564 |
| |
| $— |
| |
| $647,594 |
| |
| $282,600 |
| |
| $448,779 |
| |
| $972,400 |
| |
| $22,657 |
| |
| $3,043,594 |
| | 2015 | |
| $1,153,385 |
| |
| $— |
| |
| $4,356,362 |
| |
| $1,004,080 |
| |
| $1,681,875 |
| |
| $4,802,400 |
| |
| $88,795 |
| |
| $13,086,897 |
|
| Entergy Corp. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Haley R. Fisackerly | | 2014 | |
| $300,941 |
| |
| $— |
| |
| $236,190 |
| |
| $50,518 |
| |
| $193,878 |
| |
| $281,100 |
| |
| $33,311 |
| |
| $1,095,938 |
| | 2017 | |
| $354,451 |
| |
| $— |
| |
| $192,041 |
| |
| $49,704 |
| |
| $169,123 |
| |
| $406,300 |
| |
| $35,724 |
| |
| $1,207,343 |
|
| CEO - Entergy | | 2013 | |
| $294,090 |
| |
| $10,000 |
| |
| $214,624 |
| |
| $48,000 |
| |
| $142,368 |
| |
| $— |
| |
| $28,058 |
| |
| $737,140 |
| | 2016 | |
| $320,067 |
| |
| $— |
| |
| $229,752 |
| |
| $49,580 |
| |
| $168,000 |
| |
| $268,600 |
| |
| $34,243 |
| |
| $1,070,242 |
|
| Mississippi | | 2012 | |
| $287,296 |
| |
| $30,000 |
| |
| $186,225 |
| |
| $43,332 |
| |
| $139,000 |
| |
| $284,900 |
| |
| $26,781 |
| |
| $997,534 |
| | 2015 | |
| $320,131 |
| |
| $— |
| |
| $219,994 |
| |
| $51,345 |
| |
| $190,000 |
| |
| $102,300 |
| |
| $43,987 |
| |
| $927,757 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
|
|
| Andrew S. Marsh | | 2014 |
|
| $512,721 |
|
|
| $— |
|
|
| $940,837 |
|
|
| $304,850 |
|
|
| $706,388 |
|
|
| $750,900 |
|
|
| $26,722 |
|
|
| $3,242,418 |
| | 2017 | |
| $588,291 |
| |
| $— |
| |
| $1,022,853 |
| |
| $287,760 |
| |
| $541,800 |
| |
| $801,900 |
| |
| $51,647 |
| |
| $3,294,251 |
|
| Executive Vice | | 2013 | |
| $477,846 |
| |
| $— |
| |
| $921,927 |
| |
| $256,000 |
| |
| $476,000 |
| |
| $157,700 |
| |
| $213,663 |
| |
| $2,503,136 |
| | 2016 | |
| $553,284 |
| |
| $— |
| |
| $1,144,648 |
| |
| $333,000 |
| |
| $509,061 |
| |
| $593,700 |
| |
| $47,484 |
| |
| $3,181,177 |
|
| President and CFO - | | | | | | | | | | | | | | | | | | 2015 | |
| $532,245 |
| |
| $— |
| |
| $2,600,401 |
| |
| $273,840 |
| |
| $508,308 |
| |
| $670,200 |
| |
| $39,131 |
| |
| $4,624,125 |
|
| Entergy Corp. | | | | | | | | | | | | | | | | | |
| Acting principal | | | | | | | | | | | | | | | | | |
| financial officer | | | | | | | | | | | | | | | | | |
| Entergy Corp., | | | | | | | | | | | | | | | | | |
| Entergy Arkansas, | | | | | | | | | | | | | | | | | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Entergy Gulf States | | | | | | | | | | | | | | | | | |
| Louisiana, Entergy | | | | | | | | | | | | | | | | | |
| Louisiana, Entergy | | | | | | | | | | | | | | | | | |
| Mississippi, Entergy | | | | | | | | | | | | | | | | | |
| New Orleans, | | | | | | | | | | | | | | | | | |
| Entergy Texas | | | | | | | | | | | | | | | | | |
| Entergy Louisiana, | | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Entergy Mississippi, | | | | | | | | | | | | | | | | | |
| Entergy New | | | | | | | | | | | | | | | | | |
| Orleans, Entergy | | | | | | | | | | | | | | | | |
|
|
| Texas | | | | | | | | | | | | | | | | |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Phillip R. May, Jr. | | 2014 | |
| $335,997 |
| |
| $— |
| |
| $321,902 |
| |
| $69,680 |
| |
| $263,835 |
| |
| $546,000 |
| |
| $20,641 |
| |
| $1,558,055 |
| | 2017 | |
| $363,410 |
| |
| $— |
| |
| $302,493 |
| |
| $68,670 |
| |
| $300,000 |
| |
| $503,400 |
| |
| $26,981 |
| |
| $1,564,954 |
|
| CEO - Entergy Gulf | | 2013 |
|
| $321,860 |
|
|
| $5,000 |
|
|
| $325,813 |
|
|
| $48,000 |
|
|
| $238,223 |
|
|
| $— |
|
|
| $16,547 |
|
|
| $955,443 |
| |
| States Louisiana and | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| Entergy Louisiana | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| | | | | | | | | | | | | | | | | | |
| Hugh T. McDonald | | 2014 | |
| $350,104 |
| |
| $— |
| |
| $229,873 |
| |
| $47,905 |
| |
| $228,879 |
| |
| $400,800 |
| |
| $48,766 |
| |
| $1,306,327 |
| |
| CEO - Entergy | | 2013 | |
| $342,791 |
| |
| $10,000 |
| |
| $214,624 |
| |
| $48,000 |
| |
| $191,562 |
| |
| $— |
| |
| $48,326 |
| |
| $855,303 |
| | 2016 | |
| $353,690 |
| |
| $— |
| |
| $326,988 |
| |
| $71,040 |
| |
| $224,690 |
| |
| $600,000 |
| |
| $26,018 |
| |
| $1,602,426 |
|
| Arkansas | | 2012 | |
| $334,891 |
| |
| $30,000 |
| |
| $193,355 |
| |
| $43,332 |
| |
| $202,000 |
| |
| $452,900 |
| |
| $38,819 |
| |
| $1,295,297 |
| |
| | | | | | | | | | | | | | | | | |
| Louisiana | | | 2015 | |
| $344,035 |
| |
| $— |
| |
| $279,406 |
| |
| $57,050 |
| |
| $315,000 |
| |
| $288,100 |
| |
| $25,970 |
| |
| $1,309,561 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
Name and
Principal Position | | Year | | Salary (1)(2) | | Bonus (3) | | Stock Awards (4) | | Option Awards (5) | | Non-Equity Incentive Plan Compensation (6) | | Change in Pension Value and Non-qualified Deferred Compensation Earnings (7) | |
All
Other
Compensation (8) | | Total |
| Alyson M. Mount | | 2014 | |
| $297,166 |
| |
| $— |
| |
| $321,902 |
| |
| $74,035 |
| |
| $325,188 |
| |
| $369,400 |
| |
| $21,549 |
| |
| $1,409,240 |
|
| Former acting | | 2013 | |
| $284,896 |
| |
| $— |
| |
| $312,360 |
| |
| $71,200 |
| |
| $245,000 |
| |
| $69,200 |
| |
| $14,553 |
| |
| $997,209 |
|
| principal financial | | 2012 | |
| $252,389 |
| |
| $— |
| |
| $320,401 |
| |
| $— |
| |
| $210,000 |
| |
| $384,700 |
| |
| $11,556 |
| |
| $1,179,046 |
|
| officer Entergy | | | | | | | | | | | | | | | | | | |
| Arkansas, Entergy | | | | | | | | | | | | | | | | | | |
| Gulf States Louisiana | | | | | | | | | | | | | | | | | | |
| Entergy Louisiana, | | | | | | | | | | | | | | | | | | |
| Entergy Mississippi, | | | | | | | | | | | | | | | | | | |
| Entergy New | | | | | | | | | | | | | | | | | | |
| Orleans, Entergy | | | | | | | | | | | | | | | | | | |
| Texas | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Sallie T. Rainer | | 2014 | |
| $296,288 |
| |
| $— |
| |
| $236,190 |
| |
| $50,518 |
| |
| $171,500 |
| |
| $504,000 |
| |
| $32,250 |
| |
| $1,290,746 |
|
| CEO - Entergy | | 2013 | |
| $286,692 |
| |
| $10,000 |
| |
| $214,624 |
| |
| $46,400 |
| |
| $140,184 |
| |
| $57,800 |
| |
| $22,779 |
| |
| $778,479 |
|
| Texas | | 2012 | |
| $251,907 |
| |
| $30,000 |
| |
| $215,262 |
| |
| $— |
| |
| $128,000 |
| |
| $581,300 |
| |
| $13,714 |
| |
| $1,220,183 |
|
| | | | | | | | | | | | | | | | | | | |
| Charles L. Rice, Jr. | | 2014 | |
| $260,880 |
| |
| $— |
| |
| $220,398 |
| |
| $45,292 |
| |
| $167,864 |
| |
| $135,700 |
| |
| $31,402 |
| |
| $861,536 |
|
| CEO - Entergy New | | 2013 | |
| $255,786 |
| |
| $10,000 |
| |
| $201,704 |
| |
| $40,000 |
| |
| $112,446 |
| |
| $67,900 |
| |
| $24,078 |
| |
| $711,914 |
|
| Orleans | | 2012 | |
| $250,781 |
| |
| $30,000 |
| |
| $175,530 |
| |
| $43,332 |
| |
| $115,000 |
| |
| $96,900 |
| |
| $24,422 |
| |
| $735,965 |
|
| | | | | | | | | | | | | | | | | | | |
| Mark T. Savoff | | 2014 | |
| $641,443 |
| |
| $— |
| |
| $896,618 |
| |
| $239,525 |
| |
| $880,283 |
| |
| $733,800 |
| |
| $49,902 |
| |
| $3,441,571 |
|
| Executive Vice | | 2013 | |
| $628,913 |
| |
| $— |
| |
| $677,616 |
| |
| $200,000 |
| |
| $601,903 |
| |
| $197,400 |
| |
| $33,141 |
| |
| $2,338,973 |
|
| President and Chief | | 2012 | |
| $616,583 |
| |
| $— |
| |
| $540,644 |
| |
| $169,560 |
| |
| $412,203 |
| |
| $664,500 |
| |
| $35,775 |
| |
| $2,439,265 |
|
| Operating Officer - | | | | | | | | | | | | | | | | | | |
| Entergy Corp. | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Roderick K. West | | 2014 | |
| $623,854 |
| |
| $— |
| |
| $1,010,324 |
| |
| $313,560 |
| |
| $857,280 |
| |
| $782,400 |
| |
| $43,648 |
| |
| $3,631,066 |
|
| Executive Vice | | 2013 | |
| $606,381 |
| |
| $— |
| |
| $2,318,926 |
| |
| $320,000 |
| |
| $583,315 |
| |
| $147,800 |
| |
| $27,045 |
| |
| $4,003,467 |
|
| President and Chief | | 2012 | |
| $584,540 |
| |
| $— |
| |
| $647,594 |
| |
| $282,600 |
| |
| $391,791 |
| |
| $991,000 |
| |
| $46,097 |
| |
| $2,943,622 |
|
| Administrative | | | | | | | | | | | | | | | | | | |
| Officer - Entergy Corp. | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
Name and Principal Position (1) | | Year | | Salary (2) | | Bonus (3) | | Stock Awards (4) | | Option Awards (5) | | Non-Equity Incentive Plan Compen-sation (6) | | Change in Pension Value and Non-qualified Deferred Compen-sation Earnings (7) | |
All
Other
Compens-ation
(8) | | Total |
| Sallie T. Rainer | | 2017 | |
| $325,737 |
| |
| $— |
| |
| $195,567 |
| |
| $51,012 |
| |
| $156,259 |
| |
| $435,900 |
| |
| $35,785 |
| |
| $1,200,260 |
|
| CEO - Entergy | | 2016 | |
| $316,003 |
| |
| $— |
| |
| $229,752 |
| |
| $49,580 |
| |
| $153,348 |
| |
| $346,300 |
| |
| $53,797 |
| |
| $1,148,780 |
|
| Texas | | 2015 | |
| $304,783 |
| |
| $— |
| |
| $211,004 |
| |
| $43,358 |
| |
| $190,000 |
| |
| $189,100 |
| |
| $41,565 |
| |
| $979,810 |
|
| | | | | | | | | | | | | | | | | | | |
| Charles L. Rice, Jr. | | 2017 | |
| $284,681 |
| |
| $— |
| |
| $170,882 |
| |
| $25,506 |
| |
| $91,000 |
| |
| $221,200 |
| |
| $30,842 |
| |
| $824,111 |
|
| CEO - Entergy New | | 2016 | |
| $276,998 |
| |
| $— |
| |
| $229,752 |
| |
| $49,580 |
| |
| $67,302 |
| |
| $177,600 |
| |
| $33,807 |
| |
| $835,039 |
|
| Orleans | | 2015 | |
| $266,752 |
| |
| $— |
| |
| $211,004 |
| |
| $51,345 |
| |
| $173,000 |
| |
| $104,500 |
| |
| $33,416 |
| |
| $840,017 |
|
| | | | | | | | | | | | | | | | | | | |
| Richard C. Riley | | 2017 | |
| $341,723 |
| |
| $— |
| |
| $202,620 |
| |
| $52,320 |
| |
| $280,661 |
| |
| $437,700 |
| |
| $38,695 |
| |
| $1,353,719 |
|
| CEO - Entergy | | 2016 | |
| $325,020 |
| |
| $— |
| |
| $226,224 |
| |
| $34,780 |
| |
| $167,500 |
| |
| $277,900 |
| |
| $102,112 |
| |
| $1,133,536 |
|
| Arkansas | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Roderick K. West | | 2017 | |
| $670,876 |
| |
| $— |
| |
| $818,316 |
| |
| $190,968 |
| |
| $610,065 |
| |
| $867,200 |
| |
| $52,220 |
| |
| $3,209,645 |
|
| Group President | | 2016 | |
| $654,514 |
| |
| $— |
| |
| $1,116,424 |
| |
| $303,400 |
| |
| $461,384 |
| |
| $601,000 |
| |
| $73,706 |
| |
| $3,210,428 |
|
| Utility Operations of | | 2015 | |
| $638,876 |
| |
| $— |
| |
| $1,071,111 |
| |
| $262,430 |
| |
| $607,677 |
| |
| $543,900 |
| |
| $71,790 |
| |
| $3,195,784 |
|
| Entergy Corp. | | | | | | | | | | | | | | | | | | |
| |
| (1) | Mr. Bakken was named Executive Vice President and Chief Nuclear Officer in April 2016. Mr. Brown was not a Named Executive Officer in 2015. Mr. Riley was named Chief Executive Officer, Entergy Arkansas in May 2016. |
| |
| (2) | The amounts in column (c) represent the actual base salary paid to the Named Executive Officer.Officers. The 20142017 changes in base salaries noted in the Compensation Discussion and Analysis were effective in April 2014. |
| |
(2) | Mr. Marsh was not a Named Executive officer in 2012.2017. |
| |
| (3) | The amountsamount in column (d) in 2013 and 20122017 for Mr. Fisackerly, Mr. McDonald, Ms. Rainer, and Mr. Rice and in 2013 for Mr. May represent aBakken represents the cash bonus paid to him pursuant to the Nuclear Retention Plan. See “Nuclear Retention Plan” in recognitionCompensation Discussion and Analysis. The amount in column (d) in 2016 represents a cash sign-on bonus paid to Mr. Bakken in connection with his commencement of their work supporting the move to MISO.employment with Entergy Corporation. |
| |
| (4) | The amounts in column (e) represent the aggregate grant date fair value of restricted stock, restrictedperformance units, and performancerestricted stock units granted under the 2011 Equity Ownership PlanPlans, each calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures. The grant date fair value of the restricted stock and the restricted stock units is based on the closing price of Entergy Corporation common stock on the date of grant. The grant date fair value of performance units is based on the probable outcome of the applicable performance conditions, measured using a Monte Carlo simulation valuation model. The simulation model applies a risk-free interest rate and an expected volatility assumption. The risk-free interest rate is assumed to equal the yield on a three-year treasury bond on the grant date. Volatility is based on historical volatility for the 36-month period preceding the grant date. If the highest achievement level is attained, the maximum amounts that will be received with respect to the performance units granted in 2017 are as follows: Mr. Bakken, $1,170,798; Mr. Brown, $1,170,798; Mr. Denault, $6,869,622; Mr. Fisackerly, $260,961; Mr. Marsh, $1,170,798; Mr. May, $444,339; Ms. Rainer, $260,961; Mr. Rice, $260,961; Mr. Riley, $260,961; and Mr. West, $1,170,798. The amount in 2016 for Mr. Bakken includes restricted stock units granted to him in connection with his commencement of employment as Chief Nuclear Officer. |
that will be received with respect to the performance units granted in 2014 are as follows: Mr. Denault, $5,053,600; Mr. Fisackerly, $277,948; Mr. Marsh, $1,187,596; Mr. May, $391,654; Mr. McDonald, $277,948; Ms. Mount, $391,654; Ms. Rainer, $277,948; Mr. Rice, $277,948; Mr. Savoff, $1,187,596; and Mr. West, $1,187,596.
| |
| (5) | The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the 2011 Equity Ownership PlanPlans calculated in accordance with FASB ASC Topic 718. For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the financial statements. |
| |
| (6) | The amounts in column (g) represent cash payments made under the Annual Incentive Plan. |
| |
| (7) | TheFor all Named Executive Officers, the amounts in column (h) include the annual actuarial increase in the present value of thethese Named Executive Officers’ benefits under all pension plans established by Entergy Corporation using interest rate and mortality rate assumptions consistent with those used in Entergy Corporation’s financial statements and include amounts which the Named Executive Officers may not currently be entitled to receive because such amounts are not vested (see “2014“2017 Pension Benefits”). None of the increaseincreases for any of the Named Executive Officers is attributable to above-market or preferential earnings on non-qualified deferred compensation (see “2014“2017 Non-qualified Deferred Compensation”). |
| |
| (8) | The amounts in column (i) for 20142017 include (a) matching contributions by Entergy Corporation under the Savings Plan to each of the Named Executive Officers; (b) dividends paid on restricted stock when vested; (c) life insurance premiums; (d) tax gross up payments on club dues;dues and relocation expenses; and (e) perquisites and other compensation. The amounts are listed in the following table: |
| | Named Executive Officer | Company Contribution – Savings Plan | Dividends Paid on Restricted Stock | Life Insurance Premium | Tax Gross Up Payments | Perquisites and Other Compensation | Total | Company Contribution – Savings Plan | Dividends Paid on Restricted Stock | Life Insurance Premium | Tax Gross Up Payments | Perquisites and Other Compensation | Total |
| A. Christopher Bakken, III | |
| $16,200 |
|
| $— |
|
| $11,887 |
|
| $1,299 |
|
| $85,108 |
|
| $114,494 |
|
| Marcus V. Brown | |
| $— |
|
| $35,517 |
|
| $7,482 |
|
| $— |
|
| $270 |
|
| $43,269 |
|
| Leo P. Denault |
| $10,920 |
|
| $31,934 |
|
| $7,482 |
|
| $— |
|
| $7,202 |
|
| $57,538 |
|
| $11,340 |
|
| $93,206 |
|
| $7,482 |
|
| $— |
|
| $13,835 |
|
| $125,863 |
|
| Haley R. Fisackerly |
| $10,890 |
|
| $7,150 |
|
| $995 |
|
| $3,893 |
|
| $10,383 |
|
| $33,311 |
|
| $11,340 |
|
| $7,907 |
|
| $2,306 |
|
| $4,082 |
|
| $10,089 |
|
| $35,724 |
|
| Andrew S. Marsh |
| $10,919 |
|
| $10,816 |
|
| $3,157 |
|
| $— |
|
| $1,830 |
|
| $26,722 |
|
| $11,139 |
|
| $35,517 |
|
| $4,991 |
|
| $— |
|
| $— |
|
| $51,647 |
|
| Phillip R. May, Jr. |
| $10,920 |
|
| $6,655 |
|
| $2,646 |
|
| $— |
|
| $420 |
|
| $20,641 |
|
| $11,340 |
|
| $9,673 |
|
| $5,279 |
|
| $— |
|
| $689 |
|
| $26,981 |
|
| Hugh T. McDonald |
| $10,920 |
|
| $7,366 |
|
| $6,976 |
|
| $8,073 |
|
| $15,431 |
|
| $48,766 |
| |
| Alyson M. Mount |
| $10,920 |
|
| $7,598 |
|
| $297 |
|
| $— |
|
| $2,734 |
|
| $21,549 |
| |
| Sallie T. Rainer |
| $10,920 |
|
| $6,047 |
|
| $3,137 |
|
| $2,955 |
|
| $9,191 |
|
| $32,250 |
|
| $11,340 |
|
| $7,696 |
|
| $6,477 |
|
| $2,952 |
|
| $7,320 |
|
| $35,785 |
|
| Charles L. Rice, Jr. |
| $10,920 |
|
| $5,779 |
|
| $4,870 |
|
| $1,743 |
|
| $8,090 |
|
| $31,402 |
|
| $11,340 |
|
| $6,849 |
|
| $4,874 |
|
| $2,637 |
|
| $5,142 |
|
| $30,842 |
|
| Mark T. Savoff |
| $10,920 |
|
| $18,486 |
|
| $7,482 |
|
| $— |
|
| $13,014 |
|
| $49,902 |
| |
| Richard C. Riley | |
| $11,340 |
|
| $8,756 |
|
| $5,040 |
|
| $4,832 |
|
| $8,727 |
|
| $38,695 |
|
| Roderick K. West |
| $10,920 |
|
| $24,208 |
|
| $2,610 |
|
| $— |
|
| $5,910 |
|
| $43,648 |
|
| $11,340 |
|
| $38,270 |
|
| $2,610 |
|
| $— |
|
| $— |
|
| $52,220 |
|
Perquisites and Other Compensation
The amounts set forth in column (i) include perquisites and other personal benefits that Entergy Corporation provides to theits Named Executive Officers as part of providing a competitive executive compensation program and for employee retention. The following perquisites and other compensation were provided by Entergy Corporationto the Named Executive Officers in 2014.2017.
|
| | | | | |
Named Executive Officer | Relocation | Personal Use of Corporate Aircraft | Club Dues | Executive Physicals
Physical Exams | Event Tickets |
| A. Christopher Bakken, III | X | X | | X | |
| Marcus V. Brown | | | | X | X |
| Leo P. Denault | | X | | X | |
| Haley R. Fisackerly | | | X | X | |
| Andrew S. Marsh | | | | X | X |
| Phillip R. May, Jr. | | | | X |
Hugh T. McDonald | | X | | |
Alyson M. Mount | | | X | |
| Sallie T. Rainer | X | | X | | |
| Charles L. Rice, Jr. | | X | X | X |
Mark T. Savoff | X | | |
| Richard C. Riley | | | X | | |
| Roderick K. West | X | | | X | X |
For security and business reasons, Entergy Corporation permits its Chief Executive Officer to use its corporate aircraft for personal use at the expense of Entergy Corporation. The other Named Executive Officers may use the corporate aircraft for personal travel subject to the approval of Entergy Corporation’s Chief Executive Officer. The Personnel
Committee reviews the level of usage throughout the year. Entergy Corporation believes that its officers’ ability to use its plane for limited personal use saves time and provides additional security for them, thereby benefiting Entergy Corporation. The amounts included in column (i) for the personal use of corporate aircraft, reflect the incremental cost to Entergy Corporation for use of the corporate aircraft, determined on the basis of the variable operational costs of each flight, including fuel, maintenance, flight crew travel expense, catering, communications, and fees, including flight planning, ground handling, and landing permits. In addition, Entergy Corporation offers its executives comprehensive annual physical exams at Entergy Corporation'sCorporation’s expense. Tickets to cultural and sporting events are purchased for business purposes, and if not utilized for business purposes, the tickets are made available to the employees, including the Named Executive Officers, for personal use.
Entergy Corporation also provides relocation benefits to a broad base of employees which include assistance with moving expenses, purchase and sale of homes, and transportation of household goods. In connection with his employment, and in accordance with its relocation policies and pursuant to certain additional relocation benefits including the purchase of his home, Entergy Corporation paid $77,897 in relocation expenses for Mr. Bakken in 2017. The relocation assistance amounts reported above represent the amounts paid to Entergy Corporation’s relocation service provider or Mr. Bakken, as applicable.
None of the other perquisites referenced above exceeded $25,000 for any of the other Named Executive Officers.
20142017 Grants of Plan-Based Awards
The following table summarizes award grants during 20142017 to the Named Executive Officers.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1) | | Estimated Future Payouts under Equity Incentive Plan Awards(2) | | | | | | | | |
| (a) | | (b) | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) |
| Name | | Grant Date | |
Thresh- old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under- lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards |
| | | | | ($) | ($) | ($) | | (#) | (#) | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) |
| Leo P. | | 1/30/14 | | — | $1,332,000 | $2,664,000 | | | | | | | | | | | | |
| Denault | | 1/30/14 | | | | | | 10,000 |
| 40,000 |
| 80,000 |
| | | | | | | | $2,686,400 |
| | | 1/30/14 | | | | | | | | | | 13,900 |
| | | | | | $878,063 |
| | | 1/30/14 | | | | | | | | | | | | 106,000 |
| | $63.17 | | $923,260 |
| | | | | | | | | | | | | | | | | | | |
| Haley R. | | 1/30/14 | | — | $121,174 | $242,347 | | | | | | | | | | | | |
| Fisackerly | | 1/30/14 | | | | | | 550 |
| 2,200 |
| 4,400 |
| | | | | | | | $147,752 |
| | | 1/30/14 | | | | | | | | | | 1,400 |
| | | | | | $88,438 |
| | | 1/30/14 | | | | | | | | | | | | 5,800 |
| | $63.17 | | $50,518 |
| | | | | | | | | | | | | | | | | | | |
| Andrew S. | | 1/30/14 |
| — | $362,250 | $724,500 |
|
|
|
|
|
|
|
|
| | | | | | |
| Marsh | | 1/30/14 |
|
|
|
|
| 2,350 |
| 9,400 |
| 18,800 |
|
|
|
| | | | | | $631,304 |
| | | 1/30/14 | | | | | | | | | | 4,900 |
| | | | | | $309,533 |
| | | 1/30/14 | | | | | | | | | | | | 35,000 |
| | $63.17 | | $304,850 |
| | | | | | | | | | | | | | | | | | | |
| Phillip R. | | 1/30/14 | | — | $202,950 | $405,900 | | | | | | | | | | | | |
| May, Jr. | | 1/30/14 | | | | | | 775 |
| 3,100 |
| 6,200 |
| | | | | | | | $208,196 |
| | | 1/30/14 | | | | | | | | | | 1,800 |
| | | | | | $113,706 |
| | | 1/30/14 | | | | | | | | | | | | 8,000 |
| | $63.17 | | $69,680 |
| | | | | | | | | | | | | | | | | | | |
| Hugh T. | | 1/30/14 | | — | $176,060 | $352,121 | | | | | | | | | | | | |
| McDonald | | 1/30/14 | | | | | | 550 |
| 2,200 |
| 4,400 |
| | | | | | | | $147,752 |
| | | 1/30/14 | | | | | | | | | | 1,300 |
| | | | | | $82,121 |
| | | 1/30/14 | | | | | | | | | | | | 5,500 |
| | $63.17 | | $47,905 |
| | | | | | | | | | | | | | | | | | | |
| Alyson M. | | 1/30/14 | | — | $180,660 | $361,320 | | | | | | | | | | | | |
| Mount | | 1/30/14 | | | | | | 775 |
| 3,100 |
| 6,200 |
| | | | | | | | $208,196 |
| | | 1/30/14 | | | | | | | | | | 1,800 |
| | | | | | $113,706 |
| | | 1/30/14 | | | | | | | | | | | | 8,500 |
| | $63.17 | | $74,035 |
| | | | | | | | | | | | | | | | | | | |
| Sallie T. | | 1/30/14 | | — | $119,310 | $238,620 | | | | | | | | | | | | |
| Rainer | | 1/30/14 | | | | | | 550 |
| 2,200 |
| 4,400 |
| | | | | | | | $147,752 |
| | | 1/30/14 | | | | | | | | | | 1,400 |
| | | | | | $88,438 |
| | | 1/30/14 | | | | | | | | | | | | 5,800 |
| | $63.17 | | $50,518 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Estimated Future Payouts Under Non-Equity Incentive Plan Awards (1) | | Estimated Future Payouts under Equity Incentive Plan Awards (2) | | | | | | | | |
| (a) | | (b) | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) |
| Name | | Grant Date | | Thresh-old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under-lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards |
| | | | | ($) | ($) | ($) | | (#) | (#) | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) |
| A. Christopher | | 1/26/17 | | $- | $434,088 | $868,175 | | | | | | | | | | | | |
| Bakken, III | | 1/26/17 | | | | | | 2,075 |
| 8,300 |
| 16,600 |
| | | | | | | | $592,620 |
| | | 1/26/17 | | | | | |
|
| |
|
| | 5,200 |
| | | | | | $366,756 |
| | | 1/26/17 | | | | | | | | | | | | 37,600 |
| | $70.53 | | $245,904 |
| | | | | | | | | | | | | | | | | | | |
| Marcus V. | | 1/26/17 | | $- | $441,000 | $882,000 | | | | | | | | | | | | |
| Brown | | 1/26/17 | | | | | | 2,075 |
| 8,300 |
| 16,600 |
| | | | | | | | $592,620 |
| | | 1/26/17 | | | | | | | | | | 6,100 |
| | | | | | $430,233 |
| | | 1/26/17 | | | | | | | | | | | | 44,000 |
| | $70.53 | | $287,760 |
| | | | | | | | | | | | | | | | | | | |
| Leo P. | | 1/26/17 | | $- | $1,660,500 | $3,321,000 | | | | | | | | | | | | |
| Denault | | 1/26/17 | | | | | | 12,175 |
| 48,700 |
| 97,400 |
| | | | | | | | $3,477,180 |
| | | 1/26/17 | | | | | | | | | | 17,000 |
| | | | | | $1,199,010 |
| | | 1/26/17 | | | | | | | | | | | | 179,400 |
| | $70.53 | | $1,173,276 |
489
| | | | | | | Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1) | | Estimated Future Payouts under Equity Incentive Plan Awards(2) | | | | | | | | | | | | Estimated Future Payouts Under Non-Equity Incentive Plan Awards (1) | | Estimated Future Payouts under Equity Incentive Plan Awards (2) | | | | | | | | |
| (a) | | (b) | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) | | (b) | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) |
| Name | | Grant Date | |
Thresh- old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under- lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards | | Grant Date | | Thresh-old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under-lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards |
| | | | | ($) | | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) | | ($) | | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) |
| Haley R. | | | 1/26/17 | | $- | $142,120 | $284,240 | | | | | | |
| | | | |
| Fisackerly | | | 1/26/17 | | | | | 463 |
| 1,850 |
| 3,700 |
| | | | | | | | $132,090 |
| | | | 1/26/17 | | | | | | | 850 |
| | | | | | $59,951 |
| | | | 1/26/17 | | | | | | | | | 7,600 |
| | $70.53 | | $49,704 |
| | | | | | | | | |
| Andrew S. | | | 1/26/17 | | $- | $420,000 | $840,000 |
|
|
|
|
|
|
|
|
| | | |
| Marsh | | | 1/26/17 | |
|
|
| 2,075 |
| 8,300 |
| 16,600 |
|
|
|
| | | | $592,620 |
| | | | 1/26/17 | | | | 6,100 |
| | | | $430,233 |
| | | | 1/26/17 | | | | | | 44,000 |
| | $70.53 | | $287,760 |
| | | | | | | | | |
| Phillip R. | | | 1/26/17 | | $- | $219,690 | $439,380 | | | | | | | | | | |
| May, Jr. | | | 1/26/17 | | | | | 788 |
| 3,150 |
| 6,300 |
| | | | | | | | $224,910 |
| | | | 1/26/17 | | | | 1,100 |
| | | | $77,583 |
| | | | 1/26/17 | | | | | | 10,500 |
| | $70.53 | | $68,670 |
| | | | | | | | | |
| Sallie T. | | | 1/26/17 | | $- | $131,310 | $262,620 | | | | |
| | |
| | | | |
| Rainer | | | 1/26/17 | | | | | 463 |
| 1,850 |
| 3,700 |
| | | | | | | | $132,090 |
| | | | 1/26/17 | | | | | | | 900 |
| | | | | | $63,477 |
| | | | 1/26/17 | | | | | | 7,800 |
| | $70.53 | | $51,012 |
| | | | | | | | | |
| Charles L. | | 1/30/14 | | — | $104,915 | $209,829 | | | | | | | | | | | | 1/26/17 | | $- | $114,570 | $229,140 | | | | | | | |
| Rice, Jr. | | 1/30/14 | | | | | 550 |
| 2,200 |
| 4,400 |
| | | | | | | | $147,752 | | 1/26/17 | | | | | 463 |
| 1,850 |
| 3,700 |
| | | | | | | | $132,090 |
| | | 1/30/14 | | | | | | | 1,150 |
| | | | | | $72,646 | | 1/26/17 | | | | | | | 550 |
| | | | | | $38,792 |
| | | 1/30/14 | | | | | | | | | 5,200 |
| | $63.17 | | $45,292 | | 1/26/17 | | | | | | | | | 3,900 |
| | $70.53 | | $25,506 |
| | | | | | | | | | | | | | | |
| Mark T. | | 1/30/14 | | — | $451,427 | $902,854 | | | | | | | | | | | |
| Savoff | | 1/30/14 | | | | | 2,350 |
| 9,400 |
| 18,800 |
| | | | | | | | $631,304 | |
| Richard C. | | | 1/26/17 | | $- | $137,680 | $275,360 | | | | | | | | | | |
| Riley | | | 1/26/17 | | | | | 463 |
| 1,850 |
| 3,700 |
| | | | | | | | $132,090 |
| | | 1/30/14 | | | | | | | 4,200 |
| | | | | | $265,314 | | 1/26/17 | | | | | | | 1,000 |
| | | | | | $70,530 |
| | | 1/30/14 | | | | | | | | | 27,500 |
| | $63.17 | | $239,525 | | 1/26/17 | | | | | | 8,000 |
| | $70.53 | | $52,320 |
| | | | | | | | | | | | | | | |
| Roderick K. | | 1/30/14 | | — | $439,631 | $879,262 | | | | | | | | | | | | 1/26/17 | | $- | $472,919 | $945,837 | | | | | | | | | | |
| West | | 1/30/14 | | | | | 2,350 |
| 9,400 |
| 18,800 |
| | | | | | | | $631,304 | | 1/26/17 | | | | | 2,075 |
| 8,300 |
| 16,600 |
| | | | | | | | $592,620 |
| | | 1/30/14 | | | | | | | 6,000 |
| | | | | | $379,020 | | 1/26/17 | | | | | | | 3,200 |
| | | | | | $225,696 |
| | | 1/30/14 | | | | | | 36,000 |
| | $63.17 | | $313,560 | | 1/26/17 | | | | | | 29,200 |
| | $70.53 | | $190,968 |
| |
| (1) | The amounts in columns (c), (d), and (e) represent minimum, target, and maximum payment levels under the Annual Incentive Plan. The actual amounts awarded are reported in column (g) of the Summary Compensation Table. |
| |
| (2) | The amounts in columns (f), (g), and (h) represent the minimum, target, and maximum payment levels under the Long-Term Performance Unit Program. Performance under the program is measured by Entergy Corporation’s total shareholder return relative to the total shareholder returns of the companies included in the Philadelphia Utility Index. IfThere is no payout under the program if Entergy Corporation’s total shareholder return is not at least 25%falls within the lowest quartile of that forthe peer companies in the Philadelphia Utility Index, there is no payout.Index. Subject to the achievement of performance targets, each unit will be converted into one share of Entergy Corporation’s common stock on the last day of the performance period (December 31, 2016.2019.) Accrued dividends on the shares earned will also be paid in Entergy Corporation common stock. |
| |
| (3) | The amounts in column (i) represent shares of restricted stock granted under the 20112015 Equity Ownership Plan. Shares of restricted stock vest one-third on each of the first through third anniversaries of the grant date, have voting rights, and accrue dividends during the vesting period. |
| |
| (4) | The amounts in column (j) represent options to purchase shares of Entergy Corporation’s common stock. The options vest one-third on each of the first through third anniversaries of the grant date and have a ten-year term from the date of grant. The options were granted under the 20112015 Equity Ownership Plan. |
| |
| (5) | The amounts in column (l) are valued based on the aggregate grant date fair value of the award calculated in accordance with FASB ASC Topic 718 and, in the case of the performance units, are based on the probable outcome of the applicable performance conditions. See Notes 4 and 5 to the 2017 Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value. |
20142017 Outstanding Equity Awards at Fiscal Year-End
The following table summarizes, for each Named Executive Officer, unexercised options, restricted stock that has not vested, and equity incentive plan awards outstanding as of the end of 2014.December 31, 2017.
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Leo P. | | — |
| | 106,000(1) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| Denault | | 16,666 |
| | 33,334(2) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 20,000 |
| | 10,000(3) |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 25,000 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 50,000 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 45,000 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 50,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | 60,000 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | | | | |
| | | 50,000 |
| | — |
| | | | $68.89 | | 1/26/2016 | | | | | | | | |
| | | | | | | | | | | | | | | | | 80,000(4) | | $6,998,400 |
| | | | | | | | | | | | | | | | | 74,312(5) | | $6,500,814 |
| | | | | | | | | | | | | 13,900(6) | | $1,215,972 | | | | |
| | | | | | | | | | | | | 4,000(7) | | $349,920 | | | | |
| | | | | | | | | | | | | 1,334(8) |
| $116,698 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Haley R. | | — |
| | 5,800(1) |
| | | | $63.17 |
| 1/30/2024 | | | | | | | | |
| Fisackerly | | — |
| | 4,000(2) |
| | | | $64.60 |
| 1/31/2023 | | | | | | | | |
| | | — |
| | 1,534(3) |
| | | | $71.30 |
| 1/26/2022 | | | | | | | | |
| | | 2,900 |
| | — |
| | | | $72.79 |
| 1/27/2021 | | | | | | | | |
| | | 9,000 |
| | — |
| | | | $77.10 |
| 1/28/2020 | | | | | | | | |
| | | 3,800 |
| | — |
| | | | $77.53 |
| 1/29/2019 | | | | | | | | |
| | | 5,000 |
| | — |
| | | | $108.20 |
| 1/24/2018 | | | | | | | | |
| | | 2,500 |
| | — |
| | | | $91.82 |
| 1/25/2017 | | | | | | | | |
| | | | | | | | |
|
|
| | | | | | 4,400(4) | | $384,912 |
| | | | | | | | | | | | | | | | | 3,800(5) | | $332,424 |
| | | | | | | | | | | | | 1,400(6) | | $122,472 | | | | |
| | | | | | | | | | | | | 934(7) | | $81,706 | | | | |
| | | | | | | | | | | | | 400(8) | | $34,992 | | | | |
| | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| A. Christopher Bakken, III | | — |
| | 37,600(1) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | | | | | | | | | | | | | | | 8,300(4) | | $675,537 |
| | | | | | | | | | | | | | | | | 7,289(5) | | $593,252 |
| | | | | | | | | | | | | 5,200(6) | | $423,228 | | | | |
| | | | | | | | | | | | | 30,000(9) | | $2,441,700 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Marcus V. Brown | | — |
| | 44,000(1) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 15,000 |
| | 30,000(2) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 16,000 |
| | 8,000(3) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 30,500 |
| | — |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 16,000 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 4,600 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Andrew S. | | — |
| | 35,000(1) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| Marsh | | 10,666 |
| | 21,334(2) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 6,666 |
| | 3,334(3) |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 4,000 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 9,100 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 8,000 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 10,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | 5,000 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | | | | |
| | | 5,500 |
| | — |
| | | | $68.89 | | 1/26/2016 | | | | | | | | |
| | | | | | | | | | | | | | | | | 18,800(4) | | $1,644,624 |
| | | | | | | | | | | | | | | | | 14,884(5) | | $1,302,052 |
| | | | | | | | | | | | | 4,900(6) | | $428,652 | | | | |
| | | | | | | | | | | | | 2,667(7) | | $223,309 | | | | |
| | | | | | | | | | | | | 467(8) | | $40,853 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Phillip R. | | — |
| | 8,000(1) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| May, Jr. | | 2,000 |
| | 4,000(2) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 3,066 |
| | 1,534(3) |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 2,900 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 6,000 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 4,700 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 6,500 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | 5,000 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | | | | |
| | | 4,500 |
| | — |
| | | | $68.89 | | 1/26/2016 | | | | | | | | |
| | | | | | | | | | | | | | | | | 6,200(4) | | $542,376 |
| | | | | | | | | | | | | | | | | 5,938(5) | | $519,456 |
| | | | | | | | | | | | | 1,800(6) | | $157,464 | | | | |
| | | | | | | | | | | | | 934(7) | | $81,706 | | | | |
| | | | | | | | | | | | | 400(8) | | $34,992 | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| | | 2,800 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 7,500 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 4,300 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | | | | | | | | | | | | | | | 8,300(4) | | $675,537 |
| | | | | | | | | | | | | | | | | 8,200(5) | | $667,398 |
| | | | | | | | | | | | | 6,100(6) | | $496,479 | | | | |
| | | | | | | | | | | | | 4,267(7) | | $347,291 | | | | |
| | | | | | | | | | | | | 1,667(8) | | $135,677 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Leo P. Denault | | — |
| | 179,400(1) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 55,666 |
| | 111,334(2) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 58,666 |
| | 29,334(3) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 106,000 |
| | — |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 50,000 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 30,000 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 25,000 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 50,000 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 45,000 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 50,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | | | | | | | | | | | | | | | 48,700(4) | | $3,963,693 |
| | | | | | | | | | | | | | | | | 41,700(5) | | $3,393,963 |
| | | | | | | | | | | | | 17,000(6) | | $1,383,630 | | | | |
| | | | | | | | | | | | | 10,467(7) | | $851,909 | | | | |
| | | | | | | | | | | | | 4,000(8) | | $325,560 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Haley R. Fisackerly | | — |
| | 7,600(1) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 2,233 |
| | 4,467(2) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 3,000 |
| | 1,500(3) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 1,534 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 2,900 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 6,000 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 5,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | | | | | | | | | | | | | | | 1,850(4) | | $150,572 |
| | | | | | | | | | | | | | | | | 1,800(5) | | $146,502 |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Hugh T. | | — |
| | 5,500(1) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| McDonald | | 2,000 |
| | 4,000(2) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 3,066 |
| | 1,534(3) |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 2,900 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 4,600 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 4,500 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 7,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | 12,000 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | | | | |
| | | 7,500 |
| | — |
| | | | $68.89 | | 1/26/2016 | | | | | | | | |
| | | | | | | | | | | | | | | | | 4,400(4) | | $384,912 |
| | | | | | | | | | | | | | | | | 3,800(5) | | $332,424 |
| | | | | | | | | | | | | 1,300(6) | | $113,724 | | | | |
| | | | | | | | | | | | | 934(7) | | $81,706 | | | | |
| | | | | | | | | | | | | 434(8) | | $37,966 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Alyson M. | | — |
| | 8,500(1) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| Mount | | — |
| | 5,934(2) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 4,500 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | 5,400 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | | | | |
| | | | | | | | | | | | | | | | | 6,200(4) | | $542,376 |
| | | | | | | | | | | | | | | | | 6,000(5) | | $524,880 |
| | | | | | | | | | | | | 1,800(6) | | $157,464 | | | | |
| | | | | | | | | | | | | 1,200(7) | | $104,976 | | | | |
| | | | | | | | | | | | | 500(8) | | $43,740 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Sallie T. | | — |
| | 5,800(1) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| Rainer | | 1,933 |
| | 3,867(2) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 2,500 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 1,200 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 2,300 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | 2,000 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | | | | |
| | | 2,500 |
| | — |
| | | | $68.89 | | 1/26/2016 | | | | | | | | |
| | | | | | | | | | | | | | | | | 4,400(4) | | $384,912 |
| | | | | | | | | | | | | | | | | 3,800(5) | | $332,424 |
| | | | | | | | | | | | | 1,400(6) | | $122,472 | | | | |
| | | | | | | | | | | | | 934(7) | | $81,706 | | | | |
| | | | | | | | | | | | | 434(8) | | $37,966 | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| | | | | | | | | | | | | 850(6) | | $69,182 | | | | |
| | | | | | | | | | | | | 734(7) | | $59,740 | | | | |
| | | | | | | | | | | | | 284(8) | | $23,115 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Andrew S. Marsh | | — |
| | 44,000(1) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 15,000 |
| | 30,000(2) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 16,000 |
| | 8,000(3) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 35,000 |
| | — |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 32,000 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 10,000 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 4,000 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 9,100 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 8,000 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 10,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | | | | | | | | | | | | | | | 8,300(4) | | $675,537 |
| | | | | | | | | | | | | | | | | 8,200(5) | | $667,398 |
| | | | | | | | | | | | | 6,100(6) | | $496,479 | | | | |
| | | | | | | | | | | | | 4,267(7) | | $347,291 | | | | |
| | | | | | | | | | | | | 1,667(8) | | $135,677 | | | | |
| | | | | | | | | | | | | 21,100(10) | | $1,717,329 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Phillip R. May, Jr. | | — |
| | 10,500(1) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 3,200 |
| | 6,400(2) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 3,333 |
| | 1,667(3) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 8,000 |
| | — |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 6,000 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 4,600 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 2,900 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 6,000 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 4,700 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 6,500 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | | | | | | | | | | | | | | | 3,150(4) | | $256,379 |
| | | | | | | | | | | | | | | | | 2,700(5) | | $219,753 |
| | | | | | | | | | | | | 1,100(6) | | $89,529 | | | | |
| | | | | | | | | | | | | 934(7) | | $76,018 | | | | |
| | | | | | | | | | | | | 284(8) | | $23,115 | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Charles L. | | — |
| | 5,200(1) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| Rice, Jr. | | 1,666 |
| | 3,334(2) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 3,066 |
| | 1,534(3) |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 2,900 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | | | | | | | | | | | | | | | 4,400(4) | | $384,912 |
| | | | | | | | | | | | | | | | | 3,800(5) | | $332,424 |
| | | | | | | | | | | | | 1,150(6) | | $100,602 | | | | |
| | | | | | | | | | | | | 800(7) | | $69,984 | | | | |
| | | | | | | | | | | | | 350(8) | | $30,618 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Mark T. | | — |
| | 27,500(1) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| Savoff | | 8,333 |
| | 16,667(2) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 12,000 |
| | 6,000(3) |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 17,000 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 30,000 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 30,000 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 27,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | 35,000 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | | | | |
| | | | | | | | | | | | | | | | | 18,800(4) | | $1,644,624 |
| | | | | | | | | | | | | | | | | 15,200(5) | | $1,329,696 |
| | | | | | | | | | | | | 4,200(6) | | $367,416 | | | | |
| | | | | | | | | | | | | 1,867(7) | | $163,325 | | | | |
| | | | | | | | | | | | | 834(8) | | $72,958 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Roderick | | — |
| | 36,000(1) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| K. West | | 13,333 |
| | 26,667(2) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 20,000 |
| | 10,000(3) |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 17,000 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 7,000 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 5,000 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 8,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | 12,000 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | | | | |
| | | | | | | | | | | | | | | | | 18,800(4) | | $1,644,624 |
| | | | | | | | | | | | | | | | | 15,200(5) | | $1,329,696 |
| | | | | | | | | | | | | 6,000(6) | | $524,880 | | | | |
| | | | | | | | | | | | | 3,334(7) | | $291,658 | | | | |
| | | | | | | | | | | | | 1,334(8) | | $116,698 | | | | |
| | | | | | | | | | | | | 21,000(9) | | $1,837,080 | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Sallie T. Rainer | | — |
| | 7,800(1) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 2,233 |
| | 4,467(2) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 2,533 |
| | 1,267(3) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 2,000 |
| | — |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 2,000 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 2,300 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | |
| | |
| | | | | | | | | | | | 1,850(4) | | $150,572 |
| | | | | | | | | | | | | | | | | 1,800(5) | | $146,502 |
| | | | | | | | | | | | | 900(6) | | $73,251 | | | | |
| | | | | | | | | | | | | 734(7) | | $59,740 | | | | |
| | | | | | | | | | | | | 250(8) | | $20,348 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Charles L. Rice, Jr. | | — |
| | 3,900(1) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 2,233 |
| | 4,467(2) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 3,000 |
| | 1,500(3) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | |
| | |
| | | | | | | | | | | | 1,850(4) | | $150,572 |
| | | |
| | |
| | | | | | | | | | | | 1,800(5) | | $146,502 |
| | | |
| | |
| | | | | | | | 550(6) | | $44,765 | | | | |
| | | |
| | |
| | | | | | | | 734(7) | | $59,740 | | | | |
| | | | | | | | | | | | | 250(8) | | $20,348 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Richard C. Riley | | — |
| | 8,000(1) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 1,566 |
| | 3,134(2) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 3,000 |
| | 1,500(3) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 5,334 |
| | — |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 1,334 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 4,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | |
| | |
| | | | | | | | | | | | 1,850(4) | | $150,572 |
| | | |
| | |
| | | | | | | | | | | | 1,800(5) | | $146,502 |
| | | |
| | |
| | | | | | | | 1,000(6) | | $81,390 | | | | |
| | | |
| | |
| | | | | | | | 700(7) | | $56,973 | | | | |
| | | |
| | |
| | | | | | | | 367(8) | | $29,870 | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Roderick K. West | | — |
| | 29,200(1) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 13,666 |
| | 27,334(2) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 15,333 |
| | 7,667(3) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 12,000 |
| | — |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 30,000 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 7,000 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 5,000 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 8,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | |
| | |
| | | | | | | | | | | | 8,300(4) | | $675,537 |
| | | |
| | |
| | | | | | | | | | | | 8,200(5) | | $667,398 |
| | | |
| | |
| | | | | | | | 3,200(6) | | $260,448 | | | | |
| | | |
| | |
| | | | | | | | 4,000(7) | | $325,560 | | | | |
| | | |
| | |
| | | | | | | | 1,567(8) | | $127,538 | | | | |
| | | |
| | |
| | | | | | | | 21,000(11) | | $1,709,190 | | | | |
| |
| (1) | Consists of options that vested or will vest as follows: 1/3 of the remaining unexercisable options granted vest on each of 1/30/2015, 1/30/2016January 26, 2018, January 26, 2019, and 1/30/2017.January 26, 2020. |
| |
| (2) | Consists of options that vested or will vest as follows: 1/2 of the remaining unexercisable options vest on each of 1/31/2015January 28, 2018 and 1/31/2016.January 28, 2019. |
| |
| (3) | The remaining unexercisable options vested on 1/26/2015.January 29, 2018. |
| |
| (4) | Consists of performance units that will vest on December 31, 20162019 based on Entergy Corporation’s total shareholder return performance over the 2014-20162017-2019 performance period, as described under “What We PayEntergy Corporation Pays and Why- Executive Compensation Elements - Variable - Long-Term Incentive Compensation - Performance Unit Program” in Compensation Discussion and Analysis. |
| |
| (5) | Consists of performance units that will vest on December 31, 20152018 based on Entergy Corporation’s total shareholder return performance over the 2013-20152016-2018 performance period. |
| |
| (6) | Consists of shares of restricted stock that vested or will vest as follows: 1/3 of the shares of restricted stock granted vest on each of 1/30/2015, 1/30/2016January 26, 2018, January 26, 2019, and 1/30/2017.January 26, 2020. |
| |
| (7) | Consists of shares of restricted stock that vested or will vest as follows: 1/2 of the shares of restricted stock granted vest on each of 1/31/2015January 28, 2018 and 1/31/2016.January 28, 2019. |
| |
| (8) | Consists of shares of restricted stock that vested on 1/26/2015.January 29, 2018. |
| |
| (9) | Consists of restricted stock units granted under the 2015 Equity Ownership Plan which will vest one third on April 6, 2019, April 6, 2022, and April 6, 2025. |
| |
| (10) | Consists of restricted stock units granted under the 2015 Equity Ownership Plan which will vest on August 3, 2020. |
| |
| (11) | Consists of restricted stock units granted under the 2011 Equity Ownership Plan which will vest on May 1, 2018. |
2014
2017 Option Exercises and Stock Vested
The following table provides information concerning each exercise of stock options and each vesting of stock during 20142017 for the Named Executive Officers.
| | | | | Options Awards | | Stock Awards | | Options Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (b) | | (c) | | (d) | | (e) |
| Name | | Number of Shares Acquired on Exercise | | Value Realized on Exercise | | Number of Shares Acquired on Vesting | | Value Realized on Vesting | | Number of Shares Acquired on Exercise | | Value Realized on Exercise | | Number of Shares Acquired on Vesting | | Value Realized on Vesting (1) |
| | | | (#) | | ($) | | (#) | | ($) |
| A. Christopher Bakken, III | | | — |
| |
| $— |
| | 1,212 |
| |
| $95,154 |
|
| | | | | | | | | | |
| Marcus V. Brown | | | 5,000 |
| |
| $35,850 |
| | 8,224 |
| |
| $598,764 |
|
| | | (#) | | ($) | | (#) | | ($) | | | | | | | | |
| Leo P. Denault | | 35,000 |
| |
| $477,575 |
| | 17,370(1) | |
| $1,423,990 |
| | — |
| |
| $— |
| | 26,741 |
| |
| $1,979,459 |
|
| | | | | | | | | | | | | | | |
| Haley R. Fisackerly | | 6,066 |
| |
| $61,983 |
| | 2,136(1) | |
| $164,281 |
| | 10,734 |
| |
| $134,837 |
| | 1,734 |
| |
| $126,435 |
|
| | | | | | | | | | | | | | | |
| Andrew S. Marsh | | 7,000 |
| |
| $78,385 |
| | 4,715(1) | |
| $369,715 |
| | — |
| |
| $— |
| | 8,224 |
| |
| $598,764 |
|
| | | | | | | | | | | | | | | |
| Phillip R. May, Jr. | | 7,000 |
| |
| $75,732 |
| | 2,458(1) | |
| $193,263 |
| | — |
| |
| $— |
| | 2,202 |
| |
| $161,139 |
|
| | | | | | | | | | | | | | | |
| Hugh T. McDonald | | 10,000 |
| |
| $53,055 |
| | 2,169(1) | |
| $166,520 |
| |
| | | | | | | | |
| Alyson M. Mount | | 24,466 |
| |
| $67,906 |
| | 2,670(1) | |
| $202,276 |
| |
| | | | | | | | |
| Sallie T. Rainer | | 2,500 |
| |
| $31,434 |
| | 1,901(1) | |
| $145,240 |
| | 11,300 |
| |
| $169,289 |
| | 1,698 |
| |
| $123,893 |
|
| | | | | | | | | | | | | | | |
| Charles L. Rice, Jr. | | — |
| |
| $— |
| | 1,937(1) | |
| $150,599 |
| | 9,234 |
| |
| $147,762 |
| | 1,603 |
| |
| $117,185 |
|
| | | | | | | | | | | | | | | |
| Mark T. Savoff | | 50,000 |
| |
| $534,219 |
| | 6,257(1) | |
| $495,030 |
| |
| Richard C. Riley | | | 4,500 |
| |
| $67,559 |
| | 1,847 |
| |
| $134,414 |
|
| | | | | | | | | | | | | | | |
| Roderick K. West | | 2,001 |
| |
| $28,988 |
| | 7,490(1) | |
| $577,597 |
| | — |
| |
| $— |
| | 8,396 |
| |
| $610,908 |
|
| |
| (1) | Represents the value of performance units for the 2012-20142015-2017 performance period (payable solely in shares based on the closing stock price of the CompanyEntergy Corporation on the datesdate of vesting) under the Performance Unit Program and the vesting of shares of restricted stock in 2014.2017. |
495
20142017 Pension Benefits
The following table shows the present value as of December 31, 2014,2017, of accumulated benefits payable to each of the Named Executive Officers, including the number of years of service credited to each Named Executive Officer, under the retirement plans sponsored by Entergy Corporation, determined using interest rate and mortality rate assumptions set forth in Note 11 to the financial statements. Additional information regarding these retirement plans is included in Compensation Discussion & Analysis under the heading, “Benefits, Perquisites, Agreements, and Post-Retirement Plans" and followingfollows this table. In addition, this section includes information regarding early retirement options under the plans.
|
| | | | | | | | | | | | | |
Name | | Plan Name | | Number of Years Credited Service | | Present Value of Accumulated Benefit | | Payments During 2014 |
Leo P. Denault (1) | | Non-qualified System Executive Retirement Plan | | 30.83 |
| |
| $9,539,500 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 15.83 |
| |
| $546,100 |
| |
| $— |
|
| | | | | | | | | |
| Haley R. Fisackerly | | Non-qualified System Executive Retirement Plan | | 19.08 |
| |
| $843,300 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 19.08 |
| |
| $538,700 |
| |
| $— |
|
| | | | | | | | | |
| Andrew S. Marsh | | Non-qualified System
Executive Retirement Plan | | 16.37 |
| |
| $1,621,700 |
| |
| $— |
|
| | | Qualified defined
benefit plan | | 16.37 |
| |
| $354,600 |
| |
| $— |
|
| | | | | | | | | |
| Phillip R. May, Jr. | | Non-qualified System
Executive Retirement Plan | | 28.56 |
| |
| $1,346,100 |
| |
| $— |
|
| | | Qualified defined
benefit plan | | 28.56 |
| |
| $888,600 |
| |
| $— |
|
| | | | | | | | | |
Hugh T. McDonald (2) | | Non-qualified System Executive Retirement Plan | | 32.93 |
| |
| $1,615,100 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 31.44 |
| |
| $1,142,200 |
| |
| $— |
|
| | | | | | | | | |
| Alyson M. Mount | | Non-qualified System Executive Retirement Plan | | 12.35 |
| |
| $696,600 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 12.35 |
| |
| $294,100 |
| |
| $— |
|
| | | | | | | | | |
Sallie T. Rainer (2) | | Non-qualified System Executive Retirement Plan | | 30.38 |
| |
| $818,800 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 28.52 |
| |
| $981,100 |
| |
| $— |
|
| | | | | | | | | |
| Charles L. Rice, Jr. | | Non-qualified System Executive Retirement Plan | | 5.47 |
| |
| $256,200 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 5.47 |
| |
| $157,400 |
| |
| $— |
|
| | Name | | Plan Name | | Number of Years Credited Service | | Present Value of Accumulated Benefit | | Payments During 2014 | | Plan Name | | Number of Years Credited Service | | Present Value of Accumulated Benefit | | Payments During 2017 |
| Mark T. Savoff | | Non-qualified System Executive Retirement Plan | | 11.06 |
| |
| $3,329,000 |
| |
| $— |
| |
| A. Christopher Bakken, III | | | Cash Balance Equalization Plan | | 1.74 |
| |
| $30,600 |
| |
| $— |
|
| | | | Cash Balance Plan | | 1.74 |
| |
| $30,300 |
| |
| $— |
|
| | | | | | | | |
Marcus V. Brown(1) | | | System Executive Retirement Plan | | 22.74 |
| |
| $4,793,900 |
| |
| $— |
|
| | | | Entergy Retirement Plan | | 22.74 |
| |
| $907,400 |
| |
| $— |
|
| | | | | | | | |
Leo P. Denault (1)(2) | | | System Executive Retirement Plan | | 33.83 |
| |
| $22,072,300 |
| |
| $— |
|
| | | | Entergy Retirement Plan | | 18.83 |
| |
| $802,000 |
| |
| $— |
|
| | | | | | | | |
| Haley R. Fisackerly | | | System Executive Retirement Plan | | 22.08 |
| |
| $1,370,100 |
| |
| $— |
|
| | | | Entergy Retirement Plan | | 22.08 |
| |
| $789,100 |
| |
| $— |
|
| | | | | | | | |
| Andrew S. Marsh | | | System Executive Retirement Plan | | 19.37 |
| |
| $3,493,700 |
| |
| $— |
|
| | | | Entergy Retirement Plan | | 19.37 |
| |
| $548,400 |
| |
| $— |
|
| | | | | | | | |
Phillip R. May, Jr. (1) | | | System Executive Retirement Plan | | 31.56 |
| |
| $2,398,400 |
| |
| $— |
|
| | | | Entergy Retirement Plan | | 31.56 |
| |
| $1,227,800 |
| |
| $— |
|
| | | | | | | | |
Sallie T. Rainer (1)(3) | | | System Executive Retirement Plan | | 33.38 |
| |
| $1,356,000 |
| |
| $— |
|
| | | | Entergy Retirement Plan | | 33.00 |
| |
| $1,415,200 |
| |
| $— |
|
| | | | | | | | |
| Charles L. Rice, Jr. | | | System Executive Retirement Plan | | 8.47 |
| |
| $609,100 |
| |
| $— |
|
| | | | Entergy Retirement Plan | | 8.47 |
| |
| $307,800 |
| |
| $— |
|
| | | | | | | | |
Richard C. Riley (1)(4) | | | System Executive Retirement Plan | | 28.01 |
| |
| $1,688,200 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 11.06 |
| |
| $437,600 |
| |
| $— |
| | Entergy Retirement Plan | | 22.55 |
| |
| $866,000 |
| |
| $— |
|
| | | | | | | | | | | | | |
| Roderick K. West | | Non-qualified System Executive Retirement Plan | | 15.75 |
| |
| $2,830,500 |
| |
| $— |
| | System Executive Retirement Plan | | 18.75 |
| |
| $4,636,200 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 15.75 |
| |
| $387,700 |
| |
| $— |
| | Entergy Retirement Plan | | 18.75 |
| |
| $594,100 |
| |
| $— |
|
| |
| (1) | DuringAs of December 31, 2017, Mr. Brown, Mr. Denault, Mr. May, Ms. Rainer, and Mr. Riley were retirement eligible. |
| |
| (2) | In 2006, Mr. Denault entered into ana retention agreement granting him an additional 15 years of service and permission to retire under the non-qualified System Executive Retirement Plan in the event his employment is terminated by his Entergy employer other than for cause (as defined in the retention agreement), by Mr. Denault for good reason (as defined in the retention agreement), or on account of his death or disability. His retention agreement also provides that if he terminates employment for any other reason, he shall be entitled to the additional 15 years of service under the non-qualified System Executive Retirement Plan only if he continueshis Entergy employer grants him permission to work for an Entergy System company employer and, after age 55, retires with the permission of his employer or his employment is terminated due to death or disability.retire. The additional 15 years of service increases the present value of his benefit by $2,246,700.$3,967,700. |
| |
(2)(3) | Service under the non-qualified System Executive Retirement Plan is granted from the date of hire. Qualified plan benefit service is granted from the later of the date of hire or the plan participation date. |
| |
| (4) | Mr. Riley separated from Entergy Corporation and was subsequently rehired in June 1995. The Entergy Retirement Plan does not include any credit service prior to his rehire date, however, the System Executive Retirement Plan reflects a net credited service date of December 28, 1989. |
The tables below contain summaries of the pension benefit plans sponsored by Entergy Corporation that the Named Executive Officers participated in during 2017. Benefits for the Named Executive Officers who participate in these plans are determined using the same formulas as for other eligible employees.
Qualified Retirement Benefits
The qualified retirement plan in which the Named Executive Officers participate is a funded, tax-qualified, noncontributory defined benefit pension plan that provides benefits to most of the non-bargaining unit employees of Entergy System Companies. All Named Executive Officers are participants in this plan. Benefits under the tax-qualified pension plan are calculated as an annuity payable at age 65 and generally equal to 1.5% of a participant’s Final Average Monthly Earnings (FAME) multiplied by years of service (not to exceed 40). “Earnings” for purposes of calculating FAME generally includes the employee’s base salary and eligible annual incentive award and excludes all other bonuses. FAME is calculated using the employee’s average monthly Earnings for the 60 consecutive months in which the employee’s earnings were highest during the 120 month period immediately preceding the employee’s retirement and includes up to 5 annual bonuses paid during the 60 month period. Benefits under the tax-qualified plan are payable monthly after attainment of at least age 55 and after separation from an Entergy System company. The amount of annual earnings that may be considered in calculating benefits under the tax-qualified pension plan is limited by federal law. Participants are 100% vested in their benefit upon completing 5 years of vesting service or upon attainment of age 65 while an active employee participant in the plan. Contributions to the pension plan are made entirely by the Entergy System employer and are paid into a trust fund from which the benefits of participants will be paid. |
| | | |
| Entergy Retirement Plan | Cash Balance Plan |
| Eligible Named Executive Officers | Marcus V. Brown Haley R. Fisackerly Leo P. Denault Andrew S. Marsh Phillip R. May, Jr. | Sallie T. Rainer Charles L. Rice, Jr. Richard C. Riley Roderick K. West
| A. Christopher Bakken, III |
| Eligibility | Non-bargaining employees hired on or before July 1, 2014 | Non-bargaining employees hired on or after July 1, 2014 |
| Vesting | A participant becomes vested in the Entergy Retirement Plan upon attainment of at least 5 years of vesting service or upon attainment of age 65 while actively employed by an Entergy system company. | A participant becomes vested in the Cash Balance Plan upon attainment of at least 3 years of vesting service or upon attainment of age 65 while actively employed by an Entergy system company. |
| Form of Payment Upon Retirement | Benefits are payable as an annuity. For employees who separate from service on or after January 1, 2018, a single lump sum distribution may be elected by the participant if eligibility criteria are met. | Benefits are payable as an annuity or single lump sum distribution. |
| Retirement Benefit Formula | Benefits are calculated as a single life annuity payable at age 65 and generally are equal to 1.5% of a participant’s Final Average Monthly Earnings (FAME) multiplied by years of service (not to exceed 40).
“Earnings” for the purpose of calculating FAME generally includes the employee’s base salary and eligible annual incentive awards subject to Internal Revenue Code limitations, and excludes all other bonuses. Executive Annual Incentive Awards are not eligible for inclusion in Earnings under this plan.
FAME is calculated using the employee’s average monthly Earnings for the 60 consecutive months in which the employee’s earnings were highest during the 120 month period immediately preceding the employee’s retirement and includes up to 5 eligible annual incentive awards paid during the 60 month period.
| The normal retirement benefit at age 65 is determined by converting the sum of an employee’s annual pay credits and his or her annual interest credits, into an actuarially equivalent annuity.
Pay credits ranging from 4-8% of an employee’s eligible Earnings are allocated annually to a notional account for the employee based on an employee’s age and years of service. Earnings for purposes of calculating an employee’s pay credit include the employee’s base salary and annual incentive awards subject to Code limitations and exclude all other bonuses. Executive Annual Incentive Awards are eligible for inclusion in Earnings under this plan.
Interest credits are calculated based upon the annual rate of interest on 30-year U.S. Treasury securities, as specified by the Internal Revenue Service, for the month of August preceding the first day of the applicable calendar year subject to a minimum rate of 2.6% and a maximum rate of 9%.
|
Normal retirement under the plan is age 65. Employees who terminate employment prior to age 55 may receive a reduced deferred vested retirement benefit commencing as early as age 55 that is based on |
| | | |
| Benefit Timing | Normal retirement age under the plan is 65.
A reduced vested benefit may be commenced as early as age 55. The amount of this benefit is determined by reducing the normal retirement benefit by 7% per year for the first 5 years commencement precedes age 65, and 6% per year for each additional year commencement precedes age 65.
A subsidized early retirement benefit may be commenced by employees who are at least age 55 with 10 years of service at the time they separate from service. The amount of this benefit is determined by reducing the normal retirement benefit (reduced by 7% per year for the first 5 years commencement precedes age 65, and reduced by 6% for each additional year commencement precedes age 65). Employees who are at least age 55 with 10 years of vesting service upon termination of employment are entitled to a subsidized early retirement benefit beginning as early as age 55. The subsidized early retirement benefit is equal to the normal retirement benefit reduced by 2% per year for each year that early retirement precedes age 65. | Normal retirement age under the plan is 65.
A vested cash balance benefit can be commenced as early as the first day of the month following separation from service. The amount of the benefit is determined in the same manner as the normal retirement benefit described above in the “Retirement Benefit Formula” section. |
Mr. Denault, Mr. McDonald, and Mr. Savoff are eligible for subsidized early retirement benefits.
Non-qualified Retirement Benefits
The Named Executive Officers are eligible to participate in certain non-qualified retirement benefit plans that provide retirement income, including the Pension Equalization Plan, the Cash Balance Equalization Plan, and the System Executive Retirement Plan. Each of these plans is an unfunded non-qualified defined benefit pension plan that provides benefits to key management employees. In these plans, as described below, an executive is typically enrolled in one or more non-qualified plans, but is only paid the amount due under the plan that provides the highest benefit. In general, upon disability, participants in the Pension Equalization Plan and the System Executive Retirement Plan remain eligible for continued service credits until the earlier of recovery, separation from service due to disability, or retirement eligibility. Generally, spouses of participants who die before commencement of benefits may be eligible for a portion of the participant’s accrued benefit.
All of the Named Executive Officers participate in both the Pension Equalization Plan and the System Executive Retirement Plan.
The Pension Equalization Plan
The Pension Equalization Plan is a non-qualified unfunded restoration retirement plan that provides for the payment to participants from Entergy Corporation's general assets of a single lump sum cash distribution upon separation from service generally equal to the actuarial present value of the difference between the amount that would have been payable as an annuity under the tax-qualified pension plan, but for Internal Revenue Code limitations on pension benefits and earnings that may be considered in calculating tax-qualified pension benefits, and the amount actually payable as an annuity under the tax-qualified pension plan. The Pension Equalization Plan also takes into account as eligible earnings certain incentive awards paid under the Annual Incentive Plan and includes supplemental credited service granted to a participant in calculating his or her benefit. Participants receive their Pension Equalization Plan benefit in the form of a single sum cash distribution. The benefits under this plan are offset by benefits payable from the qualified retirement plan and may be offset by prior employer benefits. The Pension Equalization Plan benefit attributable to supplemental credited service is not vested until age 65. Subject to the prior written consent of the Entergy System Company employer (which consent is deemed given if the participant’s employment is terminated within twenty-four months following a change in control by the employer without “Cause” or by the participant for “Good Reason,” as each is defined in the plan), an employee with supplemental credited service who terminates employment prior to age 65 may be vested in his or her benefit, with payment of the lump sum benefit generally at separation from service unless delayed six months under Internal Revenue Code Section 409A. Benefits payable prior to age 65 are subject to the same reductions as qualified plan benefits.
Effective July 1, 2014, participants in the Pension Equalization Plan will not be provided with supplemental credited service unless the grant of supplemental credited service was approved and accepted in writing by the plan administrator prior to July 1, 2014. In addition, the Pension Equalization Plan was amended effective July 1, 2014 to provide that employees who participate in the Entergy Corporation’s cash balance pension plan adopted June 30, 2014 are not eligible to participate in the Pension Equalization Plan and instead are eligible to participate in a new cash balance restoration plan.
The System Executive Retirement Plan
The System Executive Retirement Plan is a non-qualified supplemental retirement plan that provides for a single sum payment at age 65. Like the Pension Equalization Plan, the System Executive Retirement Plan is designed to provide for the payment to participants from Entergy Corporation’s general assets of a single-sum cash distribution upon the participant’s separation from service. The single-sum benefit is generally equal to the actuarial present value of a specified percentage of the participant’s “Final Average Monthly Compensation” (which is generally 1/36th of the sum of the participant’s annual rate of base salary and Annual Incentive Plan award for the 3 highest years during the last 10 years preceding termination of employment), after first being reduced by the value of the participant’s tax-qualified retirement plan benefit and typically any prior employer pension benefit available to the participant.
While the System Executive Retirement Plan has a replacement ratio schedule from one year of service to the maximum of 30 years of service, the table below offers a sample ratio at 20 and 30 years of service. |
| | | | | |
| Pension Equalization Plan | Cash Balance Equalization Plan | System Executive Retirement Plan |
| Eligible Named Executive Officers | Marcus V. Brown Haley R. Fisackerly Leo P. Denault Andrew S. Marsh Phillip R. May, Jr. | Sallie T. Rainer Charles L. Rice, Jr. Richard C. Riley Roderick K. West
| A. Christopher Bakken, III | Marcus V. Brown Haley R. Fisackerly Leo P. Denault Andrew S. Marsh Phillip R. May, Jr. | Sallie T. Rainer Charles L. Rice, Jr. Richard C. Riley Roderick K. West
|
| Eligibility | Management or highly compensated employees who participate in the Entergy Retirement Plan | Management or highly compensated employees who participate in the Cash Balance Plan | Certain individuals who became executive officers before July 1, 2014 |
| Form of Payment Upon Retirement | Single lump sum distribution | Single lump sum distribution | Single lump sum distribution |
| Retirement Benefit Formula | Benefits generally are equal to the actuarial present value of the difference between (1) the amount that would have been payable as an annuity under the Entergy Retirement Plan, including Executive Annual Incentive Awards as eligible earnings and without applying Internal Revenue Code limitations on pension benefits and earnings that may be considered in calculating tax-qualified pension benefits, and (2) the amount actually payable as an annuity under the Entergy Retirement Plan. | Benefits generally are equal to the difference between the amount that would have been payable as a lump sum under the Cash Balance Plan, but for Internal Revenue Code limitations on pension benefits and earnings that may be considered in calculating tax-qualified cash balance plan benefits, and the amount actually | Benefits generally are equal to the actuarial present value of a specified percentage, based on the participant’s years of service (including supplemental service granted under the plan) and management level of the participant’s “Final Average Monthly Compensation” (which is generally 1/36th of the sum of the participant’s base salary and Annual Incentive Plan award for the 3 highest years during the last 10 years preceding separation from service), after first being reduced by the |
|
| | | | | | |
Years of Service | | Executives at Management Level 1 | | Executives at Management Levels 2 and 3 | | Executives at Management Level 4 |
| 20 Years | | 55.0% | | 50.0% | | 45.0% |
| 30 years | | 65.0% | | 60.0% | | 55.0% |
The System Executive Retirement Plan benefit is not vested until age 65. Subject to the prior written consent of the Entergy System company employer, an employee who terminates his or her employment prior to age 65 may be vested in the System Executive Retirement Plan benefit, with payment of the lump sum benefit generally at separation from service unless delayed six months under Code Section 409A. Benefits payable prior to age 65 are subject to the same reductions as qualified plan benefits. Further, in the event of a change in control, participants whose employment is terminated without “Cause” or by the employee for “Good Reason,” as each is defined in the plan are also eligible for a subsidized lump sum benefit payment, even if they do not currently meet the age or service requirements for early retirement under that plan or have company permission to separate from employment. Such lump sum benefit is payable generally at separation from service unless delayed 6 months |
| | | | | |
| Pension Equalization Plan | Cash Balance Equalization Plan | System Executive Retirement Plan |
| Executive Annual Incentive Awards are taken into account as eligible earnings under this plan. | payable as a lump sum under the Cash Balance Plan. | value of the participant’s Entergy Retirement Plan benefit. |
| Benefit timing | Payable at age 65
Benefits payable prior to age 65 are subject to the same reduced terminated vested or early retirement reduction factors as benefits payable under the Entergy Retirement Plan as described above.
An employee with supplemental credited service who terminates employment prior to age 65 must receive prior written consent of the Entergy employer in order to receive the portion of their benefit attributable to their supplemental credited service agreement.
Benefits payable upon separation from service subject to the 6 month delay required under Code Section 409A. | Payable upon separation from service subject to 6 month delay required under Code Section 409A. | Payable at age 65
Prior to age 65, vesting is conditioned on the prior written consent of the officer’s Entergy employer.
Benefits payable prior to age 65 are subject to the same reduced terminated vested or subsidized early retirement reduction factors as benefits payable under the Entergy Retirement Plan as described above.
Benefits payable upon separation from service subject to the 6 month delay required under Code Section 409A. |
Additional Information
| |
| (1) | Effective July 1, 2014, (a) no new grants of supplemental service may be provided to participants in the Pension Equalization Plan; (b) supplemental credited service granted prior to July 1, 2014 was grandfathered; and (c) participants in Entergy Corporation’s Cash Balance Plan are not eligible to participate in the Pension Equalization Plan and instead may be eligible to participate in the Cash Balance Equalization Plan. |
| |
| (2) | Benefits already accrued under the System Executive Retirement Plan, Pension Equalization Plan, and Cash Balance Equalization Plan, if any, will become fully vested if a participant is involuntarily terminated without cause or terminates his or her employment for good reason in connection with a change in control with payment generally made in a lump-sum payment as soon as reasonably practicable following the first day of the month after the termination of employment, unless delayed 6 months under Code Section 409A. |
| |
| (3) | The System Executive Retirement Plan was closed to new executive officers effective July 1, 2014. |
2017 Non-qualified Deferred Compensation
The Executive Deferred Compensation Plan, the 2007 Equity Ownership Plan and Long-Term Cash Incentive Plan, and the 2011 Equity Ownership Plan allow for the deferral of compensation for the Named Executive Officers. As of December 31, 2014, none of the Named Executive Officers had deferred compensation balances under the equity ownership plans or the Executive Deferred Compensation Plan.
As of December 31, 2014, Mr. Savoff and2017, Mr. May had a deferred account balancesbalance under a frozen Defined Contribution Restoration Plan. These amounts areThe amount is deemed invested, as chosen by the participant, in certain T. Rowe Price investment funds that are also available to participantsthe participant under the Savings Plan. Mr. Savoff and Mr. May havehas elected to receive the deferred account balancesbalance after they retire.he retires. The Defined Contribution Restoration Plan, until it was frozen in 2005, credited eligible employees’ deferral accounts with employer contributions to the extent contributions under the qualified savings plan in which the employee participated were subject to limitations imposed by the Internal Revenue Code.
Defined Contribution Restoration Plan
| | | Name | | Executive Contributions in 2014 | | Registrant Contributions in 2014 | | Aggregate Earnings in 2014 (1) | | Aggregate Withdrawals/ Distributions | | Aggregate Balance at December 31, 2014 | | Executive Contributions in 2017 | | Registrant Contributions in 2017 | | Aggregate Earnings in 2017(1) | | Aggregate Withdrawals/Distributions | | Aggregate Balance at December 31, 2017 |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (b) | | (c) | | (d) | | (e) | | (f) |
| | | | | | | | | | | | | | | | | | | | | |
| Phillip R. May, Jr. | |
| $— |
| |
| $— |
| |
| $359 |
| |
| $— |
| |
| $1,721 |
| |
| $— |
| |
| $— |
| |
| $362 |
| |
| $— |
| |
| $2,113 |
|
| | | | | | | | | | | | |
| Mark T. Savoff | |
| $— |
| |
| $— |
| |
| $8,224 |
| |
| $— |
| |
| $26,685 |
| |
| |
| (1) | Amounts in this column are not included in the Summary Compensation Table. |
20142017 Potential Payments uponUpon Termination or Change in Control
Entergy Corporation has plans and other arrangements that provide compensation to a Named Executive Officer if his or her employment terminates under specified conditions, including following a change in control of Entergy Corporation. In addition, Entergy Corporation has entered into a retention agreement with Mr. Denault that provides for payments upon certain employment termination events. There are no plans or agreements that would provide for payments to any of the Named Executive Officers solely upon a change in control.
its subsidiaries. The tables below reflect the amount of compensation each of the Named Executive Officers would have received if his or her employment with an Entergy System companyemployer had been terminated under various scenarios as of December 31, 2014.2017. For purposes of these tables, Entergy Corporation assumed that itsa stock price of $81.39 was $87.48,used, which was the closing market price on that date.
|
| | | | | | | | | | | | | | | | | | |
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement | Disability | Death | Change in Control | Termination Related to a Change in Control |
Leo P. Denault (1)(2) | | | | | | | | |
| | | | | | | | | |
Severance Payment(5) | — | — |
| $8,613,353 |
| — | — | — | — |
| $8,613,353 |
|
Performance Units:(7) | | | | | | | | |
| 2013-2015 Performance Unit Program | — | — |
| $2,112,642 |
|
| $2,166,880 |
|
| $2,112,642 |
|
| $2,112,642 |
| — |
| $2,112,642 |
|
| 2014-2016 Performance Unit Program | — | — |
| $2,112,642 |
|
| $1,166,371 |
|
| $2,112,642 |
|
| $2,112,642 |
| — |
| $2,112,642 |
|
Unvested Stock Options(9) | — | — |
| $3,501,327 |
|
| $3,501,327 |
|
| $3,501,327 |
|
| $3,501,327 |
| — |
| $3,501,327 |
|
Unvested Restricted Stock(11) | — | — |
| $1,791,514 |
| — |
| $1,791,514 |
|
| $1,791,514 |
| — |
| $1,791,514 |
|
Welfare Benefits(13) | — | — | — | — | — | — | — | |
| | | | | | | | | |
Haley Fisackerly (4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — | — | — | — | — | — | — |
| $424,107 |
|
Performance Units:(8) | | | | | | | | |
| 2013-2015 Performance Unit Program | — | — | — | — |
| $110,837 |
|
| $110,837 |
| — |
| $96,228 |
|
| 2014-2016 Performance Unit Program | — | — | — | — |
| $64,123 |
|
| $64,123 |
| — |
| $96,228 |
|
Unvested Stock Options(10) | — | — | — | — |
| $257,327 |
|
| $257,327 |
| — |
| $257,327 |
|
Unvested Restricted Stock(12) | — | — | — | — |
| $117,836 |
|
| $117,836 |
| — |
| $258,479 |
|
Welfare Benefits(14) | — | — | — | — | — | — | — |
| $18,324 |
|
| | | | | | | | | |
Andrew S. Marsh (4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — | — | — | — | — | — | — |
| $2,398,354 |
|
Performance Units:(8) | | | | | | | | |
| 2013-2015 Performance Unit Program | — | — | — | — |
| $433,988 |
|
| $433,988 |
| — |
| $489,888 |
|
| 2014-2016 Performance Unit Program | — | — | — | — |
| $274,075 |
|
| $274,075 |
| — |
| $489,888 |
|
Unvested Stock Options(10) | — | — | — | — |
| $1,392,890 |
|
| $1,392,890 |
| — |
| $1,392,890 |
|
Unvested Restricted Stock(12) | — | — | — | — |
| $298,482 |
|
| $298,482 |
| — |
| $752,247 |
|
Welfare Benefits(14) | — | — | — | — | — | — | — |
| $27,486 |
|
| | | | | | | | | |
Phillip R. May, Jr. (4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — | — | — | — | — | — | — |
| $1,014,750 |
|
Performance Units:(8) | | | | | | | | |
| 2013-2015 Performance Unit Program | — | — | — | — |
| $173,210 |
|
| $173,210 |
| — |
| $205,578 |
|
| 2014-2016 Performance Unit Program | — | — | — | — |
| $90,367 |
|
| $90,367 |
| — |
| $205,578 |
|
Unvested Stock Options(10) | — | — | — | — |
| $310,809 |
|
| $310,809 |
| — |
| $310,809 |
|
Unvested Restricted Stock(12) | — | — | — | — |
| $129,120 |
|
| $129,120 |
| — |
| $295,063 |
|
Welfare Benefits(14) | — | — | — | — | | | — |
| $27,486 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement | Disability | Death | Termination Related to a Change in Control |
A. Christopher Bakken, III(1) | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $2,511,506 |
|
Performance Units(7) | — |
| — |
| — |
| — |
|
| $620,680 |
|
| $620,680 |
|
| $1,530,132 |
|
Stock Options(8) | — |
| — |
| — |
| — |
|
| $408,336 |
|
| $408,336 |
|
| $408,336 |
|
Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $442,029 |
|
| $442,029 |
|
| $442,029 |
|
Welfare Benefits(10) | — |
| — |
| — |
| — |
| — |
| — |
|
| $20,358 |
|
Unvested Restricted Stock Units(12) | — |
| — |
|
| $813,900 |
| — |
|
| $813,900 |
|
| $813,900 |
|
| $2,441,700 |
|
| | | | | | | | |
Marcus V. Brown(2) | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $3,213,000 |
|
Performance Units(7) | — |
| — |
| — |
| $670,165 |
|
| $670,165 |
|
| $670,165 |
|
| $1,530,132 |
|
Stock Options(8) | — |
| — |
| — |
|
| $802,740 |
|
| $802,740 |
|
| $802,740 |
|
| $802,740 |
|
Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $1,041,711 |
|
| $1,041,711 |
|
| $1,054,082 |
|
Welfare Benefits(11) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| | | | | | | | |
Leo P. Denault(3) | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $10,119,954 |
|
Performance Units(6)(7) | — |
| — |
|
| $3,174,210 |
| $3,583,846 |
|
| $3,583,846 |
|
| $3,583,846 |
|
| $6,511,200 |
|
Stock Options(8) | — |
| — |
|
| $3,154,024 |
|
| $3,154,024 |
|
| $3,154,024 |
|
| $3,154,024 |
|
| $3,154,024 |
|
Restricted Stock(9) | — |
| — |
|
| $2,750,413 |
| — |
|
| $2,750,413 |
|
| $2,750,413 |
|
| $2,750,413 |
|
Welfare Benefits(11) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| | | | | | | | |
Haley R. Fisackerly(4) | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $497,420 |
|
Performance Units(7) | — |
| — |
| — |
| — |
|
| $147,886 |
|
| $147,886 |
|
| $358,116 |
|
Stock Options(8) | — |
| — |
| — |
| — |
|
| $130,910 |
|
| $130,910 |
|
| $130,910 |
|
Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $161,966 |
|
| $161,966 |
|
| $164,163 |
|
Welfare Benefits(10) | — |
| — |
| — |
| — |
| — |
| — |
|
| $18,252 |
|
| | | | | | | | |
Andrew S. Marsh(4) | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $3,060,000 |
|
Performance Units(7) | — |
| — |
| — |
| — |
|
| $670,165 |
|
| $670,165 |
|
| $1,530,132 |
|
Stock Options(8) | — |
| — |
| — |
| — |
|
| $802,740 |
|
| $802,740 |
|
| $802,740 |
|
Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $1,041,711 |
|
| $1,041,711 |
|
| $1,054,082 |
|
Welfare Benefits(10) | — |
| — |
| — |
| — |
| — |
| — |
|
| $27,378 |
|
Unvested Restricted Stock Units(13) | — |
| — |
| — |
| — |
|
| $1,717,329 |
|
| $1,717,329 |
|
| $1,717,329 |
|
| | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement | Disability | Death | Change in Control | Termination Related to a Change in Control |
Hugh T. McDonald (1)(3) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — | — | — | — | — | — | — |
| $528,181 |
|
Performance Units:(8) | | | | | | | | |
| 2013-2015 Performance Unit Program | — | — | — |
| $110,837 |
|
| $110,837 |
|
| $110,837 |
| — |
| $96,228 |
|
| 2014-2016 Performance Unit Program | — | — | — |
| $64,123 |
|
| $64,123 |
|
| $64,123 |
| — |
| $96,228 |
|
Unvested Stock Options(10) | — | — | — |
| $250,034 |
|
| $250,034 |
|
| $250,034 |
| — |
| $250,034 |
|
Unvested Restricted Stock(12) | — | — | — | — |
| $118,273 |
|
| $118,273 |
| — |
| $252,776 |
|
Welfare Benefits(13) | — | — | — | — | — | — | — | |
| | | | | | | | | |
Alyson M. Mount (4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — | — | — | — | — | — | — |
| $963,520 |
|
Performance Units:(8) | | | | | | | | |
| 2013-2015 Performance Unit Program | — | — | — | — |
| $174,960 |
|
| $174,960 |
| — |
| $205,578 |
|
| 2014-2016 Performance Unit Program | — | — | — | — |
| $90,367 |
|
| $90,367 |
| — |
| $205,578 |
|
Unvested Stock Options(10) | — | — | — | — |
| $342,390 |
|
| $342,390 |
| — |
| $342,390 |
|
Unvested Restricted Stock(12) | — | — | — | — |
| $150,203 |
|
| $150,203 |
| — |
| $330,801 |
|
Welfare Benefits(14) | — | — | — | — | — | — | — |
| $9,148 |
|
| | | | | | | | | |
Sallie T. Rainer (4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — | — | — | — | — | — | — |
| $417,585 |
|
Performance Units:(8) | | | | | | | | |
| 2013-2015 Performance Unit Program | — | — | — | — |
| $110,837 |
|
| $110,837 |
| — |
| $96,228 |
|
| 2014-2016 Performance Unit Program | — | — | — | — |
| $64,123 |
|
| $64,123 |
| — |
| $96,228 |
|
Unvested Stock Options(10) | — | — | — | — |
| $229,467 |
|
| $229,467 |
| — |
| $229,467 |
|
Unvested Restricted Stock(12) | — | — | — | — |
| $121,072 |
|
| $121,072 |
| — |
| $261,921 |
|
Welfare Benefits(14) | — | — | — | — | — | — | — |
| $18,234 |
|
| | | | | | | | | |
Charles R. Rice, Jr (4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — | — | — | — | — | — | — |
| $367,201 |
|
Performance Units:(8) | | | | | | | | |
| 2013-2015 Performance Unit Program | — | — | — | — |
| $110,837 |
|
| $110,837 |
| — |
| $96,228 |
|
| 2014-2016 Performance Unit Program | — | — | — | — |
| $64,123 |
|
| $64,123 |
| — |
| $96,228 |
|
Unvested Stock Options(10) | — | — | — | — |
| $227,488 |
|
| $227,488 |
| — |
| $227,488 |
|
Unvested Restricted Stock(12) | — | — | — | — |
| $100,340 |
|
| $100,340 |
| — |
| $217,649 |
|
Welfare Benefits(14) | — | — | — | — | — | — | — |
| $18,324 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement | Disability | Death | Termination Related to a Change in Control |
Phillip R. May, Jr.(2) | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $1,171,680 |
|
Performance Units(7) | — |
| — |
| — |
|
| $231,962 |
|
| $231,962 |
|
| $231,962 |
|
| $504,618 |
|
Stock Options(8) | — |
| — |
| — |
|
| $183,342 |
|
| $183,342 |
|
| $183,342 |
|
| $183,342 |
|
Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $201,034 |
|
| $201,034 |
|
| $203,231 |
|
Welfare Benefits(11) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| | | | | | | | |
Sallie T. Rainer(2) | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $459,585 |
|
Performance Units(7) | — |
| — |
| — |
|
| $147,886 |
|
| $147,886 |
|
| $147,886 |
|
| $358,116 |
|
Stock Options(8) | — |
| — |
| — |
|
| $133,082 |
|
| $133,082 |
|
| $133,082 |
|
| $133,082 |
|
Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $163,269 |
|
| $163,269 |
|
| $165,222 |
|
Welfare Benefits(11) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| | | | | | | | |
Charles R. Rice, Jr(4) | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $400,993 |
|
Performance Units(7) | — |
| — |
| — |
| — |
|
| $147,886 |
|
| $147,886 |
|
| $358,116 |
|
Stock Options(8) | — |
| — |
| — |
| — |
|
| $90,728 |
|
| $90,728 |
|
| $90,728 |
|
Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $133,480 |
|
| $133,480 |
|
| $135,433 |
|
Welfare Benefits(10) | — |
| — |
| — |
| — |
| — |
| — |
|
| $18,252 |
|
| | | | | | | | |
Richard C. Riley(2) | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $481,880 |
|
Performance Units(7) | — |
| — |
| — |
|
| $147,886 |
|
| $147,886 |
|
| $147,886 |
|
| $358,116 |
|
Stock Options(8) | — |
| — |
| — |
|
| $120,814 |
|
| $120,814 |
|
| $120,814 |
|
| $120,814 |
|
Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $178,896 |
|
| $178,896 |
|
| $181,663 |
|
Welfare Benefits(11) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| | | | | | | | |
Roderick K. West(4) | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $3,434,065 |
|
Performance Units(7) | — |
| — |
| — |
| — |
|
| $670,165 |
|
| $670,165 |
|
| $1,530,132 |
|
Stock Options(8) | — |
| — |
| — |
| — |
|
| $613,132 |
|
| $613,132 |
|
| $613,132 |
|
Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $762,624 |
|
| $762,624 |
|
| $774,344 |
|
Welfare Benefits(10) | — |
| — |
| — |
| — |
| — |
| — |
|
| $27,378 |
|
Unvested Restricted Stock Units(14) | — |
| — |
|
| $1,709,190 |
| — |
| — |
| — |
|
| $1,709,190 |
|
|
| | | | | | | | | | | | | | | | | | |
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement | Disability | Death | Change in Control | Termination Related to a Change in Control |
Mark T. Savoff (1)(3) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — | — | — | — | — | — | — |
| $3,278,006 |
|
Performance Units:(8) | | | | | | | | |
| 2013-2015 Performance Unit Program | — | — | — |
| $443,261 |
|
| $443,261 |
|
| $443,261 |
| — |
| $489,888 |
|
| 2014-2016 Performance Unit Program | — | — | — |
| $274,075 |
|
| $274,075 |
|
| $274,075 |
| — |
| $489,888 |
|
Unvested Stock Options(10) | | | |
| $1,146,938 |
|
| $1,146,938 |
|
| $1,146,938 |
| — |
| $1,146,938 |
|
Unvested Restricted Stock(12) | — | — | — |
|
| $278,099 |
|
| $278,099 |
| — |
| $648,346 |
|
Welfare Benefits(13) | — | — | — | — | — | — | — | — |
| | | | | | | | | |
Roderick K. West (4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — | — | — | — | — | — | — |
| $3,192,348 |
|
Performance Units:(8) | | | | | | | | |
| 2013-2015 Performance Unit Program | — | — | — | — |
| $443,261 |
|
| $443,261 |
| — |
| $489,888 |
|
| 2014-2016 Performance Unit Program | — | — | — | — |
| $274,075 |
|
| $274,075 |
| — |
| $489,888 |
|
Unvested Stock Options(10) | | | | |
| $1,647,093 |
|
| $1,647,093 |
| — |
| $1,647,093 |
|
Unvested Restricted Stock(12) | — | — | — | — |
| $440,199 |
|
| $440,199 |
| — |
| $1,004,859 |
|
Welfare Benefits(14) | — | — | — | — | — |
| | — |
| $27,486 |
|
Unvested Restricted Units(15) | — | — |
| $1,837,080 |
| — | — | — | — |
| $1,837,080 |
|
| |
(1)1) | In addition to the payments and benefits in the table, if Mr. Bakken’s employment were terminated under certain conditions relating to a change in control, on the first day of the month following the Qualifying Event (as defined in the Cash Balance Equalization Plan) he would have become vested in and would have been entitled to receive his vested pension benefits accumulated in the Cash Balance Equalization Plan as of the date of the Qualifying Event so long as a forfeiture event does not occur as described in the plan. For a description of the pension benefits under the Cash Balance Equalization Plan, see “2017 Pension Benefits.” |
| |
| 2) | As of December 31, 2014, Mr. Denault, Mr. McDonald,2017, Messrs. Brown, May, and Mr. SavoffRiley and Ms. Rainer are retirement eligible and would retire rather than voluntarily resign.resign, and in addition to the payments and benefits in the table, each also would be entitled to receive his or her vested pension benefits under the Entergy Retirement Plan. For a description of the pension |
benefits available, see “2017 Pension BenefitsBenefits.” In the event their termination by their Entergy employer without cause or by Mr. Brown, Mr. May, Ms. Rainer, or Mr. Riley for good reason in connection with a change in control, each would be eligible for subsidized early retirement benefits under the System Executive Retirement Plan even if they do not have company permission to separate from employment. If Mr. Brown’s, Mr. May’s, Ms. Rainer’s, or Mr. Riley’s employment were terminated for cause in connection with a change in control, they would not be entitled to receive a benefit under the System Executive Retirement Plan. If their employment were terminated for any reason not in connection with a change in control, or they were to retire from their Entergy employer before age 65 without the permission of their Entergy employer, they would not be entitled to receive a benefit under the System Executive Retirement Plan.
| |
(2)3) | InAs of December 31, 2017, Mr. Denault is retirement eligible and would retire rather than voluntarily resign, and in addition to the payments and benefits in the table, Mr. Denault also would have beenbe entitled to receive his vested pension benefits.benefits under the Entergy Retirement Plan. For a description of the pension benefits available, see “2017 Pension Benefits.” If Mr. Denault’s employment was terminated by his Entergy employer other than for cause, by Mr. Denault for good reason or on account of his death or disability, he would also be eligible for certain additional retirement benefits. For a description of these benefits, see “2017 Pension Benefits.” Otherwise, if Mr. Denault’s employment was terminated for cause or he was to retire from his Entergy employer before age 65 without the permission of his Entergy employer, he would not receive a benefit under the System Executive Retirement Plan. |
| |
| 4) | In addition to the payments and benefits in the table, if Mr. Fisackerly’s, Mr. Marsh’s, Mr. Rice’s, or Mr. West’s employment were terminated under certain conditions relating to a change in control, he would also be eligible for early retirement benefits. For a description of these benefits, see “2014 Pension Benefits.” In addition, Mr. Denault is subject to the following provisions: |
Mr. Denault’s retention agreement provides that, unless his employment is terminated for cause, he will be granted an additional 15 years of service under the System Executive Retirement Plan if he continues to work for an Entergy System company employer and after age 55, retires with the permission of his employer or his employment is terminated due to death or disability. If Mr. Denault’s employment is terminated for cause, he will forfeit his benefit under the System Executive Retirement Plan.
Under his retention agreement, if Mr. Denault’s employment is terminated by Mr. Denault for good reason or by Entergy Corporation not for cause (regardless of whether there is a change in control) or on account of disability, Mr. Denault would be eligible for subsidized retirement and the additional 15 years of service upon his separation of service even if he does not have permission to separate from employment.
| |
(3) | In addition to the payments and benefits in the table, Mr. McDonald and Mr. Savoff each would have been eligible to retire and entitled to receive his vested pension benefits. For a description of the pension benefits available see, “2014 Pension Benefits.” In the event of a termination by Entergy Corporation without cause or by the executive for good reason in connection with a change in control, Mr. McDonald and Mr. Savoff each would be eligible for subsidized early retirement benefits under the System Executive Retirement Plan even if he does not have permission to separate from employment. If Mr. McDonald’s and Mr. Savoff’s |
employment were terminated for cause, he would not receive a benefit under the System Executive Retirement Plan.
| |
(4) | In addition to the payments and benefits in the table, if a Named Executive Officer's, other than Messrs. Denault, McDonald, and Savoff, employment was terminated under certain conditions relating to a change in control, he or she also would have been entitled to receive his or her vested pension benefits upon attainment of age 55 under the Entergy Retirement Plan and would have been eligible for early retirement benefits under the System Executive Retirement Plan calculated using early retirement reduction factors. For a description of the pension benefits, see “2014“2017 Pension Benefits.” If the Named Executive Officers’, other than Messrs. Denault, McDonald, and Savoff,Mr. Fisackerly’s, Mr. Marsh’s, Mr. Rice’s, or Mr. West’s employment were terminated for cause in connection with a change in control, he would not be entitled to receive a benefit under the System Executive Retirement Plan. If his employment were terminated for any reason not in connection with a change in control, or sheeach were to resign from his Entergy employer before age 65 without the permission of his Entergy employer, each would forfeit his or hernot be entitled to receive a benefit under the System Executive Retirement Plan. |
Severance PaymentsPayments:
| |
(5) | In the event of a termination (not due to death or disability) by Mr. Denault for good reason or by Entergy Corporation not for cause (regardless of whether there is a change in control), Mr. Denault would be entitled to receive, pursuant to his retention agreement, a lump sum severance payment equal to the product of 2.99 times the sum of (a) his annual base salary as in effect at any time within one year prior to the effective date of the retention agreement or, if higher, immediately prior to a circumstance constituting good reason plus (b) the greater of (i) his actual annual incentive award under the Annual Incentive Plan for the calendar year immediately preceding the calendar year in which Mr. Denault’s termination date occurs or (ii) Mr. Denault’s Annual Incentive Plan target award for the calendar year in which the effective date of the retention agreement occurred. For purposes of this table, we have calculated the award using a base salary of $1,110,000 and his preceding year’s actual annual incentive award, $1,770,720. |
| |
(6)5) | In the event of a termination (not due to death or disability) by the executive for good reason or by his or her Entergy Corporationsystem employer not for cause during the period beginning upon the occurrence of a “potential change in control” (as defined in the System Executive Continuity Plan) and ending on the 2nd anniversary of a change in control, each Named Executive Officer other than Mr. Denault, would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to a multiple of the sum of (1) his or her annual base salary as in effect at any time within one year prior to the commencement of a change of control period or, if higher, immediately prior to a circumstance constituting good reason plus (2) his or her annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for 2015 and 2016 (the two calendar years immediately preceding the calendar year in which termination occurs), but in no event shall the severance payment exceed the product of for Mr. Marsh, Mr. Savoff, and Mr. West 2.99 times for Mr. May and Ms. Mount 2 times and Mr. Fisackerly, Mr. McDonald, Ms. Rainer, and Mr. Rice 1 time the sum of (a) his or her annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) the higher of his or her actual annual incentive payment under the Annual Incentive Plan for the 2016 performance year or his or her annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the2015 and 2016 (the two calendar years immediately preceding the calendar year in his or herwhich termination occurs.occurs). For purposes of this table, it assumes the following target opportunity and base salary:salary were assumed: |
| | | Named Executive Officer | Target Opportunity | Base Salary | Target Opportunity | Base Salary |
| A. Christopher Bakken III | | 35% | $620,125 |
| Marcus V. Brown | | 70% | $630,000 |
| Leo P. Denault | | 130% | $1,230,000 |
| Haley R. Fisackerly | 40% | $302,934 | 40% | $355,300 |
| Andrew S. Marsh | 55% | $517,500 | 70% | $600,000 |
| Phillip R. May | 50% | $338,250 | |
| Hugh T. McDonald | 50% | $352,121 | |
| Alyson M. Mount | 60% | $301,100 | |
| Phillip R. May Jr, | | 60% | $366,150 |
| Sallie T. Rainer | 40% | $298,275 | 40% | $328,275 |
| Charles L. Rice, Jr. | 40% | $262,287 | 40% | $286,424 |
| Mark T. Savoff | 70% | 644,896 | |
| Richard C. Riley | | 40% | $344,200 |
| Roderick K. West | 70% | 628,044 | 70% | $675,598 |
Performance UnitsUnits:
| |
(7)6) | InWith respect to Mr. Denault, in the event of a termination due to death or disability, byTermination Event (as defined in Mr. Denault for good reason, or by Entergy Corporation not for cause (in all cases, regardless of whether thereDenault’s 2006 retention agreement), he is a change in control), Mr. Denault would have forfeited his performance units for all open performance periods and would have been entitled to receive a single-lump sum severance payment pursuant toTarget LTIP Award, as defined in his 2006 retention agreement, that would not be based on any outstanding performance periods. The payment would be calculated by using the average annual number of performance units with respect to the two most recent performance periods preceding the calendar year in which his employment termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Mr. Denault’s retention payment was calculated by taking an average of the target performance units from the 2013-2015 Performance Unit Program (38,000) and from the 2014-2016 Performance Unit Program (40,000). This average number of units (39,000) multiplied by the closing price of Entergy Corporation’s common stock on December 29, 2017 ($81.39) would equal a payment of $3,174,210. In the event of death or disability, Mr. Denault receives the greater of the Target LTIP Award calculated as described above or the sum of the amount that would be payable under the provisions of each open Performance Unit Program as described in Note 7 below. |
units he would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which his termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Mr. Denault’s severance payment was calculated by taking an average of the target performance units from the 2010-2012 Performance Unit Program (22,300 units) and the 2011-2013 Performance Unit Program (26,000 units). This average number of units (24,150 units) multiplied by the closing price of Entergy stock on December 31, 2014 ($87.48) would equal a severance payment of $2,112,642 for the forfeited performance units.
In the event of Mr. Denault’s retirement not related to a change in control, Mr. Denault would not have forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on his number of months of participation in each open Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period. For purposes of the table, the value of Mr. Denault’s awards were calculated as follows:
2013 - 2015 Plan - 24,770 (24/36*37,156) performance units at target, assuming a stock price of $87.48
2014 - 2016 Plan - 13,333 (12/36*40,000) performance units at target, assuming a stock price of $87.48
| |
(8)7) | In the event of a qualifying termination related to a change in control, each Named Executive Officer other than Mr. Denault, would have forfeited his or her performance units for the 2013-20152016-2018 and 2014-20162017-2019 performance periods and would have been entitled to receive, pursuant to the 20112015 Equity Ownership Plan, a single-lump sum severance payment in lieu of any payment for each performance award that would not be based on any outstanding performance periods. For bothperiod. The payments for the 2013-20152016-2018 and the 2014-20162017-2019 performance periods the payment would have been calculated using the average annual number of performance units he or she would have been entitled to receive under each Performance Unit Program with respect to the two most recent performance periodsperiod preceding (but not including) the calendar year in which his or her termination occurs, assuming alloccurs. For purposes of the table, the value of Mr. Denault’s payments was calculated by multiplying the target performance goals were achieved at target multipliedunits for the 2014-2016 Performance Unit Program (40,000) by the closing price of Entergy Corporation’s common stock on December 31, 2014.29, 2017 ($81.39), which would equal a payment of $3,255,600 for the forfeited performance units for each performance period. The value of the payments for the other Named Executive Officers was calculated by multiplying the target performance units for the 2014-2016 Performance Unit Program (9,400) by the closing price of Entergy Corporation’s common stock on December 29, 2017 ($81.39), which would equal a payment of $765,066 for the forfeited performance units for each performance period. In the event his death or disability, Mr. Denault would receive the greater of the target Long-Term Performance Incentive award as described in note 6 above or a pro-rated number of performance units for all open performance periods, based on the number of months of his participation in each open performance period. |
For purposes of the table, the value of the severance payment for Mr. Fisackerly, Mr. McDonald, Ms. Rainer and Mr. Rice was calculated by taking an average of the target performance units from the 2010-2012 Performance Unit Program (1,000 units) and the 2011-2013 Performance Unit Program (1,200 units). This average number of units (1,100) multiplied by the closing price of Entergy stock on December 31, 2014 ($87.48) would equal a severance payment of for the forfeited performance units equal to $96,228.
The value of severance payment for Mr. May and Ms. Mount was calculated by taking an average of the target performance units from the 2010-2012 Performance Unit Program (2,200 units) and the 2011-2013 Performance Unit Program (2,500 units). This average number of units (2,350) multiplied by the closing price of Entergy stock on December 31, 2014 ($87.48) would equal a severance payment of for the forfeited performance units equal to $205,578.
The value of severance payment for Mr. Marsh, Mr. Savoff, and Mr. West was calculated by taking an average of the target performance units from the 2010-2012 Performance Unit Program (5,300 units) and the 2011-2013 Performance Unit Program (5,900 units). This average number of units (5,600) multiplied by the closing price of Entergy stock on December 31, 2014 ($87.48) would equal a severance payment of for the forfeited performance units equal to $489,888.
In the event of death or disability, or retirement in the case of Mr. McDonaldBrown, Mr. Denault, Mr. May, Ms. Rainer, or Mr. Savoff,Riley, or upon death or disability, other than Mr. Denault, each Named Executive Officer other than Mr. Denault, would not have forfeited his or her performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on his or her number of months of participation in each open Performance Unit Program performance cycle,period, in accordance with his or her grant agreement under the Performance Unit Program. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period. For purposes of the table, the valuevalues of the awards were calculated as follows:
Mr. Fisackerly’s, Mr. McDonald’s, Ms. Rainer’s and Mr. Rice’s awards:Denault’s:
20132016 - 20152018 Plan - 1,26727,800 (24/36*1,900)41,700) performance units at target, assuming a stock price of $87.48$81.39
20142017 - 20162019 Plan - 73316,233 (12/36*2,200)48,700) performance units at target, assuming a stock price of $87.48$81.39
Mr. Marsh’s awards:Bakken’s:
20132016 - 20152018 Plan - 4,9614,859 (24/36*7,442)7,289) performance units at target, assuming a stock price of $87.48$81.39
20142017 - 20162019 Plan - 3,1332,767 (12/36*9,400)8,300) performance units at target, assuming a stock price of $87.48$81.39
Mr. May’s awards:Messrs. Brown’s, Marsh’s, and West’s:
20132016 - 20152018 Plan - 1,9805,467 (24/36*2,969)8,200) performance units at target, assuming a stock price of $87.48$81.39
20142017 - 20162019 Plan - 1,0332,767 (12/36*3,100)8,300) performance units at target, assuming a stock price of $87.48$81.39
Ms. Mount’s awards:
2013Mr. May’s:
2016 - 20152018 Plan - 2,0001,800 (24/36*3,000)2,700) performance units at target, assuming a stock price of $87.48$81.39
20142017 - 20162019 Plan - 1,0331,050 (12/36*3,100)3,150) performance units at target, assuming a stock price of $87.48$81.39
Mr. Savoff’s
Messrs. Fisackerly’s, Rice’s, Riley’s, and Mr. West’s awards:Ms. Rainer’s:
2013
2016 - 20152018 Plan - 5,0671,200 (24/36*7,600)1,800) performance units at target, assuming a stock price of $87.48$81.39
20142017 - 20162019 Plan - 3,133617 (12/36*9,400)1,850) performance units at target, assuming a stock price of $87.48$81.39
Unvested
Stock OptionsOptions:
| |
(9) | In the event of Mr. Denault’s retirement, death or disability (pursuant to the 2011 Equity Ownership Plan) or upon termination by Mr. Denault for good reason or by Entergy Corporation not for cause (regardless of whether there is a change in control), pursuant to his retention agreement, all of Mr. Denault’s unvested stock options would immediately vest. In addition, he would be entitled to exercise any unexercised options during a ten-year term extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Denault exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2014, and the exercise price of each option share. |
| |
(10)8) | In the event of death or disability or qualifying termination related to a change in control, or retirement in the case of Mr. McDonaldBrown, Mr. Denault, Mr. May, Ms. Rainer, or Mr. Savoff,Riley, all of the unvested stock options of each Named Executive Officer other than Mr. Denault, would immediately vest pursuant to the Equity Ownership Plans. In addition, with respect to grants under the 2011 Equity Ownership Plan. In addition,Plan, each Named Executive Officer would be entitled to exercise his or her stock options for the remainder of the ten-year period extending from the grant date of the options.options, and with respect to grants under the 2015 Equity Ownership Plan, within the lesser of five years or the remaining term of the option grant. For purposes of this table, it is assumed that the Named Executive Officers other than Mr. Denault, exercised their options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2014,29, 2017, and the applicable exercise price of each option share. |
Unvested
In the event of a Termination Event as defined in his 2006 retention agreement, Mr. Denault will immediately vest in all unvested stock options.
Restricted StockStock:
| |
(11) | Pursuant to his retention agreement, in the event of Mr. Denault's death or disability or upon termination by Mr. Denault for good reason or by Entergy Corporation not for cause (regardless of whether there is a change in control), all of Mr. Denault’s unvested restricted stock would immediately vest. |
| |
(12)9) | In the event of death or disability (pursuantpursuant to the 2011 Equity Ownership Plan),Plan, each Named Executive Officer other than Mr. Denault, would immediately vest in a pro-rated portion of his or her unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month12-month grant date anniversary date, (asas well as dividends declared on the pro-rated portion of such restricted stock)stock pursuant to the 2011 Equity Ownership Plan. The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month12-month grant date anniversary date and the date of his or her death or disability. In the event of his or her qualifying termination related to a change in control, thea Named Executive Officers, other than Mr. Denault,Officer would immediately vest in all of their unvested restricted stock.stock, as well as dividends declared on such restricted stock granted pursuant the 2011 Equity Ownership Plan. In the event of death, disability, or qualifying termination related to a change in control, each Named Executive Officer would vest in all of their unvested restricted stock as well as dividends declared pursuant to the 2015 Equity Ownership Plan. |
In the event of a Termination Event as defined in his 2006 retention agreement, Mr. Denault will immediately vest in all unvested restricted stock.
Welfare BenefitsBenefits:
| |
(13) | Upon retirement, Mr. Denault, Mr. McDonald, and Mr. Savoff would be eligible for retiree medical and dental benefits, the same as all other retirees. Pursuant to the System Executive Continuity Plan, in the event of a |
termination related to a change in control, Messrs. Denault, McDonald, and Savoff would not be eligible to receive Entergy Corporation subsidized COBRA benefits.
| |
(14)10) | Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Marsh,Bakken, Mr. May, Ms. MountMarsh, and Mr. West would be eligible to receive Entergy Corporation subsidizedEntergy-sponsored COBRA benefits for 18 months and Mr. Fisackerly Ms. Rainer, and Mr. Rice would be eligible to receive Entergy Corporation subsidizedEntergy-sponsored COBRA benefits for 12 months. |
| |
| 11) | Upon retirement, Mr. Brown, Mr. Denault, Mr. May, Ms. Rainer, and Mr. Riley would be eligible for retiree medical and dental benefits, the same as all other retirees. |
Unvested Restricted Stock UnitsUnits:
| |
(15)12) | Mr.Bakken’s 30,000 restricted stock units vest 1/3rd on each of April 6, 2019, April 6, 2022, and April 6, 2025. Pursuant to his restricted stock unit agreement, if Mr. Bakken’s employment terminates due to total disability or death or, prior to April 6, 2019, Mr. Bakken’s employment is terminated by his Entergy employer other than for cause, then he will vest in and be paid the 10,000 restricted stock units that otherwise would have vested had he satisfied the vesting conditions of the restricted stock unit agreement through the next vesting date to occur following his date of total disability, death, or termination other than for cause prior to April 6, 2019 subject, in the case of a termination without cause, to Mr. Bakken timely executing and not revoking a release of claims against Entergy Corporation and its affiliates. In the event of a change in control, the unvested restricted stock units will fully vest upon Mr. Bakken’s termination of employment by his Entergy employer without cause or by Mr. Bakken with good reason during a change in control period (as defined in the 2015 Equity Ownership Plan). Otherwise, if Mr. Bakken voluntarily resigns or is terminated, he would forfeit these units. Pursuant to his restricted stock unit agreement, Mr. Bakken is subject to certain restrictions on his ability to compete with Entergy Corporation and its affiliates or solicit its employees or customers during and for 12 months after his employment with his Entergy employer. In addition, the restricted stock unit agreement limits Mr. Bakken’s ability to disparage Entergy Corporation and its affiliates. In the event of a breach of these restrictions, other than following certain constructive terminations of his employment, Mr. Bakken will forfeit any restricted stock units that are not yet vested and paid, and must repay to Entergy Corporation any shares of Entergy Corporation’s common stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares. |
| |
| 13) | Mr. Marsh’s 21,100 restricted stock units vest 100% in 2020. Pursuant to his restricted stock unit agreement, any unvested restricted stock units will vest immediately in the event of his termination of employment due to Mr. Marsh’s total disability or death. In the event of a change in control, the units will vest upon termination of Mr. Marsh’s employment by his Entergy employer without cause or by Mr. Marsh with good reason during a change in control period (as defined in the 2015 Equity Ownership Plan). Otherwise, if Mr. Marsh voluntarily resigns or is terminated, he would forfeit these units. Pursuant to his restricted stock unit agreement, Mr. Marsh is subject to certain restrictions on his ability to compete with Entergy Corporation and its affiliates during and for 12 months after his employment with Entergy Corporation, or to solicit its employees or customers during and for 24 months after his employment with it. In addition, the restricted stock unit agreement limits Mr. Marsh’s ability to disparage Entergy Corporation and its affiliates. In the event of a breach of these restrictions, Mr. Marsh will forfeit any restricted stock units that are not yet vested and paid, and must repay to Entergy Corporation any shares of Entergy Corporation’s common stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares. |
| |
| 14) | Mr. West’s 21,000 restricted stock units vest 100% in 2018. Pursuant to his restricted stock unit agreement, any unvested restricted stock units will vest immediately in the event of a termination for a reason other than cause, total disability, or death. Thefor cause. In the event of a change in control, the units will vest upon termination within 24 months of a change in controlMr. West’s employment by his Entergy employer without cause or by Mr. West with good reason. Ifreason during a change in control period (as defined in the 2011 Equity Ownership Plan). Otherwise, if Mr. West voluntarily resigns, or is terminated for cause, dies, or becomes disabled, he would forfeit these units. |
Mr. Denault’s 2006 Retention Agreement
Under the terms of his 2006 retention agreement, Mr. Denault’s retention agreement, Entergy Corporationemployment may terminate his employmentbe terminated for cause upon Mr. Denault’s:
continuing failure to substantially perform his duties (other than because of physical or mental illness or after he has given notice of termination for good reason) that remains uncured for 30 days after receiving a written notice from the Personnel Committee;
willfully engaging in conduct that is demonstrably and materially injurious to Entergy Corporation;
conviction of or entrance of a plea of guilty or nolo contendere to a felony or other crime that has or may have a material adverse effect on his ability to carry out his duties or upon Entergy Corporation’s reputation;
material violation of any agreement that he has entered into with Entergy Corporation; or
unauthorized disclosure of Entergy Corporation’s confidential information.
Mr. Denault may terminate his employment for good reason upon:
the substantial reduction in the nature or status of his duties or responsibilities from those in effect immediately prior to the date of the retention agreement, other than de minimis acts that are remedied after notice from Mr. Denault;
a reduction of 5% or more in his base salary as in effect on the date of the retention agreement;
the relocation of his principal place of employment to a location other than the corporate headquarters;
the failure to continue to allow him to participate in programs or plans providing opportunities for equity awards, stock options, restricted stock, stock appreciation rights, incentive compensation, bonus and other plans on a basis not materially less favorable than enjoyed at the time of the retention agreement (other than changes similarly affecting all senior executives);
the failure to continue to allow him to participate in programs or plans with opportunities for benefits not materially less favorable than those enjoyed by him or her under any of Entergy Corporation’s pension, savings, life insurance, medical, health and accident, disability, or vacation plans or policies at the time of the retention agreement (other than changes similarly affecting all senior executives); or
any purported termination of his employment not taken in accordance with his retention agreement.
System Executive Continuity Plan
Termination Related to a Change in Control
The
Entergy Corporation’s Named Executive Officers will be entitled to the benefits described in the tables above under the System Executive Continuity Plan in the event of a termination related to a change in control if a change in control occurs and their employment is terminated by antheir Entergy System companyemployer other than for cause or if they terminate their employment for good reason, in each case within a period beginning on the occurrence of a potential change in control and ending 24 months following the effective date of a change in control.
A change in control includes the following events:
The
the purchase of 30% or more of either Entergy CorporationCorporation’s common stock or the combined voting power of itsEntergy Corporation’s voting securities;
the merger or consolidation of Entergy Corporation (unless its Board members constitute at least a majority of the board members of the surviving entity);
the liquidation, dissolution, or sale of all or substantially all of Entergy Corporation’s assets; or
a change in the composition of Entergy Corporation’s Board such that, during any two-year period, the individuals serving at the beginning of the period no longer constitute a majority of theEntergy Corporation’s Board at the end of the period.
A potential change in control includes the following events:
Entergy Corporation or an affiliate enters into an agreement the consummation of which would constitute a change in control;
the Entergy Corporation Board adopts resolutions determining that, for purposes of the System Executive Continuity Plan, a potential change in control has occurred;
an Entergya System Company or other person or entity publicly announces an intention to take actions that would constitute a change in control; or
any person or entity becomes the beneficial owner (directly or indirectly) of outstanding shares of Entergy Corporation’s common stock of Entergy Corporation constituting 20% or more of the voting power or value of Entergy Corporation’s outstanding common stock.
A Named Executive Officer’s employment may be terminated for cause under the System Executive Continuity Plan if he or she:
willfully and continuously fails to substantially perform his or her duties after receiving a 30-day written demand for performance from theEntergy Corporation’s Board;
engages in conduct that is materially injurious to Entergy Corporation or any of its subsidiaries;
is convicted or pleads guilty or nolo contendere to a felony or other crime that materially and adversely affects his or her ability to perform his or her duties or Entergy Corporation’s reputation;
materially violates any agreement with Entergy Corporation or any of its subsidiaries; or
discloses any of Entergy CorporationCorporation’s confidential information without authorization.
A Named Executive Officer may terminate his or her employment with anhis or her Entergy System Companyemployer for good reason under the System Executive Continuity Plan if, without his or her consent:
the nature or status of his or her duties and responsibilities is substantially altered or reduced compared to the period prior to the change in control;
his or her salary is reduced by 5% or more;
he or she is required to be based outside of the continental United States at somewhere other than his or her primary work location prior to the change in control;
any of his or her compensation plans are discontinued without an equitable replacement;
his or her benefits or number of vacation days are substantially reduced; or
his or her Entergy employer purports to terminate his or her employment other than in accordance with the System Executive Continuity Plan.
In addition to participation in the System Executive Continuity Plan, benefits already accrued under the System Executive Retirement Plan, Pension Equalization Plan, and Supplemental RetirementCash Balance Equalization Plan, if any, will become fully vested if the executive is involuntarily terminated without cause or the executive terminates his or her employment for good reason within two years after the occurrence of a change in control. Any awards granted under the equity ownership plansEquity Ownership Plans will become fully vested if the executive is involuntarily terminated without cause or terminates employment for good reason within two years after the occurrence of a change in control. In 2010, Entergy Corporation eliminated tax gross up payments for any severance benefits paid under the System Executive Continuity Plan.
Under certain circumstances described below, the payments and benefits received by a Named Executive Officer pursuant to the System Executive Continuity Plan may be forfeited and, in certain cases, subject to repayment. Benefits are no longer payable under the System Executive Continuity Plan, and unvested performance units under the Performance Unit Program are subject to forfeiture, if the executive:
accepts employment with Entergy Corporation or any of its subsidiaries;
elects to receive the benefits of another severance or separation program;
removes, copies or fails to return any property belonging to Entergy Corporation or any of its subsidiaries;
discloses non-public data or information concerning Entergy Corporation or any of its subsidiaries; or
violates his or her non-competitionnon-compete provision, which generally runs for two years but extends to three years if permissible under applicable law.
Furthermore, if the executive discloses non-public data or information concerning Entergy Corporation or any of its subsidiaries or violates his or her non-competitionnon-compete provision, he or she will be required to repay any benefits previously received under the System Executive Continuity Plan.
Voluntary Resignation
If a Named Executive Officer voluntarily resigns from his or her Entergy employer:
all unvested stock options, shares of restricted stock and restricted stock units as well as any perquisites to which he or she is entitled as an officer are forfeited;
incentive payments under any outstanding performance periods under the Long-Term Performance Unit Program or the Annual Incentive Plan are forfeited; provided however, if an officer resigns after the completion of an Annual Incentive Plan or Long-Term Performance Unit Program performance period, he or she could receive a payout under the Long-Term Performance Unit Program based on the outcome of the performance period and could, at Entergy Corporation’s discretion, receive an annual incentive payment under the Annual Incentive Plan;
any vested stock options held by the officer as of the separation date will expire the earlier of ten years from date of grant or 90 days from the last day of active employment; and
he or she is entitled to all vested accrued benefits and compensation as of the separation date, including qualified pension benefits (if any) and other post-employment benefits on terms consistent with those generally available to other salaried employees.
Termination for Cause
If a Named Executive Officer’s employment is terminated for “cause” (as defined in the System Executive Continuity Plan and described above under “Termination Related to a Change in Control”), he or she is generally entitled to the same compensation and separation benefits described belowabove under “Voluntary Resignation,” except that all options are no longer exercisable.
Voluntary Resignation
IfRetirement
Upon a Named Executive Officer voluntarily resigns from his or her Entergy System company employer, he or she is entitled to all accrued benefits and compensation as of Officer’s retirement:
the separation date, including qualified pension benefits (if any) and other post-employment benefits on terms consistent with those generally available to other salaried employees. In the case of voluntary resignation, the officer would forfeit all unvested stock options, shares of restricted stock, and restricted units as well as any perquisites to which he or she is entitled as an officer. In addition, the officer would forfeit, except as described below, his or her right to receive incentive payments under any outstanding performance periods under the Long-Term Performance Unit Program or the Annual Incentive Plan. If the officer resigns after the completion of an Annual Incentive Plan or Long-Term Performance Unit Program performance period, he or she could receive a payout under the Long-Term Performance Unit Program based on the outcome of the
performance cycle and could, at the Entergy Corporation’s discretion, receive an annual incentive payment under the Annual Incentive Plan. Any vestedPlan is generally pro-rated based on the actual number of days employed during the performance year in which the retirement date occurs, subject to negative discretion that may be applied to reduce or disallow the payment; payments are delivered at the conclusion of the annual period, consistent with the timing of payments to active participants in the Annual Incentive Plan;
payments under the Long-Term Performance Unit Program for those retiring with a minimum of 12 months of participation are pro-rated based on the actual full months of participation in each outstanding performance period in which the retirement date occurs, and payments are delivered at the conclusion of each performance period, consistent with the timing of payments to active participants in the Long-Term Performance Unit Program;
unvested stock options held byissued under the officer as2011 Equity Ownership Plan vest on the retirement date and expire ten years from the grant date of the separationoptions;
unvested stock options issued under the 2015 Equity Ownership Plan vest on the retirement date willand expire the earlier of tenfive years from the grant date of grantthe options or 90 days from the last dayoriginal term of active employment.ten years;
Retirementany unvested restricted stock and restricted stock units held by the executive upon his retirement are forfeited; and
Under Entergy Corporation’s retirement plans, a Named Executive Officer’s eligibility for retirement benefits is based on a combination of age and years of service. Normal retirement is defined as age 65. Early retirement is defined under the qualified retirement plan as minimum age 55 with 10 years of service and in the case of the System Executive Retirement Plan and the supplemental credited service under the Pension Equalization Plan, the consent of the Entergy System company employer.
Upon a Named Executive Officer’s retirement, he or she is generally entitled to all vested accrued benefits and compensation as of the separation date, including qualified pension benefits and other post-employment benefits consistent with those generally available to salaried employees. The annual incentive payment under the Annual Incentive Plan is pro-rated based on the actual number of days employed during the performance year in which the retirement date occurs. Similarly, payments under the Performance Unit Program for those retiring with a minimum 12 months of participation are pro-rated based on the actual full months of participation, in each outstanding performance cycle, in which the retirement date occurs. In each case, payments are delivered at the conclusion of each annual or performance cycle, consistent with the timing of payments to active participants in the Annual Incentive Plan and the Performance Unit Program, respectively. Unvested stock options issued under Entergy Corporation’s equity ownership plans vest on the retirement date and expire ten years from the grant date of the options. Any restricted stock and restricted stock units (other than those issued under the Performance Unit Program) held by the executive upon his or her retirement are forfeited, and perquisites are not available following the separation date.
Disability
If a Named Executive Officer’s employment is terminated due to disability, he or she generally is entitled to the same compensation and separation benefits described above under “Retirement,” except that unvested restricted stock and restricted stock units may be subject to specific disability benefits (asas noted, where applicable, in the tables above).above.
Death
If a Named Executive Officer dies while actively employed by an Entergy System company employer, he or she generally is entitled to the same compensation and separation benefits described above under “Retirement,” including:
allexcept that unvested restricted stock options will vest immediately;
vestedand restricted stock options will expire ten years from the grant date; and
restricted units may be subject to specific death benefits depending on the restricted unit agreement (asas noted, where applicable, in the tables above).above.
CompensationPay Ratio
As required by Section 953(b) of Directorsthe Dodd-Frank Wall Street Reform and Consumer Protection Act, the following disclosure is being provided about the relationship of the annual total compensation of the employees of each of the Utility operating companies to the annual total compensation of their respective Presidents and Chief Executive Officers.
Identification of Median Employee
For information regardingeach of the Utility operating companies, October 6, 2017 was selected as the date on which to determine the median employee. To identify the median employee from each of the Utility operating companies’ employee population base, all compensation included in Box 5 of Form W-2 was considered with all before-tax deductions added back to this compensation (Box 5 Compensation). For purposes of determining the median employee of each Utility operating company, Box 5 Compensation was selected as it is believed it is representative of the compensation received by the employees of each respective Utility operating company and is readily available. The calculation of annual total compensation of the directorsmedian employee for each Utility operating company is the same calculation used to determine total compensation for purposes of Entergy Corporation, see the Proxy Statement under2017 Summary Compensation Table with respect to each of the heading “Director Compensation,” which information is incorporated herein by reference. The Boards of Directors of Named Executive Officers.
Entergy Arkansas Entergy Gulf States Louisiana, Ratio
For 2017,
Mr. Riley’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $1,353,719.
The annual total compensation of the median employee was $127,560.
Based on this information, the ratio of the annual total compensation of Mr. Riley to the median employee is estimated to be 11:1.
Entergy Louisiana Ratio
For 2017,
Mr. May’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $1,564,954.
The annual total compensation of the median employee was $144,954.
Based on this information, the ratio of the annual total compensation of Mr. May to the median employee is estimated to be 11:1.
Entergy Mississippi Ratio
For 2017,
Mr. Fisackerly’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $1,207,343.
The annual total compensation of the median employee was $112,110.
Based on this information, the ratio of the annual total compensation of Mr. Fisackerly to the median employee is estimated to be 11:1.
Entergy New Orleans and Ratio
For 2017,
Mr. Rice’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $824,111.
The annual total compensation of the median employee was $91,346.
Based on this information, the ratio of the annual total compensation of Mr. Rice to the median employee is estimated to be 9:1.
Entergy Texas are comprised solelyRatio
For 2017,
Ms. Rainer’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $1,200,260.
The annual total compensation of the median employee directors who receive nowas $129,877.
Based on this information, the ratio of the annual total compensation for service as directors.of Ms. Rainer to the median employee is estimated to be 9:1.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Entergy Corporation owns 100% of the outstanding common stock of registrants Entergy Arkansas, Entergy Gulf States Louisiana,Mississippi, Entergy Texas, and indirectly 100% of the outstanding common membership interests of registrant Entergy Louisiana Entergy Mississippi,and Entergy New Orleans, and Entergy Texas.Orleans. The information with respect to persons known by Entergy Corporation to be beneficial owners of more than 5% of Entergy Corporation’s outstanding common stock is included under the heading “Stockholders Who Own at Least“Entergy Share Ownership - Beneficial Owners of More Than Five Percent” in the Proxy Statement, which information is incorporated herein by reference. The registrants know of no contractual arrangements that may, at a subsequent date, result in a change in control of any of the registrants.
The following table sets forth the beneficial ownership of Common Stockcommon stock of Entergy Corporation and stock-based units as of January 31, 20152018 for all non-employee directors and Named Executive Officers. Unless otherwise noted, each person had sole voting and investment power over the number of shares of Common Stockcommon stock and stock-based units of Entergy Corporation set forth across from his or her name.
|
| | | | | | | | | |
Name | | Shares (1) | | Options Exercisable Within 60 Days | | Stock Units (2) |
| Entergy Corporation | | | | | | |
| Maureen S. Bateman* | | 6,258 |
| | — |
| | 11,263 |
|
| Leo P. Denault*** | | 64,450 |
| | 378,666 |
| | — |
|
| Kirkland H. Donald* | | 965 |
| | — |
| | 753 |
|
| Gary W. Edwards* | | 1,791 |
| | — |
| | 10,852 |
|
| Alexis Herman* | | 556 |
| | — |
| | 8,863 |
|
| Donald C. Hintz* | | 3,650 |
| | — |
| | 10,471 |
|
| Stuart L. Levenick* | | 5,758 |
| | — |
| | 7,094 |
|
| Blanche L. Lincoln* | | 2,618 |
| | — |
| | 2,663 |
|
| Andrew S. Marsh** | | 18,620 |
| | 84,599 |
| | — |
|
| William M. Mohl** | | 18,946 |
| | 80,799 |
| | — |
|
| Stewart C. Myers* | | 3,682 |
| | — |
| | 3,846 |
|
| Mark T. Savoff** | | 26,546 |
| | 182,832 |
| | 305 |
|
| W. J. Tauzin* | | 5,658 |
| | — |
| | 6,956 |
|
| Roderick K. West** | | 26,191 |
| | 117,666 |
| | — |
|
| Steven V. Wilkinson* | | 6,813 |
| | — |
| | 8,490 |
|
| All directors and executive | | | | | | |
| officers as a group (20 persons) | | 271,309 |
| | 1,153,759 |
| | 71,617 |
|
| | | | | | | |
| Entergy Arkansas | | |
| | |
| | |
|
| Theodore H. Bunting, Jr.* | | 21,009 |
| | 111,466 |
| | — |
|
| Leo P. Denault** | | 64,450 |
| | 378,666 |
| | — |
|
| Andrew S. Marsh*** | | 18,620 |
| | 84,599 |
| | — |
|
| Hugh T. McDonald*** | | 15,653 |
| | 48,933 |
| | — |
|
| Alyson M. Mount** | | 9,653 |
| | 15,700 |
| | — |
|
| Mark T. Savoff*** | | 26,546 |
| | 182,832 |
| | 305 |
|
| Roderick K. West** | | 26,191 |
| | 117,666 |
| | — |
|
| All directors and executive | | | | | | |
| officers as a group (10 persons) | | 230,267 |
| | 1,121,893 |
| | 366 |
|
| | | | | | | |
| Entergy Gulf States Louisiana | | | | | | |
| Theodore H. Bunting, Jr.* | | 21,009 |
| | 111,466 |
| | — |
|
| Leo P. Denault** | | 64,450 |
| | 378,666 |
| | — |
|
| Andrew S. Marsh*** | | 18,620 |
| | 84,599 |
| | — |
|
| Phillip R. May, Jr.*** | | 12,886 |
| | 40,866 |
| | 11 |
|
| Alyson M. Mount** | | 9,653 |
| | 15,700 |
| | — |
|
| Mark T. Savoff*** | | 26,546 |
| | 182,832 |
| | 305 |
|
| Roderick K. West** | | 26,191 |
| | 117,666 |
| | — |
|
| All directors and executive | | | | | | |
| officers as a group (10 persons) | | 227,500 |
| | 1,113,826 |
| | 377 |
|
|
| | | | | | | | | |
Name | | Shares (1) | | Options Exercisable Within 60 Days | | Stock Units (2) |
| Entergy Louisiana | | | | | | |
| Theodore H. Bunting, Jr.* | | 21,009 |
| | 111,466 |
| | — |
|
| Leo P. Denault** | | 64,450 |
| | 378,666 |
| | — |
|
| Andrew S. Marsh*** | | 18,620 |
| | 84,599 |
| | — |
|
| Phillip R. May, Jr.*** | | 12,886 |
| | 40,866 |
| | 11 |
|
| Alyson M. Mount** | | 9,653 |
| | 15,700 |
| | — |
|
| Mark T. Savoff*** | | 26,546 |
| | 182,832 |
| | 305 |
|
| Roderick K. West** | | 26,191 |
| | 117,666 |
| | — |
|
| All directors and executive | | | | | | |
| officers as a group (10 persons) | | 227,500 |
| | 1,113,826 |
| | 377 |
|
| | | | | | | |
| Entergy Mississippi | | | | | | |
| Theodore H. Bunting, Jr.* | | 21,009 |
| | 111,466 |
| | — |
|
| Leo P. Denault** | | 64,450 |
| | 378,666 |
| | — |
|
| Haley R. Fisackerly*** | | 7,269 |
| | 28,667 |
| | — |
|
| Andrew S. Marsh*** | | 18,620 |
| | 84,599 |
| | — |
|
| Alyson M. Mount** | | 9,653 |
| | 15,700 |
| | — |
|
| Mark T. Savoff*** | | 26,546 |
| | 182,832 |
| | 305 |
|
| Roderick K. West** | | 26,191 |
| | 117,666 |
| | — |
|
| All directors and executive | | | | | | |
| officers as a group (9 persons) | | 203,967 |
| | 1,002,461 |
| | 305 |
|
| | | | | | | |
| Entergy New Orleans | | | | | | |
| Theodore H. Bunting, Jr.* | | 21,009 |
| | 111,466 |
| | — |
|
| Leo P. Denault** | | 64,450 |
| | 378,666 |
| | — |
|
| Andrew S. Marsh*** | | 18,620 |
| | 84,599 |
| | — |
|
| Alyson M. Mount** | | 9,653 |
| | 15,700 |
| | — |
|
| Charles L. Rice, Jr.*** | | 4,831 |
| | 12,566 |
| | — |
|
| Mark T. Savoff*** | | 26,546 |
| | 182,832 |
| | 305 |
|
| Roderick K. West** | | 26,191 |
| | 117,666 |
| | — |
|
| All directors and executive | | | | | | |
| officers as a group (9 persons) | | 201,529 |
| | 986,360 |
| | 305 |
|
| | | | | | | |
| Entergy Texas | | | | | | |
| Theodore H. Bunting, Jr.* | | 21,009 |
| | 111,466 |
| | — |
|
| Leo P. Denault** | | 64,450 |
| | 378,666 |
| | — |
|
| Andrew S. Marsh*** | | 18,620 |
| | 84,599 |
| | — |
|
| Alyson M. Mount** | | 9,653 |
| | 15,700 |
| | — |
|
| Sallie T. Rainer*** | | 8,586 |
| | 16,299 |
| | — |
|
| Mark T. Savoff*** | | 26,546 |
| | 182,832 |
| | 305 |
|
| Roderick K. West** | | 26,191 |
| | 117,666 |
| | — |
|
| All directors and executive | | | | | | |
| officers as a group (9 persons) | | 205,284 |
| | 990,093 |
| | 305 |
|
|
| | | | | | | | | |
| Name | | Shares (1)(2) | | Options Exercisable Within 60 Days | | Stock Units (3) |
| Entergy Corporation | | | | | | |
| A. Christopher Bakken, III** | | 10,710 |
| | 12,533 |
| | — |
|
| Maureen S. Bateman* | | 22,716 |
| | — |
| | — |
|
| Marcus V. Brown** | | 27,803 |
| | 130,066 |
| | — |
|
| Patrick J. Condon* | | 4,460 |
| | — |
| | — |
|
| Leo P. Denault*** | | 133,457 |
| | 565,133 |
| | — |
|
| Kirkland H. Donald* | | 5,736 |
| | — |
| | 1,389 |
|
| Philip L. Frederickson* | | 2,775 |
| | — |
| | 805 |
|
| Alexis M. Herman* | | 12,581 |
| | — |
| | — |
|
| Donald C. Hintz* | | 15,096 |
| | — |
| | 3,942 |
|
| Stuart L. Levenick* | | 18,047 |
| | — |
| | — |
|
| Blanche L. Lincoln* | | 11,004 |
| | — |
| | — |
|
| Andrew S. Marsh** | | 60,425 |
| | 166,766 |
| | — |
|
| Karen A. Puckett* | | 4,460 |
| | — |
| | — |
|
| W. J. Tauzin* | | 17,809 |
| | — |
| | — |
|
| Roderick K. West** | | 42,475 |
| | 114,066 |
| | — |
|
| All directors and executive officers as a group (19 persons) | | 444,591 |
| | 1,112,495 |
| | 6,136 |
|
| | | | | | | |
| Entergy Arkansas | | |
| | |
| | |
|
| A. Christopher Bakken, III** | | 10,710 |
| | 12,533 |
| | — |
|
| Marcus V. Brown** | | 27,803 |
| | 130,066 |
| | — |
|
| Leo P. Denault** | | 133,457 |
| | 565,133 |
| | — |
|
| Andrew S. Marsh*** | | 60,425 |
| | 166,766 |
| | — |
|
| Richard C. Riley*** | | 11,169 |
| | 16,967 |
| | — |
|
| Roderick K. West*** | | 42,475 |
| | 114,066 |
| | — |
|
| All directors and executive officers as a group (10 persons) | | 341,076 |
| | 1,129,462 |
| | — |
|
| | | | | | | |
| Entergy Louisiana | | | | | | |
| A. Christopher Bakken, III** | | 10,710 |
| | 12,533 |
| | — |
|
| Marcus V. Brown** | | 27,803 |
| | 130,066 |
| | — |
|
| Leo P. Denault** | | 133,457 |
| | 565,133 |
| | — |
|
| Andrew S. Marsh*** | | 60,425 |
| | 166,766 |
| | — |
|
| Phillip R. May, Jr.*** | | 18,203 |
| | 47,100 |
| | 12 |
|
| Roderick K. West*** | | 42,475 |
| | 114,066 |
| | — |
|
| All directors and executive officers as a group (10 persons) | | 348,110 |
| | 1,159,595 |
| | 12 |
|
Table of Contents |
| | | | | | | | | |
| Name | | Shares (1)(2) | | Options Exercisable Within 60 Days | | Stock Units (3) |
| Entergy Mississippi | | | | | | |
| Marcus V. Brown** | | 27,803 |
| | 130,066 |
| | — |
|
| Leo P. Denault** | | 133,457 |
| | 565,133 |
| | — |
|
| Haley R. Fisackerly*** | | 6,605 |
| | 21,933 |
| | — |
|
| Andrew S. Marsh*** | | 60,425 |
| | 166,766 |
| | — |
|
| Roderick K. West*** | | 42,475 |
| | 114,066 |
| | — |
|
| All directors and executive officers as a group (9 persons) | | 325,802 |
| | 1,121,895 |
| | — |
|
| | | | | | | |
| Entergy New Orleans | | | | | | |
| Marcus V. Brown** | | 27,803 |
| | 130,066 |
| | — |
|
| Leo P. Denault** | | 133,457 |
| | 565,133 |
| | — |
|
| Andrew S. Marsh*** | | 60,425 |
| | 166,766 |
| | — |
|
| Charles L. Rice, Jr.*** | | 5,855 |
| | 10,266 |
| | — |
|
| Roderick K. West*** | | 42,475 |
| | 114,066 |
| | — |
|
| All directors and executive officers as a group (9 persons) | | 325,052 |
| | 1,110,228 |
| | — |
|
| | | | | | | |
| Entergy Texas | | | | | | |
| Marcus V. Brown** | | 27,803 |
| | 130,066 |
| | — |
|
| Leo P. Denault** | | 133,457 |
| | 565,133 |
| | — |
|
| Andrew S. Marsh*** | | 60,425 |
| | 166,766 |
| | — |
|
| Sallie T. Rainer*** | | 7,884 |
| | 14,866 |
| | — |
|
| Roderick K. West*** | | 42,475 |
| | 114,066 |
| | — |
|
| All directors and executive officers as a group (9 persons) | | 327,081 |
| | 1,114,828 |
| | — |
|
|
| |
| * | Director of the respective Company |
| ** | Named Executive Officer of the respective Company |
| *** | Director and Named Executive Officer of the respective Company |
| |
| (1) | The number of shares of Entergy Corporation common stock owned by each individual and by all non-employee directors and executive officers as a group does not exceed one percent of the outstanding shares of Entergy Corporation common stock. |
| |
| (2) | For the non-employee directors, the balances include phantom units that are issued under the Service Recognition Program. All non-employee directors are credited with phantom units for each year of service on the Entergy Corporation Board. These phantom units do not have voting rights, accrue dividends, and will be settled in shares of Entergy Corporation common stock following the non-employee director’s separation from the Board. |
| |
| (3) | Represents the balances of phantom units each executive holds under the defined contribution restoration plan and the deferral provisions of the Equity Ownership Plan. These units will be paid out in either Entergy Corporation Common Stock or cash equivalent to the value of one share of Entergy Corporation common stock per unit on the date of payout, including accrued dividends. The deferral period is determined by the individual and is at least two years from the award of the bonus. For directors of Entergy Corporation the phantom units are issued under the Service Recognition Program for Outside Directors. All non-employee directors are credited with units for each year of service on the Board. In addition, Messrs. EdwardsDonald, Hintz, and HintzFrederickson have deferred receipt of some of their quarterly stock grants. The deferred shares will be settled in cash in an amount equal to the market value of Entergy Corporation common stock at the end of the deferral period. |
Equity Compensation Plan Information
The following table summarizes the equity compensation plan information as of December 31, 2014.2017. Information is included for equity compensation plans approved by the stockholders and equity compensation plans not approved by the stockholders.
| | Plan | | Number of Securities to be Issued Upon Exercise of Outstanding Options (a) | | Weighted Average Exercise Price (b) | | Number of Securities Remaining Available for Future Issuance (excluding securities reflected in column (a)) (c) | | Number of Securities to be Issued Upon Exercise of Outstanding Options (a) | | Weighted Average Exercise Price (b) | | Number of Securities Remaining Available for Future Issuance (excluding securities reflected in column (a))(c) |
Equity compensation plans approved by security holders (1) | | 7,281,396 |
| | $83.25 | | 3,569,309 |
| | 5,164,854 |
| | $83.26 | | 3,498,788 |
|
Equity compensation plans not approved by security holders(2) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total | | 7,281,396 |
| | $83.25 | | 3,569,309 |
| | 5,164,854 |
| | $83.26 | | 3,498,788 |
|
| |
| (1) | Includes the 2007 Equity Ownership Plan, which was approved by the shareholders on May 15, 1998, the 20072011 Equity Ownership Plan, and the 20112015 Equity Ownership Plan. The 2007 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 12, 2006, and 7,000,000 shares of Entergy Corporation common stock can be issued, with no more than 2,000,000 shares available for non-option grants.only applied to awards granted between January 1, 2007 and May 5, 2011. The 2011 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 6, 2011, and 5,500,000only applied to awards granted between May 6, 2011 and May 7, 2015. The 2015 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 8, 2015, and 6,900,000 shares of Entergy Corporation common stock can be issued from the 20112015 Equity Ownership Plan, with no more than 2,000,0001,500,000 shares available for incentive stock option grants. The 2015 Plan applies to awards granted on or after May 8, 2015. The 2007 Equity Ownership Plan, the 20072011 Equity Ownership Plan, and the 20112015 Equity Ownership Plan (the “Plans”) are administered by the Personnel Committee of the Board of Directors (other than with respect to awards granted to non-employee directors, which awards are administered by the entire Board of Directors). Eligibility under the Plans is limited to the non-employee directors and to the officers and employees of an Entergy System employer and any corporation 80% or more of whose stock (based on voting power) or value is owned, directly or indirectly, by Entergy Corporation. The Plans provide for the issuance of stock options, restricted shares,stock, equity awards (units whose value is related to the value of shares of the Common Stockcommon stock but do not represent actual shares of Common Stock)common stock), performance awards (performance shares or units valued by reference to shares of Common Stockcommon stock or performance units valued by reference to financial measures or property other than Common Stock)common stock), restricted stock unit awards, and other stock-based awards. |
| |
| (2) | Entergy has a Board-approved stock-based compensation plan. However, effective May 9, 2003, the Board has directed that no further awards be issued under that plan. As of December 31, 2014,2017, all options outstanding under the plan were either exercised or expired. |
Item 13. Certain Relationships and Related Party Transactions and Director Independence
For information regarding certain relationships,relationship, related transactions and director independence of Entergy Corporation, see the Proxy Statement under the headings “Corporate Governance at Entergy - Director Independence” and “Transactions“Corporate Governance at Entergy - Governance Policies - Our Transactions with Related Persons,” which information is incorporated herein by reference.
Since December 31, 2011, none of the Subsidiaries or any of their affiliates has participated in any transaction involving an amount in excess of $120,000 in which any director or executive officer of any of the Subsidiaries, any nominee for director, or any immediate family member of the foregoing had a material interest as contemplated by Item 404(a) of Regulation S-K (“Related Party Transactions”).Persons Policy.”
Entergy Corporation’s Board of Directors has adopted written policies and procedures for the review, approval or ratification of any transaction involving an amount in excess of $120,000 in which any director or executive officer of Entergy Corporation, any nominee for director, or any immediate family member of the foregoing has or will have a material interest as contemplated by Item 404(a) of Regulation S-K (“Related Party Transactions.Person Transactions”). Under these policies and procedures, theEntergy Corporation’s Corporate Governance Committee or a subcommittee of theits Board of Directors of Entergy Corporation composedconsisting entirely of independent directors reviews the transaction and either approves or rejects the transaction after taking into account the following factors:
Whether the proposed transaction is on terms that are at least as favorable to Entergy Corporation or the subsidiary as those achievable with an unaffiliated third party;
Size of the transaction and amount of consideration;
Nature of the interest;
Whether the transaction involves a conflict of interest;
Whether the transaction involves services available from unaffiliated third parties; and
Any other factors that the Corporate Governance Committee or subcommittee deems relevant.
The policy does not apply to (a) compensation and Related Party Transactionsrelated person transactions involving a director or an executive officer solely resulting from that person’s service as a director or employment with the CompanyEntergy Corporation so long as the compensation is approved by Entergy’sthe Board of Directors (or an appropriate committee), (b) transactions involving the rendering of services as a public utility services at rates or charges fixed in conformity with law or governmental authority, or (c) any other categories of transactions currently or in the future excluded from the reporting requirements of Item 404(a) of Regulation SK.S-K.
None of the Subsidiaries are listed issuers. As previously noted, the Boards of Directors of the Subsidiaries are composed solely of employee directors. None of the Boards of Directors ofRelated Party Transactions
Since January 1, 2017, neither Entergy Corporation nor any of the Subsidiariesits affiliates has participated in any committees.Related Person Transaction.
Item 14. Principal Accountant Fees and Services (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Aggregate fees billed to Entergy Corporation (consolidated), Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy for the years ended December 31, 20142017 and 20132016 by Deloitte & Touche LLP were as follows:
| | | | 2014 | | 2013 | 2017 | | 2016 |
| Entergy Corporation (consolidated) | | | | | | |
| Audit Fees |
| $8,097,000 |
| |
| $9,832,698 |
|
| $8,401,895 |
| |
| $8,932,000 |
|
| Audit-Related Fees (a) | 1,135,000 |
| | 545,000 |
| 875,000 |
| | 865,000 |
|
| Total audit and audit-related fees | 9,232,000 |
| | 10,377,698 |
| 9,276,895 |
| | 9,797,000 |
|
| Tax Fees (b) | — |
| | — |
| |
| Tax Fees | | — |
| | — |
|
| All Other Fees | — |
| | — |
| — |
| | — |
|
| Total Fees (c) |
| $9,232,000 |
| |
| $10,377,698 |
| |
| Total Fees (b) | |
| $9,276,895 |
| |
| $9,797,000 |
|
| Entergy Arkansas | | | | | | |
| Audit Fees |
| $984,813 |
| |
| $985,484 |
|
| $1,018,860 |
| |
| $1,056,881 |
|
| Audit-Related Fees (a) | 19,000 |
| | — |
| — |
| | — |
|
| Total audit and audit-related fees | 1,003,813 |
| | 985,484 |
| 1,018,860 |
| | 1,056,881 |
|
| Tax Fees | — |
| | — |
| — |
| | — |
|
| All Other Fees | — |
| | — |
| — |
| | — |
|
| Total Fees (c) |
| $1,003,813 |
| |
| $985,484 |
| |
| Entergy Gulf States Louisiana | | | | |
| Audit Fees |
| $874,813 |
| |
| $840,484 |
| |
| Audit-Related Fees (a) | 375,000 |
| | 100,000 |
| |
| Total audit and audit-related fees | 1,249,813 |
| | 940,484 |
| |
| Tax Fees | — |
| | — |
| |
| All Other Fees | — |
| | — |
| |
| Total Fees (c) |
| $1,249,813 |
| |
| $940,484 |
| |
| Total Fees (b) | |
| $1,018,860 |
| |
| $1,056,881 |
|
| Entergy Louisiana | | | | | | |
| Audit Fees |
| $1,134,813 |
| |
| $985,484 |
|
| $1,887,719 |
| |
| $2,138,762 |
|
| Audit-Related Fees (a) | 375,000 |
| | 100,000 |
| 500,000 |
| | 450,000 |
|
| Total audit and audit-related fees | 1,509,813 |
| | 1,085,484 |
| 2,387,719 |
| | 2,588,762 |
|
| Tax Fees | — |
| | — |
| — |
| | — |
|
| All Other Fees | — |
| | — |
| — |
| | — |
|
| Total Fees (c) |
| $1,509,813 |
| |
| $1,085,484 |
| |
| Total Fees (b) | |
| $2,387,719 |
| |
| $2,588,762 |
|
| Entergy Mississippi | | | | |
| Audit Fees | |
| $933,860 |
| |
| $971,881 |
|
| Audit-Related Fees (a) | | — |
| | — |
|
| Total audit and audit-related fees | | 933,860 |
| | 971,881 |
|
| Tax Fees | | — |
| | — |
|
| All Other Fees | | — |
| | — |
|
| Total Fees (b) | |
| $933,860 |
| |
| $971,881 |
|
| | | | 2014 | | 2013 | 2017 | | 2016 |
| Entergy Mississippi | | | | |
| Audit Fees |
| $869,813 |
| |
| $840,484 |
| |
| Audit-Related Fees (a) | — |
| | — |
| |
| Total audit and audit-related fees | 869,813 |
| | 840,484 |
| |
| Tax Fees | — |
| | — |
| |
| All Other Fees | — |
| | — |
| |
| Total Fees (c) |
| $869,813 |
| |
| $840,484 |
| |
| Entergy New Orleans | | | | | | |
| Audit Fees |
| $824,813 |
| |
| $885,484 |
|
| $953,860 |
| |
| $1,056,881 |
|
| Audit-Related Fees (a) | — |
| | — |
| — |
| | — |
|
| Total audit and audit-related fees | 824,813 |
| | 885,484 |
| 953,860 |
| | 1,056,881 |
|
| Tax Fees | — |
| | — |
| — |
| | — |
|
| All Other Fees | — |
| | — |
| — |
| | — |
|
| Total Fees (c) |
| $824,813 |
| |
| $885,484 |
| |
| Total Fees (b) | |
| $953,860 |
| |
| $1,056,881 |
|
| Entergy Texas | | | | | | |
| Audit Fees |
| $1,004,813 |
| |
| $1,886,280 |
|
| $1,093,860 |
| |
| $1,076,881 |
|
| Audit-Related Fees (a) | — |
| | — |
| — |
| | — |
|
| Total audit and audit-related fees | 1,004,813 |
| | 1,886,280 |
| 1,093,860 |
| | 1,076,881 |
|
| Tax Fees | — |
| | — |
| — |
| | — |
|
| All Other Fees | — |
| | — |
| — |
| | — |
|
| Total Fees (c) |
| $1,004,813 |
| |
| $1,886,280 |
| |
| Total Fees (b) | |
| $1,093,860 |
| |
| $1,076,881 |
|
| System Energy | | | | | | |
| Audit Fees |
| $824,813 |
| |
| $840,484 |
|
| $868,860 |
| |
| $861,881 |
|
| Audit-Related Fees (a) | — |
| | — |
| — |
| | — |
|
| Total audit and audit-related fees | 824,813 |
| | 840,484 |
| 868,860 |
| | 861,881 |
|
| Tax Fees | — |
| | — |
| — |
| | — |
|
| All Other Fees | — |
| | — |
| — |
| | — |
|
| Total Fees (c) |
| $824,813 |
| |
| $840,484 |
| |
| Total Fees (b) | |
| $868,860 |
| |
| $861,881 |
|
| |
| (a) | Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services. |
| |
| (b) | Includes fees for tax advisory services. |
| |
(c) | 100% of fees paid in 20142017 and 20132016 were pre-approved by the Entergy Corporation Audit Committee. |
Entergy Audit Committee Guidelines for Pre-approval of Independent Auditor Services
The Audit Committee has adopted the following guidelines regarding the engagement of Entergy’s independent auditor to perform services for Entergy:
| |
| 1. | The independent auditor will provide the Audit Committee, for approval, an annual engagement letter outlining the scope of services proposed to be performed during the fiscal year, including audit services and other permissible non-audit services (e.g. audit-related services, tax services, and all other services). |
| |
| 2. | For other permissible services not included in the engagement letter, Entergy management will submit a description of the proposed service, including a budget estimate, to the Audit Committee for pre-approval. Management and the independent auditor must agree that the requested service is consistent with the SEC’s rules on auditor independence prior to submission to the Audit Committee. The Audit Committee, at its discretion, will pre-approve permissible services and has established the following additional guidelines for permissible non-audit services provided by the independent auditor: |
Aggregate non-audit service fees are targeted at fifty percent or less of the approved audit service fee.
All other services should only be provided by the independent auditor if it is the onlya highly qualified provider of that service or if the Audit Committee specifically requestspre-approves the independent audit firm to provide the service.
| |
| 3. | The Audit Committee will be informed quarterly as to the status of pre-approved services actually provided by the independent auditor. |
| |
| 4. | To ensure prompt handling of unexpected matters, the Audit Committee delegates to the Audit Committee Chair or its designee the authority to approve permissible services and fees. The Audit Committee Chair or designee will report action taken to the Audit Committee at the next scheduled Audit Committee meeting. |
| |
| 5. | The Vice President and General Auditor will be responsible for tracking all independent auditor fees and will report quarterly to the Audit Committee. |
PART IV
Item 15. Exhibits and Financial Statement Schedules
|
| |
| (a)1. | Financial Statements and Independent Auditors’ Reports for Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Table of Contents. |
| | |
| (a)2. | Financial Statement Schedules |
| | |
| | Report of Independent Registered Public Accounting Firm (see page 529)530) |
| | |
| | Financial Statement Schedules are listed in the Index to Financial Statement Schedules (see page S-1) |
| | |
| (a)3. | Exhibits |
| | |
| | Exhibits for Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Exhibit Index (see page E-1)507). Each management contract or compensatory plan or arrangement required to be filed as an exhibit hereto is identified as such by footnote in the Exhibit Index. |
Item 16. Form 10-K Summary (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
None.
EXHIBIT INDEX
The following exhibits indicated by an asterisk preceding the exhibit number are filed herewith. The balance of the exhibits have heretofore been filed with the SEC as the exhibits and in the file numbers indicated and are incorporated herein by reference. The exhibits marked with a (+) are management contracts or compensatory plans or arrangements required to be filed herewith and required to be identified as such by Item 15 of Form 10-K.
Some of the agreements included or incorporated by reference as exhibits to this Form 10-K contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties were made solely for the benefit of the other parties to the applicable agreement and (i) were not intended to be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate; (ii) may have been qualified in such agreement by disclosures that were made to the other party in connection with the negotiation of the applicable agreement; (iii) may apply contract standards of “materiality” that are different from the standard of “materiality” under the applicable securities laws; and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement.
Entergy acknowledges that, notwithstanding the inclusion of the foregoing cautionary statements, it is responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in this Form 10-K not misleading.
(2) Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
Entergy Louisiana
|
| |
| (a) 1 -- | |
| |
| (a) 2 -- | |
| |
| (a) 3 -- | |
| |
| (a) 4 -- |
|
(3) Articles of Incorporation and By-laws
Entergy Corporation
System Energy
Entergy Arkansas
Entergy Louisiana
Entergy Mississippi
Entergy New Orleans
Entergy Texas
(4)Instruments Defining Rights of ContentsSecurity Holders, Including Indentures
Entergy Corporation
|
| |
| (a) 1 -- | See (4)(b) through (4)(g) below for instruments defining the rights of security holders of System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. |
| |
| (a) 2 -- | |
| |
| (a) 3 -- | |
| |
| (a) 4 -- | |
|
| |
| (a) 5 -- | |
| |
| (a) 6 -- | |
| |
| (a) 7 -- | |
| |
| (a) 8 -- | Amendment dated as of August 28, 2015, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Corporation, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(h) to Form 10-Q for the quarter ended September 30, 2015 in 1-11299). |
| |
| (a) 9 -- | Extension Agreement, dated August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Corporation, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(l) to Form 10-Q for the quarter ended September 30, 2016 in 1-11299). |
| |
| (a) 10 -- | Amendment dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Corporation, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(m) to Form 10-Q for the quarter ended September 30, 2016 in 1-11299). |
| |
| (a) 11 -- | Extension Agreement, dated August 7, 2017, to Amended and Restated Credit Agreement dated as of August 14, 2015, as amended, among Entergy Corporation, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(a) to Form 10-Q for the quarter ended September 30, 2017).
|
| |
| (a) 12 -- | Amendment, dated as of October 17, 2017, to Amended and Restated Credit Agreement dated as of August 14, 2015, as amended, among Entergy Corporation, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(b) to Form 10-Q for the quarter ended September 30, 2017). |
| |
| (a) 13 -- | Agreement, dated as of October 17, 2017, pursuant to Amended and Restated Credit Agreement dated as of August 14, 2015, as amended, among Entergy Corporation, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(c) to Form 10-Q for the quarter ended September 30, 2017). |
System Energy
|
| |
| (b) 1 -- | |
| |
| (b) 2 -- | |
| |
| *(b) 3 -- | |
Entergy Arkansas
|
| |
| (c) 1 -- | Mortgage and Deed of Trust, dated as of October 1, 1944, as amended by the following Supplemental Indentures: (7(d) in 2-5463 (Mortgage); 7(b) in 2-7121 (First); 4(a)-7 in 2-10261 (Seventh); 2(b)-10 in 2-15767 (Tenth); 2(c) in 2-28869 (Sixteenth); 2(c) in 2-35107 (Eighteenth); 2(d) in 2-36646 (Nineteenth); 2(c) in 2-39253 (Twentieth); * Filed herewith (Thirtieth); * Filed herewith (Thirty-first); * Filed herewith (Thirty-ninth); * Filed herewith (Forty-first); 4(d)(2) in 33-54298 (Forty-sixth); C-2 to Form U5S for the year ended December 31,1995 (Fifty-third); 4.06 to Form 8-K filed October 8, 2010 in 1-10764 (Sixty-ninth); 4.06 to Form 8-K filed November 12, 2010 in 1-10764 (Seventieth); 4.06 to Form 8-K filed December 13, 2012 in 1-10764 (Seventy-first); 4(e) to Form 8-K filed January 9, 2013 in 1-10764 (Seventy-second); 4.06 to Form 8-K filed May 30, 2013 in 1-10764 (Seventy-third); 4.06 to Form 8-K filed June 4, 2013 in 1-10764 (Seventy-fourth); 4.05 to Form 8-K filed March 14, 2014 in 1-10764 (Seventy-sixth); 4.05 to Form 8-K filed December 9, 2014 in 1-10764 (Seventy-seventh); 4.05 to Form 8-K filed January 8, 2016 in 1-10764 (Seventy-eighth); and 4.05 to Form 8-K filed August 16, 2016 in 1-10764 (Seventy-ninth)). |
| |
| (c) 2 -- | |
| |
| (c) 3 -- | Amendment dated as of August 28, 2015, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Arkansas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(j) to Form 10-Q for the quarter ended September 30, 2015 in 1-10764). |
| |
| (c) 4 -- | Extension Agreement, dated August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Arkansas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(n) to Form 10-Q for the quarter ended September 30, 2016 in 1-10764). |
| |
| (c) 5 -- | Amendment dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Arkansas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(o) to Form 10-Q for the quarter ended September 30, 2016 in 1-10764). |
| |
| (c) 6 -- | Extension Agreement, dated August 7, 2017, to Amended and Restated Credit Agreement dated as of August 14, 2015, as amended, among Entergy Arkansas, Inc., as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(d) to Form 10-Q for the quarter ended September 30, 2017 in 1-10764). |
| |
| (c) 7 -- | Amendment, dated as of October 17, 2017, to Amended and Restated Credit Agreement dated as of August 14, 2015, as amended, among Entergy Arkansas, Inc., as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(e) to Form 10-Q for the quarter ended September 30, 2017 in 1-10764). |
| |
| (c) 8-- | Agreement, dated as of October 17, 2017, pursuant to Amended and Restated Credit Agreement dated as of August 14, 2015, as amended, among Entergy Arkansas, Inc., as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(f) to Form 10-Q for the quarter ended September 30, 2017 in 1-10764). |
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| *(c) 9 -- | |
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| (c) 10 -- | |
Entergy Louisiana
|
| |
| (d) 1 -- | Mortgage and Deed of Trust, dated as of April 1, 1944, as amended by the following Supplemental Indentures: (7(d) in 2-5317 (Mortgage); 7(b) in 2-7408 (First); * Filed herewith (Sixth); 2(c) in 2-34659 (Twelfth); * Filed herewith (Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); * Filed herewith (Twenty-first); * Filed herewith (Twenty-fifth); * Filed herewith (Twenty-ninth); * Filed herewith (Forty-second); A-2(a) to Rule 24 Certificate filed April 4, 1996 in 70-8487 (Fifty-first); B-4(i) to Rule 24 Certificate filed January 10, 2006 in 70-10324 (Sixty-third); B-4(ii) to Rule 24 Certificate filed January 10, 2006 in 70-10324 (Sixty-fourth); 4(a) to Form 10-Q for the quarter ended September 30, 2008 in 1-32718 (Sixty-fifth); 4(e)1 to Form 10-K for the year ended December 31, 2009 in 1-132718 (Sixty-sixth); 4.08 to Form 8-K filed September 24, 2010 in 1-32718 (Sixty-eighth); 4.08 to Form 8-K filed March 24, 2011 in 1-32718 (Seventy-first); 4(a) to Form 10-Q for the quarter ended June 30, 2011 in 1-32718 (Seventy-second); 4.08 to Form 8-K filed July 3, 2012 in 1-32718 (Seventy-fifth); 4.08 to Form 8-K filed December 4, 2012 in 1-32718 (Seventy-sixth); 4.08 to Form 8-K filed May 21, 2013 in 1-32718 (Seventy-seventh); 4.08 to Form 8-K filed August 23, 2013 in 1-32718 (Seventy-eighth); 4.08 to Form 8-K filed June 24, 2014 in 1-32718 (Seventy-ninth); 4.08 to Form 8-K filed July 1, 2014 in 1-32718 (Eightieth); 4.08 to Form 8-K filed November 21, 2014 (Eighty-first); 4.1 to Form 8-K12B filed October 1, 2015 (Eighty-second); 4(g) to Form 8-K filed March 18, 2016 in 1-32718 (Eighty-third); 4.33 to Form 8-K filed March 24, 2016 in 1-32718 (Eighty-fourth); 4.33 to Form 8-K filed August 17, 2016 in 1-32718 (Eighty-sixth); 4.33 to Form 8-K filed October 4, 2016 in 1-32718 (Eighty-seventh); and 4.43 to Form 8-K filed May 23, 2017 in 1-32718 (Eighty-eighth)). |
| |
| (d) 2 -- | |
| |
| (d) 3 -- | Amendment dated as of August 28, 2015, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Louisiana [Old Entergy Louisiana] and Entergy Gulf States Louisiana, as the Borrowers, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4.5 to Form 8-K12B filed October 1, 2015 in 1-32718). |
| |
| (d) 4 -- | Borrower Assumption Agreement dated as of October 1, 2015 of Entergy Louisiana [New Entergy Louisiana] under Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Louisiana [Old Entergy Louisiana] and Entergy Gulf States Louisiana, as the Borrowers, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto, as amended (4.6 to Form 8-K12B filed October 1, 2015 in 1-32718). |
| |
| (d) 5 -- | Extension Agreement, dated August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Louisiana, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(p) to Form 10-Q for the quarter ended September 30, 2016 in 1-32718). |
| |
| (d) 6 -- | Amendment dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Louisiana, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(q) to Form 10-Q for the quarter ended September 30, 2016 in 1-32718). |
| |
| (d) 7 -- | Extension Agreement, dated August 7, 2017, to Amended and Restated Credit Agreement dated as of August 14, 2015, as amended, among Entergy Louisiana, LLC, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(g) to Form 10-Q for the quarter ended September 30, 2017 in 1-32718). |
| |
|
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| (d) 8 -- | Amendment, dated as of October 17, 2017, to Amended and Restated Credit Agreement dated as of August 14, 2015, as amended, among Entergy Louisiana, LLC, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(h) to Form 10-Q for the quarter ended September 30, 2017 in 1-32718). |
| |
| (d) 9 -- | Agreement, dated as of October 17, 2017, pursuant to Amended and Restated Credit Agreement dated as of August 14, 2015, as amended, among Entergy Louisiana, LLC, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(i) to Form 10-Q for the quarter ended September 30, 2017 in 1-32718). |
| |
| *(d) 10 -- | |
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| *(d) 11 -- | |
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| *(d) 12 -- | |
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| (d) 13 -- | |
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| (d) 14 -- | |
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| (d) 15 -- | Indenture of Mortgage, dated September 1, 1926, as amended by the following Supplemental Indentures: (7-A-9 in Registration No. 2-6893 (Seventh); * Filed herewith (Eighteenth); 2-A-8 in Registration No. 2-66612 (Thirty-eighth); 4(b) to Form 10-Q for the quarter ended March 31,1999 in 1-27031 (Fifty-eighth); 4(a) to Form 10-Q for the quarter ended June 30, 2008 in 333-148557 (Seventy-sixth); 4(a) to Form 10-Q for the quarter ended September 30, 2009 in 0-20371 (Seventy-seventh); 4.07 to Form 8-K filed October 1, 2010 in 0-20371 (Seventy-eighth); 4.07 to Form 8-K filed July 1, 2014 in 0-20371 (Eighty-first); 4.2 to Form 8-K12B filed October 1, 2015 in 1-32718 (Eighty-second); 4.3 to Form 8-K12B filed October 1, 2015 in 1-32718 (Eighty-third);4.42 to Form 8-K filed March 24, 2016 in 1-32718 (Eighty-fourth); 4.42 to Form 8-K filed May 19, 2016 in 1-32718 (Eighty-fifth); 4.42 to Form 8-K filed August 17, 2016 in 1-32718 (Eighty-sixth); 4.42 to Form 8-K filed October 4, 2016 in 1-32718 (Eighty-seventh); and 4.42 to Form 8-K filed May 23, 2017 in 1-32718 (Eighty-eighth)). |
| |
| (d) 16 -- | Agreement of Resignation, Appointment and Acceptance, dated as of October 3, 2007, among Entergy Gulf States, Inc., JPMorgan Chase Bank, National Association, as resigning trustee, and The Bank of New York, as successor trustee (4(a) to Form 10-Q for the quarter ended September 30, 2007 in 1-27031). |
| |
| (d) 17 -- | Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015, as amended by the following Supplemental Indentures: (4.38 in Registration No. 333-190911-07 (Mortgage); 4(f) to Form 8-K filed March 18, 2016 in 1-32718 (First); 4.40 to Form 8-K filed March 24, 2016 in 1-32718 (Second); 4(h) to Form 10-Q for the quarter ended March 31, 2016 in 1-32718 (Fourth); 4.40 to Form 8-K filed May 19, 2016 in 1-32718 (Fifth); 4.40 to Form 8-K filed August 17, 2016 in 1-32718 (Sixth); 4.41 to Form 8-K filed October 4, 2016 in 1-32718 (Seventh); and 4.41 to Form 8-K filed May 23, 2017 in 1-32718 (Eighth)). |
| |
| (d) 18 -- | |
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| (d) 19 -- | |
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| (d) 20 -- | |
|
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| (d) 21 -- | |
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| (d) 22 -- | |
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| (d) 23 -- | |
Entergy Mississippi
|
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| (e) 1 -- | Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by the following Supplemental Indentures: (* Filed herewith (Mortgage); * Filed herewith (Sixth); A-2(c) to Rule 24 Certificate filed May 14, 1999 in 70-8719 (Thirteenth); 4(b) to Form 10-Q for the quarter ended June 30, 2009 in 1-31508 (Twenty-sixth); 4.38 to Form 8-K filed December 11, 2012 in 1-31508 (Thirtieth); 4.05 to Form 8-K filed March 21, 2014 in 1-31508 (Thirty-first); 4.05 to Form 8-K filed May 13, 2016 in 1-31508 (Thirty-second); 4.16 to Form 8-K filed September 15, 2016 in 1-31508 (Thirty-third); and 4.16 to Form 8-K filed November 14, 2017 in 1-31508 (Thirty-fourth)). |
Entergy New Orleans
|
| |
| (f) 1 -- | Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by the following Supplemental Indentures: (* Filed herewith (Mortgage); * Filed herewith (Third); 4(b) to Form 10-Q for the quarter ended June 30, 1998 in 0-5807 (Seventh); 4.02 to Form 8-K filed November 23, 2010 in 0-5807 (Fifteenth); 4.02 to Form 8-K filed November 29, 2012 in 1-35747 (Sixteenth); 4.02 to Form 8-K filed June 21, 2013 in 1-35747 (Seventeenth); 4(m) to Form 10-Q for the quarter ended March 31, 2016 in 1-35747 (Eighteenth); 4.02 to Form 8-K filed March 22, 2016 in 1-35747 (Nineteenth); 4.02 to Form 8-K filed May 24, 2016 in 1-35747 (Twentieth); and 4.1 to Form 8-K12B filed December 1, 2017 in 1-35747 (Twenty-first)). |
| |
| (f) 2 -- | Amended and Restated Credit Agreement ($25,000,000), dated as of November 20, 2015, among Entergy New Orleans, as the Borrower, the banks and other financial institutions party thereto as Lenders, and Bank of America, N.A., as Administrative Agent (4(f)2 to Form 10-K for the year ended December 31, 2015 in 1-35747). |
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| (f) 3 -- | Amendment, dated as of June 30, 2016, to Amended and Restated Credit Agreement, dated as of November 20, 2015, among Entergy New Orleans, as the Borrower, the banks and other financial institutions party thereto as Lenders, and Bank of America, N.A., as Administrative Agent (4(f) to Form 10-Q for the quarter ended June 30, 2016 in 1-35747). |
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| (f) 4 -- | Amendment, dated as of September 26, 2017, to Amended and Restated Credit Agreement, dated as of November 20, 2015, as amended, among Entergy New Orleans, as the Borrower, the banks and other financial institutions party thereto as Lenders, and Bank of America, N.A., as Administrative Agent (4(j) to Form 10-Q for the quarter ending September 30, 2017 in 1-35747). |
| |
| (f) 5 -- | Borrower Assumption Agreement, dated as of November 30, 2017, of Entergy New Orleans Power, LLC under the Amended and Restated Credit Agreement dated as of November, 2015, as amended, among Entergy New Orleans, Inc., as the Borrower, the banks and other financial institutions party thereto as Lenders, Bank of America, N.A., as Administrative Agent (4.2 to Form 8-K12B filed December 1, 2017 in 1-35747). |
Entergy Texas
|
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| (g) 2 -- | |
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| (g) 3 -- | |
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| *(g) 4 -- | |
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| (g) 5 -- | |
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| (g) 6 -- | |
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| (g) 7 -- | |
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| (g) 8 -- | |
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| (g) 9 -- | Amendment dated as of August 28, 2015, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Texas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(l) to Form 10-Q for the quarter ended September 30, 2015 in 1-34360). |
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| (g) 10 -- | Extension Agreement, dated August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Texas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(r) to Form 10-Q for the quarter ended September 30, 2016 in 1-34360). |
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| (g) 11 -- | Amendment dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Texas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(s) to Form 10-Q for the quarter ended September 30, 2016 in 1-34360). |
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| (g) 12 -- | Extension Agreement, dated August 7, 2017, to Amended and Restated Credit Agreement dated as of August 14, 2015, as amended, among Entergy Texas, Inc., as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(k) to Form 10-Q for the quarter ended September 30, 2017 in 1-34360). |
| |
| (g) 13 -- | Amendment, dated as of October 17, 2017, to Amended and Restated Credit Agreement dated as of August 14, 2015, as amended, among Entergy Texas, Inc., as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(l) to Form 10-Q for the quarter ended September 30, 2017 in 1-34360). |
| |
|
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| (g) 14 -- | Amendment, dated as of October 17, 2017, pursuant to Amended and Restated Credit Agreement dated as of August 14, 2015, as amended, among Entergy Texas, Inc., as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(m) to Form 10-Q for the quarter ended September 30, 2017 in 1-34360). |
(10) Material Contracts
Entergy Corporation
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| +(a) 1 -- | |
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| +(a) 2 -- | |
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| +(a) 3 -- | |
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| +(a) 4 -- | |
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| +(a) 5 -- | |
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| +(a) 6 -- | |
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| +(a) 7 -- | |
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| +(a) 8 -- | |
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| +(a) 9 -- | |
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| +(a) 10 -- | |
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| +(a) 11 -- | |
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| +(a) 12 -- | |
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| +(a) 13 -- | |
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| +(a) 14 -- | |
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| +(a) 15 -- | |
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| +(a) 16 -- | |
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| +(a) 17 -- | |
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| +(a) 18 -- | |
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| +(a) 19 -- | |
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| +(a) 20 -- | |
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| +(a) 21 -- | |
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| +(a) 22 -- | |
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| +(a) 23 -- | |
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| +(a) 24 -- | |
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| +(a) 25 -- | |
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| +(a) 26 -- | |
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| +(a) 27 -- | |
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| +(a) 28 -- | |
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| +(a) 29 -- | |
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| +(a) 30 -- | |
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| +(a) 31 -- | |
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| +(a) 32 -- | |
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| +(a) 33 -- | |
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| +(a) 34 -- | |
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| +(a) 35 -- | |
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| +(a) 36 -- | |
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| +(a) 37 -- | |
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| +(a) 38 -- | |
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| +(a) 39 -- | Retention Agreement effective August 3, 2006 between Leo P. Denault and Entergy Corporation (10(b) to Form 10-Q for the quarter ended June 30, 2006 in 1-11299). |
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| +(a) 40 -- | |
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| +(a) 41 -- | |
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| +(a) 42 -- | |
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| +(a) 43 -- | |
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| +(a) 44 -- | |
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| +(a) 45 -- | |
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| *+(a) 46 -- | |
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| *+(a) 47 -- | |
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| *+(a) 48 -- | |
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| *+(a) 49 -- | |
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| +(a) 50 -- | |
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| +(a) 51 -- | |
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| +(a) 52 -- | |
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| +(a) 53 -- | |
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| +(a) 54 -- | |
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| +(a) 55 -- | |
System Energy
|
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| *(b) 1 -- | |
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| *(b) 2 -- | |
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| *(b) 3 -- | |
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| *(b) 4 -- | |
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| *(b) 5 -- | |
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| (b) 6 -- | Thirty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 2012, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee (10(a)15 to Form 10-K for the year ended December 31, 2012 in 1-11299). |
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| (b) 7 -- | Amendment to the Thirty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of September 18, 2015, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee (4.25 to Form S-3 filed October 2, 2015). |
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| *(b) 8 -- | |
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| *(b) 9 -- | |
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| (b) 10 -- | |
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| *(b) 11 -- | |
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| (b) 12 -- | |
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| *(b) 13 -- | |
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| (b) 14 -- | |
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| *(b) 15 -- | |
(12) Statement Re Computation of Ratios
(23) Consents of Experts and Counsel
(31) Rule 13a-14(a)/15d-14(a) Certifications
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| *(a) | |
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| *(b) | |
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| *(d) | |
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| *(e) | |
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| *(f) | |
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| *(g) | |
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| *(h) | |
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| *(i) | |
(32) Section 1350 Certifications
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| *(a) | |
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| *(b) | |
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| *(c) | |
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| *(d) | |
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| *(e) | |
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| *(f) | |
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| *(g) | |
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| *(h) | |
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| *(i) | |
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| *(j) | |
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| *(k) | |
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| *(l) | |
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| *(m) | |
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| *(n) | |
(101) XBRL Documents
Entergy Corporation
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| *INS - | XBRL Instance Document. |
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| *SCH - | XBRL Taxonomy Extension Schema Document. |
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| *CAL - | XBRL Taxonomy Extension Calculation Linkbase Document. |
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| *DEF - | XBRL Taxonomy Extension Definition Linkbase Document. |
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| *LAB - | XBRL Taxonomy Extension Label Linkbase Document. |
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| *PRE - | XBRL Taxonomy Extension Presentation Linkbase Document. |
_________________
|
| | |
| * | Filed herewith. |
| + | Management contracts or compensatory plans or arrangements. |
ENTERGY CORPORATION
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
| | ENTERGY CORPORATION |
| | |
| | By /s/ Alyson M. Mount |
| | Alyson M. Mount |
| | Senior Vice President and Chief Accounting Officer |
| | |
| | Date: February 26, 20152018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | |
| Signature | Title | Date |
| | | |
/s/ Alyson M. Mount Alyson M. Mount | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 20152018 |
Leo P. Denault (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President and Chief Financial Officer; Principal Financial Officer); Maureen S. Bateman, Patrick J. Condon, Kirkland H. Donald, Gary W. Edwards,Philip L. Frederickson, Alexis M. Herman, Donald C. Hintz, Stuart L. Levenick, Blanche L. Lincoln, Stewart C. Myers,Karen A. Puckett, and W. J. Tauzin and Steven V. Wilkinson (Directors).
|
| |
By: /s/ Alyson M. Mount | February 26, 20152018 |
| (Alyson M. Mount, Attorney-in-fact) | |
ENTERGY ARKANSAS, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
| | ENTERGY ARKANSAS, INC. |
| | |
| | By /s/ Alyson M. Mount |
| | Alyson M. Mount |
| | Senior Vice President and Chief Accounting Officer |
| | |
| | Date: February 26, 20152018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | |
| Signature | Title | Date |
| | | |
/s/ Alyson M. Mount Alyson M. Mount | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 20152018 |
Hugh T. McDonaldRichard C. Riley (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr.Paul D. Hinnenkamp and Mark T. SavoffRoderick K. West (Directors).
|
| |
By: /s/ Alyson M. Mount | February 26, 20152018 |
| (Alyson M. Mount, Attorney-in-fact) | |
ENTERGY GULF STATES LOUISIANA, L.L.C.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
| ENTERGY GULF STATES LOUISIANA, L.L.C. |
| |
| By /s/ Alyson M. Mount
|
| Alyson M. Mount |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 26, 2015 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | |
Signature | Title | Date |
| | |
/s/ Alyson M. Mount
Alyson M. Mount
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 26, 2015 |
Phillip R. May, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr. and Mark T. Savoff (Directors).
|
| |
By: /s/ Alyson M. Mount
| February 26, 2015 |
(Alyson M. Mount, Attorney-in-fact) | |
ENTERGY LOUISIANA, LLC
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
| | ENTERGY LOUISIANA, LLC |
| | |
| | By /s/ Alyson M. Mount |
| | Alyson M. Mount |
| | Senior Vice President and Chief Accounting Officer |
| | |
| | Date: February 26, 20152018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | |
| Signature | Title | Date |
| | | |
/s/ Alyson M. Mount Alyson M. Mount | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 20152018 |
Phillip R. May, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr.Paul D. Hinnenkamp and Mark T. SavoffRoderick K. West (Directors).
|
| |
By: /s/ Alyson M. Mount | February 26, 20152018 |
| (Alyson M. Mount, Attorney-in-fact) | |
ENTERGY MISSISSIPPI, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
| | ENTERGY MISSISSIPPI, INC. |
| | |
| | By /s/ Alyson M. Mount |
| | Alyson M. Mount |
| | Senior Vice President and Chief Accounting Officer |
| | |
| | Date: February 26, 20152018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | |
| Signature | Title | Date |
| | | |
/s/ Alyson M. Mount Alyson M. Mount | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 20152018 |
Haley R. Fisackerly (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr.Paul D. Hinnenkamp and Mark T. SavoffRoderick K. West (Directors).
|
| |
By: /s/ Alyson M. Mount | February 26, 20152018 |
| (Alyson M. Mount, Attorney-in-fact) | |
ENTERGY NEW ORLEANS, INC.LLC
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
| | ENTERGY NEW ORLEANS, INC.LLC |
| | |
| | By /s/ Alyson M. Mount |
| | Alyson M. Mount |
| | Senior Vice President and Chief Accounting Officer |
| | |
| | Date: February 26, 20152018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | |
| Signature | Title | Date |
| | | |
/s/ Alyson M. Mount Alyson M. Mount | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 20152018 |
Charles L. Rice, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr.Paul D. Hinnenkamp and Mark T. SavoffRoderick K. West (Directors).
|
| |
By: /s/ Alyson M. Mount | February 26, 20152018 |
| (Alyson M. Mount, Attorney-in-fact) | |
ENTERGY TEXAS, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
| | ENTERGY TEXAS, INC. |
| | |
| | By /s/ Alyson M. Mount |
| | Alyson M. Mount |
| | Senior Vice President and Chief Accounting Officer |
| | |
| | Date: February 26, 20152018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | |
| Signature | Title | Date |
| | | |
/s/ Alyson M. Mount Alyson M. Mount | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 20152018 |
Sallie T. Rainer (Chair of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr.Paul D. Hinnenkamp and Mark T. SavoffRoderick K. West (Directors).
|
| |
By: /s/ Alyson M. Mount | February 26, 20152018 |
| (Alyson M. Mount, Attorney-in-fact) | |
SYSTEM ENERGY RESOURCES, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
| | SYSTEM ENERGY RESOURCES, INC. |
| | |
| | By /s/ Alyson M. Mount |
| | Alyson M. Mount |
| | Senior Vice President and Chief Accounting Officer |
| | |
| | Date: February 26, 20152018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | |
| Signature | Title | Date |
| | | |
/s/ Alyson M. Mount Alyson M. Mount | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 20152018 |
Theodore H. Bunting, Jr.Roderick K. West (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Jeffrey S. ForbesA. Christopher Bakken, III and Steven C. McNeal (Directors).
|
| |
By: /s/ Alyson M. Mount | February 26, 20152018 |
| (Alyson M. Mount, Attorney-in-fact) | |
EXHIBIT 23(a)
CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333-190911333-213335 on Form S-3 and in Registration Statements Nos. 333-55692, 333-68950, 333-75097, 333-90914, 333-98179, 333-140183, 333-142055, 333-168664, 333-174148, 333-204546, and 333-183090333-206556 on Form S-8 of our reports dated February 26, 2015,2018, relating to the consolidated financial statements and financial statement schedule of Entergy Corporation and Subsidiaries, and the effectiveness of Entergy Corporation and Subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Corporation for the year ended December 31, 2014.2017.
We consent to the incorporation by reference in Registration Statement No. 333-190911-02333-213335-06 on Form S-3 of our reports dated February 26, 2015,2018, relating to the consolidated financial statements and financial statement schedule of Entergy Arkansas, Inc. and Subsidiaries appearing in this Annual Report on Form 10-K of Entergy Arkansas, Inc. for the year ended December 31, 2014.2017.
We consent to the incorporation by reference in Registration Statement No. 333-190911-07333-213335-03 on Form S-3 of our reports dated February 26, 2015,2018, relating to the consolidated financial statements and financial statement schedule of Entergy Louisiana, LLC and Subsidiaries appearing in this Annual Report on Form 10‑K of Entergy Louisiana, LLC for the year ended December 31, 2014.2017.
We consent to the incorporation by reference in Registration Statement No. 333-190911-06333-213335-05 on Form S-3 of our reports dated February 26, 2015, relating to the financial statements and financial statement schedule of Entergy Mississippi, Inc. appearing in this Annual Report on Form 10-K of Entergy Mississippi, Inc. for the year ended December 31, 2014.
We consent to the incorporation by reference in Registration Statement No. 333-190911-05 on Form S-3 of our reports dated February 26, 2015, relating to the financial statements and financial statement schedule of Entergy New Orleans, Inc. appearing in this Annual Report on Form 10-K of Entergy New Orleans, Inc. for the year ended December 31, 2014.
We consent to the incorporation by reference in Registration Statement No. 333-190911-04 on Form S-3 of our reports dated February 26, 2015,2018, relating to the consolidated financial statements and financial statement schedule of Entergy Texas, Inc. and Subsidiaries appearing in this Annual Report on Form 10-K of Entergy Texas, Inc. for the year ended December 31, 2014.2017.
We consent to the incorporation by reference in Registration Statement No. 333-190911-03333-213335-04 on Form S-3 of our reportsreport dated February 26, 2015,2018, relating to the financial statements of System Energy Resources, Inc. appearing in this Annual Report on Form 10-K of System Energy Resources, Inc. for the year ended December 31, 2014.2017.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 20152018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors and Shareholders of
Entergy Corporation and Subsidiaries
Opinion on the Financial Statement Schedule
We have audited the consolidated financial statements of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 20142017 and 2013,2016, and for each of the three years in the period ended December 31, 2014,2017, and the Corporation’s internal control over financial reporting as of December 31, 2014,2017, and have issued our reports thereon dated February 26, 2015; such consolidated financial statements and reports are included elsewhere in this Form 10-K.2018. Our audits also included the consolidated financial statement schedulesschedule of the Corporation listed in Item Item��15. TheseThis consolidated financial statement schedules areschedule is the responsibility of the Corporation’s management. Our responsibility is to express an opinion on the Corporation’s consolidated financial statement schedule based on our audits. In our opinion, such consolidated financial statement schedules,schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presentpresents fairly, in all material respects, the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 20152018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors and Shareholders of
Entergy Arkansas, Inc. and Subsidiaries
Entergy Mississippi, Inc.
Entergy New Orleans, Inc.
Entergy Texas, Inc. and Subsidiaries
To the members and Board of Directors and Members of
Entergy Gulf States Louisiana, L.L.C.
Entergy Louisiana, LLC and Subsidiaries
Entergy New Orleans, LLC and Subsidiaries
Opinion on the Financial Statement Schedules
We have audited the consolidated financial statements of Entergy Arkansas, Inc. and Subsidiaries, Entergy Louisiana, LLC and Subsidiaries, Entergy New Orleans, LLC and Subsidiaries, and Entergy Texas, Inc. and Subsidiaries, and we have also audited the financial statements of Entergy Gulf States Louisiana, L.L.C., Entergy Mississippi, Inc., and Entergy New Orleans, Inc. (collectively the “Companies”) as of December 31, 20142017 and 2013,2016, and for each of the three years in the period ended December 31, 2014,2017, and have issued our reports thereon dated February 26, 2015; such financial statements and reports are included elsewhere in this Form 10-K.2018. Our audits also included the financial statement schedules of the respective Companies listed in Item 15. These financial statement schedules are the responsibility of the respective Companies’ managements.management. Our responsibility is to express an opinion on the Companies’ financial statement schedules based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 20152018
INDEX TO FINANCIAL STATEMENT SCHEDULES
|
| | |
| Schedule | | Page |
| | | |
| II | Valuation and Qualifying Accounts 2014, 2013,2017, 2016, and 2012:2015: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | Entergy New Orleans, Inc. | |
| Entergy Texas, Inc. and Subsidiaries | |
Schedules other than those listed above are omitted because they are not required, not applicable, or the required information is shown in the financial statements or notes thereto.
Columns have been omitted from schedules filed because the information is not applicable.
|
| | | | | | | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2014, 2013, and 2012 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2014 | |
| $34,311 |
| |
| $4,573 |
| |
| $3,221 |
| |
| $35,663 |
|
| 2013 | |
| $31,956 |
| |
| $2,355 |
| |
| $— |
| |
| $34,311 |
|
| 2012 | |
| $31,159 |
| |
| $2,448 |
| |
| $1,651 |
| |
| $31,956 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2014, 2013, and 2012 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2014 | |
| $30,113 |
| |
| $2,881 |
| |
| $747 |
| |
| $32,247 |
|
| 2013 | |
| $28,343 |
| |
| $1,770 |
| |
| $— |
| |
| $30,113 |
|
| 2012 | |
| $26,155 |
| |
| $2,188 |
| |
| $— |
| |
| $28,343 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2014, 2013, and 2012 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2014 | |
| $909 |
| |
| $326 |
| |
| $610 |
| |
| $625 |
|
| 2013 | |
| $711 |
| |
| $198 |
| |
| $— |
| |
| $909 |
|
| 2012 | |
| $843 |
| |
| $123 |
| |
| $255 |
| |
| $711 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2014, 2013, and 2012 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2014 | |
| $965 |
| |
| $516 |
| |
| $497 |
| |
| $984 |
|
| 2013 | |
| $867 |
| |
| $98 |
| |
| $— |
| |
| $965 |
|
| 2012 | |
| $1,147 |
| |
| $121 |
| |
| $401 |
| |
| $867 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2014, 2013, and 2012 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2014 | |
| $906 |
| |
| $269 |
| |
| $302 |
| |
| $873 |
|
| 2013 | |
| $910 |
| |
| ($4 | ) | |
| $— |
| |
| $906 |
|
| 2012 | |
| $756 |
| |
| $154 |
| |
| $— |
| |
| $910 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2014, 2013, and 2012 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2014 | |
| $974 |
| |
| $99 |
| |
| $811 |
| |
| $262 |
|
| 2013 | |
| $446 |
| |
| $528 |
| |
| $— |
| |
| $974 |
|
| 2012 | |
| $465 |
| |
| $12 |
| |
| $31 |
| |
| $446 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2014, 2013, and 2012 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2014 | |
| $443 |
| |
| $483 |
| |
| $254 |
| |
| $672 |
|
| 2013 | |
| $680 |
| |
| ($237 | ) | |
| $— |
| |
| $443 |
|
| 2012 | |
| $1,461 |
| |
| ($21 | ) | |
| $760 |
| |
| $680 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
EXHIBIT INDEX
The following exhibits indicated by an asterisk preceding the exhibit number are filed herewith. The balance of the exhibits have heretofore been filed with the SEC as the exhibits and in the file numbers indicated and are incorporated herein by reference. The exhibits marked with a (+) are management contracts or compensatory plans or arrangements required to be filed herewith and required to be identified as such by Item 15 of Form 10-K.
Some of the agreements included or incorporated by reference as exhibits to this Form 10-K contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties were made solely for the benefit of the other parties to the applicable agreement and (i) were not intended to be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate; (ii) may have been qualified in such agreement by disclosures that were made to the other party in connection with the negotiation of the applicable agreement; (iii) may apply contract standards of “materiality” that are different from the standard of “materiality” under the applicable securities laws; and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement.
Entergy acknowledges that, notwithstanding the inclusion of the foregoing cautionary statements, it is responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in this Form 10-K not misleading.
(2) Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
Entergy Gulf States Louisiana
|
| |
(b) 1 -- | Plan of Merger of Entergy Gulf States, Inc. effective December 31, 2007 (2(ii) to Form 8-K15D5 filed January 7, 2008 in 333-148557). |
|
| | | | | | | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2017, 2016, and 2015 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2017 | |
| $11,924 |
| |
| $4,211 |
| |
| $2,548 |
| |
| $13,587 |
|
| 2016 | |
| $39,895 |
| |
| $7,505 |
| |
| $35,476 |
| |
| $11,924 |
|
| 2015 | |
| $35,663 |
| |
| $6,926 |
| |
| $2,694 |
| |
| $39,895 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
(3) Articles of Incorporation and By-laws
Entergy Corporation
|
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(a) 1 -- | Restated Certificate of Incorporation of Entergy Corporation dated October 10, 2006 (3(a) to Form 10-Q for the quarter ended September 30, 2006). |
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(a) 2 -- | By-Laws of Entergy Corporation as amended February 12, 2007, and as presently in effect (3(ii) to Form 8-K filed February 16, 2007 in 1-11299). |
System Energy
|
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(b) 1 -- | Amended and Restated Articles of Incorporation of System Energy and amendments thereto through April 28, 1989 (A-1(a) to Form U-1 in 70-5399). |
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(b) 2 -- | By-Laws of System Energy effective July 6, 1998, and as presently in effect (3(f) to Form 10-Q for the quarter ended June 30, 1998 in 1-9067). |
Entergy Arkansas
|
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(c) 1 -- | Articles of Amendment and Restatement for the Second Amended and Restated Articles of Incorporation of Entergy Arkansas, effective August 19, 2009 (3 to Form 8-K filed August 24, 2009 in 1-10764). |
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(c) 2 -- | By-Laws of Entergy Arkansas effective November 26, 1999, and as presently in effect (3(ii)(c) to Form 10-K for the year ended December 31, 1999 in 1-10764). |
Entergy Gulf States Louisiana
|
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(d) 1 -- | Articles of Organization of Entergy Gulf States Louisiana effective December 31, 2007 (3(i) to Form 8-K15D5 filed January 7, 2008 in 333-148557). |
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(d) 2 -- | Operating Agreement of Entergy Gulf States Louisiana, effective as of December 31, 2007 (3(ii) to Form 8-K15D5 filed January 7, 2008 in 333-148557). |
Entergy Louisiana
|
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(e) 1 -- | Articles of Organization of Entergy Louisiana effective December 31, 2005 (3(c) to Form 8-K filed January 6, 2006 in 1-32718). |
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(e) 2 -- | Regulations of Entergy Louisiana effective December 31, 2005, and as presently in effect (3(d) to Form 8-K filed January 6, 2006 in 1-32718). |
Entergy Mississippi
|
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(f) 1 -- | Second Amended and Restated Articles of Incorporation of Entergy Mississippi, effective July 21, 2009 (99.1 to Form 8-K filed July 27, 2009 in 1-31508). |
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(f) 2 -- | By-Laws of Entergy Mississippi effective November 26, 1999, and as presently in effect (3(ii)(f) to Form 10-K for the year ended December 31, 1999 in 0-320). |
Entergy New Orleans
|
| |
(g) 1 -- | Amended and Restated Articles of Incorporation of Entergy New Orleans, effective May 8, 2007 (3(a) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807). |
| |
(g) 2 -- | Amended By-Laws of Entergy New Orleans effective May 8, 2007, and as presently in effect (3(b) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807). |
Entergy Texas
|
| |
(h) 1 -- | Certificate of Formation of Entergy Texas, effective December 31, 2007 (3(i) to Form 10 filed March 14, 2008 in 000-53134). |
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(h) 2 -- | Bylaws of Entergy Texas effective December 31, 2007 (3(ii) to Form 10 filed March 14, 2008 in 000-53134). |
(4)Instruments Defining Rights of Security Holders, Including Indentures
Entergy Corporation
|
| |
(a) 1 -- | See (4)(b) through (4)(h) below for instruments defining the rights of holders of long-term debt of System Energy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. |
| |
(a) 2 -- | Credit Agreement ($3,500,000,000), dated as of March 9, 2012, among Entergy Corporation, as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, Bank of the West, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, National Cooperative Services Corporation, and The Northern Trust Company), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.1 to Form 8-K filed March 14, 2012 in 1-11299). |
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*(a) 3 -- | Extension Agreement, dated as of March 1, 2013, to Credit Agreement. |
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*(a) 4 -- | Extension Agreement, dated as of March 14, 2014, to Credit Agreement. |
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(a) 5 -- | Indenture (For Unsecured Debt Securities), dated as of September 1, 2010, between Entergy Corporation and Wells Fargo Bank, National Association (4.01 to Form 8-K filed September 16, 2010 in 1-11299). |
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(a) 6 -- | Officer’s Certificate for Entergy Corporation relating to 3.625% Senior Notes due September 15, 2015 (4.02(a) to Form 8-K filed September 16, 2010 in 1-11299). |
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(a) 7 -- | Officer’s Certificate for Entergy Corporation relating to 5.125% Senior Notes due September 15, 2020 (4.02(b) to Form 8-K filed September 16, 2010 in 1-11299). |
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(a) 8 -- | Officer’s Certificate for Entergy Corporation relating to 4.70% Senior Notes due January 15, 2017 (4.02 to Form 8-K filed January 13, 2012 in 1-11299). |
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(a) 9 -- | Officer’s Certificate for Entergy Corporation relating to 4.50% Senior Note due December 16, 2028 (4(a)7 to Form 10-K for the year ended December 31, 2013 in 1-11299). |
System Energy
|
| |
(b) 1 -- | Mortgage and Deed of Trust, dated as of June 15, 1977, as amended by twenty-four Supplemental Indentures (A-1 in 70-5890 (Mortgage); B and C to Rule 24 Certificate in 70-5890 (First); B to Rule 24 Certificate in 70-6259 (Second); 20(a)-5 to Form 10-Q for the quarter ended June 30, 1981 in 1-3517 (Third); A-1(e)-1 to Rule 24 Certificate in 70-6985 (Fourth); B to Rule 24 Certificate in 70-7021 (Fifth); B to Rule 24 Certificate in 70-7021 (Sixth); A-3(b) to Rule 24 Certificate in 70-7026 (Seventh); A-3(b) to Rule 24 Certificate in 70-7158 (Eighth); B to Rule 24 Certificate in 70-7123 (Ninth); B-1 to Rule 24 Certificate in 70-7272 (Tenth); B-2 to Rule 24 Certificate in 70-7272 (Eleventh); B-3 to Rule 24 Certificate in 70-7272 (Twelfth); B-1 to Rule 24 Certificate in 70-7382 (Thirteenth); B-2 to Rule 24 Certificate in 70-7382 (Fourteenth); A-2(c) to Rule 24 Certificate in 70-7946 (Fifteenth); A-2(c) to Rule 24 Certificate in 70-7946 (Sixteenth); A-2(d) to Rule 24 Certificate in 70-7946 (Seventeenth); A-2(e) to Rule 24 Certificate dated May 4, 1993 in 70-7946 (Eighteenth); A-2(g) to Rule 24 Certificate dated May 6, 1994 in 70-7946 (Nineteenth); A-2(a)(1) to Rule 24 Certificate dated August 8, 1996 in 70-8511 (Twentieth); A-2(a)(2) to Rule 24 Certificate dated August 8, 1996 in 70-8511 (Twenty-first); A-2(a) to Rule 24 Certificate filed October 4, 2002 in 70-9753 (Twenty-second); 4(b) to Form 10-Q for the quarter ended September 30, 2007 in 1-9067 (Twenty-third); and 4.42 to Form 8-K dated September 25, 2012 in 1-9067 (Twenty-fourth)). |
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(b) 2 -- | Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-3(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182). |
| |
(b) 3 -- | Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-4(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182). |
Entergy Arkansas
|
| |
(c) 1 -- | Mortgage and Deed of Trust, dated as of October 1, 1944, as amended by seventy-seven Supplemental Indentures (7(d) in 2-5463 (Mortgage); 7(b) in 2-7121 (First); 7(c) in 2-7605 (Second); 7(d) in 2-8100 (Third); 7(a)-4 in 2-8482 (Fourth); 7(a)-5 in 2-9149 (Fifth); 4(a)-6 in 2-9789 (Sixth); 4(a)-7 in 2-10261 (Seventh); 4(a)-8 in 2-11043 (Eighth); 2(b)-9 in 2-11468 (Ninth); 2(b)-10 in 2-15767 (Tenth); D in 70-3952 (Eleventh); D in 70-4099 (Twelfth); 4(d) in 2-23185 (Thirteenth); 2(c) in 2-24414 (Fourteenth); 2(c) in 2-25913 (Fifteenth); 2(c) in 2-28869 (Sixteenth); 2(d) in 2-28869 (Seventeenth); 2(c) in 2-35107 (Eighteenth); 2(d) in 2-36646 (Nineteenth); 2(c) in 2-39253 (Twentieth); 2(c) in 2-41080 (Twenty-first); C-1 to Rule 24 Certificate in 70-5151 (Twenty-second); C-1 to Rule 24 Certificate in 70-5257 (Twenty-third); C to Rule 24 Certificate in 70-5343 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-5404 (Twenty-fifth); C to Rule 24 Certificate in 70-5502 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-5556 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-5693 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6078 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6174 (Thirtieth); C-1 to Rule 24 Certificate in 70-6246 (Thirty-first); C-1 to Rule 24 Certificate in 70-6498 (Thirty-second); A-4b-2 to Rule 24 Certificate in 70-6326 (Thirty-third); C-1 to Rule 24 Certificate in 70-6607 (Thirty-fourth); C-1 to Rule 24 Certificate in 70-6650 (Thirty-fifth); C-1 to Rule 24 Certificate dated December 1, 1982 in 70-6774 (Thirty-sixth); C-1 to Rule 24 Certificate dated February 17, 1983 in 70-6774 (Thirty-seventh); A-2(a) to Rule 24 Certificate dated December 5, 1984 in 70-6858 (Thirty-eighth); A-3(a) to Rule 24 Certificate in 70-7127 (Thirty-ninth); A-7 to Rule 24 Certificate in 70-7068 (Fortieth); A-8(b) to Rule 24 Certificate dated July 6, 1989 in 70-7346 (Forty-first); A-8(c) to Rule 24 Certificate dated February 1, 1990 in 70-7346 (Forty-second); 4 to Form 10-Q for the quarter ended September 30, 1990 in 1-10764 (Forty-third); A-2(a) to Rule 24 Certificate dated November 30, 1990 in 70-7802 (Forty-fourth); A-2(b) to Rule 24 Certificate dated January 24, 1991 in 70-7802 (Forty-fifth); 4(d)(2) in 33-54298 (Forty-sixth); 4(c)(2) to Form 10-K for the year ended December 31, 1992 in 1-10764 (Forty-seventh); 4(b) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-eighth); 4(c) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-ninth); 4(b) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fiftieth); 4(c) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fifty-first); 4(a) to Form 10-Q for the quarter ended June 30, 1994 in 1-10764 (Fifty-second); C-2 to Form U5S for the year ended December 31, 1995 (Fifty-third); C-2(a) to Form U5S for the year ended December 31, 1996 (Fifty-fourth); 4(a) to Form 10-Q for the quarter ended March 31, 2000 in 1-10764 (Fifty-fifth); 4(a) to Form 10-Q for the quarter ended September 30, 2001 in 1-10764 (Fifty-sixth); C-2(a) to Form U5S for the year ended December 31, 2001 (Fifty-seventh); 4(c)1 to Form 10-K for the year December 31, 2002 in 1-10764 (Fifty-eighth); 4(a) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Fifty-ninth); 4(f) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Sixtieth); 4(h) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Sixty-first); 4(e) to Form 10-Q for the quarter ended September 30, 2004 in 1-10764 (Sixty-second); 4(c)1 to Form 10-K for the year December 31, 2004 in 1-10764 (Sixty-third); C-2(a) to Form U5S for the year ended December 31, 2004 (Sixty-fourth); 4(c) to Form 10-Q for the quarter ended June 30, 2005 in 1-10764 (Sixty-fifth); 4(a) to Form 10-Q for the quarter ended June 30, 2006 in 1-10764 (Sixty-sixth); 4(b) to Form 10-Q for the quarter ended June 30, 2008 in 1-10764 (Sixty-seventh); 4(c)1 to Form 10-K for the year ended December 31, 2008 in 1-10764 (Sixty-eighth); 4.06 to Form 8-K dated October 8, 2010 in 1-10764 (Sixty-ninth); 4.06 to Form 8-K dated November 12, 2010 in 1-10764 (Seventieth); 4.06 to Form 8-K dated December 13, 2012 in 1-10764 (Seventy-first); 4(e) to Form 8-K dated January 9, 2013 in 1-10764 (Seventy-second); 4.06 to Form 8-K dated May 30, 2013 in 1-10764 (Seventy-third); 4.06 to Form 8-K dated June 4, 2013 in 1-10764 (Seventy-fourth); 4.02 to Form 8-K dated July 26, 2013 in 1-10764 (Seventy-fifth); 4.05 to Form 8-K dated March 14, 2014 in 1-10764 (Seventy-sixth); and 4.05 to Form 8-K dated December 9, 2014 in 1-10764 (Seventy-Seventh)). |
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(c) 2 -- | Credit Agreement ($150,000,000), dated as of March 9, 2012, among Entergy Arkansas, Inc., as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.2 to Form 8-K filed March 14, 2012 in 1-10764). |
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*(c) 3 -- | Extension Agreement, dated as of March 1, 2013, to Credit Agreement. |
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*(c) 4 -- | Extension Agreement, dated as of March 14, 2014, to Credit Agreement. |
Entergy Gulf States Louisiana
|
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(d) 1 -- | Indenture of Mortgage, dated September 1, 1926, as amended by certain Supplemental Indentures (B-a-I-1 in Registration No. 2-2449 (Mortgage); 7-A-9 in Registration No. 2-6893 (Seventh); B to Form 8-K dated September 1, 1959 (Eighteenth); B to Form 8-K dated February 1, 1966 (Twenty-second); B to Form 8-K dated March 1, 1967 (Twenty-third); C to Form 8-K dated March 1, 1968 (Twenty-fourth); B to Form 8-K dated November 1, 1968 (Twenty-fifth); B to Form 8-K dated April 1, 1969 (Twenty-sixth); 2-A-8 in Registration No. 2-66612 (Thirty-eighth); 4-2 to Form 10-K for the year ended December 31, 1984 in 1-27031 (Forty-eighth); 4-2 to Form 10-K for the year ended December 31, 1988 in 1-27031 (Fifty-second); 4 to Form 10-K for the year ended December 31, 1991 in 1-27031 (Fifty-third); 4 to Form 8-K dated July 29, 1992 in 1-27031 (Fifth-fourth); 4 to Form 10-K dated December 31, 1992 in 1-27031 (Fifty-fifth); 4 to Form 10-Q for the quarter ended March 31, 1993 in 1-27031 (Fifty-sixth); 4-2 to Amendment No. 9 to Registration No. 2-76551 (Fifty-seventh); 4(b) to Form 10-Q for the quarter ended March 31,1999 in 1-27031 (Fifty-eighth); A-2(a) to Rule 24 Certificate dated June 23, 2000 in 70-8721 (Fifty-ninth); A-2(a) to Rule 24 Certificate dated September 10, 2001 in 70-9751 (Sixtieth); A-2(b) to Rule 24 Certificate dated November 18, 2002 in 70-9751 (Sixty-first); A-2(c) to Rule 24 Certificate dated December 6, 2002 in 70-9751 (Sixty-second); A-2(d) to Rule 24 Certificate dated June 16, 2003 in 70-9751 (Sixty-third); A-2(e) to Rule 24 Certificate dated June 27, 2003 in 70-9751 (Sixty-fourth); A-2(f) to Rule 24 Certificate dated July 11, 2003 in 70-9751 (Sixty-fifth); A-2(g) to Rule 24 Certificate dated July 28, 2003 in 70-9751 (Sixty-sixth); A-3(i) to Rule 24 Certificate dated November 4, 2004 in 70-10158 (Sixty-seventh); A-3(ii) to Rule 24 Certificate dated November 23, 2004 in 70-10158 (Sixty-eighth); A-3(iii) to Rule 24 Certificate dated February 16, 2005 in 70-10158 (Sixty-ninth); A-3(iv) to Rule 24 Certificate dated June 2, 2005 in 70-10158 (Seventieth); A-3(v) to Rule 24 Certificate dated July 21, 2005 in 70-10158 (Seventy-first); A-3(vi) to Rule 24 Certificate dated October 7, 2005 in 70-10158 (Seventy-second); A-3(vii) to Rule 24 Certificate dated December 19, 2005 in 70-10158 (Seventy-third); 4(a) to Form 10-Q for the quarter ended March 31, 2006 in 1-27031 (Seventy-fourth); 4(iv) to Form 8-K15D5 dated January 7, 2008 in 333-148557 (Seventy-fifth); 4(a) to Form 10-Q for the quarter ended June 30, 2008 in 333-148557 (Seventy-sixth); 4(a) to Form 10-Q for the quarter ended September 30, 2009 in 0-20371 (Seventy-seventh); 4.07 to Form 8-K dated October 1, 2010 in 0-20371 (Seventy-eighth); 4(c) to Form 8-K filed October 12, 2010 in 0-20371 (Seventy-ninth); 4(f) to Form 8-K filed October 12, 2010 in 0-20371 (Eightieth); and 4.07 to Form 8-K dated July 1, 2014 in 0-20371 (Eighty-first)). |
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(d) 2 -- | Indenture, dated March 21, 1939, accepting resignation of The Chase National Bank of the City of New York as trustee and appointing Central Hanover Bank and Trust Company as successor trustee (B-a-1-6 in Registration No. 2-4076). |
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(d) 3 -- | Agreement of Resignation, Appointment and Acceptance, dated as of October 3, 2007, among Entergy Gulf States, Inc., JPMorgan Chase Bank, National Association, as resigning trustee, and The Bank of New York, as successor trustee (4(a) to Form 10-Q for the quarter ended September 30, 2007 in 1-27031). |
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(d) 4 -- | Assumption Agreement, dated as of May 30, 2008, among Entergy Texas, Inc., Entergy Gulf States Louisiana, L.L.C. and Citibank, N.A., as administrative agent (10(a) to Form 10-Q for the quarter ended March 31, 2008 in 0-53134). |
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(d) 5 -- | Credit Agreement ($150,000,000), dated as of March 9, 2012, among Entergy Gulf States Louisiana, L.L.C., as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.3 to Form 8-K filed March 14, 2012 in 0-20371). |
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*(d) 6 -- | Extension Agreement, dated as of March 1, 2013, to Credit Agreement. |
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*(d) 7 -- | Extension Agreement, dated as of March 14, 2014, to Credit Agreement. |
Entergy Louisiana
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(e) 1 -- | Mortgage and Deed of Trust, dated as of April 1, 1944, as amended by seventy-eight Supplemental Indentures (7(d) in 2-5317 (Mortgage); 7(b) in 2-7408 (First); 7(c) in 2-8636 (Second); 4(b)-3 in 2-10412 (Third); 4(b)-4 in 2-12264 (Fourth); 2(b)-5 in 2-12936 (Fifth); D in 70-3862 (Sixth); 2(b)-7 in 2-22340 (Seventh); 2(c) in 2-24429 (Eighth); 4(c)-9 in 2-25801 (Ninth); 4(c)-10 in 2-26911 (Tenth); 2(c) in 2-28123 (Eleventh); 2(c) in 2-34659 (Twelfth); C to Rule 24 Certificate in 70-4793 (Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); 2(b)-2 in 2-39437 (Fifteenth); 2(b)-2 in 2-42523 (Sixteenth); C to Rule 24 Certificate in 70-5242 (Seventeenth); C to Rule 24 Certificate in 70-5330 (Eighteenth); C-1 to Rule 24 Certificate in 70-5449 (Nineteenth); C-1 to Rule 24 Certificate in 70-5550 (Twentieth); A-6(a) to Rule 24 Certificate in 70-5598 (Twenty-first); C-1 to Rule 24 Certificate in 70-5711 (Twenty-second); C-1 to Rule 24 Certificate in 70-5919 (Twenty-third); C-1 to Rule 24 Certificate in 70-6102 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-6169 (Twenty-fifth); C-1 to Rule 24 Certificate in 70-6278 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-6355 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-6508 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6556 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6635 (Thirtieth); C-1 to Rule 24 Certificate in 70-6834 (Thirty-first); C-1 to Rule 24 Certificate in 70-6886 (Thirty-second); C-1 to Rule 24 Certificate in 70-6993 (Thirty-third); C-2 to Rule 24 Certificate in 70-6993 (Thirty-fourth); C-3 to Rule 24 Certificate in 70-6993 (Thirty-fifth); A-2(a) to Rule 24 Certificate in 70-7166 (Thirty-sixth); A-2(a) in 70-7226 (Thirty-seventh); C-1 to Rule 24 Certificate in 70-7270 (Thirty-eighth); 4(a) to Quarterly Report on Form 10-Q for the quarter ended June 30, 1988 in 1-8474 (Thirty-ninth); A-2(b) to Rule 24 Certificate in 70-7553 (Fortieth); A-2(d) to Rule 24 Certificate in 70-7553 (Forty-first); A-3(a) to Rule 24 Certificate in 70-7822 (Forty-second); A-3(b) to Rule 24 Certificate in 70-7822 (Forty-third); A-2(b) to Rule 24 Certificate in 70-7822 (Forty-fourth); A-3(c) to Rule 24 Certificate in 70-7822 (Forty-fifth); A-2(c) to Rule 24 Certificate dated April 7, 1993 in 70-7822 (Forty-sixth); A-3(d) to Rule 24 Certificate dated June 4, 1993 in 70-7822 (Forth-seventh); A-3(e) to Rule 24 Certificate dated December 21, 1993 in 70-7822 (Forty-eighth); A-3(f) to Rule 24 Certificate dated August 1, 1994 in 70-7822 (Forty-ninth); A-4(c) to Rule 24 Certificate dated September 28, 1994 in 70-7653 (Fiftieth); A-2(a) to Rule 24 Certificate dated April 4, 1996 in 70-8487 (Fifty-first); A-2(a) to Rule 24 Certificate dated April 3, 1998 in 70-9141 (Fifty-second); A-2(b) to Rule 24 Certificate dated April 9, 1999 in 70-9141 (Fifty-third); A-3(a) to Rule 24 Certificate dated July 6, 1999 in 70-9141 (Fifty-fourth); A-2(c) to Rule 24 Certificate dated June 2, 2000 in 70-9141 (Fifty-fifth); A-2(d) to Rule 24 Certificate dated April 4, 2002 in 70-9141 (Fifty-sixth); A-3(a) to Rule 24 Certificate dated March 30, 2004 in 70-10086 (Fifty-seventh); A-3(b) to Rule 24 Certificate dated October 15, 2004 in 70-10086 (Fifty-eighth); A-3(c) to Rule 24 Certificate dated October 26, 2004 in 70-10086 (Fifty-ninth); A-3(d) to Rule 24 Certificate dated May 18, 2005 in 70-10086 (Sixtieth); A-3(e) to Rule 24 Certificate dated August 25, 2005 in 70-10086 (Sixty-first); A-3(f) to Rule 24 Certificate dated October 31, 2005 in 70-10086 (Sixty-second); B-4(i) to Rule 24 Certificate dated January 10, 2006 in 70-10324 (Sixty-third); B-4(ii) to Rule 24 Certificate dated January 10, 2006 in 70-10324 (Sixty-fourth); 4(a) to Form 10-Q for the quarter ended September 30, 2008 in 1-32718 (Sixty-fifth); 4(e)1 to Form 10-K for the year ended December 31, 2009 in 1-132718 (Sixty-sixth); 4(a) to Form 10-Q for the quarter ended March 31, 2010 in 1-32718 (Sixty-seventh); 4.08 to Form 8-K dated September 24, 2010 in 1-32718 (Sixty-eighth); 4(c) to Form 8-K filed October 12, 2010 in 1-32718 (Sixty-ninth); 4.08 to Form 8-K dated November 23, 2010 in 1-32718 (Seventieth); 4.08 to Form 8-K dated March 24, 2011 in 1-32718 (Seventy-first); 4(a) to Form 10-Q for the quarter ended June 30, 2011 in 1-32718 (Seventy-second); 4.08 to Form 8-K dated December 15, 2011 in 1-32718 (Seventy-third); 4.08 to Form 8-K dated January 12, 2012 in 1-32718 (Seventy-fourth); 4.08 to Form 8-K dated July 3, 2012 in 1-32718 (Seventy-fifth); 4.08 to Form 8-K dated December 4, 2012 in 1-32718 (Seventy-sixth); 4.08 to Form 8-K dated May 21, 2013 in 1-32718 (Seventy-seventh); 4.08 to Form 8-K dated August 23, 2013 in 1-32718 (Seventy-eighth); 4.08 to Form 8-K dated June 24, 2014 in 1-32718 (Seventy-ninth); 4.08 to Form 8-K dated July 1, 2014 in 1-32718 (Eightieth); and 4.08 to Form 8-K dated November 21, 2014 (Eighty-first)). |
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(e) 2 -- | Facility Lease No. 1, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-1 in Registration No. 33-30660), as supplemented by Lease Supplement No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 1, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 2 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474). |
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(e) 3 -- | Facility Lease No. 2, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-2 in Registration No. 33-30660), as supplemented by Lease Supplemental No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 2, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 3 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474). |
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(e) 4 -- | Facility Lease No. 3, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-3 in Registration No. 33-30660), as supplemented by Lease Supplemental No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 3, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 4 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474). |
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(e) 5 -- | Credit Agreement ($200,000,000), dated as of March 9, 2012, among Entergy Louisiana, LLC, as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.4 to Form 8-K filed March 14, 2012 in 1-32718). |
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*(e) 6 -- | Extension Agreement, dated as of March 1, 2013, to Credit Agreement. |
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*(e) 7 -- | Extension Agreement, dated as of March 14, 2014, to Credit Agreement. |
Entergy Mississippi
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(f) 1 -- | Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by thirty-one Supplemental Indentures (A-2(a)-2 to Rule 24 Certificate in 70-7461 (Mortgage); A-2(b)-2 in 70-7461 (First); A-5(b) to Rule 24 Certificate in 70-7419 (Second); A-4(b) to Rule 24 Certificate in 70-7554 (Third); A-1(b)-1 to Rule 24 Certificate in 70-7737 (Fourth); A-2(b) to Rule 24 Certificate dated November 24, 1992 in 70-7914 (Fifth); A-2(e) to Rule 24 Certificate dated January 22, 1993 in 70-7914 (Sixth); A-2(g) to Form U-1 in 70-7914 (Seventh); A-2(i) to Rule 24 Certificate dated November 10, 1993 in 70-7914 (Eighth); A-2(j) to Rule 24 Certificate dated July 22, 1994 in 70-7914 (Ninth); (A-2(l) to Rule 24 Certificate dated April 21, 1995 in 70-7914 (Tenth); A-2(a) to Rule 24 Certificate dated June 27, 1997 in 70-8719 (Eleventh); A-2(b) to Rule 24 Certificate dated April 16, 1998 in 70-8719 (Twelfth); A-2(c) to Rule 24 Certificate dated May 12, 1999 in 70-8719 (Thirteenth); A-3(a) to Rule 24 Certificate dated June 8, 1999 in 70-8719 (Fourteenth); A-2(d) to Rule 24 Certificate dated February 24, 2000 in 70-8719 (Fifteenth); A-2(a) to Rule 24 Certificate dated February 9, 2001 in 70-9757 (Sixteenth); A-2(b) to Rule 24 Certificate dated October 31, 2002 in 70-9757 (Seventeenth); A-2(c) to Rule 24 Certificate dated December 2, 2002 in 70-9757 (Eighteenth); A-2(d) to Rule 24 Certificate dated February 6, 2003 in 70-9757 (Nineteenth); A-2(e) to Rule 24 Certificate dated April 4, 2003 in 70-9757 (Twentieth); A-2(f) to Rule 24 Certificate dated June 6, 2003 in 70-9757 (Twenty-first); A-3(a) to Rule 24 Certificate dated April 8, 2004 in 70-10157 (Twenty-second); A-3(b) to Rule 24 Certificate dated April 29, 2004 in 70-10157 (Twenty-third); A-3(c) to Rule 24 Certificate dated October 4, 2004 in 70-10157 (Twenty-fourth); A-3(d) to Rule 24 Certificate dated January 27, 2006 in 70-10157 (Twenty-fifth); 4(b) to Form 10-Q for the quarter ended June 30, 2009 in 1-31508 (Twenty-sixth); 4(b) to Form 10-Q for the quarter ended March 31, 2010 in 1-31508 (Twenty-seventh); 4.38 to Form 8-K dated April 15, 2011 in 1-31508 (Twenty-eighth); 4.38 to Form 8-K dated May 13, 2011 in 1-31508 (Twenty-ninth); 4.38 to Form 8-K dated December 11, 2012 in 1-31508 (Thirtieth); and 4.05 to Form 8-K dated March 21, 2014 in 1-31508 (Thirty-first)). |
Entergy New Orleans
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(g) 1 -- | Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by seventeen Supplemental Indentures (A-2(c) to Rule 24 Certificate in 70-7350 (Mortgage); A-5(b) to Rule 24 Certificate in 70-7350 (First); A-4(b) to Rule 24 Certificate in 70-7448 (Second); 4(f)4 to Form 10-K for the year ended December 31, 1992 in 0-5807 (Third); 4(a) to Form 10-Q for the quarter ended September 30, 1993 in 0-5807 (Fourth); 4(a) to Form 8-K dated April 26, 1995 in 0-5807 (Fifth); 4(a) to Form 8-K dated March 22, 1996 in 0-5807 (Sixth); 4(b) to Form 10-Q for the quarter ended June 30, 1998 in 0-5807 (Seventh); 4(d) to Form 10-Q for the quarter ended June 30, 2000 in 0-5807 (Eighth); C-5(a) to Form U5S for the year ended December 31, 2000 (Ninth); 4(b) to Form 10-Q for the quarter ended September 30, 2002 in 0-5807 (Tenth); 4(k) to Form 10-Q for the quarter ended June 30, 2003 in 0-5807 (Eleventh); 4(a) to Form 10-Q for the quarter ended September 30, 2004 in 0-5807 (Twelfth); 4(b) to Form 10-Q for the quarter ended September 30, 2004 in 0-5807 (Thirteenth); 4(e) to Form 10-Q for the quarter ended June 30, 2005 in 0-5807 (Fourteenth); 4.02 to Form 8-K dated November 23, 2010 in 0-5807 (Fifteenth); 4.02 to Form 8-K dated November 29, 2012 in 0-5807 (Sixteenth); and 4.02 to Form 8-K dated June 21, 2013 in 0-5807 (Seventeenth)). |
Entergy Texas
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(h) 1 -- | Credit Agreement ($150,000,000), dated as of March 9, 2012, among Entergy Texas, Inc., as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.5 to Form 8-K filed March 14, 2012 in 1-34360). |
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*(h) 2 -- | Extension Agreement, dated as of March 1, 2013, to Credit Agreement. |
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*(h) 3 -- | Extension Agreement, dated as of March 14, 2014, to Credit Agreement. |
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(h) 4 -- | Assumption Agreement, dated as of May 30, 2008, among Entergy Texas, Inc., Entergy Gulf States Louisiana, L.L.C. and Citibank, N.A., as administrative agent (10(a) to Form 10-Q for the quarter ended March 31, 2008 in 0-53134). |
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(h) 5 -- | Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(h)2 to Form 10-K for the year ended December 31, 2008 in 0-53134). |
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(h) 6 -- | Officer’s Certificate No. 1-B-1 dated January 27, 2009, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(h)3 to Form 10-K for the year ended December 31, 2008 in 0-53134). |
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(h) 7 -- | Officer’s Certificate No. 2-B-2 dated May 14, 2009, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(a) to Form 10-Q for the quarter ended June 30, 2009 in 1-34360). |
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(h) 8 -- | Officer’s Certificate No. 3-B-3 dated May 18, 2010, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(a) to Form 10-Q for the quarter ended June 30, 2010 in 1-34360). |
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(h) 9 -- | Officer’s Certificate No. 5-B-4 dated September 7, 2011, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4.40 to Form 8-K dated September 13, 2011 in 1-34360). |
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(h) 10 -- | Officer’s Certificate No. 7-B-5 dated May 13, 2014, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(d) to Form 10-Q for the quarter ended June 30, 2014 in 1-34360). |
(10) Material Contracts
Entergy Corporation
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(a) 1 -- | Agreement, dated April 23, 1982, among certain System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
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(a) 2 -- | Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-11299). |
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(a) 3 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080). |
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(a) 4 -- | Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-41080). |
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(a) 5 -- | Amendment, dated April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517). |
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(a) 6 -- | Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(a)12 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
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(a) 7 -- | Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 2013 in 1-11299). |
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(a) 8 -- | Availability Agreement, dated June 21, 1974, among System Energy and certain other System companies (B to Rule 24 Certificate dated June 24, 1974 in 70-5399). |
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(a) 9 -- | First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate dated June 24, 1977 in 70-5399). |
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(a) 10 -- | Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate dated July 1, 1981 in 70-6592). |
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(a) 11 -- | Third Amendment to Availability Agreement, dated as of June 28, 1984 (B-13(a) to Rule 24 Certificate dated July 6, 1984 in 70-6985). |
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(a) 12 -- | Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate dated June 8, 1989 in 70-5399). |
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(a) 13 -- | Thirty-fifth Assignment of Availability Agreement, Consent and Agreement, dated as of December 22, 2003, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, and Union Bank of California, N.A (10(a)25 to Form 10-K for the year ended December 31, 2003 in 1-11299). |
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(a) 14 -- | First Amendment to Thirty-fifth Assignment of Availability Agreement, Consent and Agreement, dated as of December 17, 2004 (10(a)24 to Form 10-K for the year ended December 31, 2004 in 1-11299). |
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(a) 15 -- | Thirty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 2012, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee (10(a)15 to Form 10-K for the year ended December 31, 2012 in 1-11299). |
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(a) 16 -- | Capital Funds Agreement, dated June 21, 1974, between Entergy Corporation and System Energy (C to Rule 24 Certificate dated June 24, 1974 in 70-5399). |
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(a) 17 -- | First Amendment to Capital Funds Agreement, dated as of June 1, 1989 (B to Rule 24 Certificate dated June 8, 1989 in 70-5399). |
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(a) 18 -- | Thirty-fifth Supplementary Capital Funds Agreement and Assignment, dated as of December 22, 2003, among Entergy Corporation, System Energy, and Union Bank of California, N.A (10(a)38 to Form 10-K for the year ended December 31, 2003 in 1-11299). |
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(a) 19 -- | Thirty-seventh Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 2012, among Entergy Corporation, System Energy, and The Bank of New York Mellon, as successor trustee (10(a)19 to Form 10-K for the year ended December 31, 2012 in 1-11299). |
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(a) 20 -- | First Amendment to Supplementary Capital Funds Agreements and Assignments, dated as of June 1, 1989, by and between Entergy Corporation, System Energy, Deposit Guaranty National Bank, United States Trust Company of New York and Gerard F. Ganey (C to Rule 24 Certificate dated June 8, 1989 in 70-7026). |
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(a) 21 -- | First Amendment to Supplementary Capital Funds Agreements and Assignments, dated as of June 1, 1989, by and between Entergy Corporation, System Energy, United States Trust Company of New York and Gerard F. Ganey (C to Rule 24 Certificate dated June 8, 1989 in 70-7123). |
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(a) 22 -- | First Amendment to Supplementary Capital Funds Agreement and Assignment, dated as of June 1, 1989, by and between Entergy Corporation, System Energy and Chemical Bank (C to Rule 24 Certificate dated June 8, 1989 in 70-7561). |
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(a) 23 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
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(a) 24 -- | Joint Construction, Acquisition and Ownership Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B-1(a) in 70-6337), as amended by Amendment No. 1, dated as of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31, 1980 (1 to Rule 24 Certificate dated October 30, 1981 in 70-6337). |
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(a) 25 -- | Operating Agreement dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337). |
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(a) 26 -- | Assignment, Assumption and Further Agreement No. 1, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561). |
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(a) 27 -- | Assignment, Assumption and Further Agreement No. 2, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561). |
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(a) 28 -- | Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337). |
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(a) 29 -- | Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033). |
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(a) 30 -- | Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and Entergy Louisiana (28(a) to Form 8-K dated June 4, 1982 in 1-3517). |
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(a) 31 -- | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
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(a) 32 -- | First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
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(a) 33 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
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(a) 34 -- | Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987). |
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(a) 35 -- | First Amendment, dated January 1, 1990, to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). |
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(a) 36 -- | Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). |
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(a) 37 -- | Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
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(a) 38 -- | Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
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(a) 39 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-11299). |
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(a) 40 -- | Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-11299). |
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(a) 41 -- | Guaranty Agreement between Entergy Corporation and Entergy Arkansas, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757). |
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(a) 42 -- | Guarantee Agreement between Entergy Corporation and Entergy Louisiana, dated as of September 20, 1990 (B-2(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757). |
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(a) 43 -- | Guarantee Agreement between Entergy Corporation and System Energy, dated as of September 20, 1990 (B-3(a) to Rule 24 Certificate dated September 27, 1990 in 70- 7757). |
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(a) 44 -- | Loan Agreement between Entergy Operations and Entergy Corporation, dated as of September 20, 1990 (B-12(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679). |
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(a) 45 -- | Loan Agreement between Entergy Corporation and Entergy Systems and Service, Inc., dated as of December 29, 1992 (A-4(b) to Rule 24 Certificate in 70-7947). |
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+(a) 46 -- | 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (Effective for Grants and Elections On or After January 1, 2007) (Appendix B to Entergy Corporation’s Definitive Proxy Statement filed on March 24, 2006 in 1-11299). |
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+(a) 47 -- | First Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective October 26, 2006 (10(a)50 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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+(a) 48 -- | Second Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective January 1, 2009 (10(a)51 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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+(a) 49 -- | Third Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective December 30, 2010 (10(a)52 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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+(a) 50 -- | Amended and Restated 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries (Effective for Grants and Elections After February 13, 2003) (10(a) to Form 10-Q for the quarter ended March 31, 2003 in 1-11299). |
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+(a) 51 -- | First Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective January 1, 2005 (10(a)54 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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+(a) 52 -- | Second Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective October 26, 2006 (10(a)55 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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+(a) 53 -- | Third Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009 (10(a)56 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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+(a) 54 -- | 2011 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (Annex A to Entergy Corporation’s Definitive Proxy Statement filed on March 24, 2011 in 1-11299). |
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+(a) 55 -- | Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)57 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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+(a) 56 -- | First Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)58 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 57 -- | Second Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)57 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
| |
+(a) 58 -- | Third Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(b) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299). |
| |
+(a) 59 -- | Fourth Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(c) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299). |
| |
+(a) 60 -- | Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)59 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 61 -- | First Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)60 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 62 -- | Second Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)60 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
| |
+(a) 63 -- | Executive Disability Plan of Entergy Corporation and Subsidiaries (10(a)74 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
| |
+(a) 64 -- | Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)62 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 65 -- | First Amendment of the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)63 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 66 -- | Second Amendment of the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)64 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
| |
+(a) 67 -- | System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective as of January 1, 2009 (10(a)77 to Form 10-K for the year ended December 31, 2009 in 1-11299). |
| |
+(a) 68-- | First Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 1, 2010 (10(a)78 to Form 10-K for the year ended December 31, 2009 in 1-11299). |
| |
+(a) 69 -- | Second Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)69 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
|
| |
+(a) 70 -- | Third Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)71 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
| |
+(a) 71 -- | Post-Retirement Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)80 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
| |
+(a) 72 -- | Amendment, effective December 28, 2001, to the Post-Retirement Plan of Entergy Corporation and Subsidiaries (10(a)81 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
| |
+(a) 73 -- | Pension Equalization Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)74 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 74 -- | First Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)75 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 75 -- | Second Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)76 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
| |
+(a) 76 -- | Third Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective June 19, 2013 (10(b) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299). |
| |
+(a) 77 -- | Fourth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(c) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299). |
| |
+(a) 78 -- | Fifth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(a) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299). |
| |
+(a) 79 -- | Service Recognition Program for Non-Employee Outside Directors of Entergy Corporation and Subsidiaries, as amended and restated effective June 1, 2012 (10(a) to Form 10-Q for the quarter ended September 30, 2012 in 1-11299). |
| |
+(a) 80 -- | Executive Income Security Plan of Gulf States Utilities Company, as amended effective March 1, 1991 (10(a)86 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
| |
+(a) 81 -- | System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009 (10(a)78 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 82 -- | First Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)79 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 83 -- | Second Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)81 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
| |
+(a) 84-- | Third Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 26, 2012 (10(a)81 to Form 10-K for the year ended December 31, 2013 in 1-11299). |
| |
+(a) 85 -- | Fourth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(d) to Form 10-Q for the year ended June 30, 2013 in 1-11299). |
| |
+(a) 86 -- | Fifth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(d) to Form 10-Q for the year ended September 30, 2014 in 1-11299). |
| |
(a) 87 -- | Agreement of Limited Partnership of Entergy-Koch, LP among EKLP, LLC, EK Holding I, LLC, EK Holding II, LLC and Koch Energy, Inc. dated January 31, 2001 (10(a)94 to Form 10-K/A for the year ended December 31, 2000 in 1-11299). |
| |
|
| |
+(a) 88 -- | Employment Agreement effective November 24, 2003 between Mark T. Savoff and Entergy Services (10(a)99 to Form 10-K for the year ended December 31, 2003 in 1-11299). |
| |
+(a) 89 -- | Employment Agreement effective February 9, 1999 between Leo P. Denault and Entergy Services (10(a) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299). |
| |
+(a) 90 -- | Amendment to Employment Agreement effective March 5, 2004 between Leo P. Denault and Entergy Corporation (10(b) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299). |
| |
+(a) 91 -- | Retention Agreement effective August 3, 2006 between Leo P. Denault and Entergy Corporation (10(b) to Form 10-Q for the quarter ended June 30, 2006 in 1-11299). |
| |
+(a) 92 -- | Amendment to Retention Agreement effective January 1, 2009 between Leo P. Denault and Entergy Corporation (10(a)93 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 93 -- | Amendment to Retention Agreement effective January 1, 2010 between Leo P. Denault and Entergy Corporation (10(a)101 to Form 10-K for the year ended December 31, 2009 in 1-11299). |
| |
+(a) 94 -- | Amendment to Retention Agreement effective December 30, 2010 between Leo P. Denault and Entergy Corporation (10(a)95 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 95 -- | Shareholder Approval of Future Severance Agreements Policy, effective March 8, 2004 (10(f) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299). |
| |
+(a) 96 -- | Entergy Corporation Outside Director Stock Program Established under the 2011 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (10(b) to Form 10-Q for the quarter ended June 30, 2011 in 1-11299). |
| |
+(a) 97 -- | First Amendment to Entergy Corporation Outside Director Stock Program Established under the 2011 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation Subsidiaries (10(b) to Form 10-Q for the quarter ended September 30, 2012 in 1-11299). |
| |
+(a) 98 -- | Entergy Nuclear Retention Plan, as amended and restated January 1, 2007 (10(a)107 to Form 10-K for the year ended December 31, 2007 in 1-11299). |
| |
+(a) 99 -- | Executive Annual Incentive Plan of Entergy Corporation and Subsidiaries as amended and restated effective January 1, 2010 (Annex A to Entergy Corporation’s Definitive Proxy Statement filed on March 17, 2010 in 1-11299). |
| |
+(a) 100 -- | First Amendment of the Executive Annual Incentive Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)106 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
| |
*+(a)101- | Form of Stock Option Grant Letter. |
| |
*+(a)102- | Form of Long Term Incentive Program Performance Unit Grant Letter. |
| |
*+(a)103- | Form of Restricted Stock Grant Letter. |
| |
(a) 104 -- | Employee Matters Agreement, dated as of December 4, 2011, among Entergy Corporation, Mid South TransCo LLC and ITC Holdings Corp. (10.1 to Form 8-K filed December 6, 2011 in 1-11299). |
| |
*+(a)105- | Retention Agreement effective February 1, 2013 between William M. Mohl and Entergy Corporation. |
| |
+(a)106 -- | Restricted Units Agreement between Roderick K. West and Entergy Corporation (10(a) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299). |
| |
|
| |
+(a)107 -- | Restricted Unit Agreement between Jeffrey S. Forbes and Entergy Corporation (10(a)109 to Form 10-K for the year ended December 31, 2013 in 1-11299). |
System Energy
|
| |
(b) 1 through |
(b) 8 -- See 10(a)8 through 10(a)15 above. |
|
(b) 9 through |
(b) 15 -- See 10(a)16 through 10(a)22 above. |
|
(b) 16 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
| |
(b) 17 -- | Joint Construction, Acquisition and Ownership Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B-1(a) in 70-6337), as amended by Amendment No. 1, dated as of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31, 1980 (1 to Rule 24 Certificate dated October 30, 1981 in 70-6337). |
| |
(b) 18 -- | Operating Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337). |
| |
(b) 19 -- | Amended and Restated Installment Sale Agreement, dated as of February 15, 1996, between System Energy and Claiborne County, Mississippi (B-6(a) to Rule 24 Certificate dated March 4, 1996 in 70-8511). |
| |
(b) 20 -- | Loan Agreement, dated as of October 15, 1998, between System Energy and Mississippi Business Finance Corporation (B-6(b) to Rule 24 Certificate dated November 12, 1998 in 70-8511). |
| |
(b) 21 -- | Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-3(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182). |
| |
(b) 22 -- | Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-4(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182). |
| |
(b) 23 -- | Assignment, Assumption and Further Agreement No. 1, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561). |
| |
(b) 24 -- | Assignment, Assumption and Further Agreement No. 2, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561). |
| |
(b) 25 -- | Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337). |
| |
|
| |
(b) 26 -- | Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033). |
| |
(b) 27 -- | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
| |
(b) 28 -- | First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
| |
(b) 29 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
| |
(b) 30 -- | Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(b) to Rule 24 Certificate dated March 3, 1989 in 70-7604). |
| |
(b) 31 -- | System Energy’s Consent, dated January 31, 1995, pursuant to Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(c) to Rule 24 Certificate dated February 13, 1995 in 70-7604). |
| |
(b) 32 -- | Sales Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (D to Rule 24 Certificate dated June 26, 1974 in 70-5399). |
| |
(b) 33 -- | Service Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (E to Rule 24 Certificate dated June 26, 1974 in 70-5399). |
| |
(b) 34 -- | Partial Termination Agreement, dated as of December 1, 1986, between System Energy and Entergy Mississippi (A-2 to Rule 24 Certificate dated January 8, 1987 in 70-5399). |
| |
(b) 35 -- | Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987). |
| |
(b) 36 -- | First Amendment, dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). |
| |
(b) 37 -- | Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). |
| |
(b) 38 -- | Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
| |
(b) 39 -- | Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
| |
(b) 40 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-9067). |
| |
(b) 41 -- | Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-9067). |
| |
(b) 42 -- | Service Agreement with Entergy Services, dated as of July 16, 1974, as amended (10(b)43 to Form 10-K for the year ended December 31, 1988 in 1-9067). |
| |
|
| |
(b) 43 -- | Amendment, dated January 1, 2004, to Service Agreement with Entergy Services (10(b)57 to Form 10-K for the year ended December 31, 2004 in 1-9067). |
| |
(b) 44 -- | Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (10(b)44 to Form 10-K for the year ended December 31, 2013 in 1-9067). |
| |
(b) 45 -- | Operating Agreement between Entergy Operations and System Energy, dated as of June 6, 1990 (B-3(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679). |
| |
(b) 46 -- | Guarantee Agreement between Entergy Corporation and System Energy, dated as of September 20, 1990 (B-3(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757). |
| |
(b) 47 -- | Letter of Credit and Reimbursement Agreement, dated as of December 22, 2003, among System Energy Resources, Inc., Union Bank of California, N.A., as administrating bank and funding bank, Keybank National Association, as syndication agent, Banc One Capital Markets, Inc., as documentation agent, and the Banks named therein, as Participating Banks (10(b)63 to Form 10-K for the year ended December 31, 2003 in 1-9067). |
| |
(b) 48 -- | Amendment to Letter of Credit and Reimbursement Agreement, dated as of December 22, 2003 (10(b)62 to Form 10-K for the year ended December 31, 2004 in 1-9067). |
| |
(b) 49 -- | First Amendment and Consent, dated as of May 3, 2004, to Letter of Credit and Reimbursement Agreement (10(b)63 to Form 10-K for the year ended December 31, 2004 in 1-9067). |
| |
(b) 50 -- | Second Amendment and Consent, dated as of December 17, 2004, to Letter of Credit and Reimbursement Agreement (99 to Form 8-K dated December 22, 2004 in 1-9067). |
| |
(b) 51 -- | Third Amendment and Consent, dated as of May 14, 2009, to Letter of Credit and Reimbursement Agreement (10(b)69 to Form 10-K for the year ended December 31, 2009 in 1-9067). |
| |
(b) 52 -- | Fourth Amendment and Consent, dated as of April 15, 2010, to Letter of Credit and Reimbursement Agreement (10(a) to Form 10-Q for the quarter ended March 31, 2010 in 1-9067). |
| |
(b) 53 -- | Fifth Amendment and Consent, dated as of November 15, 2012, to Letter of Credit and Reimbursement Agreement (10(b)55 to Form 10-K for the year ended December 31, 2012 in 1-9067). |
Entergy Arkansas
|
| |
(c) 1 -- | Agreement, dated April 23, 1982, among Entergy Arkansas and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a) 1 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
| |
(c) 2 -- | Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-10764). |
| |
(c) 3 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080). |
| |
(c) 4 -- | Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-41080). |
| |
(c) 5 -- | Amendment, dated December 19, 2013, to Service Agreement, with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services, Service Agreement for Generation Planning and Operational Support Services, and Service Agreement for Transmission Planning and Reliability Support Services (10(c)5 to Form 10-K for the year ended December 31, 2013 in 1-10764). |
| |
(c) 6 through |
(c) 13 -- See 10(a)8 through 10(a)15 above. |
|
|
| |
(c) 14 -- | Agreement, dated August 20, 1954, between Entergy Arkansas and the United States of America (SPA)(13(h) in 2-11467). |
| |
(c) 15 -- | Amendment, dated April 19, 1955, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)2 in 2-41080). |
| |
(c) 16 -- | Amendment, dated January 3, 1964, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)3 in 2-41080). |
| |
(c) 17 -- | Amendment, dated September 5, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)4 in 2-41080). |
| |
(c) 18 -- | Amendment, dated November 19, 1970, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)5 in 2-41080). |
| |
(c) 19 -- | Amendment, dated July 18, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)6 in 2-41080). |
| |
(c) 20 -- | Amendment, dated December 27, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)7 in 2-41080). |
| |
(c) 21 -- | Amendment, dated January 25, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)8 in 2-41080). |
| |
(c) 22 -- | Amendment, dated October 14, 1971, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)9 in 2-43175). |
| |
(c) 23 -- | Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)10 in 2-60233). |
| |
(c) 24 -- | Agreement, dated May 14, 1971, between Entergy Arkansas and the United States of America (SPA) (5(e) in 2-41080). |
| |
(c) 25 -- | Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated May 14, 1971 (5(e)1 in 2-60233). |
| |
(c) 26 -- | Contract, dated May 28, 1943, Amendment to Contract, dated July 21, 1949, and Supplement to Amendment to Contract, dated December 30, 1949, between Entergy Arkansas and McKamie Gas Cleaning Company; Agreements, dated as of September 30, 1965, between Entergy Arkansas and former stockholders of McKamie Gas Cleaning Company; and Letter Agreement, dated June 22, 1966, by Humble Oil & Refining Company accepted by Entergy Arkansas on June 24, 1966 (5(k)7 in 2-41080). |
| |
(c) 27 -- | Fuel Lease, dated as of December 22, 1988, between River Fuel Trust #1 and Entergy Arkansas (B-1(b) to Rule 24 Certificate in 70-7571). |
| |
(c) 28 -- | White Bluff Operating Agreement, dated June 27, 1977, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas (B-2(a) to Rule 24 Certificate dated June 30, 1977 in 70-6009). |
| |
(c) 29 -- | White Bluff Ownership Agreement, dated June 27, 1977, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas (B-1(a) to Rule 24 Certificate dated June 30, 1977 in 70-6009). |
| |
(c) 30 -- | Agreement, dated June 29, 1979, between Entergy Arkansas and City of Conway, Arkansas (5(r)3 in 2-66235). |
| |
(c) 31 -- | Transmission Agreement, dated August 2, 1977, between Entergy Arkansas and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r)3 in 2-60233). |
| |
|
| |
(c) 32 -- | Power Coordination, Interchange and Transmission Service Agreement, dated as of June 27, 1977, between Arkansas Electric Cooperative Corporation and Entergy Arkansas (5(r)4 in 2-60233). |
| |
(c) 33 -- | Independence Steam Electric Station Operating Agreement, dated July 31, 1979, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas and City of Conway, Arkansas (5(r)6 in 2-66235). |
| |
(c) 34 -- | Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c)51 to Form 10-K for the year ended December 31, 1984 in 1-10764). |
| |
(c) 35 -- | Independence Steam Electric Station Ownership Agreement, dated July 31, 1979, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas and City of Conway, Arkansas (5(r)7 in 2-66235). |
| |
(c) 36 -- | Amendment, dated December 28, 1979, to the Independence Steam Electric Station Ownership Agreement (5(r)7(a) in 2-66235). |
| |
(c) 37 -- | Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c)54 to Form 10-K for the year ended December 31, 1984 in 1-10764). |
| |
(c) 38 -- | Owner’s Agreement, dated November 28, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station (10(c)55 to Form 10-K for the year ended December 31, 1984 in 1-10764). |
| |
(c) 39 -- | Consent, Agreement and Assumption, dated December 4, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station and United States Trust Company of New York, as Trustee (10(c)56 to Form 10-K for the year ended December 31, 1984 in 1-10764). |
| |
(c) 40 -- | Power Coordination, Interchange and Transmission Service Agreement, dated as of July 31, 1979, between Entergy Arkansas and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r)8 in 2-66235). |
| |
(c) 41 -- | Power Coordination, Interchange and Transmission Agreement, dated as of June 29, 1979, between City of Conway, Arkansas and Entergy Arkansas (5(r)9 in 2-66235). |
| |
(c) 42 -- | Agreement, dated June 21, 1979, between Entergy Arkansas and Reeves E. Ritchie (10(b)90 to Form 10-K for the year ended December 31, 1980 in 1-10764). |
| |
(c) 43 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
| |
(c) 44 -- | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
| |
(c) 45 -- | First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
| |
(c) 46 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
| |
(c) 47 -- | Contract For Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated June 30, 1983, among the DOE, System Fuels and Entergy Arkansas (10(b)57 to Form 10-K for the year ended December 31, 1983 in 1-10764). |
| |
(c) 48 -- | Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987). |
| |
|
| |
(c) 49 -- | First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). |
| |
(c) 50 -- | Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). |
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(c) 51 -- | Third Amendment dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
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(c) 52 -- | Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
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(c) 53 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-10764). |
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(c) 54 -- | Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-10764). |
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(c) 55 -- | Assignment of Coal Supply Agreement, dated December 1, 1987, between System Fuels and Entergy Arkansas (B to Rule 24 letter filing dated November 10, 1987 in 70-5964). |
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(c) 56 -- | Coal Supply Agreement, dated December 22, 1976, between System Fuels and Antelope Coal Company (B-1 in 70-5964), as amended by First Amendment (A to Rule 24 Certificate in 70-5964); Second Amendment (A to Rule 24 letter filing dated December 16, 1983 in 70-5964); and Third Amendment (A to Rule 24 letter filing dated November 10, 1987 in 70-5964). |
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(c) 57 -- | Operating Agreement between Entergy Operations and Entergy Arkansas, dated as of June 6, 1990 (B-1(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679). |
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(c) 58 -- | Guaranty Agreement between Entergy Corporation and Entergy Arkansas, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757). |
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(c) 59 -- | Agreement for Purchase and Sale of Independence Unit 2 between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-3(c) to Rule 24 Certificate dated September 6, 1990 in 70-7684). |
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(c) 60 -- | Agreement for Purchase and Sale of Ritchie Unit 2 between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-4(d) to Rule 24 Certificate dated September 6, 1990 in 70-7684). |
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(c) 61 -- | Ritchie Steam Electric Station Unit No. 2 Operating Agreement between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-5(a) to Rule 24 Certificate dated September 6, 1990 in 70-7684). |
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(c) 62 -- | Ritchie Steam Electric Station Unit No. 2 Ownership Agreement between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-6(a) to Rule 24 Certificate dated September 6, 1990 in 70-7684). |
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(c) 63 -- | Power Coordination, Interchange and Transmission Service Agreement between Entergy Power and Entergy Arkansas, dated as of August 28, 1990 (10(c)71 to Form 10-K for the year ended December 31, 1990 in 1-10764). |
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(c) 64 -- | Loan Agreement, dated as of January 1, 2013, between Jefferson County, Arkansas and Entergy Arkansas relating to Revenue Bonds (Entergy Arkansas, Inc. Project) Series 2013 (4(b) to Form 8-K filed January 9, 2013 in 1-10764). |
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(c) 65 -- | Loan Agreement, dated as of January 1, 2013, between Independence County, Arkansas and Entergy Arkansas relating to Revenue Bonds (Entergy Arkansas, Inc. Project) Series 2013 (4(d) to Form 8-K filed January 9, 2013 in 1-10764). |
Entergy Gulf States Louisiana
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(d) 1 -- | Agreement effective February 1, 1964, between Sabine River Authority, State of Louisiana, and Sabine River Authority of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Company, Inc., and Louisiana Power & Light Company, as supplemented (B to Form 8-K dated May 6, 1964, A to Form 8-K dated October 5, 1967, A to Form 8-K dated May 5, 1969, and A to Form 8-K dated December 1, 1969 in 1-27031). |
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(d) 2 -- | Joint Ownership Participation and Operating Agreement regarding River Bend Unit 1 Nuclear Plant, dated August 20, 1979, between Entergy Gulf States, Inc., Cajun, and SRG&T; Power Interconnection Agreement with Cajun, dated June 26, 1978, and approved by the REA on August 16, 1979, between Entergy Gulf States, Inc. and Cajun; and Letter Agreement regarding CEPCO buybacks, dated August 28, 1979, between Entergy Gulf States, Inc. and Cajun (2, 3, and 4, respectively, to Form 8-K dated September 7, 1979 in 1-27031). |
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(d) 3 -- | Lease Agreement, dated September 18, 1980, between BLC Corporation and Entergy Gulf States, Inc. (1 to Form 8-K dated October 6, 1980 in 1-27031). |
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(d) 4 -- | Joint Ownership Participation and Operating Agreement for Big Cajun, between Entergy Gulf States, Inc., Cajun Electric Power Cooperative, Inc., and Sam Rayburn G&T, Inc, dated November 14, 1980 (6 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 1, dated December 12, 1980 (7 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 2, dated December 29, 1980 (8 to Form 8-K dated January 29, 1981 in 1-27031). |
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(d) 5 -- | Agreement of Joint Ownership Participation between SRMPA, SRG&T and Entergy Gulf States, Inc., dated June 6, 1980, for Nelson Station, Coal Unit #6, as amended (8 to Form 8-K dated June 11, 1980, A-2-b to Form 10-Q for the quarter ended June 30, 1982; and 10-1 to Form 8-K dated February 19, 1988 in 1-27031). |
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(d) 6 -- | Agreements between Southern Company and Entergy Gulf States, Inc., dated February 25, 1982, which cover the construction of a 140-mile transmission line to connect the two systems, purchase of power and use of transmission facilities (10-31 to Form 10-K for the year ended December 31, 1981 in 1-27031). |
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(d) 7 -- | Transmission Facilities Agreement between Entergy Gulf States, Inc. and Mississippi Power Company, dated February 28, 1982, and Amendment, dated May 12, 1982 (A-2-c to Form 10-Q for the quarter ended March 31, 1982 in 1-27031) and Amendment, dated December 6, 1983 (10-43 to Form 10-K for the year ended December 31, 1983 in 1-27031). |
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(d) 8 -- | First Amended Power Sales Agreement, dated December 1, 1985 between Sabine River Authority, State of Louisiana, and Sabine River Authority, State of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Co., Inc., and Louisiana Power and Light Company (10-72 to Form 10-K for the year ended December 31, 1985 in 1-27031). |
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+(d) 9 -- | Deferred Compensation Plan for Directors of Entergy Gulf States, Inc. and Varibus Corporation, as amended January 8, 1987, and effective January 1, 1987 (10-77 to Form 10-K for the year ended December 31, 1986 in 1-27031). Amendment dated December 4, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551). |
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+(d) 10 -- | Trust Agreement for Deferred Payments to be made by Entergy Gulf States, Inc. pursuant to the Executive Income Security Plan, by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective November 1, 1986 (10-78 to Form 10-K for the year ended December 31, 1986 in 1-27031). |
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+(d) 11 -- | Trust Agreement for Deferred Installments under Entergy Gulf States, Inc. Management Incentive Compensation Plan and Administrative Guidelines by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective June 1, 1986 (10-79 to Form 10-K for the year ended December 31, 1986 in 1-27031). |
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+(d) 12 -- | Nonqualified Deferred Compensation Plan for Officers, Nonemployee Directors and Designated Key Employees, effective December 1, 1985, as amended, continued and completely restated effective as of March 1, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551). |
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+(d) 13 -- | Trust Agreement for Entergy Gulf States, Inc. Nonqualified Directors and Designated Key Employees by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective July 1, 1991 (10-4 to Form 10-K for the year ended December 31, 1992 in 1-27031). |
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(d) 14 -- | Nuclear Fuel Lease Agreement between Entergy Gulf States, Inc. and River Bend Fuel Services, Inc. to lease the fuel for River Bend Unit 1, dated February 7, 1989 (10-64 to Form 10-K for the year ended December 31, 1988 in 1-27031). |
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(d) 15 -- | Trust and Investment Management Agreement between Entergy Gulf States, Inc. and Morgan Guaranty and Trust Company of New York (the “Decommissioning Trust Agreement”) with respect to decommissioning funds authorized to be collected by Entergy Gulf States, Inc., dated March 15, 1989 (10-66 to Form 10-K for the year ended December 31, 1988 in 1-27031). |
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(d) 16 -- | Amendment No. 2 dated November 1, 1995 between Entergy Gulf States, Inc. and Mellon Bank to Decommissioning Trust Agreement (10(d)31 to Form 10-K for the year ended December 31, 1995 in 1-27031). |
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(d) 17 -- | Amendment No. 3 dated March 5, 1998 between Entergy Gulf States, Inc. and Mellon Bank to Decommissioning Trust Agreement (10(d)23 to Form 10-K for the year ended December 31, 2004 in 1-27031). |
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(d) 18 -- | Amendment No. 4 dated December 17, 2003 between Entergy Gulf States, Inc. and Mellon Bank to Decommissioning Trust Agreement (10(d)24 to Form 10-K for the year ended December 31, 2004 in 1-27031). |
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(d) 19 -- | Amendment No. 5 dated December 31, 2007 between Entergy Gulf States Louisiana, L.L.C. and Mellon Bank. N.A. to Decommissioning Trust Agreement (10(d)21 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
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(d) 20 -- | Partnership Agreement by and among Conoco Inc., and Entergy Gulf States, Inc., CITGO Petroleum Corporation and Vista Chemical Company, dated April 28, 1988 (10-67 to Form 10-K for the year ended December 31, 1988 in 1-27031). |
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+(d) 21 -- | Gulf States Utilities Company Executive Continuity Plan, dated January 18, 1991 (10-6 to Form 10-K for the year ended December 31, 1990 in 1-27031). |
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+(d) 22 -- | Trust Agreement for Entergy Gulf States, Inc. Executive Continuity Plan, by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective May 20, 1991 (10-5 to Form 10-K for the year ended December 31, 1992 in 1-27031). |
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+(d) 23 -- | Gulf States Utilities Board of Directors’ Retirement Plan, dated February 15, 1991 (10-8 to Form 10-K for the year ended December 31, 1990 in 1-27031). |
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(d) 24 -- | Third Amendment, dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
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(d) 25 -- | Fourth Amendment, dated April 1, 1997, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
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(d) 26 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 0-20371). |
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(d) 27 -- | Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 0-20371). |
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(d) 28 -- | Operating Agreement dated as of January 1, 2008, between Entergy Operations, Inc. and Entergy Gulf States Louisiana (10(d)39 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
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(d) 29 -- | Service Agreement dated as of January 1, 2008, between Entergy Services, Inc. and Entergy Gulf States Louisiana (10(d)40 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
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(d) 30 -- | Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services and Service Agreement for Generation Planning and Operational Support Services) (10(d)30 to Form 10-K for the year ended December 31, 2013 in 0-20371). |
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(d) 31 -- | Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
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(d) 32 -- | Decommissioning Trust Agreement, dated as of December 22, 1997, by and between Cajun Electric Power Cooperative, Inc. and Mellon Bank, N.A. with respect to decommissioning funds authorized to be collected by Cajun Electric Power Cooperative, Inc. and related Settlement Term Sheet (10(d)42 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
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(d) 33 -- | First Amendment to Decommissioning Trust Agreement, dated as of December 23, 2003, by and among Cajun Electric Power Cooperative, Inc., Mellon Bank, N.A., Entergy Gulf States, Inc., and the Rural Utilities Services of the United States Department of Agriculture (10(d)43 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
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(d) 34 -- | Second Amendment to Decommissioning Trust Agreement, dated December 31, 2007, by and among Cajun Electric Power Cooperative, Inc., Mellon Bank, N.A., Entergy Gulf States Louisiana, L.L.C., and the Rural Utilities Services of the United States Department of Agriculture (10(d)44 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
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(d) 35 -- | Second Amended and Restated Limited Liability Company Agreement of Entergy Holdings Company LLC dated as of July 22, 2010 (10(a) to Form 10-Q for the quarter ended June 30, 2010). |
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(d) 36 -- | Loan Agreement, dated as of October 1, 2010, between the Louisiana Public Facilities Authority and Entergy Gulf States Louisiana, L.L.C. relating to Revenue Bonds (Entergy Gulf States Louisiana, L.L.C. Project) Series 2010A (4(b) to Form 8-K filed October 12, 2010 in 0-20371). |
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(d) 37 -- | Loan Agreement, dated as of October 1, 2010, between the Louisiana Public Facilities Authority and Entergy Gulf States Louisiana, L.L.C. relating to Revenue Bonds (Entergy Gulf States Louisiana, L.L.C. Project) Series 2010B (4(e) to Form 8-K filed October 12, 2010 in 0-20371). |
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(d) 38 -- | Asset Purchase Agreement, dated as of December 8, 2014, by and among Union Power Partners, L.P., Entegra TC LLC, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas (10.1 to Form 8-K filed December 12, 2014 in 0-20371). |
Entergy Louisiana
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(e) 1 -- | Agreement, dated April 23, 1982, among Entergy Louisiana and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982, in 1-3517). |
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(e) 2 -- | Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-32718). |
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(e) 3 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080). |
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(e) 4 -- | Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-42523). |
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(e) 5 -- | Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services and Service Agreement for Generation Planning and Operational Support Services) (10(e)5 to Form 10-K for the year ended December 31, 2013 in 1-32718). |
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(e) 6 through |
(e) 13 -- See 10(a)8 through 10(a)15 above. |
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(e) 14 -- | Fuel Lease, dated as of January 31, 1989, between River Fuel Company #2, Inc., and Entergy Louisiana (B-1(b) to Rule 24 Certificate in 70-7580). |
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(e) 15 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
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(e) 16 -- | Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and Entergy Louisiana (28(a) to Form 8-K dated June 4, 1982 in 1-8474). |
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(e) 17 -- | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
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(e) 18 -- | First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
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(e) 19 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
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(e) 20 -- | Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated February 2, 1984, among DOE, System Fuels and Entergy Louisiana (10(d)33 to Form 10-K for the year ended December 31, 1984 in 1-8474). |
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(e) 21-- | Operating Agreement between Entergy Operations and Entergy Louisiana, dated as of June 6, 1990 (B-2(c) to Rule 24 Certificate dated June 15, 1990 in 70-7679). |
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(e) 22 -- | Guarantee Agreement between Entergy Corporation and Entergy Louisiana, dated as of September 20, 1990 (B-2(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757). |
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(e) 23 -- | Second Amended and Restated Limited Liability Company Agreement of Entergy Holdings Company LLC dated as of July 22, 2010 (10(a) to Form 10-Q for the quarter ended June 30, 2010). |
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(e) 24 -- | Third Amended and Restated Limited Liability Company Agreement of Entergy Holdings Company LLC dated as of August 6, 2014 (10(a) to Form 10-Q for the quarter ended June 30, 2014). |
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(e) 25 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-32718). |
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(e) 26 -- | Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-32718). |
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(e) 27 -- | Loan Agreement, dated as of October 1, 2010, between the Louisiana Public Facilities Authority and Entergy Louisiana, LLC relating to Revenue Bonds (Entergy Louisiana, LLC Project) Series 2010 (4(b) to Form 8-K filed October 12, 2010 in 1-32718). |
Entergy Mississippi
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(f) 1 -- | Agreement dated April 23, 1982, among Entergy Mississippi and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
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(f) 2 -- | Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-31508). |
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(f) 3 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080). |
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(f) 4 -- | Service Agreement with Entergy Services, dated as of April 1, 1963 (D in 37-63). |
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(f) 5 -- | Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services and Service Agreement for Generation Planning and Operational Support Services) (10(f)5 to Form 10-K for the year ended December 31, 2013 in 1-31508). |
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(f) 6 through |
(f) 13 -- See 10(a)8 through 10(a)15 above. |
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(f) 14 -- | Refunding Agreement, dated as of May 1, 1999, between Entergy Mississippi and Independence County, Arkansas (B-6(a) to Rule 24 Certificate dated June 8, 1999 in 70-8719). |
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(f) 15 -- | Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B-3(a) in 70-6337). |
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(f) 16 -- | Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c)51 to Form 10-K for the year ended December 31, 1984 in 0-375). |
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(f) 17 -- | Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c)54 to Form 10-K for the year ended December 31, 1984 in 0-375). |
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(f) 18 -- | Owners Agreement, dated November 28, 1984, among Entergy Arkansas, Entergy Mississippi and other co-owners of the Independence Station (10(c)55 to Form 10-K for the year ended December 31, 1984 in 0-375). |
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(f) 19 -- | Consent, Agreement and Assumption, dated December 4, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station and United States Trust Company of New York, as Trustee (10(c)56 to Form 10-K for the year ended December 31, 1984 in 0-375). |
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(f) 20 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
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+(f) 21 -- | Post-Retirement Plan (10(d)24 to Form 10-K for the year ended December 31, 1983 in 0-320). |
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(f) 22 -- | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
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(f) 23 -- | First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
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(f) 24 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
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(f) 25 -- | Sales Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (D to Rule 24 Certificate dated June 26, 1974 in 70-5399). |
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(f) 26 -- | Service Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (E to Rule 24 Certificate dated June 26, 1974 in 70-5399). |
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(f) 27 -- | Partial Termination Agreement, dated as of December 1, 1986, between System Energy and Entergy Mississippi (A-2 to Rule 24 Certificate dated January 8, 1987 in 70-5399). |
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(f) 28 -- | Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987). |
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(f) 29 -- | First Amendment dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). |
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(f) 30 -- | Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). |
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(f) 31 -- | Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
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(f) 32 -- | Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
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(f) 33 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-31508). |
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(f) 34 -- | Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-31508). |
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(f) 35 -- | Purchase and Sale Agreement by and between Central Mississippi Generating Company, LLC and Entergy Mississippi, Inc., dated as of March 16, 2005 (10(b) to Form 10-Q for the quarter ended March 31, 2005 in 1-31508). |
Entergy New Orleans
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(g) 1 -- | Agreement, dated April 23, 1982, among Entergy New Orleans and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
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(g) 2 -- | Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 0-5807). |
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(g) 3 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080). |
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(g) 4 -- | Service Agreement with Entergy Services dated as of April 1, 1963 (5(a)5 in 2-42523). |
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(g) 5 -- | Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services and Service Agreement for Generation Planning and Operational Support Services) (10(g)5 to Form 10-K for the year ended December 31, 2013 in 0-5807). |
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(g) 6 through |
(g) 13 -- See 10(a)8 through 10(a)15 above. |
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(g) 14 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
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(g) 15 -- | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
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(g) 16 -- | First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
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(g) 17 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
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(g) 18 -- | Transfer Agreement, dated as of June 28, 1983, among the City of New Orleans, Entergy New Orleans and Regional Transit Authority (2(a) to Form 8-K dated June 24, 1983 in 1-1319). |
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(g) 19 -- | Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987). |
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(g) 20 -- | First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). |
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(g) 21 -- | Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). |
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(g) 22 -- | Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
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(g) 23 -- | Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
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(g) 24 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 0-5807). |
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(g) 25 -- | Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 0-5807). |
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(g) 26 -- | Chapter 11 Plan of Reorganization of Entergy New Orleans, Inc., as modified, dated May 2, 2007, confirmed by bankruptcy court order dated May 7, 2007 (2(a) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807). |
Entergy Texas
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(h) 1 -- | Agreement effective February 1, 1964, between Sabine River Authority, State of Louisiana, and Sabine River Authority of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Company, Inc., and Louisiana Power & Light Company, as supplemented (B to Form 8-K dated May 6, 1964, A to Form 8-K dated October 5, 1967, A to Form 8-K dated May 5, 1969, and A to Form 8-K dated December 1, 1969 in 1-27031). |
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(h) 2 -- | Ground Lease, dated August 15, 1980, between Statmont Associates Limited Partnership (Statmont) and Entergy Gulf States, Inc., as amended (3 to Form 8-K dated August 19, 1980 and A-3-b to Form 10-Q for the quarter ended September 30, 1983 in 1-27031). |
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(h) 3 -- | Lease and Sublease Agreement, dated August 15, 1980, between Statmont and Entergy Gulf States, Inc., as amended (4 to Form 8-K dated August 19, 1980 and A-3-c to Form 10-Q for the quarter ended September 30, 1983 in 1-27031). |
| |
(h) 4 -- | Lease Agreement, dated September 18, 1980, between BLC Corporation and Entergy Gulf States, Inc. (1 to Form 8-K dated October 6, 1980 in 1-27031). |
| |
(h) 5 -- | Joint Ownership Participation and Operating Agreement for Big Cajun, between Entergy Gulf States, Inc., Cajun Electric Power Cooperative, Inc., and Sam Rayburn G&T, Inc, dated November 14, 1980 (6 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 1, dated December 12, 1980 (7 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 2, dated December 29, 1980 (8 to Form 8-K dated January 29, 1981 in 1-27031). |
| |
(h) 6 -- | Agreement of Joint Ownership Participation between SRMPA, SRG&T and Entergy Gulf States, Inc., dated June 6, 1980, for Nelson Station, Coal Unit #6, as amended (8 to Form 8-K dated June 11, 1980, A-2-b to Form 10-Q for the quarter ended June 30, 1982; and 10-1 to Form 8-K dated February 19, 1988 in 1-27031). |
| |
(h) 7 -- | First Amended Power Sales Agreement, dated December 1, 1985 between Sabine River Authority, State of Louisiana, and Sabine River Authority, State of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Co., Inc., and Louisiana Power and Light Company (10-72 to Form 10-K for the year ended December 31, 1985 in 1-27031). |
| |
+(h) 8 -- | Deferred Compensation Plan for Directors of Entergy Gulf States, Inc. and Varibus Corporation, as amended January 8, 1987, and effective January 1, 1987 (10-77 to Form 10-K for the year ended December 31, 1986 in 1-27031). Amendment dated December 4, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551). |
| |
+(h) 9 -- | Trust Agreement for Deferred Payments to be made by Entergy Gulf States, Inc. pursuant to the Executive Income Security Plan, by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective November 1, 1986 (10-78 to Form 10-K for the year ended December 31, 1986 in 1-27031). |
| |
+(h) 10 -- | Trust Agreement for Deferred Installments under Entergy Gulf States, Inc. Management Incentive Compensation Plan and Administrative Guidelines by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective June 1, 1986 (10-79 to Form 10-K for the year ended December 31, 1986 in 1-27031). |
| |
+(h) 11 -- | Nonqualified Deferred Compensation Plan for Officers, Nonemployee Directors and Designated Key Employees, effective December 1, 1985, as amended, continued and completely restated effective as of March 1, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551). |
| |
+(h) 12 -- | Trust Agreement for Entergy Gulf States, Inc. Nonqualified Directors and Designated Key Employees by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective July 1, 1991 (10-4 to Form 10-K for the year ended December 31, 1992 in 1-27031). |
| |
(h) 13 -- | Lease Agreement, dated as of June 29, 1987, among GSG&T, Inc., and Entergy Gulf States, Inc. related to the leaseback of the Lewis Creek generating station (10-83 to Form 10-K for the year ended December 31, 1988 in 1-27031). |
| |
+(h) 14 -- | Gulf States Utilities Company Executive Continuity Plan, dated January 18, 1991 (10-6 to Form 10-K for the year ended December 31, 1990 in 1-27031). |
| |
+(h) 15 -- | Trust Agreement for Entergy Gulf States, Inc. Executive Continuity Plan, by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective May 20, 1991 (10-5 to Form 10-K for the year ended December 31, 1992 in 1-27031). |
| |
|
| |
+(h) 16 -- | Gulf States Utilities Board of Directors’ Retirement Plan, dated February 15, 1991 (10-8 to Form 10-K for the year ended December 31, 1990 in 1-27031). |
| |
(h) 17 -- | Third Amendment, dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
| |
(h) 18 -- | Fourth Amendment, dated April 1, 1997, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
| |
(h) 19 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-34360). |
| |
(h) 20 -- | Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-34360). |
| |
(h) 21 -- | Service Agreement dated as of January 1, 2008, between Entergy Services, Inc. and Entergy Texas (10(h)25 to Form 10-K for the year ended December 31, 2008 in 3-53134). |
| |
(h) 22 -- | Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services and Service Agreement for Generation Planning and Operational Support Services) (10(h)22 to Form 10-K for the year ended December 31, 2013 in 1-34360). |
(12) Statement Re Computation of Ratios
|
| |
*(a) | Entergy Arkansas’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. |
| |
*(b) | Entergy Gulf States Louisiana’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Distributions, as defined. |
| |
*(c) | Entergy Louisiana’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Distributions, as defined. |
| |
*(d) | Entergy Mississippi’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. |
| |
*(e) | Entergy New Orleans’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. |
| |
*(f) | Entergy Texas’s Computation of Ratios of Earnings to Fixed Charges, as defined. |
| |
*(g) | System Energy’s Computation of Ratios of Earnings to Fixed Charges, as defined. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2017, 2016, and 2015 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2017 | |
| $1,211 |
| |
| $503 |
| |
| $651 |
| |
| $1,063 |
|
| 2016 | |
| $34,226 |
| |
| $902 |
| |
| $33,917 |
| |
| $1,211 |
|
| 2015 | |
| $32,247 |
| |
| $2,759 |
| |
| $780 |
| |
| $34,226 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
*(21) Subsidiaries of the Registrants
(23) Consents of Experts and Counsel
|
| |
*(a) | The consent of Deloitte & Touche LLP is contained herein at page 528. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2017, 2016, and 2015 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2017 | |
| $6,277 |
| |
| $3,108 |
| |
| $955 |
| |
| $8,430 |
|
| 2016 | |
| $4,209 |
| |
| $2,942 |
| |
| $874 |
| |
| $6,277 |
|
| 2015 | |
| $1,609 |
| |
| $3,464 |
| |
| $864 |
| |
| $4,209 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
*(24) Powers of Attorney
(31) Rule 13a-14(a)/15d-14(a) Certifications
|
| |
*(a) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation. |
| |
*(b) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation. |
| |
*(c) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas. |
| |
*(d) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas. |
| |
*(e) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Gulf States Louisiana. |
| |
*(f) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Gulf States Louisiana. |
| |
*(g) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Louisiana. |
| |
*(h) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Louisiana. |
| |
*(i) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi. |
| |
*(j) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi. |
| |
*(k) | Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans. |
| |
*(l) | Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans. |
| |
*(m) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Texas. |
| |
*(n) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Texas. |
| |
*(o) | Rule 13a-14(a)/15d-14(a) Certification for System Energy. |
| |
*(p) | Rule 13a-14(a)/15d-14(a) Certification for System Energy. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2017, 2016, and 2015 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2017 | |
| $549 |
| |
| $255 |
| |
| $230 |
| |
| $574 |
|
| 2016 | |
| $718 |
| |
| $259 |
| |
| $428 |
| |
| $549 |
|
| 2015 | |
| $873 |
| |
| $247 |
| |
| $402 |
| |
| $718 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
(32) Section 1350 Certifications
|
| |
*(a) | Section 1350 Certification for Entergy Corporation. |
| |
*(b) | Section 1350 Certification for Entergy Corporation. |
| |
*(c) | Section 1350 Certification for Entergy Arkansas. |
| |
*(d) | Section 1350 Certification for Entergy Arkansas. |
| |
*(e) | Section 1350 Certification for Entergy Gulf States Louisiana. |
| |
*(f) | Section 1350 Certification for Entergy Gulf States Louisiana. |
| |
*(g) | Section 1350 Certification for Entergy Louisiana. |
| |
*(h) | Section 1350 Certification for Entergy Louisiana. |
| |
*(i) | Section 1350 Certification for Entergy Mississippi. |
| |
*(j) | Section 1350 Certification for Entergy Mississippi. |
| |
*(k) | Section 1350 Certification for Entergy New Orleans. |
| |
*(l) | Section 1350 Certification for Entergy New Orleans. |
| |
*(m) | Section 1350 Certification for Entergy Texas. |
| |
*(n) | Section 1350 Certification for Entergy Texas. |
| |
*(o) | Section 1350 Certification for System Energy. |
| |
*(p) | Section 1350 Certification for System Energy. |
(101) XBRL Documents |
| | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2017, 2016, and 2015 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2017 | |
| $3,059 |
| |
| $152 |
| |
| $154 |
| |
| $3,057 |
|
| 2016 | |
| $268 |
| |
| $2,872 |
| |
| $81 |
| |
| $3,059 |
|
| 2015 | |
| $262 |
| |
| $217 |
| |
| $211 |
| |
| $268 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
Entergy Corporation
|
| |
*INS - | XBRL Instance Document. |
| |
*SCH - | XBRL Taxonomy Extension Schema Document. |
| |
*CAL - | XBRL Taxonomy Extension Calculation Linkbase Document. |
| |
*DEF - | XBRL Taxonomy Extension Definition Linkbase Document. |
| |
*LAB - | XBRL Taxonomy Extension Label Linkbase Document. |
| |
*PRE - | XBRL Taxonomy Extension Presentation Linkbase Document. |
_________________
|
| | |
| * | Filed herewith. |
| + | Management contracts or compensatory plans or arrangements. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2017, 2016, and 2015 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2017 | |
| $828 |
| |
| $192 |
| |
| $557 |
| |
| $463 |
|
| 2016 | |
| $474 |
| |
| $531 |
| |
| $177 |
| |
| $828 |
|
| 2015 | |
| $672 |
| |
| $239 |
| |
| $437 |
| |
| $474 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |