Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 30,000 MW of electric generating capacity, including approximately 9,0008,000 MW of nuclear power. Entergy delivers electricity to 2.93.0 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $10.9$10.1 billion in 20192020 and had more than 13,000 employees as of December 31, 2019.2020.
Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.
See Note 13 to the financial statements for financial information regarding Entergy’s business segments.
The Utility business segment includes five retail electric utility subsidiaries: Entergy Arkansas, 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 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 five 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.
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 12, 2019,10, 2020, Entergy reached a 20192020 peak demand of 21,59821,340 MWh, compared to the 20182019 peak of 21,58721,598 MWh recorded on July 20, 2018.August 12, 2019. Selected electric energy sales data is shown in the table below:
See “Selected Financial Data” for each of the Utility operating companies for the detail of their sales by customer class for 2015-2019.2016-2020.
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 11,099,8129,467,899 and 7,090,8786,268,003 Mcf, respectively, of natural gas to retail customers in 2019.2020. In 2019,2020, 99% of Entergy Louisiana’s operating revenue was derived from the electric utility business, and only 1% from the natural gas distribution business. For Entergy New Orleans, 87%88% of operating revenue was derived from the electric utility business and 13%12% from the natural gas distribution business in 2019. 2020.
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 | | $8.0 (a) | | 9.25% - 10.25% | | 5.20% | | 36.49% | | - forward test year formula rate plan
- riders: MISO, capacity, Grand
Gulf, tax adjustment, energy
efficiency, fuel and purchased power | |
| | | | | | | | | | | | |
| Entergy Louisiana (electric) | | $10.4 (b) | | 9.2% - 10.4% | | 6.98% | | 48.64% | | - formula rate plan through 2019 test
year
- riders/specific recovery: MISO,
capacity, transmission, fuel | |
| | | | | | | | | | | | |
| Entergy Louisiana (gas) | | $0.07 (c) | | 9.45% - 10.45% | | 7.04% | | 48.26% | | - gas rate stabilization plan
- rider: gas infrastructure | |
| | | | | | | | | | | | |
| Entergy Mississippi | | $2.6 (d) | | 9.33% - 11.35% | | 7.24% | | 49.67% | | - 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, vegetation,
grid modernization, restructuring
credit | |
| | | | | | | | | | | | |
| Entergy New Orleans (electric) | | $0.8 (e) | | 9.35% | | 7.09% | | 50% | | - formula rate plan with forward-looking features
- specific recovery: fuel | |
| | | | | | | | | | | | |
| Entergy New Orleans (gas) | | $0.1 (e) | | 9.35% | | 7.09% | | 50% | | - formula rate plan with forward-looking features
- rider: purchased gas | |
| | | | | | | | | | | | |
| Entergy Texas | | $2.4 (f) | | 9.65% | | 7.73% | | 50.9% | | - rate case
- riders: fuel, distribution and transmission, rate case expenses, AMI surcharge, tax reform, among others | |
| | | | | | | | | | | | |
| System Energy | | $1.4 (g) | | 10.94% (h) | | 8.50% | | 65% (h) | | - monthly cost of service | |
| |
(a) | Based on 2020 test year. |
| |
(b) | Based on December 31, 2018 test year and excludes approximately $800 million for the St. Charles Power Station, included in capacity rider, and $300 million of transmission plant, included in transmission rider. |
| |
(c) | Based on September 30, 2018 test year. |
| |
(d) | Based on 2019 forward test year. |
| |
(e) | Based on December 31, 2018 test year and known and measurables through December 31, 2019. |
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| |
(f) | Based on December 31, 2017 test year. |
| |
(g) | Based on calculation as of December 31, 2019. |
| |
(h) | See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity and capital structure. |
Entergy Arkansas
Fuel and Purchased Power Cost Recovery
Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased power 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 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.
Production Cost Allocation Rider
Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.
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 hedgeshistorically hedged 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 iswas 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, which was approved in November 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.
Retail Rates - Gas
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 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
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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,
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among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band 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 LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.
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 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.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power 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.
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.
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Entergy Corporation, Utility operating companies, and System Energy
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
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Formula Rate Plan
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 was still appropriate or could 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 proceeding. In March 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. 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.
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.
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 Corporation, Utility operating companies, and System Energy
Energy Efficiency Programs
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 and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. 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. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
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
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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 Reliability Corporation (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
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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.
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.
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.
The PUCT determined that unrecovered costs that may 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 amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
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.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The draft rule wasPUCT approved for publication at the PUCT’s February 2020 open meeting, and two rounds of public comment will be taken in March and April 2020. The PUCT is expected to approve a final rule within six months of publication.in July 2020.
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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 Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in 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 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.
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Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city 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 over the period 2020-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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, 2019,2020, is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,175 | | | 2,091 | | | 1,817 | | | 1,194 | | | 73 | | | — | |
| Entergy Louisiana | | 11,317 | | | 8,827 | | | 2,144 | | | 346 | | | — | | | — | |
| Entergy Mississippi | | 3,347 | | | 2,929 | | | — | | | 416 | | | — | | | 2 | |
| Entergy New Orleans | | 665 | | | 638 | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 2,260 | | | 2,005 | | | — | | | 255 | | | — | | | — | |
| System Energy | | 1,256 | | | — | | | 1,256 | | | — | | | — | | | — | |
| Total | | 24,020 | | | 16,490 | | | 5,217 | | | 2,211 | | | 73 | | | 29 | |
|
| | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,183 |
| | 2,106 |
| | 1,810 |
| | 1,194 |
| | 73 |
| | — |
|
| Entergy Louisiana | | 10,050 |
| | 7,556 |
| | 2,144 |
| | 350 |
| | — |
| | — |
|
| Entergy Mississippi | | 3,342 |
| | 2,923 |
| | — |
| | 417 |
| | — |
| | 2 |
|
| Entergy New Orleans | | 508 |
| | 507 |
| | — |
| | — |
| | — |
| | 1 |
|
| Entergy Texas | | 2,293 |
| | 2,034 |
| | — |
| | 259 |
| | — |
| | — |
|
| System Energy | | 1,393 |
| | — |
| | 1,393 |
| | — |
| | — |
| | — |
|
| Total | | 22,769 |
| | 15,126 |
| | 5,347 |
| | 2,220 |
| | 73 |
| | 3 |
|
| |
(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. |
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Summer peak load for the Utility has averaged 21,63621,591 MW over the previous decade.
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, the availability and price of power, the location of new load, the economy, environmental regulations,Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation 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 7,3148,801 MW of new long-term resources and the deactivation of over 4,465about 4,664 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.
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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 MISO reliability requirements as well as longer-termlong-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:
Entergy Louisiana’s June 2005 purchase of the 718 MW, gas-fired Perryville plant, of which 35% of the output is sold to 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, owns one-third of the facility;
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;
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 began commercial operation in December 2014;
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facilityfacility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County generating facilityPower Station at its existing Lewis Creek electric generating station. Entergy Texas received regulatory approval from the PUCTThe facility began commercial operation in July 2017 and the facility is scheduled to be in service by mid-2021;January 2021;
•Entergy Louisiana’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 LPSCstation site. The facility began commercial operation in July 2017 and the facility is scheduled to be in service by mid-2020;March 2020;
•In October 2018, Entergy Mississippi signed an asset acquisition agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility locatedthat will be sited on approximately 1,000 acres in Sunflower County, Mississippi. In December 2018, Entergy Mississippi filed forreceived regulatory approval. A hearing beforeapproval from the MPSC is targeted to occur by the second quarterin April 2020, and closingthe facility is expectedscheduled to occurbe in service by the end of 2021;early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020 and the facility is scheduled to be in service by the end of 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility.The facility was placed in service in December 2020;
•In May 2019,June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction
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is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2021;2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas.In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals.Closing is expected to occur by the end of 2023.
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Entergy New Orleans’s construction of the 20 MW, self-build solar project New Orleans Solar Station located at the NASA Michoud Facility. In August 2019, Entergy New Orleans received regulatory approvalCorporation, Utility operating companies, and the facility is scheduled to be in service as early as late-2020.System Energy
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 BendBend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy ArkansasArkansas’s 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);
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 Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf 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 petroleum 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, 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 10-year agreement 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;
•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;
•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 approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 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 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 received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and will beginthe PPA began in AugustNovember 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the agreement is expected to beginPPA began in second quarterOctober 2020;
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019;2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019.2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas.The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP was seeking 300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
Other Procurements From Third PartiesNatural Gas
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; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4),Louisiana 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); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The Utility operating companies haveOrleans also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant under construction approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana will purchase the plant upon completion, anticipated to be later in 2020, for a fixed payment to reimburse construction costs plus an associated premium.
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 facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of 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, 2019, Entergy New Orleans distributed and transporteddistribute natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2019, the gas properties of Entergy Louisiana, which are locatedto retail customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Gas transferred to customers is measured by a meter at the customer’s property. Entergy issues monthly invoices to customers at rates approved by regulators for the volume of gas transferred to date.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Competitive Businesses Revenues
The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power and capacity produced by its operating plants to wholesale customers. The majority of Entergy Wholesale Commodities’ revenues are from Entergy’s nuclear power plants located in the northern United States. Entergy issues monthly invoices to the counterparties for these electric sales at the respective contracted or ISO market rate of electricity and related services provided during the previous month.
Almost all of the Palisades nuclear plant output is sold under a 15-year PPA with Consumers Energy, executed as part of the acquisition of the plant in 2007 and expiring in April 2022. Prices under the original PPA range from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA is $51/MWh. Entergy executed an additional PPA to cover the period from the expiration of the original PPA through final shutdown in May 2022, at a price of $24.14/MWh. Entergy issues monthly invoices to Consumers Energy for electric sales based on the actual output of electricity and related services provided during the previous month at the contract price. The PPA was at below-market prices at the time of the acquisition and Entergy amortizes a liability to revenue over the life of the agreement. The amount amortized each period is based upon 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 $11 million in 2020, $10 million in 2019, and $6 million in 2018. Amounts to be amortized to revenue through the remaining life of the agreement will be approximately $12 million in 2021 and $5 million in 2022.
Practical Expedients and Exceptions
Entergy has elected not to disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less, or for revenue recognized in an amount equal to what Entergy has the right to bill the customer for services performed.
Most of Entergy’s contracts, except in a few cases where there are defined minimums or stated terms, are on demand. This results in customer bills that vary each month based on an approved tariff and usage. Entergy imposes monthly or annual minimum requirements on some customers primarily as credit and cost recovery guarantees and not as pricing for unsatisfied performance obligations. These minimums typically expire after the initial term or when specified costs have been recovered. The minimum amounts are part of each month’s bill and recognized as revenue accordingly. Some of the subsidiaries within the Entergy Wholesale Commodities segment have operations and maintenance services contracts that have fixed components and terms longer than one year. The total fixed consideration related to these unsatisfied performance obligations, however, is not material to Entergy Louisiana’srevenues.
Recovery of Fuel Costs
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 based on a pre-determined fuel cost (fixed fuel factor), 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 Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are based 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.
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
Entergy Corporation and Subsidiaries
Notes to Financial Statements
some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues.
Allowance for doubtful accounts
The allowance for doubtful accounts reflects Entergy’s best estimate of expected losses on its accounts receivable balances. Due to the essential nature of utility services, Entergy has historically experienced a low rate of default on its accounts receivables. Due to the effect of the COVID-19 pandemic on customer receivables, however, Entergy recorded an increase in its allowance for doubtful accounts, as shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy | | Entergy
Arkansas | | Entergy
Louisiana | | Entergy
Mississippi | | Entergy
New
Orleans | | Entergy
Texas |
| | (In Millions) |
| Balance as of December 31, 2019 | $7.4 | | | $1.2 | | | $1.9 | | | $0.6 | | | $3.2 | | | $0.5 | |
| Provisions (a) | 109.0 | | | 16.2 | | | 43.7 | | | 18.8 | | | 14.1 | | | 16.2 | |
| Write-offs | (8.6) | | | (1.8) | | | (3.5) | | | (1.2) | | | (1.0) | | | (1.1) | |
| Recoveries | 9.9 | | | 2.7 | | | 3.6 | | | 1.3 | | | 1.1 | | | 1.2 | |
| Balance as of December 31, 2020 | $117.7 | | | $18.3 | | | $45.7 | | | $19.5 | | | $17.4 | | | $16.8 | |
(a)Provisions include estimated incremental bad debt expenses resulting from the COVID-19 pandemic of $87.1 million for Entergy, $10.5 million for Entergy Arkansas, $36 million for Entergy Louisiana, $15.5 million for Entergy Mississippi, $12.2 million for Entergy New Orleans, and $12.9 million for Entergy Texas that have been deferred as regulatory assets. See Note 2 to the financial position.statements for discussion of the COVID-19 orders issued by retail regulators.
Title
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 20. QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Operating results for the four quarters of 2020 and 2019 for Entergy Corporation and subsidiaries were:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Revenues | | Operating Income | | Consolidated Net Income | | Net Income Attributable to Entergy Corporation |
| | (In Thousands) |
| 2020: | | | |
| First Quarter | $2,427,179 | | | $399,756 | | | $123,294 | | | $118,714 | |
| Second Quarter | $2,412,788 | | | $439,311 | | | $365,113 | | | $360,533 | |
| Third Quarter | $2,903,568 | | | $778,016 | | | $525,699 | | | $521,119 | |
| Fourth Quarter | $2,370,101 | | | $152,112 | | | $392,547 | | | $387,968 | |
| 2019: | | | |
| First Quarter | $2,609,584 | | | $283,254 | | | $258,646 | | | $254,537 | |
| Second Quarter | $2,666,209 | | | $338,775 | | | $240,533 | | | $236,424 | |
| Third Quarter | $3,140,575 | | | $519,929 | | | $369,459 | | | $365,240 | |
| Fourth Quarter | $2,462,305 | | | $248,539 | | | $389,606 | | | $385,025 | |
Earnings per average common share
| | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 |
| | Basic | | Diluted | | Basic | | Diluted |
| First Quarter | $0.59 | | | $0.59 | | | $1.34 | | | $1.32 | |
| Second Quarter | $1.80 | | | $1.79 | | | $1.22 | | | $1.22 | |
| Third Quarter | $2.60 | | | $2.59 | | | $1.84 | | | $1.82 | |
| Fourth Quarter | $1.95 | | | $1.93 | | | $1.96 | | | $1.94 | |
Results of operations for 2020 include resolution of the 2014-2015 IRS audit, which resulted in a reduction in deferred income tax expense of $230 million that includes a $396 million reduction in deferred income tax expense at Utility related to the basis of assets contributed in the 2015 Entergy Louisiana and Entergy Gulf States Louisiana business combination, including the recognition of previously uncertain tax positions, and deferred income tax expense of $105 million at Entergy Wholesale Commodities and $61 million at Parent and Other resulting from the revaluation of net operating losses as a result of the release of the reserves. See Note 3 to the financial statements for further discussion of the IRS audit resolution.
Results of operations for 2019 include: 1) a loss of $190 million ($156 million net-of-tax) as a result of the sale of the Pilgrim plant in August 2019; 2) a $156 million reduction in income tax expense recognized by Entergy Wholesale Commodities as a result of an internal restructuring; and 3) impairment charges of $100 million ($79 million net-of-tax) due to costs being charged directly 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 exit the Entergy Wholesale Commodities’ merchant power business. See Note 3 to the financial statements for further discussion of the internal restructuring. See Note 14 to the financial statements for further discussion of the sale of the Pilgrim plant.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 2020 and 2019 were:
Operating Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) |
| 2020: | | | | | | | | | | | |
| First Quarter | $481,912 | | | $930,647 | | | $293,922 | | | $149,302 | | | $339,336 | | | $130,664 | |
| Second Quarter | $491,767 | | | $1,011,652 | | | $297,954 | | | $147,343 | | | $372,194 | | | $126,049 | |
| Third Quarter | $644,389 | | | $1,120,022 | | | $356,496 | | | $182,064 | | | $494,922 | | | $148,517 | |
| Fourth Quarter | $466,426 | | | $1,007,541 | | | $299,482 | | | $155,132 | | | $380,673 | | | $90,228 | |
| 2019: | | | | | | | | | | | |
| First Quarter | $545,812 | | | $959,330 | | | $282,244 | | | $163,194 | | | $340,474 | | | $140,104 | |
| Second Quarter | $542,929 | | | $1,106,317 | | | $302,737 | | | $175,793 | | | $363,580 | | | $139,009 | |
| Third Quarter | $687,526 | | | $1,231,677 | | | $398,732 | | | $194,204 | | | $442,877 | | | $145,472 | |
| Fourth Quarter | $483,327 | | | $987,851 | | | $339,330 | | | $153,032 | | | $342,024 | | | $148,825 | |
Operating Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) |
| 2020: | | | | | | | | | | | |
| First Quarter | $67,835 | | | $166,779 | | | $41,181 | | | $12,091 | | | $36,060 | | | $35,309 | |
| Second Quarter | $107,949 | | | $256,412 | | | $67,705 | | | $7,602 | | | $56,443 | | | $31,236 | |
| Third Quarter | $217,648 | | | $324,496 | | | $93,843 | | | $32,322 | | | $108,306 | | | $48,896 | |
| Fourth Quarter | $9,126 | | | $117,134 | | | $33,466 | | | $12,397 | | | $46,040 | | | $1,303 | |
| 2019: | | | | | | | | | | | |
| First Quarter | $42,471 | | | $153,944 | | | $30,792 | | | $16,136 | | | $16,741 | | | $31,368 | |
| Second Quarter | $69,774 | | | $241,520 | | | $45,607 | | | $17,509 | | | $36,022 | | | $24,300 | |
| Third Quarter | $182,176 | | | $336,754 | | | $87,024 | | | $28,876 | | | $69,510 | | | $29,086 | |
| Fourth Quarter | $32,576 | | | $164,424 | | | $40,331 | | | $6,164 | | | $24,229 | | | $30,231 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Net Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) |
| 2020: | | | | | | | | | | | |
| First Quarter | $44,595 | | | $189,396 | | | $22,526 | | | $11,186 | | | $32,707 | | | $28,513 | |
| Second Quarter | $60,170 | | | $170,459 | | | $38,893 | | | $4,929 | | | $46,868 | | | $28,991 | |
| Third Quarter | $135,843 | | | $223,466 | | | $58,589 | | | $19,450 | | | $92,164 | | | $31,064 | |
| Fourth Quarter | $4,624 | | | $499,031 | | | $20,575 | | | $13,773 | | | $43,334 | | | $10,563 | |
| 2019: | | | | | | | | | | | |
| First Quarter | $39,121 | | | $127,633 | | | $15,398 | | | $9,023 | | | $21,342 | | | $23,578 | |
| Second Quarter | $50,299 | | | $183,084 | | | $26,667 | | | $13,003 | | | $38,936 | | | $24,472 | |
| Third Quarter | $149,716 | | | $255,260 | | | $56,237 | | | $24,908 | | | $73,224 | | | $25,031 | |
| Fourth Quarter | $23,828 | | | $125,560 | | | $21,623 | | | $5,695 | | | $25,895 | | | $26,039 | |
Earnings Applicable to Common Equity/Stock
| | | | | | | | | | | | | |
| | | | | | | Entergy Texas |
| | | | | | (In Thousands) |
| 2020: | | | | | | | |
| First Quarter | | | | | | | $32,237 | |
| Second Quarter | | | | | | | $46,397 | |
| Third Quarter | | | | | | | $91,694 | |
| Fourth Quarter | | | | | | | $42,863 | |
| 2019: | | | | | | | |
| First Quarter | | | | | | | $21,342 | |
| Second Quarter | | | | | | | $38,936 | |
| Third Quarter | | | | | | | $73,114 | |
| Fourth Quarter | | | | | | | $25,425 | |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
RISK FACTORS SUMMARY
Entergy’s business is subject to numerous risks and uncertainties that could affect its ability to successfully implement its business strategy and affect its financial results. Carefully consider all of the information in this report and, in particular, the following principal risks and all of the other specific factors described in Item 1A. of this report, “Risk Factors,” before deciding whether to invest in Entergy or the Registrant Subsidiaries.
Utility Regulatory Risks
•The impacts of the COVID-19 pandemic and responsive measures taken are highly uncertain and cannot be predicted.
•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 can be lengthy and subject to appeal, potentially resulting in lengthy litigation and uncertainty as to ultimate results.
•The Utility operating companies’ generating stationscompanies recover fuel, purchased power, and associated costs through rate mechanisms that are generally located on properties ownedsubject to risks of delay or disallowance in fee simple. Mostregulatory proceedings.
•Entergy’s business could experience adverse effects related to changes to state or federal legislation or regulation.
•There remains uncertainty regarding the effect of the substationstermination of the System Agreement on the Utility operating companies.
•The Utility operating companies are subject to risks associated with participation in the MISO markets and the allocation of transmission upgrade costs.
•A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather (including from Hurricane Laura, Hurricane Delta, and distribution linesHurricane Zeta) could have material effects on Entergy and those Utility operating companies affected by severe weather.
Nuclear Operating, Shutdown, and Regulatory Risks
•The results of operations, financial condition, and liquidity of Entergy Arkansas, Entergy Louisiana, System Energy, and Entergy Wholesale Commodities could be materially affected by the following:
◦failure to consistently operate their nuclear power plants at high capacity factors;
◦refueling outages that last longer than anticipated or unplanned outages;
◦risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication);
◦the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants;
◦risks and costs related to operating and maintaining their nuclear power plants;
◦the costs associated with the storage of the spent nuclear fuel, as well as the costs of and their ability to fully decommission their nuclear power plants;
◦the potential requirement to pay substantial retrospective premiums imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance;
◦the risk that the decommissioning trust fund assets for the nuclear power plants may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts; and
◦new or existing safety concerns regarding operating nuclear power plants and nuclear fuel.
•Entergy Wholesale Commodities’ power plants are constructed on private propertysubject to impairment charges in certain circumstances and its nuclear power plants are exposed to price risk.
•The Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or publicmarket design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
General Business Risks
•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. 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.
•A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could, among other things, negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital.
•Changes in tax legislation and 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’ ability to successfully execute on their business strategies, including their ability to complete capital projects, other capital improvements, and strategic transactions is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies.
•Failure to attract, retain, and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
•The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs (i) to fulfill their obligations related to environmental and other matters or (ii) related to reliability standards.
•Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations.
•Entergy could be negatively affected by the effects of climate change and environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions.
•Entergy is dependent on the continued and future availability and quality of water for cooling, process, and sanitary uses.
•Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices.
•The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations.
•Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
•The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.
•Terrorist attacks, cyber attacks, system failures, or data breaches of Entergy’s and its subsidiaries’ or its suppliers’ technology systems may adversely affect Entergy’s results of operations.
•The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
•System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings.
•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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
rights-of-way pursuantENTERGY’S BUSINESS
Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 30,000 MW of electric generating capacity, including approximately 8,000 MW of nuclear power. Entergy delivers electricity to easements, servitudes, or appropriate franchises. Some substation properties3.0 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $10.1 billion in 2020 and had more than 13,000 employees as of December 31, 2020.
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 operation 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. 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 and 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 strategy is to operate and grow the premier utility business that creates sustainable value for its customers, employees, communities, and owners. Entergy’s strategy to achieve its stakeholder objectives has two key aspects. First, Entergy invests in the Utility for the benefit of its customers, which supports steady, predictable growth in earnings and dividends. Second, Entergy manages risks by ensuring its Utility investments are owned in fee simple. customer-centric, supported by progressive regulatory constructs, and executed with disciplined project management. Entergy’s strategy for the Entergy Wholesale Commodities business segment is to continue to manage the risk of its operating portfolio as Entergy completes its exit from the merchant power business.
Utility
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 theirbusiness segment includes five retail electric utility operations.
Substantially all of the physical properties and assets owned bysubsidiaries: Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas,Texas. These companies generate, transmit, distribute, and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy 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, are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station of Entergy Texas was acquired by merger with a wholly-owned subsidiary of Entergy TexasCorporation 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 five 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 currently not subject toregulated by the lienFERC because all of its transactions are at wholesale. The overall generation portfolio of the Entergy Texas indenture.
Fuel Supply
The sources ofUtility, which relies heavily on natural gas and nuclear generation, and average fuel cost per kWhis consistent with Entergy’s strong support for the Utility operating companies and System Energy for the years 2017-2019 were:environment.
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 |
| 2019 | | 40 | | 2.33 |
| | 28 | | 0.73 |
| | 6 | | 2.31 |
| | 8 | | 4.86 |
| | 18 | | 2.71 |
|
| 2018 | | 39 | | 2.84 |
| | 27 | | 0.84 |
| | 9 | | 2.24 |
| | 8 | | 5.23 |
| | 17 | | 3.71 |
|
| 2017 | | 38 | | 2.60 |
| | 26 | | 0.86 |
| | 8 | | 2.35 |
| | 8 | | 4.02 |
| | 20 | | 3.09 |
|
Actual 2019 and projected 2020 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 (d) | | MISO Purchases (e) |
| | 2019 | | 2020 | | 2019 | | 2020 | | 2019 | | 2020 | | 2019 | | 2020 | | 2019 | | 2020 |
| Entergy Arkansas (a) | 28 | % | | 33 | % | | 53 | % | | 53 | % | | 15 | % | | 13 | % | | 1 |
| | 1 | % | | 3 | % | | — |
| Entergy Louisiana | 43 | % | | 56 | % | | 25 | % | | 28 | % | | 2 | % | | 4 | % | | 10 | % | | 12 | % | | 20 | % | | — |
| Entergy Mississippi (b) | 49 | % | | 72 | % | | 25 | % | | 19 | % | | 9 | % | | 9 | % | | — |
| | — |
| | 17 | % | | — |
| Entergy New Orleans (b) | 51 | % | | 58 | % | | 39 | % | | 39 | % | | 2 | % | | 2 | % | | 1 | % | | 1 | % | | 7 | % | | — |
| Entergy Texas | 29 | % | | 32 | % | | 9 | % | | 18 | % | | 4 | % | | 11 | % | | 30 | % | | 39 | % | | 28 | % | | — |
| System Energy (c) | — |
| | — |
| | 100 | % | | 100 | % | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Utility (a) (b) | 40 | % | | 51 | % | | 28 | % | | 32 | % | | 6 | % | | 7 | % | | 8 | % | | 10 | % | | 18 | % | | — |
| |
(a) | Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2019 and is expected to provide less than 1% of its generation in 2020. |
| |
(b) | Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2019 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2020. |
| |
(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 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. The MISO purchases metric provided for 2019 is not projected for 2020. |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
SomeAs of December 31, 2020, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Electric Customers | | Gas Customers |
| | Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) |
| Entergy Arkansas | Portions of Arkansas | | 722 | | | 25 | % | | | | |
| Entergy Louisiana | Portions of Louisiana | | 1,096 | | | 37 | % | | 94 | | | 47 | % |
| Entergy Mississippi | Portions of Mississippi | | 456 | | | 15 | % | | | | |
| Entergy New Orleans | City of New Orleans | | 207 | | | 7 | % | | 108 | | | 53 | % |
| Entergy Texas | Portions of Texas | | 473 | | | 16 | % | | | | |
| Total customers | | | 2,954 | | | 100 | % | | 202 | | | 100 | % |
Electric Energy Sales
The electric energy sales of the Utility’s gas-fired plantsUtility operating companies are also capablesubject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of using fuel oil, if necessary. Although basedeach year. On August 10, 2020, Entergy reached a 2020 peak demand of 21,340 MWh, compared to the 2019 peak of 21,598 MWh recorded on current economicsAugust 12, 2019. Selected electric energy sales data is shown in the table below:
Selected 2020 Electric Energy Sales Data
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| | (In GWh) |
| Sales to retail customers | 20,749 | | | 53,896 | | | 12,402 | | | 5,447 | | | 18,677 | | | — | | | 111,170 | |
| Sales for resale: | | | | | | | | | | | | | |
| Affiliates | 1,659 | | | 5,585 | | | — | | | — | | | 1,203 | | | 5,849 | | | — | |
| Others | 4,198 | | | 2,365 | | | 4,316 | | | 1,969 | | | 810 | | | — | | | 13,658 | |
| Total | 26,606 | | | 61,846 | | | 16,718 | | | 7,416 | | | 20,690 | | | 5,849 | | | 124,828 | |
| Average use per residential customer (kWh) | 12,633 | | | 14,576 | | | 14,093 | | | 12,315 | | | 14,829 | | | — | | | 13,917 | |
(a)Includes the effect of intercompany eliminations.
The following table illustrates the Utility does not expectoperating companies’ 2020 combined electric sales volume as a percentage of total electric sales volume, and 2020 combined electric revenues as a percentage of total 2020 electric revenue, each by customer class.
| | | | | | | | | | | | | | |
| Customer Class | | % of Sales Volume | | % of Revenue |
| Residential | | 28.2 | | 39.2 |
| Commercial | | 21.2 | | 25.4 |
| Industrial (a) | | 37.7 | | 25.8 |
| Governmental | | 2.0 | | 2.3 |
| Wholesale/Other | | 10.9 | | 7.3 |
(a)Major industrial customers are primarily in the petroleum refining and chemical industries.
See “Selected Financial Data” for each of the Utility operating companies for the detail of their sales by customer class for 2016-2020.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Selected 2020 Natural Gas Sales Data
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 9,467,899 and 6,268,003 Mcf, respectively, of natural gas to retail customers in 2020. In 2020, 99% of Entergy Louisiana’s operating revenue was derived from the electric utility business, and only 1% from the natural gas distribution business. For Entergy New Orleans, 88% of operating revenue was derived from the electric utility business and 12% from the natural gas distribution business in 2020.
Following is data concerning Entergy New Orleans’s 2020 retail operating revenue sources.
| | | | | | | | | | | | | | |
| Customer Class | | Electric Operating Revenue | | Natural Gas Operating Revenue |
| Residential | | 48% | | 51% |
| Commercial | | 35% | | 25% |
| Industrial | | 5% | | 18% |
| Governmental/Municipal | | 12% | | 6% |
Retail Rate Regulation
General (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, 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 | | $8.4 (a) | | 9.25% - 10.25% | | 5.04% | | 36.6% | | - forward test year formula rate
plan through 2021 test year (i)
- riders: MISO, capacity, Grand
Gulf, tax adjustment, energy
efficiency, fuel and purchased
power | |
| | | | | | | | | | | |
| Entergy Louisiana (electric) | | $11.9 (b) | | 9.2% - 10.4% | | 6.97% | | 48.63% | | - formula rate plan through 2019
test year (j)
- riders/specific recovery: MISO,
capacity, transmission, fuel | |
| | | | | | | | | | | |
| Entergy Louisiana (gas) | | $0.08 (c) | | 9.3% - 10.3% | | 6.96% | | 48.37% | | - gas rate stabilization plan
- rider: gas infrastructure | |
| | | | | | | | | | | |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Mississippi | | $3.0 (d) | | 8.89% - 10.93% | | 6.82% | | 49.09% | | - 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,
vegetation, grid modernization,
restructuring credit | |
| | | | | | | | | | | |
| Entergy New Orleans (electric) | | $0.8 (e) | | 9.35% | | 7.09% | | 50% | | - formula rate plan with forward-looking features
- riders/specific recovery: fuel and purchased power, MISO, energy efficiency, environmental | |
| | | | | | | | | | | |
| Entergy New Orleans (gas) | | $0.1 (e) | | 9.35% | | 7.09% | | 50% | | - formula rate plan with forward-looking features
- rider: purchased gas | |
| | | | | | | | | | | |
| Entergy Texas | | $2.4 (f) | | 9.65% | | 7.73% | | 50.9% | | - rate case
- riders: fuel, distribution and
transmission, generation, rate case
expenses, AMI surcharge,
tax reform, among others | |
| | | | | | | | | | | |
| System Energy | | $1.6 (g) | | 10.94% (h) | | 8.57 % | | 65% (h) | | - monthly cost of service | |
(a)Based on 2021 test year.
(b)Based on December 31, 2019 test year and excludes approximately $800 million for the Lake Charles Power Station and $300 million for the Washington Parish Energy Center, each included in the capacity rider, and $400 million of transmission plant, included in the transmission rider.
(c)Based on September 30, 2019 test year.
(d)Based on 2020 forward test year and excludes approximately $300 million for the Choctaw Generating Station, included in interim capacity mechanism.
(e)Based on December 31, 2018 test year and known and measurables through December 31, 2019. Electric rate base excludes approximately $190 million for New Orleans Power Station and $40 million for New Orleans Solar Station.
(f)Based on December 31, 2017 test year and excludes $1.0 billion in cost recovery riders.
(g)Based on calculation as of December 31, 2020.
(h)See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity and capital structure.
(i)See Note 2 to the financial statements for discussion of Entergy Arkansas’s pending formula rate plan extension request.
(j)See Note 2 to the financial statements for discussion of Entergy Louisiana’s pending formula rate plan extension request.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy Arkansas
Fuel and Purchased Power Cost Recovery
Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel oil useand purchased power costs in 2020, itmonthly 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 possibleredetermined 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 upon the level of over- or under-recovery of fuel and purchased energy costs. In December 2007 the APSC issued an order stating that various operational eventsEntergy 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.
Production Cost Allocation Rider
Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.
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 weather or pipeline maintenance may requirecarrying 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 historically hedged 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 was 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, which was approved in November 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 oil.costs incurred with fuel cost revenues billed to customers, including carrying charges.
Retail Rates - Gas
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 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
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 the upper end of the earnings band 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 LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.
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 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.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power 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.
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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
Formula Rate Plan
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 was still appropriate or could 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 proceeding. In March 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. 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.
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.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Energy Efficiency Programs
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 and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. 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. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
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 Reliability Corporation (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
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Entergy Corporation, Utility operating companies, and System Energy
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.
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.
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.
The PUCT determined that unrecovered costs that may 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 amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
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.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
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 Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in 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 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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city 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 over the period 2020-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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, 2020, is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,175 | | | 2,091 | | | 1,817 | | | 1,194 | | | 73 | | | — | |
| Entergy Louisiana | | 11,317 | | | 8,827 | | | 2,144 | | | 346 | | | — | | | — | |
| Entergy Mississippi | | 3,347 | | | 2,929 | | | — | | | 416 | | | — | | | 2 | |
| Entergy New Orleans | | 665 | | | 638 | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 2,260 | | | 2,005 | | | — | | | 255 | | | — | | | — | |
| System Energy | | 1,256 | | | — | | | 1,256 | | | — | | | — | | | — | |
| Total | | 24,020 | | | 16,490 | | | 5,217 | | | 2,211 | | | 73 | | | 29 | |
(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 21,591 MW over the previous decade.
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, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation 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 8,801 MW of new long-term resources and the deactivation of about 4,664 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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 MISO reliability requirements as well as long-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:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•In October 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the facility is scheduled to be in service by early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020 and the facility is scheduled to be in service by the end of 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility.The facility was placed in service in December 2020;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas.In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals.Closing is expected to occur by the end of 2023.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s 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);
•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 Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf 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 petroleum 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, 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 10-year agreement 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;
•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;
•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 approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 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 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 received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas.The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP was seeking 300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
Natural Gas
Entergy Louisiana and Entergy New Orleans also distribute natural gas to retail customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Gas transferred to customers is measured by a meter at the customer’s property. Entergy issues monthly invoices to customers at rates approved by regulators for the volume of gas transferred to date.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Competitive Businesses Revenues
The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power and capacity produced by its operating plants to wholesale customers. The majority of Entergy Wholesale Commodities’ revenues are from Entergy’s nuclear power plants located in the northern United States. Entergy issues monthly invoices to the counterparties for these electric sales at the respective contracted or ISO market rate of electricity and related services provided during the previous month.
Almost all of the Palisades nuclear plant output is sold under a 15-year PPA with Consumers Energy, executed as part of the acquisition of the plant in 2007 and expiring in April 2022. Prices under the original PPA range from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA is $51/MWh. Entergy executed an additional PPA to cover the period from the expiration of the original PPA through final shutdown in May 2022, at a price of $24.14/MWh. Entergy issues monthly invoices to Consumers Energy for electric sales based on the actual output of electricity and related services provided during the previous month at the contract price. The PPA was at below-market prices at the time of the acquisition and Entergy amortizes a liability to revenue over the life of the agreement. The amount amortized each period is based upon 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 $11 million in 2020, $10 million in 2019, and $6 million in 2018. Amounts to be amortized to revenue through the remaining life of the agreement will be approximately $12 million in 2021 and $5 million in 2022.
Practical Expedients and Exceptions
Entergy has elected not to disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less, or for revenue recognized in an amount equal to what Entergy has the right to bill the customer for services performed.
Most of Entergy’s contracts, except in a few cases where there are defined minimums or stated terms, are on demand. This results in customer bills that vary each month based on an approved tariff and usage. Entergy imposes monthly or annual minimum requirements on some customers primarily as credit and cost recovery guarantees and not as pricing for unsatisfied performance obligations. These minimums typically expire after the initial term or when specified costs have been recovered. The minimum amounts are part of each month’s bill and recognized as revenue accordingly. Some of the subsidiaries within the Entergy Wholesale Commodities segment have operations and maintenance services contracts that have fixed components and terms longer than one year. The total fixed consideration related to these unsatisfied performance obligations, however, is not material to Entergy revenues.
Recovery of Fuel Costs
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 based on a pre-determined fuel cost (fixed fuel factor), 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 Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are based 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.
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
Entergy Corporation and Subsidiaries
Notes to Financial Statements
some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues.
Allowance for doubtful accounts
The allowance for doubtful accounts reflects Entergy’s best estimate of expected losses on its accounts receivable balances. Due to the essential nature of utility services, Entergy has historically experienced a low rate of default on its accounts receivables. Due to the effect of the COVID-19 pandemic on customer receivables, however, Entergy recorded an increase in its allowance for doubtful accounts, as shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy | | Entergy
Arkansas | | Entergy
Louisiana | | Entergy
Mississippi | | Entergy
New
Orleans | | Entergy
Texas |
| | (In Millions) |
| Balance as of December 31, 2019 | $7.4 | | | $1.2 | | | $1.9 | | | $0.6 | | | $3.2 | | | $0.5 | |
| Provisions (a) | 109.0 | | | 16.2 | | | 43.7 | | | 18.8 | | | 14.1 | | | 16.2 | |
| Write-offs | (8.6) | | | (1.8) | | | (3.5) | | | (1.2) | | | (1.0) | | | (1.1) | |
| Recoveries | 9.9 | | | 2.7 | | | 3.6 | | | 1.3 | | | 1.1 | | | 1.2 | |
| Balance as of December 31, 2020 | $117.7 | | | $18.3 | | | $45.7 | | | $19.5 | | | $17.4 | | | $16.8 | |
(a)Provisions include estimated incremental bad debt expenses resulting from the COVID-19 pandemic of $87.1 million for Entergy, $10.5 million for Entergy Arkansas, $36 million for Entergy Louisiana, $15.5 million for Entergy Mississippi, $12.2 million for Entergy New Orleans, and $12.9 million for Entergy Texas that have been deferred as regulatory assets. See Note 2 to the financial statements for discussion of the COVID-19 orders issued by retail regulators.
The allowance for currently expected credit losses is calculated as the historical rate of customer write-offs multiplied by the current accounts receivable balance, taking into account the length of time the receivable balances have been outstanding. Although the rate of customer write-offs has historically experienced minimal variation, management monitors the current condition of individual customer accounts to manage collections and ensure bad debt expense is recorded in a timely manner.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 20. QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Operating results for the four quarters of 2020 and 2019 for Entergy Corporation and subsidiaries were:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Revenues | | Operating Income | | Consolidated Net Income | | Net Income Attributable to Entergy Corporation |
| | (In Thousands) |
| 2020: | | | |
| First Quarter | $2,427,179 | | | $399,756 | | | $123,294 | | | $118,714 | |
| Second Quarter | $2,412,788 | | | $439,311 | | | $365,113 | | | $360,533 | |
| Third Quarter | $2,903,568 | | | $778,016 | | | $525,699 | | | $521,119 | |
| Fourth Quarter | $2,370,101 | | | $152,112 | | | $392,547 | | | $387,968 | |
| 2019: | | | |
| First Quarter | $2,609,584 | | | $283,254 | | | $258,646 | | | $254,537 | |
| Second Quarter | $2,666,209 | | | $338,775 | | | $240,533 | | | $236,424 | |
| Third Quarter | $3,140,575 | | | $519,929 | | | $369,459 | | | $365,240 | |
| Fourth Quarter | $2,462,305 | | | $248,539 | | | $389,606 | | | $385,025 | |
Earnings per average common share
| | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 |
| | Basic | | Diluted | | Basic | | Diluted |
| First Quarter | $0.59 | | | $0.59 | | | $1.34 | | | $1.32 | |
| Second Quarter | $1.80 | | | $1.79 | | | $1.22 | | | $1.22 | |
| Third Quarter | $2.60 | | | $2.59 | | | $1.84 | | | $1.82 | |
| Fourth Quarter | $1.95 | | | $1.93 | | | $1.96 | | | $1.94 | |
Results of operations for 2020 include resolution of the 2014-2015 IRS audit, which resulted in a reduction in deferred income tax expense of $230 million that includes a $396 million reduction in deferred income tax expense at Utility related to the basis of assets contributed in the 2015 Entergy Louisiana and Entergy Gulf States Louisiana business combination, including the recognition of previously uncertain tax positions, and deferred income tax expense of $105 million at Entergy Wholesale Commodities and $61 million at Parent and Other resulting from the revaluation of net operating losses as a result of the release of the reserves. See Note 3 to the financial statements for further discussion of the IRS audit resolution.
Results of operations for 2019 include: 1) a loss of $190 million ($156 million net-of-tax) as a result of the sale of the Pilgrim plant in August 2019; 2) a $156 million reduction in income tax expense recognized by Entergy Wholesale Commodities as a result of an internal restructuring; and 3) impairment charges of $100 million ($79 million net-of-tax) due to costs being charged directly 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 exit the Entergy Wholesale Commodities’ merchant power business. See Note 3 to the financial statements for further discussion of the internal restructuring. See Note 14 to the financial statements for further discussion of the sale of the Pilgrim plant.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 2020 and 2019 were:
Operating Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) |
| 2020: | | | | | | | | | | | |
| First Quarter | $481,912 | | | $930,647 | | | $293,922 | | | $149,302 | | | $339,336 | | | $130,664 | |
| Second Quarter | $491,767 | | | $1,011,652 | | | $297,954 | | | $147,343 | | | $372,194 | | | $126,049 | |
| Third Quarter | $644,389 | | | $1,120,022 | | | $356,496 | | | $182,064 | | | $494,922 | | | $148,517 | |
| Fourth Quarter | $466,426 | | | $1,007,541 | | | $299,482 | | | $155,132 | | | $380,673 | | | $90,228 | |
| 2019: | | | | | | | | | | | |
| First Quarter | $545,812 | | | $959,330 | | | $282,244 | | | $163,194 | | | $340,474 | | | $140,104 | |
| Second Quarter | $542,929 | | | $1,106,317 | | | $302,737 | | | $175,793 | | | $363,580 | | | $139,009 | |
| Third Quarter | $687,526 | | | $1,231,677 | | | $398,732 | | | $194,204 | | | $442,877 | | | $145,472 | |
| Fourth Quarter | $483,327 | | | $987,851 | | | $339,330 | | | $153,032 | | | $342,024 | | | $148,825 | |
Operating Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) |
| 2020: | | | | | | | | | | | |
| First Quarter | $67,835 | | | $166,779 | | | $41,181 | | | $12,091 | | | $36,060 | | | $35,309 | |
| Second Quarter | $107,949 | | | $256,412 | | | $67,705 | | | $7,602 | | | $56,443 | | | $31,236 | |
| Third Quarter | $217,648 | | | $324,496 | | | $93,843 | | | $32,322 | | | $108,306 | | | $48,896 | |
| Fourth Quarter | $9,126 | | | $117,134 | | | $33,466 | | | $12,397 | | | $46,040 | | | $1,303 | |
| 2019: | | | | | | | | | | | |
| First Quarter | $42,471 | | | $153,944 | | | $30,792 | | | $16,136 | | | $16,741 | | | $31,368 | |
| Second Quarter | $69,774 | | | $241,520 | | | $45,607 | | | $17,509 | | | $36,022 | | | $24,300 | |
| Third Quarter | $182,176 | | | $336,754 | | | $87,024 | | | $28,876 | | | $69,510 | | | $29,086 | |
| Fourth Quarter | $32,576 | | | $164,424 | | | $40,331 | | | $6,164 | | | $24,229 | | | $30,231 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Net Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) |
| 2020: | | | | | | | | | | | |
| First Quarter | $44,595 | | | $189,396 | | | $22,526 | | | $11,186 | | | $32,707 | | | $28,513 | |
| Second Quarter | $60,170 | | | $170,459 | | | $38,893 | | | $4,929 | | | $46,868 | | | $28,991 | |
| Third Quarter | $135,843 | | | $223,466 | | | $58,589 | | | $19,450 | | | $92,164 | | | $31,064 | |
| Fourth Quarter | $4,624 | | | $499,031 | | | $20,575 | | | $13,773 | | | $43,334 | | | $10,563 | |
| 2019: | | | | | | | | | | | |
| First Quarter | $39,121 | | | $127,633 | | | $15,398 | | | $9,023 | | | $21,342 | | | $23,578 | |
| Second Quarter | $50,299 | | | $183,084 | | | $26,667 | | | $13,003 | | | $38,936 | | | $24,472 | |
| Third Quarter | $149,716 | | | $255,260 | | | $56,237 | | | $24,908 | | | $73,224 | | | $25,031 | |
| Fourth Quarter | $23,828 | | | $125,560 | | | $21,623 | | | $5,695 | | | $25,895 | | | $26,039 | |
Earnings Applicable to Common Equity/Stock
| | | | | | | | | | | | | |
| | | | | | | Entergy Texas |
| | | | | | (In Thousands) |
| 2020: | | | | | | | |
| First Quarter | | | | | | | $32,237 | |
| Second Quarter | | | | | | | $46,397 | |
| Third Quarter | | | | | | | $91,694 | |
| Fourth Quarter | | | | | | | $42,863 | |
| 2019: | | | | | | | |
| First Quarter | | | | | | | $21,342 | |
| Second Quarter | | | | | | | $38,936 | |
| Third Quarter | | | | | | | $73,114 | |
| Fourth Quarter | | | | | | | $25,425 | |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
RISK FACTORS SUMMARY
Entergy’s business is subject to numerous risks and uncertainties that could affect its ability to successfully implement its business strategy and affect its financial results. Carefully consider all of the information in this report and, in particular, the following principal risks and all of the other specific factors described in Item 1A. of this report, “Risk Factors,” before deciding whether to invest in Entergy or the Registrant Subsidiaries.
Utility Regulatory Risks
•The impacts of the COVID-19 pandemic and responsive measures taken are highly uncertain and cannot be predicted.
•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 can be lengthy and subject to appeal, potentially resulting in lengthy litigation and uncertainty as to ultimate results.
•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.
•Entergy’s business could experience adverse effects related to changes to state or federal legislation or regulation.
•There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
•The Utility operating companies are subject to risks associated with participation in the MISO markets and the allocation of transmission upgrade costs.
•A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta) could have material effects on Entergy and those Utility operating companies affected by severe weather.
Nuclear Operating, Shutdown, and Regulatory Risks
•The results of operations, financial condition, and liquidity of Entergy Arkansas, Entergy Louisiana, System Energy, and Entergy Wholesale Commodities could be materially affected by the following:
◦failure to consistently operate their nuclear power plants at high capacity factors;
◦refueling outages that last longer than anticipated or unplanned outages;
◦risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication);
◦the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants;
◦risks and costs related to operating and maintaining their nuclear power plants;
◦the costs associated with the storage of the spent nuclear fuel, as well as the costs of and their ability to fully decommission their nuclear power plants;
◦the potential requirement to pay substantial retrospective premiums imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance;
◦the risk that the decommissioning trust fund assets for the nuclear power plants may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts; and
◦new or existing safety concerns regarding operating nuclear power plants and nuclear fuel.
•Entergy Wholesale Commodities’ power plants are subject to impairment charges in certain circumstances and its nuclear power plants are exposed to price risk.
•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.
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General Business Risks
•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. 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.
•A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could, among other things, negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital.
•Changes in tax legislation and 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’ ability to successfully execute on their business strategies, including their ability to complete capital projects, other capital improvements, and strategic transactions is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies.
•Failure to attract, retain, and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
•The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs (i) to fulfill their obligations related to environmental and other matters or (ii) related to reliability standards.
•Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations.
•Entergy could be negatively affected by the effects of climate change and environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions.
•Entergy is dependent on the continued and future availability and quality of water for cooling, process, and sanitary uses.
•Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices.
•The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations.
•Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
•The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.
•Terrorist attacks, cyber attacks, system failures, or data breaches of Entergy’s and its subsidiaries’ or its suppliers’ technology systems may adversely affect Entergy’s results of operations.
•The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
•System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings.
•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.
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ENTERGY’S BUSINESS
Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 30,000 MW of electric generating capacity, including approximately 8,000 MW of nuclear power. Entergy delivers electricity to 3.0 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $10.1 billion in 2020 and had more than 13,000 employees as of December 31, 2020.
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 operation 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. 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 and 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 strategy is to operate and grow the premier utility business that creates sustainable value for its customers, employees, communities, and owners. Entergy’s strategy to achieve its stakeholder objectives has two key aspects. First, Entergy invests in the Utility for the benefit of its customers, which supports steady, predictable growth in earnings and dividends. Second, Entergy manages risks by ensuring its Utility investments are customer-centric, supported by progressive regulatory constructs, and executed with disciplined project management. Entergy’s strategy for the Entergy Wholesale Commodities business segment is to continue to manage the risk of its operating portfolio as Entergy completes its exit from the merchant power business.
Utility
The Utility business segment includes five retail electric utility subsidiaries: Entergy Arkansas, 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 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 five 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.
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Customers
As of December 31, 2020, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Electric Customers | | Gas Customers |
| | Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) |
| Entergy Arkansas | Portions of Arkansas | | 722 | | | 25 | % | | | | |
| Entergy Louisiana | Portions of Louisiana | | 1,096 | | | 37 | % | | 94 | | | 47 | % |
| Entergy Mississippi | Portions of Mississippi | | 456 | | | 15 | % | | | | |
| Entergy New Orleans | City of New Orleans | | 207 | | | 7 | % | | 108 | | | 53 | % |
| Entergy Texas | Portions of Texas | | 473 | | | 16 | % | | | | |
| Total customers | | | 2,954 | | | 100 | % | | 202 | | | 100 | % |
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 10, 2020, Entergy reached a 2020 peak demand of 21,340 MWh, compared to the 2019 peak of 21,598 MWh recorded on August 12, 2019. Selected electric energy sales data is shown in the table below:
Selected 2020 Electric Energy Sales Data
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| | (In GWh) |
| Sales to retail customers | 20,749 | | | 53,896 | | | 12,402 | | | 5,447 | | | 18,677 | | | — | | | 111,170 | |
| Sales for resale: | | | | | | | | | | | | | |
| Affiliates | 1,659 | | | 5,585 | | | — | | | — | | | 1,203 | | | 5,849 | | | — | |
| Others | 4,198 | | | 2,365 | | | 4,316 | | | 1,969 | | | 810 | | | — | | | 13,658 | |
| Total | 26,606 | | | 61,846 | | | 16,718 | | | 7,416 | | | 20,690 | | | 5,849 | | | 124,828 | |
| Average use per residential customer (kWh) | 12,633 | | | 14,576 | | | 14,093 | | | 12,315 | | | 14,829 | | | — | | | 13,917 | |
(a)Includes the effect of intercompany eliminations.
The following table illustrates the Utility operating companies’ 2020 combined electric sales volume as a percentage of total electric sales volume, and 2020 combined electric revenues as a percentage of total 2020 electric revenue, each by customer class.
| | | | | | | | | | | | | | |
| Customer Class | | % of Sales Volume | | % of Revenue |
| Residential | | 28.2 | | 39.2 |
| Commercial | | 21.2 | | 25.4 |
| Industrial (a) | | 37.7 | | 25.8 |
| Governmental | | 2.0 | | 2.3 |
| Wholesale/Other | | 10.9 | | 7.3 |
(a)Major industrial customers are primarily in the petroleum refining and chemical industries.
See “Selected Financial Data” for each of the Utility operating companies for the detail of their sales by customer class for 2016-2020.
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Selected 2020 Natural Gas Sales Data
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 9,467,899 and 6,268,003 Mcf, respectively, of natural gas to retail customers in 2020. In 2020, 99% of Entergy Louisiana’s operating revenue was derived from the electric utility business, and only 1% from the natural gas distribution business. For Entergy New Orleans, 88% of operating revenue was derived from the electric utility business and 12% from the natural gas distribution business in 2020.
Following is data concerning Entergy New Orleans’s 2020 retail operating revenue sources.
| | | | | | | | | | | | | | |
| Customer Class | | Electric Operating Revenue | | Natural Gas Operating Revenue |
| Residential | | 48% | | 51% |
| Commercial | | 35% | | 25% |
| Industrial | | 5% | | 18% |
| Governmental/Municipal | | 12% | | 6% |
Retail Rate Regulation
General (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, 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 | | $8.4 (a) | | 9.25% - 10.25% | | 5.04% | | 36.6% | | - forward test year formula rate
plan through 2021 test year (i)
- riders: MISO, capacity, Grand
Gulf, tax adjustment, energy
efficiency, fuel and purchased
power | |
| | | | | | | | | | | |
| Entergy Louisiana (electric) | | $11.9 (b) | | 9.2% - 10.4% | | 6.97% | | 48.63% | | - formula rate plan through 2019
test year (j)
- riders/specific recovery: MISO,
capacity, transmission, fuel | |
| | | | | | | | | | | |
| Entergy Louisiana (gas) | | $0.08 (c) | | 9.3% - 10.3% | | 6.96% | | 48.37% | | - gas rate stabilization plan
- rider: gas infrastructure | |
| | | | | | | | | | | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Mississippi | | $3.0 (d) | | 8.89% - 10.93% | | 6.82% | | 49.09% | | - 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,
vegetation, grid modernization,
restructuring credit | |
| | | | | | | | | | | |
| Entergy New Orleans (electric) | | $0.8 (e) | | 9.35% | | 7.09% | | 50% | | - formula rate plan with forward-looking features
- riders/specific recovery: fuel and purchased power, MISO, energy efficiency, environmental | |
| | | | | | | | | | | |
| Entergy New Orleans (gas) | | $0.1 (e) | | 9.35% | | 7.09% | | 50% | | - formula rate plan with forward-looking features
- rider: purchased gas | |
| | | | | | | | | | | |
| Entergy Texas | | $2.4 (f) | | 9.65% | | 7.73% | | 50.9% | | - rate case
- riders: fuel, distribution and
transmission, generation, rate case
expenses, AMI surcharge,
tax reform, among others | |
| | | | | | | | | | | |
| System Energy | | $1.6 (g) | | 10.94% (h) | | 8.57 % | | 65% (h) | | - monthly cost of service | |
(a)Based on 2021 test year.
(b)Based on December 31, 2019 test year and excludes approximately $800 million for the Lake Charles Power Station and $300 million for the Washington Parish Energy Center, each included in the capacity rider, and $400 million of transmission plant, included in the transmission rider.
(c)Based on September 30, 2019 test year.
(d)Based on 2020 forward test year and excludes approximately $300 million for the Choctaw Generating Station, included in interim capacity mechanism.
(e)Based on December 31, 2018 test year and known and measurables through December 31, 2019. Electric rate base excludes approximately $190 million for New Orleans Power Station and $40 million for New Orleans Solar Station.
(f)Based on December 31, 2017 test year and excludes $1.0 billion in cost recovery riders.
(g)Based on calculation as of December 31, 2020.
(h)See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity and capital structure.
(i)See Note 2 to the financial statements for discussion of Entergy Arkansas’s pending formula rate plan extension request.
(j)See Note 2 to the financial statements for discussion of Entergy Louisiana’s pending formula rate plan extension request.
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Entergy Arkansas
Fuel and Purchased Power Cost Recovery
Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased power 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 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.
Production Cost Allocation Rider
Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.
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 historically hedged 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 was 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, which was approved in November 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.
Retail Rates - Gas
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 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
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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 the upper end of the earnings band 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 LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.
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 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.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power 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.
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.
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Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
Formula Rate Plan
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 was still appropriate or could 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 proceeding. In March 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. 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.
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.
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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Energy Efficiency Programs
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 and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. 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. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
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 Reliability Corporation (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
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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.
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.
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.
The PUCT determined that unrecovered costs that may 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 amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
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.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
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 Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in 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 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.
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Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city 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 over the period 2020-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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, 2020, is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,175 | | | 2,091 | | | 1,817 | | | 1,194 | | | 73 | | | — | |
| Entergy Louisiana | | 11,317 | | | 8,827 | | | 2,144 | | | 346 | | | — | | | — | |
| Entergy Mississippi | | 3,347 | | | 2,929 | | | — | | | 416 | | | — | | | 2 | |
| Entergy New Orleans | | 665 | | | 638 | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 2,260 | | | 2,005 | | | — | | | 255 | | | — | | | — | |
| System Energy | | 1,256 | | | — | | | 1,256 | | | — | | | — | | | — | |
| Total | | 24,020 | | | 16,490 | | | 5,217 | | | 2,211 | | | 73 | | | 29 | |
(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 21,591 MW over the previous decade.
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, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation 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 8,801 MW of new long-term resources and the deactivation of about 4,664 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.
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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 MISO reliability requirements as well as long-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:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•In October 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the facility is scheduled to be in service by early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020 and the facility is scheduled to be in service by the end of 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility.The facility was placed in service in December 2020;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas.In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals.Closing is expected to occur by the end of 2023.
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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’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s 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);
•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 Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf 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 petroleum 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, 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 10-year agreement 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;
•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;
•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 approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 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 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 received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
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•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas.The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP was seeking 300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
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; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; 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); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility is an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, owned by East Texas Electric Cooperative. Entergy Texas is currently seeking regulatory certification to move forward with the purchase of the facility. The facility has been in operation since January 2010.
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Power Through Program
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation that is to be installed at commercial and industrial customer premises. If approved, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.”
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-electric production facilities, combustion-turbine generators, pressurized and boiling water nuclear reactors, and inverter-based technologies operating in the MISO energy and ancillary services market. 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 facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of 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 Bulk Electric System reliability standards within the SERC Region.
Gas Property
As of December 31, 2020, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2020, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy 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 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 of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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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 2018-2020 were:
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| | | 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 |
| 2020 | | 47 | | | 1.92 | | | 29 | | | 0.57 | | | 3 | | | 2.54 | | | 8 | | | 4.36 | | | 13 | | | 2.48 | |
| 2019 | | 40 | | | 2.33 | | | 28 | | | 0.73 | | | 6 | | | 2.31 | | | 8 | | | 4.86 | | | 18 | | | 2.71 | |
| 2018 | | 39 | | | 2.84 | | | 27 | | | 0.84 | | | 9 | | | 2.24 | | | 8 | | | 5.23 | | | 17 | | | 3.71 | |
Actual 2020 and projected 2021 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:
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| | Natural Gas | | Nuclear | | Coal | | Purchased Power (d) | | MISO Purchases (e) |
| | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 |
| Entergy Arkansas (a) | 24 | % | | 35 | % | | 60 | % | | 51 | % | | 10 | % | | 13 | % | | 1 | % | | 1 | % | | 5 | % | | — | |
| Entergy Louisiana | 51 | % | | 59 | % | | 26 | % | | 27 | % | | 1 | % | | 2 | % | | 9 | % | | 12 | % | | 13 | % | | — | |
| Entergy Mississippi (b) | 73 | % | | 69 | % | | 14 | % | | 22 | % | | 4 | % | | 9 | % | | — | | | — | | | 9 | % | | — | |
| Entergy New Orleans (b) | 55 | % | | 56 | % | | 33 | % | | 40 | % | | 1 | % | | 2 | % | | 2 | % | | 2 | % | | 9 | % | | — | |
| Entergy Texas | 39 | % | | 60 | % | | 11 | % | | 13 | % | | 2 | % | | 6 | % | | 23 | % | | 21 | % | | 25 | % | | — | |
| System Energy (c) | — | | | — | | | 100 | % | | 100 | % | | — | | | — | | | — | | | — | | | — | | | — | |
| Utility (a) (b) | 47 | % | | 55 | % | | 29 | % | | 31 | % | | 3 | % | | 6 | % | | 8 | % | | 8 | % | | 13 | % | | — | |
(a)Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2020 and is expected to provide less than 1% of its generation in 2021.
(b)Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2020 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2021.
(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 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. The MISO purchases metric provided for 2020 is not projected for 2021.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2021, it is possible that various operational events including weather or pipeline maintenance may require the 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. Over 50% of the Utility operating companies’ power plants maintain some level of long-termlong-
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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 primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies 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 may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to seven one- to three-year and two spot contracts that will supply approximately 85% of the total coal supply needs in 2020.2021. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 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 2020.2021. Coal will be transported to Arkansas via an existing transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2020.2021.
Entergy Louisiana has committed to fourfive one- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2020.2021. 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 2020.2021. Coal will be transported to Nelson primarily via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2020.2021.
For the year 2019,2020, coal transportation delivery rates to Entergy Arkansas-and Entergy Louisiana-operated coal-fired units were satisfactoryadequate to meet supply needs and obligations. Delivery rates improvedobligations, and it is expected that delivery times in the second half of the year as track restoration efforts were completed by the railroads following spring flooding events, although flooding impacts were overall inconsequential2021 will continue to the companies’ coal operations.be consistent. Both Entergy Arkansas and Entergy 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 Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2020.2021. Entergy 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;
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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, Entergy Arkansas, Entergy Louisiana, and System 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
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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.
Based upon currently planned fuel cycles, the Utility 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 or fixed prices through most of 2023. 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 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 seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with CenterPoint 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 CenterPoint Energy Service gas supply is
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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.
Entergy Louisiana purchased natural gas for resale in 20192020 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy 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 and interstate transmission of electricity, including 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.
System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
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 engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which was a rate schedule approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources were jointly operated by the Utility operating companies that were participating in the System Agreement. The System Agreement provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) would receive payments from those parties having generating reserves that were less than their allocated share of reserves (short companies). Such payments were 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 were 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 were required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
Although the System Agreement has terminated, certain of the Utility operating companies’ and their retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. The proceedings include challenges to the 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
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did 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 MISO region, including the Utility operating companies. MISO also exercises functional control of transmission
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planning and congestion management and 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 markets. 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. 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
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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 July 2001 a rate proceeding commenced by System Energy at the FERC in 1995 became final, with the FERC approving a prospective 10.94% return on equity. 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 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 complaints filed with the FERC 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 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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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
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Entergy Corporation, Utility operating companies, and 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 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 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 onetwo outstanding series of first mortgage 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 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.
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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.
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Service Companies
Entergy Services, a limited liability company 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 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 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 Unit 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, 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 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. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses 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, 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 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.
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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.
Entergy Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated 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 assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed 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 is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
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•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light 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 Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
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-related services, to nuclear power plants owned by non-affiliated entities in the United States. 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.
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 operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
Property
Nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:
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| Power Plant | | Market | | In Service Year | | Acquired | | Location | | Capacity - Reactor Type | | License Expiration Date |
| Indian Point 3 (a) | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2025 (a) |
| Indian Point 2 (a) | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2024 (a) |
| Palisades (b) | | MISO | | 1971 | | Apr. 2007 | | Covert,
MI | | 811 MW - Pressurized Water | | 2031 (b) |
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(a) | The Indian Point 2 and Indian Point 3 plants are expected to cease operation by April 30, 2020 and April 30, 2021, respectively. |
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(b) | The Palisades plant is expected to cease operations no later than May 31, 2022. |
(a)Power operations ceased at the Indian Point 2 plant in April 2020. The fuel was permanently removed from the reactor vessel and placed in the spent fuel pool in May 2020. The Indian Point 3 plant is expected to cease operations on April 30, 2021. Entergy and Holtec jointly filed a license transfer application with the NRC in November 2019, requesting approval for the transfer of the Indian Point plants, along with their nuclear decommissioning trusts and decommissioning liabilities, from Entergy to Holtec. The NRC approved the license transfer application on November 23, 2020.
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(b)The Palisades plant is expected to cease operations on May 31, 2022. There is a contract to sell the plant to Holtec subject to NRC and other regulatory approvals.
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 operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
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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. Both Big Rock Point and Indian Point 1 are under contract to be sold with their respective plants.
Non-nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, the following non-nuclear power plants:
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| Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| RS Cogen; 425 MW (c) | | Lake Charles, LA | | 50% | | 213 MW | | Gas/Steam |
| Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
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(a) | “Net Owned Capacity” refers to the nameplate rating on the generating unit. |
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(b) | (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 an interest in an unconsolidated joint venture. In December 2020, Entergy’s wholly-owned subsidiary with a direct interest in RS Cogen, LLC entered into a membership interest purchase agreement with a subsidiary of the other 50% equity partner to sell its 50% membership interest in the joint venture to the equity partner. The targeted closing date for the transaction is October 2022.
Jointly-Owned Generating Stations” in Note 1 to the financial statements.
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(c) | Indirectly owned through interests in unconsolidated joint ventures. |
Independent System Operators
The 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 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. 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. See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.
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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 receives 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. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022 and transfer to Holtec thereafter.
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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 Consumers Energy, the company from which Entergy purchased the Palisades plant, and NYISO and MISO. Substantially all of the credit 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 NYISO market is highly competitive. Entergy Wholesale Commodities has numerous competitors in 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 York power market 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 majoritymost of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. The majorityAlmost all of Palisades’ current output is contracted to Consumers Energy through May 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 in the spring and fall, and cause volumetric decreases during those seasons. When outdoor and cooling water temperatures are 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.
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,
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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 plant owners. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment has been adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the Indian Point 2, Indian Point 3 and Palisades plants. Fuel procurement for the Entergy Wholesale Commodities segment iswas primarily limited to the requirements of the Palisades plant’s final refueling in 2020.
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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 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. ENPM’s functions include origination of new energy and capacity transactions and generation scheduling.
Entergy Nuclear, Inc. can 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.
TLG Services, a subsidiary ofin the Entergy Nuclear, Inc.,Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Entergy provides plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.
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.
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 the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC 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.
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State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and conditions of service;
•service standards;
•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
•avoided cost payments to Qualifying Facilities;
•net energy metering;
•integrated resource planning;
•utility mergers and acquisitions and other changes of control; and
•the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory 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 rateratemaking or other regulatory schemejurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and purchase power contracts;
•procurement process to acquire over 50 MW;
•audits of the environmental adjustment charge, avoided cost payment to Qualifying Facilities, and energy efficiency rider;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
retail rates and charges, including depreciation rates;
fuel cost recovery, including audits of the energy cost recovery mechanism;
terms and conditions of service;
service standards;
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•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
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, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other 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 the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects;
•utility service areas, including extensions into new areas;
•avoided cost payments to Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
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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 civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, 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 operators of Indian Point Energy Center, Palisades, and Big Rock Point.
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Entergy Corporation, Utility operating companies, and System Energy
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, 20192020 of $191.1$192.0 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 Vermont Yankee spent fuel disposal contract was assigned to NorthStar as part of the sale of the plant which was completed in January 2019. The Pilgrim spent fuel disposal contract was transferred to Holtec as part of the sale of Entergy Nuclear Generation Company in August 2019. The owners of these plants previous to Entergy have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the 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. Specific steps were taken to discontinue the Yucca Mountain project, including 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. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the 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
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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 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.
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. These subsidiaries have been, and continue to be, involved in litigation to recover
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the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2017, 2018, 2019, and 20192020 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2019,2020, Entergy’s subsidiaries won and collected on judgments against the government totaling over $600approximately $800 million.
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 River Bend in 2005, at Grand Gulf in 2006, at Indian Point in 2008, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, 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. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. 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.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In October 2020, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and ANO 2 decommissioning trusts were adequately funded without further collections, and in December 2020, the APSC ordered zero collections for ANO 1 and ANO 2 decommissioning.
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. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). An evidentiary hearing onBecause of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing has been scheduled for Julywas no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice.
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In December 20182010 the APSC ordered collections in rates forPUCT approved increased decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In November 2019, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and ANO 2 decommissioning trusts were adequately funded without further collections, and in December 2019, the APSC ordered zero collections for ANO 1 and ANO 2 decommissioning.the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal.
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, (amongamong other things)things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
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 January 2019, Entergy sold 100% of the membership interest in Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar. As a result of the sale, NorthStar assumed ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 9 to the financial statements for further discussion of Vermont Yankee decommissioning 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.
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In August 2019, Entergy sold 100% of the equity interests in Entergy Nuclear Generation Company, LLC to a subsidiary of Holtec International. As a result of the sale, Holtec assumed ownership of Pilgrim and its decommissioning trust, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 14 to the financial statements for further discussion of the sale.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities 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. 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, which 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 transaction. See Note 14 to the financial statements for discussion of the FitzPatrick sale.
In March 20192020 filings with the NRC were made reporting on decommissioning funding for all of Entergy subsidiaries’ nuclear plants reporting on decommissioning funding.plants. Those reports showed that decommissioning funding for each of thosethe nuclear plants met the NRC’s financial assurance and planning requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 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
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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 $137.6 million per reactor (with 9897 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, 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.
NRC Reactor Oversight Process
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. The nuclear generating plants owned and operated by Entergy’s Utility and Entergy Wholesale Commodities businesses are currently in Column 1.1, except for Grand Gulf, which is currently in Column 2.
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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, 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, 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); •2) 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 permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
•New and existing source standards for greenhouse gas and other air 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. In August 2019December 2020 the EPA proposed to amendamended the NSR regulations to clarify when a physical change or change in the method of operation will constitute such a modification. Entergy has an established process for identifying modifications requiring additional permitting approval and is monitoring the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. Several years ago, however, the EPA implemented 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 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, including NSR requirements and air permits issued by the Arkansas Department of Energy and Environment, Division of Environmental Quality.Quality (ADEQ). In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 an additional request for similar information was received for the White Bluff facility. Entergy responded to all requests. None of these EPA requests for information alleged that the facilities were in violation of law.
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In January 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. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims as well as other issues facing Entergy Arkansas’s fossil generation plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. In October 2019 the District Court requested supplemental briefing on several issues to be resolved prior to addressing the motion to approve the settlement.
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settlement; that briefing was completed in May 2020. For further information about the settlement, see “Regional Haze” discussed below.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is 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.
Ozone Nonattainment
Entergy Texas operates onetwo fossil-fueled generating facilityfacilities (Lewis Creek)Creek and is in the process of constructing another fossil-fueled generating facility (MontgomeryMontgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for construction and operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
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. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. 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 December 2020 the EPA designated East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. Challenges to these final designations must be filed within 60 days of publication in the Federal Register. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In February 2019May 2020 the EPA published its proposedfinalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. However, the proposalThe final appropriate and necessary finding does not seek to revise the underlying MATS rule at this time.rule. Several lawsuits have been filed challenging the appropriate and necessary finding. Entergy will continue to monitor this situation.
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.
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Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions. In September 2016 the EPA finalized the CSAPR Update Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 the final rule requires reductions in summer nitrogen oxides (NOx) emissions. Several states, including Arkansas and Texas, filed a challenge to the Update Rule. In September 2019 the D.C. Circuit upheld the EPA’s underlying approach to the Update Rule, but determined that it was inconsistent with the Clean Air Act because it failed to include deadlines consistent with downwind states’ deadlines for attainment. The court remanded the rule to the EPA for further consideration, but did not vacate so the rule remains in effect pending the EPA’s further review. In October 2020 the EPA issued its proposal intended to address the D.C. Circuit’s remand. The draft rule proposes to finalize interstate transport obligations for 21 states. For nine states, including Arkansas, Mississippi, and Texas, the EPA proposes that additional emission reductions are not necessary. For 12 states, however, including Louisiana, the EPA proposes additional emission reductions through proposed reductions in the number of NOx emission allowances allocated to each state. Entergy, through its various trade associations, filed comments on the proposal and will continue to monitor the rulemaking and its potential impact on its facilities in Louisiana. If the October 2020 proposal is finalized, ozone season NOx emissions may become more expensive in Louisiana.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could 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 Energy and Environment, Division of Environmental Quality (ADEQ) prepared a state implementation plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. In April 2012 the EPA finalized a decision addressing the Arkansas Regional Haze SIP, in which it disapproved a large portion of the Arkansas 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 granted the stay pending settlement discussions and pending the State’s development of a SIP that, if approved by the EPA, would replace the FIP. The state hashad 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. The Part I SIP requires that Entergy address NOx impacts on visibility via compliance with the Cross StateCross-State Air Pollution Rule ozone-season emission trading program. Arkansas has finalized a Part II SIP which has been approved by the EPA but is currently pending a state court appeal. That appeal has been stayed pending the outcome of a federal court case, which may resolve many of the issues on appeal. The final Part II SIP requires that Entergy achieve SO2 emission reductions via the use of low-sulfur coal at both White Bluff and Independence within three years. The
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Part II SIP also requires that Entergy cease to use coal at White Bluff by December 31, 2028 and notes the current planning assumption that Entergy’s Independence units will cease to burnuse coal by December 31, 2030.
In January 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. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement and in many cases also the Part II SIP, Entergy Arkansas, along with co-owners, will begin using only low-sulfur coal at Independence and White Bluff by mid-2021; cease to use coal at White Bluff and Independence by the end of 2028 and 2030, respectively; cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserve the option to develop new generating sources at each plant site; and commit to install or propose to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waive certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the
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National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. The EPA, which is allowed to comment on such a settlement agreement, has stated that it has no objections to the settlement. Pending beforeIn November 2020 the court are a motion by the plaintiffs to approve the settlement, in support of which Entergy made a filing, anddenied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. Still pending before the court is a motion by the plaintiffs to approve the settlement, in support of which Entergy made a filing. The Arkansas Attorney General also filed an application before the APSC in December 2018 seeking an investigation into the effects of the settlement. The Arkansas Affordable Energy Coalition filed to support the Arkansas Attorney General’s application, and Entergy Arkansas filed a motion to dismiss.dismiss it. The application remains pending before the APSC. In October 2019 the District Court requested supplemental briefing on several issues to be resolved prior to addressing the motion to approve the settlement.settlement; that briefing concluded in May 2020.
In Louisiana, Entergy has worked with the Louisiana Department of Environmental Quality (LDEQ) and the EPA to revise the Louisiana SIP for regional haze, which had been 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 of January 22, 2021. The EPA issued final approval in December 2017. The EPA approval was appealed to the U.S. Court of Appeals for the Fifth Circuit. In October 2019 the Fifth Circuit affirmed the EPA’s SIP approval. A petition for rehearing filed by plaintiffs was denied by the Fifth Circuit. Plaintiffs did not petition for further review by the Supreme Court.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by 2021. Entergy received information collection requests from Arkansas and Louisiana requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, and Ninemile. Responses to the information requests have been submitted to the respective state agencies.
New and Existing Source Performance Standards for Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, rule.which established
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national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy is evaluatingfacilities to help the final Affordable Clean Energy Rule’s impacts on its coal unitsstates collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests and will continue to monitor litigation challenging the rule. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also hasvacated the repeal of the Clean Power Plan. The vacatur will not be effective until the court issues its mandate which is being held until after disposition of any petitions for rehearing. Entergy is currently reviewing the court’s opinion.
In 2018 the EPA proposed a revision to the new source performance standard on greenhouse gas emissions that primarily impacts new coal units and, therefore, should not impact Entergy. In January 2021 the EPA finalized a pollutant-specific contribution finding for greenhouse gas emissions from new, modified, and reconstructed electric generating units. The rule establishes a three percent threshold for determining when a pollutant significantly contributes to air pollution and reaffirms the EPA’s position that the Clean Air Act Section 111(b) requires the EPA to make pollutant-specific significant contribution findings before promulgation of a new source performance standard. The EPA did not, however, finalize the new source performance standard on greenhouse gas emissions and intends to address the 2018 proposal in a future action.
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; •x, 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 federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of Federalfederal 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;
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efforts on the local, state, and federal level to codify renewable portfolio standards, clean energy standards, 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;
•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;polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of carbon dioxide emissionsenvironmental, social, and governance risk;
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•the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds; and
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals.residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in aan economy-wide, 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 megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020. In 2020, Entergy succeeded in achieving its initial climate commitment to reduce carbon dioxide cumulative emissions by 20% from 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 39.1 million tons in 2020 and 40.7 million tons in 2019 and 43.7 tons2019. Since its original commitment in 2018.2001, Entergy’s cumulative emissions are approximately 7.6% below its 2020 goal.
Entergy voluntarily conducted a climate scenario analysis and published a comprehensive report in March 2019. The report follows the framework and recommendations of the Task Force on Climate-related Disclosures, describing climate-related governance, strategy, risk management, and metrics and targets. Scenario analysisanalyses resulted in Entergy developing and publishing a new goal of reducing the Utility’s emission rate by 50 percent from 2000 levels by 2030. In September 2020, Entergy committed to achieving net-zero carbon emissions by 2050, while continuing its commitment to grid reliability and affordability for customers. In December 2020, Entergy published a report regarding this long-term commitment that describes its approach and technology point-of-view. Technology research and development, innovation, and advancement are critical to Entergy’s ability to meet this climate commitment.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s annual greenhouse gas emissions inventory is also third-party verified, and that certification is made available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 20192020 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for eighteennineteen consecutive years. Entergy also participated in the 2020 CDP and CDP Water evaluations, receiving a ‘B’ for both responses.
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, section 402, 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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Steam Electric Effluent Guidelines
The 2015 Steam Electric Effluent Limitations Guidelines (ELG) rule requires,required, among other things, that there be no discharge of bottom ash transport water. The no-discharge requirement contains no exceptions and could cause compliance problemsIn October 2020 the EPA issued its final rule revision on bottom ash transport water allowing the discharge of up to 10% system volume for Entergy’s coal facilities during heavycertain purge waters, including storm events and under certain non-routine operational conditions.operations. The ELG rule’sfinal rule requires compliance dates currently are delayed whileas soon as possible beginning October 31, 2021, but no later than December 31, 2025. Several challenges to the EPA reconsiders the rule.final rule have been filed. Additionally, the Fifth Circuit Court of Appeals recentlypreviously vacated and remanded the provisions of the rule related to legacy wastewater and leachate. In November 2019leachate, which the EPA released a proposed rule revision on bottom ash transport water that will allow some flexibility for storm events and non-routine operations. A separate rulemaking is expectedplans to address the legacy wastewater and leachate issues.in a separate rulemaking. Despite the impending rulemaking,final rule and pending challenges, Entergy is implementing projects at its White Bluff and Independence plants to convert to zero-discharge systems to comply with the ELG rule and the coal combustion residuals restrictions on impoundments. Additionally, the Nelson Unit 6 facility is implementing operational and maintenance measures to ensure its original zero-discharge designminimize the potential for discharge of bottom ash transport water from the existing bottom ash handling system at the site, and is maintainedreviewing the effectiveness of these changes for compliance with the ELGrequirements of the October 2020 final rule.
Federal Jurisdiction of Waters of the United States
In February 2019 the EPA published its proposed revised definition of Waters of the United States, which proposes to narrow the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. The final rule was released in January 2020 and effective in June 2020. In October 2019 the EPA repealed the 2015 rule and re-codified the pre-existing regulations. That rule was effective late December 2019. Numerous challenges are expected forhave been filed against both rules.
Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to 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, Indian Point, Palisades, Grand Gulf, 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.
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
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Entergy Corporation, Utility operating companies, and System Energy
disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. 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 such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental 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 RCRAResource Conservation and Recovery Act (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 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, 2019,2020, Entergy has recorded asset retirement obligations related to CCR management of $19.2$20.1 million.
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 program. In September 2017 the EPA agreed to reconsider certain provisions of the CCR rule in light of the WIIN Act. In July 2018 the EPA released its initial revisions extending certain deadlines and incorporating some risk-based standards. In August 2018 the D.C. Circuit vacated several provisions of the CCR rule on the basis that they were inconsistent with the Resource Conservation and Recovery Act and remanded the matter to the EPA to conduct further rulemaking. In August 2019 the EPA released its second set of proposed revisions to the CCR rule and plans at least three additional rulemakings.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. 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. InConsequently, in order to meet these regulations,move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of one of its two recycle ponds, at White Bluff commenced closurewith the remaining pond being held in October 2018. Additionally,reserve during initial operation of the secondnew bottom ash handling system. Closure of the remaining recycle pond at White Bluff planseach site will commence as soon as possible, but no later than April 11, 2021, which is the deadline under the finalized CCR rule to initiatecommence closure on or before October 31, 2020.of any unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new EPACCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Other Environmental Matters
Entergy Louisiana and Entergy Texas
Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, currently is 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 routed to a portion of the property for disposal. The same area also has 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. Removal actions addressed contaminated source material, soil, and sediment and included capping certain soil on and off-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. The EPA released the second Five Year Review in 2015. In that review, the EPA indicated that the remediation technique was insufficient and that Entergy would need to utilize other remediation technologies on the site. In July 2015, Entergy submitted a Focused Feasibility Study to the EPA outlining the potential remedies and suggesting installation of the new remedial method, a waterloo barrier. The estimated cost for this remedy is approximately $2 million, to be allocated between Entergy Louisiana and Entergy Texas. In early 2017 the EPA indicated that the waterloo barrier may not be necessary and requested revisions to the Focused Feasibility Study. The EPA released the third Five Year Review in late-2019 confirming that a new remedial method is not necessary but requiring continuation of the current groundwater monitoring. The site’s remedy includes monitored natural attenuation of groundwater, and institutional controls to restrict groundwater and land use. The EPA has determined that no additional actions are needed for the remedy to be protective over the long-term, and the remedy is protective of human health and the environment.
Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, 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 existed at the site. Entergy subsidiaries sent transformers to this facility. Entergy Arkansas, Entergy Louisiana, and Entergy Texas responded to an information request from the TCEQ. Entergy Louisiana and Entergy Texas 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 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. Current estimates, although variable depending on ultimate remediation design and performance, indicate that Entergy’s total share of remediation costs likely will be approximately $1.5 million to $2 million. Groundwater monitoring wells at the site were plugged and abandoned in December 2019 following receipt of a certificate of completion issued by the TCEQ. Site decommissioning activities will occur,are complete and final disposition of the property will be determined at a later time.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand
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letter seeking reimbursement for response costs totaling $4 million expended at the site. The demand letter is being evaluated and liability and PRP allocation of response costs are yet to be determined.
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 Texas Commission on Environmental Quality (TCEQ)TCEQ and the National Response Center were immediately notified, and the 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, Entergy entered into the Voluntary Cleanup Program with the TCEQ. In November 2017, additional soil sampling was completed in the wetland area and, in February 2018, a site summary report of findings was submitted to the TCEQ. The TCEQ responded in June 2018 and requested an ecological exclusion criteria checklist/Tier II screening-level ecological risk assessment, and additional site assessment, additional soil samples, groundwater samples, and some additional diagrams and maps. In October 2018, Entergy submitted the requested information to the TCEQ. In January 2019 the TCEQ responded with another request for information. In March 2019, Entergy submitted the requested information to the TCEQ. In August 2019 the TCEQ responded with a request for additional information including an Affected Property Assessment Report (APAR) and water well survey. The TCEQ has agreed that the necessity of the water well survey is dependent on the results of the groundwater resampling that will occur. Groundwater sampling was completed in December 2019 and results were submitted to the TCEQ for review. Based on the groundwater sampling results, the TCEQ has indicatedconfirmed in February 2020 that a water well survey is not necessary. The deadline for submittal ofnecessary and requested the APAR will be 180 days followingand an Ecological Risk Assessment by August 2020. Due to COVID-19 delays, the receipt ofTCEQ extended the TCEQ’s letter confirming approval of the groundwater sampling results.APAR and Ecological Risk Assessment submittal dates to December 2020, which Entergy timely met.
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)
Mississippi Attorney General Complaint
See Note 2 to the financial statements for a discussion of this proceeding.
Asbestos Litigation (Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, 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
Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2019,2020, Entergy subsidiaries employed 13,63513,400 people.
|
| | | | |
| Utility: | |
|
| Entergy Arkansas | 1,2511,244 |
|
| Entergy Louisiana | 1,6701,654 |
|
| Entergy Mississippi | 745750 |
|
| Entergy New Orleans | 308303 |
|
| Entergy Texas | 643658 |
|
| System Energy | — |
|
| Entergy Operations | 3,5643,529 |
|
| Entergy Services | 3,8993,859 |
|
| Entergy Nuclear Operations | 1,5051,356 |
|
| Other subsidiaries | 5047 |
|
| Total Entergy | 13,63513,400 |
|
Approximately 4,1003,900 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, and Fire Professionals of America.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
| Gender (%) | 2020 | | 2019 |
| Female | 21 | | 20 |
| Male | 79 | | 80 |
| 100 | | 100 |
| | | | | | | | | | | |
| Race/Ethnicity (%) | 2020 | | 2019 |
| White | 78 | | 79 |
| Black/African American | 15 | | 15 |
| Hispanic/Latino | 3 | | 2 |
| Asian | 2 | | 2 |
| Other | 2 | | 2 |
| 100 | | 100 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion and belonging; and talent management.
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Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Personnel Committee establishes priorities and reviews performance on a range of topics. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development and succession plans to align a high performing executive team with Entergy’s priorities. The Personnel Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on ethics and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. While the COVID-19 pandemic and historical hurricane season presented significant challenges, Entergy’s safety strategy and commitment to excellence showed results in 2020. Entergy employees achieved a total recordable incident rate of 0.40 in 2020 compared to 0.56 in 2019 and 0.48 in 2018. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases. This marked improvement in total recordable incident rate placed Entergy in top-decile in safety performance when benchmarked amongst peers within the Edison Electric Institute.
Organizational Health, including Diversity, Inclusion and Belonging
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (near top quartile). In addition to significantly improved scores, initial employee participation of 66 percent in 2014 rose to and remains at 90 percent in 2018-2020.
Entergy believes that a culture focused on diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. Among other actions, the primary focus of its 2020 actions was taking a stand against social injustice, reinforcing expectations, training and leading by example, starting at the top of the organization and cascading through management ranks.
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Entergy Corporation, Utility operating companies, and System Energy
Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the future, and reflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.
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 SEC 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. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
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 annual and quarterly reports on Forms 10-K and 10-Q (including related filings in Inline XBRL format) and current reports on Form 8-K; 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 internet 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.
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Entergy Corporation, Utility operating companies, and System Energy
RISK FACTORS
See “RISK FACTOR SUMMARY” in Part I Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ 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 Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
In December 2019 a novel strain of coronavirus was reported to have surfaced in Wuhan, China. Since then, COVID-19 has spread throughout most countries in the world, including the United States. Public health officials in the United States have both recommended and mandated wearing of masks, precautions to mitigate the spread of COVID-19, including prohibitions on congregating in heavily-populated areas, mandated closure or limitations on the functions of non-essential business, and shelter-in-place orders or similar measures, including throughout Entergy’s service areas. While some of these mitigation measures have been lifted, it is unclear how long certain forms of mitigation measures will remain in place, whether they will be reinstated in the future, and how they will ultimately impact the general economy, Entergy’s customers, and its operations.
Entergy and its Utility operating companies have experienced a decline in commercial and industrial sales and an increase in arrearages and bad debt expense due to non-payment by customers, and expect such reduced levels of sales and increased arrearages and bad debt expense to continue, the extent and duration of which management cannot predict. The Utility operating companies temporarily suspended disconnecting customers for non-payment of bills, and the suspension remains in place at Entergy Arkansas, has been re-instituted at Entergy New Orleans, and could be re-instituted at the other Utility operating companies should their regulators mandate. While they are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is unknown. Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges, supply chain, vendor, and contractor disruptions; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed outages; delays in regulatory proceedings; workforce availability, health or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees telecommuting; increased late or uncollectible customer payments; volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and initiatives.
A sustained or further economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the COVID-19 pandemic on their customers. In addition, if the COVID-19 pandemic continues to create disruptions or turmoil in the credit or financial markets, or adversely impacts Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its
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liquidity needs, or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the outbreak, the impact of new variants of COVID-19, the timing, availability, distribution or effectiveness of a vaccine, anti-viral or other treatments for COVID-19, governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
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 can be lengthy and subject to appeal, that could resultpotentially resulting in delays in effecting rate changes, lengthy litigation and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. 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, including adjustment upon the initiative of a regulator or affected stakeholders.
In addition, regulators may initiate proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s 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 may 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. Traditional 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 these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and the Utility operating companies may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation of their assets and infrastructure or the quality of their service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements.
The base rates of Entergy Texas are established largely in traditional base rate case proceedings.Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. For example, Entergy Texas has recovered distribution-related capital investments through theThese riders include a distribution cost recovery factor rider mechanism transmission-relatedfor the recovery of distribution-related capital investmentsinvestment and certain non-fuel MISO charges, through thea transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a generation cost recovery rider mechanism for the recovery of generation-related capital investments, and a fixed fuel factor mechanism for the recovery of MISO fuel and energy-related costs
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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 necessary and reasonable, and makes a prudence finding for each of the fuel-related contracts for the reconciliation period.Entergy Texas also is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Between base rate cases, Entergy Arkansas and Entergy Mississippi 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 unless2021. Entergy Arkansas requests, and thehas requested APSC approves,approval of the extension of the formula rate plan tariff for an additional five years through 2026.If Entergy Arkansas’s formula rate plan were terminated or not extended beyond the initial term, Entergy Arkansas could file an 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 plan was most recently extended through the test year 2019; certain modifications were made in that extension, including a decrease to the allowed return on equity and the addition of a transmission cost recovery mechanism.The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC and as noted, for certain transmission investment, among other items.MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause.Entergy Louisiana has a pending request to extend its formula rate plan with certain modifications, including implementation of a distribution investment recovery mechanism and use of end of period rate base.In the event that the electric formula rate plan is not renewed or extended, Entergy Louisiana would revert to the more traditional rate case environment.
Entergy New Orleans previously operated under a formula rate plan that ended with the 2011 test year.Based on a settlement agreement approved by the City Council, with limited exceptions, the base rates of Entergy New Orleans were frozen until rates were implemented in connection with the base rate case filed by Entergy New Orleans in 2018.In November 2019 the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019.The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes.In November 2020 the City Council issued a resolution approving a settlement of the 2018 rate case.As part of this settlement, Entergy New Orleans has appealedagreed to postpone the resolution. filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle.See Note 2 to the financial statements for further discussion.
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 allowshas monthly adjustments tobillings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the
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reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a request in a separate proceedingrequest for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies have agreedSystem Energy has received FERC acceptance for billing protocols to implement certain protocols for providingprovide retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
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
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requests for, and the continuation of, cost recovery mechanisms. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales could put upward pressure on rates, resulting in adverse regulatory actions to mitigate such effects on rates. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
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 or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may 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 and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
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.
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There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
The Utility operating companies historically 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 had been approved by the FERC. The System Agreement terminated in its entirety on August 31, 2016.
There 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 existence. In the absence 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 offew outstanding System Agreement proceedings at the FERC and at the D.C. Circuit that may require future adjustments, including challenges to
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the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
For further information regarding the regulatory proceedings relating to the System Agreement, see Note 2 to the 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. 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 powercapacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or the cost of serving the Utility operating companies’ respective loads, and MISO market rules may change in ways that cause additional risk.
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. MISO has made filings with FERC proposing changes in the transmission project criteria in MISO. These changes, if adopted, could potentially result in a larger 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 thesetransmission projects of others, 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, the
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allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits 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, or generally allow the retail regulator to direct the making of such 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.
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(Entergy Corporation, Entergy Arkansas, 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 (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta), or the impact on customer bills of permitted storm cost recovery, could have material effects on Entergy and thoseits Utility operating companies affected by severe weather.companies.
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. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills.
In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, 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
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costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity 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 owned or contractually controlled 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.
Certain of the Utility operating companies and 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.
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. Plant maintenance and upgrades are often scheduled during such planned outages, which typically extends the planned outage duration. 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.
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Certain of the Utility operating companies and System Energy and Entergy Wholesale Commodities face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks 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 2020 and beyond. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment has been adjusted to reflect reduced overall requirements related to the planned permanent shutdown and sale of the Palisades, Indian Point 2 and Indian Point 3 plants over the next three years and fuel procurement is limited to the final refueling of the Palisades plant in 2020. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium 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 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 and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, or shifting trade arrangements between countries. 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 changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy, and Entergy Wholesale Commodities.Energy.
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 international sanctions or tariffs could further restrict the ability of such
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suppliers to continue to supply fuel or provide such services at acceptable prices or at all. 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 and System Energy, and Entergy Wholesale Commodities.Energy.
Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, suspend 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, 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 nuclear facilities. 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
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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.1.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate 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 the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities.
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 increased costs, some of which costs may not be fully recoverable by the Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. 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
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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, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture 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 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
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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 NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are 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 will 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 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 Louisiana, and System Energy and Note 8 to the financial statements.
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, which is referred to as Secondary Financial Protection, up to approximately $137.6 million per reactor. With 9897 reactors currently
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participating, this translates to a total public liability cap of approximately $14 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, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the 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 primary insurance level, up to a maximum of approximately $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.101 billion). The retrospective premium payment is currently limited to approximately $21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $137.6 million cap.
NEIL is a utility industry mutual insurance company, owned by its 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 NEIL surplus (reserve) be significantly depleted due to insured losses. As of December 31, 2019,2020, the maximum annual assessment amounts total $112$104 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential 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,
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or liquidity of Entergy, certain of the Utility operating companies, System Energy, or the Entergy Wholesale Commodities subsidiaries.
The 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 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. 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.
Under NRC regulations, nuclear plant owners 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 nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent
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decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments 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.
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, or accelerate the timing for funding of, the obligations related to the decommissioning of the Utility operating companies, System Energy, or Entergy Wholesale Commodities nuclear power plants or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. 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
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
power business, the impairment charges that resulted from such decision, and the planned salesales of Palisades and Indian Point Energy Center (which, in each case, will include the transfer of the associated decommissioning trust)trusts), 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.
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. These concerns have led to, and may 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 might lead to the shutdown of nuclear units, 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 and financial condition.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation)
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. 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, 2019,2020, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 97% in 2020, 92%98% in 2021 and 66%99% in 2022 of its generation portfolio’s planned energy output, reflecting the planned shutdown and sale of the remaining 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.
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.
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
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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).licenses.
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 “Market and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the closure (or sale) of its nuclear plants, Entergy Wholesale Commodities may enter into fewer forward sales contracts for output from such plants.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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. 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$1.29 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. 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. 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, 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, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other 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 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 remaining assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure and sale of its nuclear power plants. Moreover, prior to the closure and 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, or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
If Entergy concludes that any of its nuclear power plants is unlikely to operate through its planned shutdown date, which conclusion would be based on a variety of factors, such a conclusion could result in a 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 remaining 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 - Impairment of Long-lived Assets and Trust Fund Investments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
General BusinessProduction Cost Allocation Rider
(Entergy Corporation, Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)Arkansas as a result of System Agreement proceedings.
Entergy and the Utility operating companies depend on accessLouisiana
Fuel Recovery
Entergy Louisiana’s rate schedules include a fuel adjustment clause designed 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, andrecover the cost of capital.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.
Entergy’s business is capital intensiveTo 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 historically hedged 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 was reviewed on an annual basis. In January 2018, Entergy Louisiana filed an application with the LPSC to suspend these seasonal hedging programs and dependent uponimplement financial hedges with terms up to five years for a portion of its abilitynatural gas exposure, which was approved in November 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 access capital at reasonable ratescustomers, including carrying charges.
Retail Rates - Gas
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
Part I Item 1A & 1B1
Entergy Corporation, Utility operating companies, and System Energy
other terms. At times there are also spikesinvestment 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 the price for natural gas and other commodities that increase the liquidity requirementsexcess of the Utility operating companiesupper end of the earnings band 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 LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Wholesale Commodities. Louisiana’s filings to recover storm-related costs.
Other
In addition, Entergy’sMarch 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 Utility operating companies’ liquidity needs could significantly increase insecond is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the eventLPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a hurricane orutility’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.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other weather-related or unforeseen disaster similarregulatory environments, and recommend a plan for how 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, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown events, could causeensure customers are 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 accessfocus. There was no opposition to the capital markets.directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020.
The inability to raise capital on favorable terms, particularly during times of high interest rates, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in companies that experience extreme weather events, that rely on fossil fuels or offerings to fund fossil fuel projects, or due to risks related to climate change. Events beyond Entergy’s control 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 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, abilityMississippi’s rate schedules include energy cost recovery riders 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.
Most of Entergy Corporation’s and its subsidiaries’ 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,costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the counterparties may require postingover-recovery or under-recovery of collateral in cash or lettersthe energy costs as of credit, prepaymentthe 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.
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 fuel,the gas or purchased power or accelerated payment, or counterparties may decline business with Entergy Corporation orused to serve its subsidiaries. At December 31, 2019, basednative electric load for all months of the year. The hedge quantity is reviewed on power prices at that time, Entergy had liquidity exposure of $78 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $19 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 asan annual basis.
Part I Item 1A & 1B1
Entergy Corporation, Utility operating companies, and System Energy
of December 31, 2019, Entergy would have been required to provide approximately $30 million of additional cash or letters of credit under some of the agreements. As of December 31, 2019, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $90 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, and cash flows.
The Tax Cuts and Jobs Act of 2017 significantly changed 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 and interpretive guidance from the IRS are unclear in certain respects and will require further 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.
As further described in Note 3 to the financial statements, as a result of amortization of accumulated deferred income taxes and payment of such amounts to customers in 2019, Entergy’s net regulatory liability for income taxes balance is $1.7 billion as of December 31, 2019. Depending on the outcome of IRS examinations or tax positions and elections that Entergy may make, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense. Further, there may be other material effects resulting from the legislation that have not been identified.
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, 2018 and 2019 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, andSee Note 2 to the financial statements discussesfor a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
Formula Rate Plan
In August 2012 the regulatory proceedingsMPSC 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 was still appropriate or could 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 proceeding. In March 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 have consideredtime. In June 2014 the effectsMPSC expanded the scope of the Act.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. The docket remains open.
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 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 its subsidiaries make judgments regardingpurchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the potential tax effectsmonthly reconciliation of various transactionsactual fuel and results of operationspurchased power costs incurred with fuel cost revenues billed to estimate their obligationscustomers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include provisionsreflect estimated gas costs for potential adverse outcomes regarding tax positionsthe billing month, adjusted by a surcharge or credit similar to that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including thoseincluded in the formelectric fuel adjustment clause, including carrying charges.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of carryforwards for whichits natural gas hedging program consistent with the benefits have already been reflectedCity Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the financial statements. Changes in federal, state, or local tax laws, adverse tax audit results or adverse tax rulings on positions taken bywholesale price of natural gas purchased to serve Entergy and its subsidiaries could negatively affect Entergy’s,New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity. For further information regarding Entergy’s income taxes, seewinter months.
Storm Cost Recovery
See Note 32 to the financial statements.statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.
Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies, which could materially affect their future prospects, results of operations and benefits that they anticipate from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, which are subject to business, regulatory, economic and other risks and uncertainties, many of which are beyond their control. As a result, Entergy and its subsidiaries may be unable to fully achieve the anticipated results of such strategies.
Part I Item 1A & 1B1
Entergy Corporation, Utility operating companies, and System Energy
Additionally,
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 its subsidiaries have pursuedprovided 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 mayrough 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 pursue strategic transactionsbe 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 and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. 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. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
Entergy Texas
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including merger, acquisition, divestiture, joint venture, restructuring or other strategic transactions. For example, Entergy has entered into an agreement to sell its equity interestsinterest, that are not included in the subsidiary that owns the Palisades Nuclear Plant and the decommissioned Big Rock Point Nuclear Power Plant and an agreement to sell the equity interests of Indian Point 1, Indian Point 2, and Indian Point 3, in each case after eachbase rates. Semi-annual revisions of the plants has been shut downfixed fuel factor are made in March and defueled. Also, a significant portionSeptember based on the market price of Entergy’s utility business over the next several years includes the constructionnatural gas and /or purchase of a variety of generating units. These transactionschanges in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and plansany interim surcharge or refund are or may become subject to regulatory approval and other material conditions or contingencies.fuel reconciliation proceedings before the PUCT. The failurePUCT fuel cost proceedings are discussed in Note 2 to complete these transactions or plans or anythe 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 strategic transaction successfullycapacity 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 Reliability Corporation (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 timely basis could have an adverse effect on Entergy’s or its subsidiaries’ financial condition or 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:
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;
Entergy may experience issues integrating businesses into its internal controls over financial reporting;
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 and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition or results of operations.
The completion of capital projects, including the construction of power generation facilities, and other capital improvements involve substantial risks. Should such 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 capital projects, including the 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, escalating costs for materials, labor, and environmental compliance, and reliance on suppliers for timely and satisfactory performance. Delays in obtaining permits, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under 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 the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.
Part I Item 1A & 1B1
Entergy Corporation, Utility operating companies, and System Energy
For further information regarding capital expenditure plans and other uses of capital in connection with capital projects, includingexist. Under the potential construction and/or purchase of additional generation supply sources withinlaw, the Utility operating companies’ service territory, and asPUCT may not approve a transition to the Entergy Wholesale Commodities business, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysiscompetition plan for Entergy and eachTexas until the expiration of four years from the Registrant Subsidiaries.PUCT’s certification of Entergy Texas’s power region.
Failure
The law further amended already existing law that had required Entergy Texas to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
We rely onpropose for PUCT approval a large and changing workforce of team members, including employees, contractors and temporary staffing. Certain events, such as an aging workforce, mismatching of skill sets, failingtariff to appropriately anticipate future workforce needs, or the unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base and the time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may increase. Failure to hire and adequately train replacement employees, or the future availability and cost of contract labor may adversely affectallow eligible customers the ability to managecontract 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 operateprovide the business, especially consideringgeneration at retail to the workforce needs associated with nuclear generation facilitiescustomer;” and new skills required3) 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 operatean applicable decision, rule, or policy statement of a modernized, technology-enabled power grid. If Entergy and its subsidiaries are unable to successfully attract, retain and manage an appropriately qualified workforce, their results of operations, financial position and cash flows could be negatively affected.federal regulatory agency having jurisdiction.
The Utility operating companies, System Energy,PUCT determined that unrecovered costs that may be recovered through the rider consist only of those costs necessary to implement and administer the Entergy Wholesale Commodities businesscompetitive generation program and do not include lost revenues or embedded generation costs. The amount of customer load that 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 vestedbe included in the competitive generation service program is limited to 115 MW.
In September 2011 the PUCT adopted a proposed rule implementing agencies. Developinga distribution cost recovery factor to recover capital 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 significantcapital-related costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases,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 regulated air emissions from generating plantstaxes, and return on investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises are potentially subjectunlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas franchises are considered to increased regulation, controlsbe contracts and, mitigation expenses. In addition, existing air regulations and programs promulgated bytherefore, are terminable pursuant to the EPA often are challenged legally, or are revised or withdrawn by the EPA, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the natureterms of the changes. Risks relatingfranchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in 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 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.
Part I Item 1A & 1B1
Entergy Corporation, Utility operating companies, and System Energy
global climate change, initiativesEntergy New Orleans provides electric and gas service in the City of New Orleans pursuant to compel greenhouseindeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and 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.
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 over the period 2020-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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, 2020, is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,175 | | | 2,091 | | | 1,817 | | | 1,194 | | | 73 | | | — | |
| Entergy Louisiana | | 11,317 | | | 8,827 | | | 2,144 | | | 346 | | | — | | | — | |
| Entergy Mississippi | | 3,347 | | | 2,929 | | | — | | | 416 | | | — | | | 2 | |
| Entergy New Orleans | | 665 | | | 638 | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 2,260 | | | 2,005 | | | — | | | 255 | | | — | | | — | |
| System Energy | | 1,256 | | | — | | | 1,256 | | | — | | | — | | | — | |
| Total | | 24,020 | | | 16,490 | | | 5,217 | | | 2,211 | | | 73 | | | 29 | |
(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 21,591 MW over the previous decade.
The Utility operating companies, System Energy,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, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the Entergy Wholesale Commodities business may incur substantial costs relatedage and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to reliability standards.
Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established bybe met through long-term resources, whether owned or contracted. Over the NERC,past decade, the 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 resultPortfolio Transformation Strategy has resulted in the impositionaddition of fines or civil penalties,about 8,801 MW of new long-term resources and potential exposure to third party claims for alleged violationsthe deactivation 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,about 4,664 MW of legacy generation. As MISO market participants, the Utility operating companies have incurredalso participate in MISO’s Day Ahead and expectReal Time Energy and Ancillary Services markets to incur significant costs relatedeconomically dispatch generation and purchase energy to compliance with newserve customers reliably and existing reliability standards, including costs associated withat the Utility operating companies’ transmission system and generation assets. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the 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 businesses.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations.
Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, mild temperatures in either season tend to decrease energy usage and resulting revenues. Higher consumption levels coupled with seasonal pricing differentials 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 including hurricanes or tropical storms, flooding events, or ice storms 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 reduced 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 weather and economic conditions, 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 grid demand. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and their replacement with more efficient ones, adoption of newer technologies including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales growth in the future. The
Part I Item 1A & 1B1
Entergy Corporation, Utility operating companies, and System Energy
Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower 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 increase clean or renewable energy requirements 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, some 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 CO2 and other “greenhouse gases” under the Clean Air Act, the EPA, various environmental interest groups, and other organizations focused considerable attention on CO2 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. During 2012 and 2014, the EPA proposed CO2 emission standards for new and existing sources. The EPA finalized these standards in 2015; however, in June 2019, the EPA repealed and replaced certain aspects of those regulations. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. The impact that continued changes in the governmental response to climate change risk 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 or clean/renewable energy 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. The operations of low or non-emitting generating units (such as nuclear units) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing the company’s greenhouse gas emission rate. 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 CO
2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy’s utility operating companies, their suppliers or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy’s utility operating companies are unable to fully recover the costs and investment in generation and (iv) could increase the difficulty that Entergy and its utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations and liquidity of Entergy and its subsidiaries. In addition, lawsuits have 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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, wildfires, wetland and barrier island erosion, risks of flooding and changes in weather conditions, (such as increases in precipitation, drought, or changes in average 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 the physical impacts of climate change, 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, more frequent and longer lasting outages, 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, and Entergy Wholesale Commodities’ business operations. Entergy’s facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also 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.
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 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 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,
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 andfrom time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the Entergy Wholesale Commodities business are exposedspot market to meet 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 practicesunique regional needs 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 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.
Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
companies. 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 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 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 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.
Terrorist attacks, cyber attacks, system failures or data breaches of Entergy’s and its subsidiaries’ or our suppliers’ technology systems may adversely affect Entergy’s results of operations.
Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers and employees, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply chain activities. Any significant failure or malfunction of such information technology systems could result in loss of data or disruptions of operations.
There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. As an operator of critical infrastructure, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, cyber attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions. An actual act could affect Entergy’s ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct business.
Given the rapid technological advancements of existing and emerging threats, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security and controls. 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 could be unable to perform critical business functions that are essential to the company’s well-being and could result in a loss of its confidential, sensitive, and proprietary information, including personal information of its customers, employees, suppliers, and others in Entergy’s care. Although malware was discovered on Entergy’s business network in 2018, it was remediated on a timely basis and did not affect Entergy’s operational systems, generation plants (including nuclear), or transmission and distribution networks, nor did it have a material effect on Entergy’s business operations.
Any such attacks, failures or data breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, results of operations or reputation. Insurance may not be adequate to cover losses that might arise in connection with these events. Such events may also expose Entergy to an increased risk of litigation (and associated damages and fines).
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect 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 New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. 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.
(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 paidRFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as consideration for their respective entitlementswell as long-term requirements through a broad range of wholesale power products, including limited-term (1 to receive capacity3 years) and energy.long-term contractual products and asset acquisitions. The useful economic lifeRFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s construction of Grand Gulf is finite and is limited by the terms of980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its operating license, which expires in November 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 continuedexisting Little Gypsy electric generating station. The facility began commercial operation of Grand Gulf. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s authorized return on equity and capital structure and a request in separate proceeding for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussionMay 2019;
•Entergy Texas’s construction of the proceedings.993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The Utility operating companies have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
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, see Notes 8 and 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 subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy Corporation depends 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. Prior to providing funds to Entergy Corporation, such subsidiaries have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of Entergy Utility Holding Company and Entergy Texas, dividends and distributions on preferred securities. Any distributions from the Registrant Subsidiaries other than Entergy Texas and System Energy
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
are paid directly to Entergy Utility Holding Company and are therefore subject to prior payment of distributions on its preferred securities.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2019 Compared to 2018
Net Income
Net income increased $10.3 million primarily due to higher retail electric price and lower nuclear refueling outage expenses, partially offset by lower volume/weather, higher interest expense, and higher depreciation and amortization expenses.
Operating Revenues
Following is an analysisLouisiana’s construction of the change in operating revenues comparing 2019 to 2018:
|
| | | |
| Amount |
| (In Millions) |
2018 operating revenues |
| $2,060.6 |
|
Fuel, rider, and other revenues that do not significantly affect net income | (74.9 | ) |
Return of unprotected excess accumulated deferred income taxes to customers | 241.4 |
|
Retail electric price | 66.7 |
|
Volume/weather | (34.2 | ) |
2019 operating revenues |
| $2,259.6 |
|
Entergy Arkansas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a tax adjustment rider beginning in April 2018. In 2019, $126.3 million was returned to customers as compared to $367.7 million in 2018. There was no effect on net income as the reduction in operating revenues in each period was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
The retail electric price variance is primarily due to an increase in formula rate plan rates effective with the first billing cycle of January 2019, as approved by the APSC. See Note 2 to the financial statements for further discussion of the formula rate plan filing.
The volume/weather variance is primarily due to a decrease of 707 GWh, or 3%, in billed electricity usage, including the effect of less favorable weather on residential andfacility began commercial sales and a decrease in industrial usage. The decrease in industrial usage is primarily due to a decrease in small industrial sales.
Other Income Statement Variances
Nuclear refueling outage expenses decreased primarily due to the amortization of lower costs associated with the most recent outages as compared to previous outages.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other operation and maintenance expenses decreased primarily due to:
a decrease of $20.2 million in nuclear generation expenses primarily due to a lower scope of work performed in 2019 as compared to 2018;
the effects of recording in 2019 a final judgment to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $11.9 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
| |
• | a decrease of $5.5 million in vegetation maintenance costs.
|
The decrease was partially offset by:
an $11.2 million write-off in 2019 of specific costs related to the potential construction of scrubbers at the White Bluff plant;
an increase of $8.5 million in information technology expenses primarily due to higher costs related to applications and infrastructure support, enhanced cyber security, and upgrades and maintenance;
an increase of $7.4 million due to spending on initiatives to explore new customer products and services; and
an increase of $5.5 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2019 as compared to prior year.
Taxes other than income taxes increased primarily due to increases in local franchise taxes and ad valorem taxes. The increase in local franchise taxes is primarily due to higher electric retail revenues. The increase in ad valorem taxes is primarily due to higher assessments and millage rates.
Depreciation and amortization expenses increased primarily due to additions to plant in service and an increase in the ANO 1 and ANO 2 asset retirement cost assets. See Note 9 to the financial statements for discussion of the increase in the asset retirement cost assets.
Interest expense increased primarily due to the issuance of $350 million of 4.20% Series mortgage bonds in March 2019 and the issuance of $250 million of 4.00% Series mortgage bonds in May 2018.
The effective income tax rates were (21.6%) for 2019 and 669.7% for 2018. The differences in the effective income tax rates versus the federal statutory rate of 21% for 2019 and 2018 were primarily due to the amortization of excess accumulated deferred income taxes. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
2018 Compared to 2017
•See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2018 for discussion of results of operations for 2018 compared to 2017.
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, 2018, and 2019 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 the regulatory proceedings that have considered the effects of the Act.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2019, 2018, and 2017 were as follows:
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $119 |
| |
| $6,216 |
| |
| $20,509 |
|
| | | | | | |
| Net cash provided by (used in): | | | | | |
|
| Operating activities | 677,766 |
| | 211,825 |
| | 555,556 |
|
| Investing activities | (676,293 | ) | | (688,727 | ) | | (829,312 | ) |
| Financing activities | 1,927 |
| | 470,805 |
| | 259,463 |
|
| Net increase (decrease) in cash and cash equivalents | 3,400 |
| | (6,097 | ) | | (14,293 | ) |
| | | | | | |
| Cash and cash equivalents at end of period |
| $3,519 |
| |
| $119 |
| |
| $6,216 |
|
2019 Compared to 2018
Operating Activities
Net cash flow provided by operating activities increased $465.9 million in 2019 primarily due to:
a decrease in the return of unprotected excess accumulated deferred income taxes to customers in 2019 as compared to 2018. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act;
payments in 2018 of $135 million to the other Utility operating companies as a result of a compliance filing made in response to the FERC’sIn October 2018, order in the opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding;
income tax refunds of $34 million in 2019 compared to income tax payments of $44.4 million in 2018. Entergy Arkansas had income tax refunds in 2019 and income tax payments in 2018 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2019 resulted from the utilization of Entergy Arkansas’s net operating losses. The income tax payments in 2018 primarily resulted from the settlement of the 2012-2013 audit;
a decrease of $44.1 million in spending on nuclear refueling outages in 2019; and
the timing of recovery of fuel and purchased power costs.
The increase was partially offset by the timing of collection of receivables from customers and an increase of $11.8 million in pension contributions in 2019. 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.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Investing Activities
Net cash flow used in investing activities decreased $12.4 million in 2019 primarily due to:
a decrease of $32.1 million in nuclear construction expenditures primarily due to a lower scope of work performed on various nuclear projects in 2019 as compared to 2018;
a decrease of $25.8 million in transmission construction expenditures primarily due to a lower scope of work performed on various projects in 2019 as compared to 2018; and
a decrease of $13 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.
The decrease was partially offset by an increase of $35.6 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Arkansas’s distribution system, including increased spending on advanced metering infrastructure, and an increase of $15.6 million in storm spending.
Financing Activities
Entergy Arkansas’s cash provided by financing activities decreased $468.9 million in 2019 primarily due to:
a $350 million capital contribution from Entergy Corporation in May 2018 in anticipation of the return of unprotected excess accumulated deferred income taxes to customers and upcoming planned capital investments;
the issuance of $250 million of 4.0% Series first mortgage bonds in May 2018;
money pool activity;
net repayments of long-term borrowings of $44.5 million in 2019 compared to net long-term borrowings of $34.7 million in 2018 on the Entergy Arkansas nuclear fuel company variable interest entity credit facility; and
an increase of $23.2 million in common equity distributions paid in 2019 primarily to maintain Entergy Arkansas’s capital structure.
The decrease was partially offset by:
the issuance of $350 million of 4.20% Series mortgage bonds in March 2019;
net repayments of short-term borrowings of $50 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2018; and
the redemption of $31.4 million of preferred stock in 2018 in connection with the internal restructuring. See Note 2 to the financial statements for further discussion of the internal restructuring and Note 6 to the financial statements for details of preferred stock activity.
Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased by $161.1 million in 2019 compared to increasing by $16.6 million in 2018. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2018 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2018 for discussion of operating, investing, and financing cash flow activities for 2018 compared to 2017.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio is primarily due to the issuance of long-term debt in 2019.
|
| | | |
| | December 31,
2019 | | December 31,
2018 |
| Debt to capital | 53.0% | | 52.0% |
| Effect of excluding the securitization bonds | —% | | (0.2%) |
| Debt to capital, excluding securitization bonds (a) | 53.0% | | 51.8% |
| Effect of subtracting cash | —% | | —% |
| Net debt to net capital, excluding securitization bonds (a) | 53.0% | | 51.8% |
| |
(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, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas 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 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 distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its 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 distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Arkansas 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
distribution and interest payments.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
|
| | | | | | | | | | | |
| | 2020 | | 2021 | | 2022 |
| | (In Millions) |
| Planned construction and capital investment: | | | |
| | |
|
| Generation |
| $250 |
| |
| $445 |
| |
| $595 |
|
| Transmission | 110 |
| | 50 |
| | 65 |
|
| Distribution | 190 |
| | 125 |
| | 125 |
|
| Utility Support | 185 |
| | 165 |
| | 240 |
|
| Total |
| $735 |
| |
| $785 |
| |
| $1,025 |
|
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
|
| | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $142 |
| |
| $737 |
| |
| $877 |
| |
| $4,377 |
| |
| $6,133 |
|
| Operating leases (b) |
| $13 |
| |
| $20 |
| |
| $13 |
| |
| $12 |
| |
| $58 |
|
| Finance leases (b) |
| $3 |
| |
| $4 |
| |
| $3 |
| |
| $2 |
| |
| $12 |
|
| Purchase obligations (c) |
| $553 |
| |
| $939 |
| |
| $561 |
| |
| $4,485 |
| |
| $6,538 |
|
| |
(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) | 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 $32.5 million to its qualified pension plans and approximately $509 thousand to its other postretirement health care and life insurance plans in 2020, although the 2020 required pension contributions will be known with more certainty when the January 1, 2020 valuations are completed, which is expected by April 1, 2020. 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 $207.1 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 Arkansas includes 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 advanced meters and related investments; resource planning, including potential generation projects; system improvements; investments in ANO 1 and 2; software and security; 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 maturities in Note 5 to the financial statements.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Searcy Solar Facility
In March 2019, Entergy Arkansas announced that itMississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the facility is scheduled to be in service by early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. The purchase is contingent upon, among other things, obtaining necessary approvals from applicable federal and state regulatory and permitting agencies. The project will be constructed by a subsidiary of NextEra Energy Resources. Entergy Arkansas will purchasereceived regulatory approval from the APSC in April 2020 and the facility upon mechanical completion and after the other purchase contingencies have been met. Closing is expectedscheduled to occurbe in service by the end of 2021. 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility.The facility was placed in service in December 2020;
•In May 2019,June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2022;
•In September 2019 other parties filed testimony largely supporting2020, Entergy Arkansas signed an agreement for the resource acquisition but disputing Entergy Arkansas’s proposed methodpurchase of cost recovery.an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas.In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals.Closing is expected to occur by the end of 2023.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s 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);
•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 Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf 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 petroleum 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, 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 10-year agreement with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from its rebuttal testimonylandfill gas-fueled power generation facility located in Cleveland, 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;
•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 approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 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 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 received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas.The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP was seeking 300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
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; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; 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); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In FebruaryMay 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility is an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, owned by East Texas Electric Cooperative. Entergy Texas is currently seeking regulatory certification to move forward with the purchase of the facility. The facility has been in operation since January 2010.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Power Through Program
In December 2020, Entergy Arkansas,Texas filed an application with the Attorney General,PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation that is to be installed at commercial and industrial customer premises. If approved, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.”
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-electric production facilities, combustion-turbine generators, pressurized and boiling water nuclear reactors, and inverter-based technologies operating in the MISO energy and ancillary services market. 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 APSC general staff filedCanadian province of Manitoba. As a partial settlement agreement asking the APSC to approve, based on the record in the proceeding, all issues except certain issues that are submittedRegional Transmission Organization, MISO assures consumers of unbiased regional grid management and open access to the APSCtransmission facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC). SERC is a nonprofit corporation responsible for determination.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 Bulk Electric System reliability standards within the SERC Region.
SourcesGas Property
As of CapitalDecember 31, 2020, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2020, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position.
Entergy Arkansas’s sourcesTitle
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 meet its capital requirements include: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.
internally generated funds;
cash on hand;
debt or preferred membership interest issuances;
capital contributions;Substantially all of the physical properties and
bank financing under new or existing facilities.
Entergy Arkansas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
All debt and common and preferred membership interest issuances assets owned by Entergy Arkansas, require prior regulatory approval. Debt issuancesEntergy 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 of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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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 2018-2020 were:
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| | | 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 |
| 2020 | | 47 | | | 1.92 | | | 29 | | | 0.57 | | | 3 | | | 2.54 | | | 8 | | | 4.36 | | | 13 | | | 2.48 | |
| 2019 | | 40 | | | 2.33 | | | 28 | | | 0.73 | | | 6 | | | 2.31 | | | 8 | | | 4.86 | | | 18 | | | 2.71 | |
| 2018 | | 39 | | | 2.84 | | | 27 | | | 0.84 | | | 9 | | | 2.24 | | | 8 | | | 5.23 | | | 17 | | | 3.71 | |
Actual 2020 and projected 2021 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:
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| | Natural Gas | | Nuclear | | Coal | | Purchased Power (d) | | MISO Purchases (e) |
| | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 |
| Entergy Arkansas (a) | 24 | % | | 35 | % | | 60 | % | | 51 | % | | 10 | % | | 13 | % | | 1 | % | | 1 | % | | 5 | % | | — | |
| Entergy Louisiana | 51 | % | | 59 | % | | 26 | % | | 27 | % | | 1 | % | | 2 | % | | 9 | % | | 12 | % | | 13 | % | | — | |
| Entergy Mississippi (b) | 73 | % | | 69 | % | | 14 | % | | 22 | % | | 4 | % | | 9 | % | | — | | | — | | | 9 | % | | — | |
| Entergy New Orleans (b) | 55 | % | | 56 | % | | 33 | % | | 40 | % | | 1 | % | | 2 | % | | 2 | % | | 2 | % | | 9 | % | | — | |
| Entergy Texas | 39 | % | | 60 | % | | 11 | % | | 13 | % | | 2 | % | | 6 | % | | 23 | % | | 21 | % | | 25 | % | | — | |
| System Energy (c) | — | | | — | | | 100 | % | | 100 | % | | — | | | — | | | — | | | — | | | — | | | — | |
| Utility (a) (b) | 47 | % | | 55 | % | | 29 | % | | 31 | % | | 3 | % | | 6 | % | | 8 | % | | 8 | % | | 13 | % | | — | |
(a)Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2020 and is expected to provide less than 1% of its generation in 2021.
(b)Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2020 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2021.
(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 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. The MISO purchases metric provided for 2020 is not projected for 2021.
Some of the Utility’s gas-fired plants are also subject to issuance tests set forthcapable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in Entergy Arkansas’s bond indentures2021, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.short-term interruptible gas contracts for both supply and transportation. Over 50% of the Utility operating companies’ power plants maintain some level of long-
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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 primarily tied to weather conditions as well as to the money pool wereprices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies 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 may in some instances use alternate fuels, such as follows as of December 31 for each of the following years.oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
|
| | | | | | |
| 2019 | | 2018 | | 2017 | | 2016 |
| (In Thousands) |
| $21,634 | | $182,738 | | $166,137 | | $51,232 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has committed to seven one- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2021. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 15% of total coal requirements will be satisfied by contracts with a credit facilityterm 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 2021. Coal will be transported to Arkansas via an existing transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2021.
Entergy Louisiana has committed to five one- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2021. 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 2021. Coal will be transported to Nelson primarily via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2021.
For the year 2020, coal transportation delivery rates to Entergy Arkansas-and Entergy Louisiana-operated coal-fired units were adequate to meet supply needs and obligations, and it is expected that delivery times in 2021 will continue to be consistent. Both Entergy Arkansas and Entergy 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 Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2021. Entergy 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, Entergy Arkansas, Entergy Louisiana, and System 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
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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.
Based upon currently planned fuel cycles, the Utility 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 or fixed prices through most of 2023. 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 Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the amountfinancial statements of $150 million scheduled to expire in September 2024. Entergy Arkansas also has a $20 millionand the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit facility scheduled to expire in April 2020. The $150 million credit facility includes fronting commitments foragreements and the issuance of lettersnotes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of credit against $5 millionnatural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with CenterPoint 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 CenterPoint 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.
Entergy Louisiana purchased natural gas for resale in 2020 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the borrowingimplementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy 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 facility. AsUtility
State or local regulatory authorities, as described above, regulate the retail rates of December 31, 2019, there were no cash borrowingsthe Utility operating companies. The FERC regulates wholesale sales of electricity rates and no lettersinterstate transmission of credit outstanding under the credit facilities. In addition,electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, is a partyEntergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2019, a $1 million letter of credit was outstanding under Entergy Arkansas’s uncommitted letter of credit facility.the Unit Power Sales Agreement. See Note 42 to the financial statements for further discussion of the credit facilities.federal regulation proceedings.
(Entergy Corporation, Entergy Arkansas, LLCEntergy Louisiana, Entergy Mississippi, Entergy New Orleans, and SubsidiariesEntergy Texas)
Management’s Financial Discussion and Analysis
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facilityPrior to each operating company’s termination of participation in the amountSystem 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 engaged in the coordinated planning, construction, and operation of $80 million scheduled to expire in September 2021. As of December 31, 2019, $15.1 million in loans were outstandinggenerating and bulk transmission facilities under the Entergy Arkansas nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for further discussionterms of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorization from the FERC through November 2020 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and 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 authorizedSystem Agreement, which was a rate schedule approved by the FERC. The APSC has concurrent jurisdiction over Entergy Arkansas’s first mortgage bond/secured issuances. Entergy Arkansas has obtained long-term financing authorization fromUnder the FERC that extends through November 2020. Entergy Arkansas has obtained first mortgage bond/secured financing authorization fromterms of the APSC that extends through December 2020.
StateSystem Agreement, generating capacity and Local Rate Regulation and Fuel-Cost Recovery
Retail Rates
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 madeother power resources were jointly operated 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 issuesUtility operating companies that were participating in the proceedingSystem Agreement. The System Agreement provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) would receive payments from those parties having generating reserves that were less than their allocated share of reserves (short companies). Such payments were at amounts sufficient to cover certain of the long companies’ costs for intermediate and providing for recovery of certain 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.
2018 Formula Rate Plan Filing
In July 2018, Entergy Arkansas filed with the APSC its 2018 formula rate plan filing to set its formula rate for the 2019 calendar year. The filing showed Entergy Arkansas’s projected earned returnpeaking oil/gas-fired generation, including operating expenses, fixed charges on commondebt, dividend requirements on preferred equity, for the twelve months ended December 31, 2019 test period to be below the formula rate plan bandwidth. Additionally, the filing includes the first netting adjustment under the current formula rate plan for the historical test year 2017, reflecting the change in formula rate plan revenues associated with actual 2017 results when compared to the allowed rate of return on equity. The filing includes a projected $73.4 millionrevenue deficiency for 2019 and a $95.6 million revenue deficiency for the 2017 historical test year, for a total revenue requirement of $169 million for this filing. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeds the constraint, the resulting increase is limited to four percent of total revenue, which originally was $65.4 million but was increased to $66.7 million based upon the APSC staff’s updated calculation of 2018 revenue. In October 2018, Entergy Arkansas and the parties to the proceeding filed joint motions to approve a partial settlement agreement as to certain factual issues and agreed to brief contested legal issues. In November 2018 the APSC held a hearing and was briefed on a certain contested legal issue. In December 2018 the APSC issued a decision related to the initial legal brief, approved the
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
partial settlement agreement and $66.7 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan, with updated rates going into effect for the first billing cycle of January 2019.
2019 Formula Rate Plan Filing
In July 2019, Entergy Arkansas filed with the APSC its 2019 formula rate plan filing to set its formula rate for the 2020 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2020 and a netting adjustment for the historical year 2018. The total proposed formula rate plan rider revenue change designed to produce a targetfair rate of return on common equity investment. Under the System Agreement, the rates used to compensate long companies were 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 were required to pay the cost of 9.75% is $15.3 million, which is based uponfuel consumed in generating such energy plus a deficiency of approximately $61.9 million forcharge to cover other associated costs.
Although the 2020 projected year, netted with a credit of approximately $46.6 million in the 2018 historical year netting adjustment. During 2018 Entergy Arkansas experienced higher-than expected sales volume, and actual costs were lower than forecasted. These changes, coupled with a reduced income tax rate resulting from the Tax Cuts and Jobs Act, resulted in the credit for the historical year netting adjustment. In the fourth quarter 2018 Entergy Arkansas recorded a provision of $35.1 million that reflected the estimate of the historical year netting adjustment that was expected to be included in the 2019 filing. In 2019, Entergy Arkansas recorded additional provisions totaling $11.5 million to reflect the updated estimate of the historical year netting adjustment included in the 2019 filing. In October 2019 other parties in the proceeding filed their errors and objections requesting certain adjustments to Entergy Arkansas’s filing that would reduce or eliminate Entergy Arkansas’s proposed revenue change. Entergy Arkansas filed its response addressing the requested adjustments in October 2019. In its response, Entergy Arkansas acceptedSystem Agreement has terminated, certain of the adjustments recommendedUtility operating companies’ and their retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. The proceedings include challenges to the allocation of costs as defined by the General StaffSystem 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
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did 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 MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and 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 markets. 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. 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
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establish transmission rates within MISO. The terms and conditions of the APSC that would reduceMISO tariff, including provisions related to the proposed formula rate plan rider revenue changedesign and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to $14 million. Entergy Arkansas disputed the remaining adjustments proposedregulation by the parties. In October 2019, Entergy Arkansas filed a unanimous settlement agreement with the other parties in the proceeding seeking APSC approval of a revised total formula rate plan rider revenue change of $10.1 million. In its July 2019 formula rate plan filing, Entergy Arkansas proposed to recover an $11.2 million regulatory asset, amortized over five years, associated with specificFERC.
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 potential construction of scrubbersUnit Power Sales Agreement (described below). In July 2001 a rate proceeding commenced by System Energy at the White Bluff plant. AlthoughFERC in 1995 became final, with the FERC approving a prospective 10.94% return on equity. In 1998 the FERC approved requests by Entergy Arkansas does not concede thatand 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 power obligations ceased effective July 2001 and July 2003, respectively, as approved by the regulatory asset lacks merit,FERC. See Note 2 to the financial statements for purposesdiscussion of reachingcomplaints filed with the FERC 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 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 on the total formula rate plan rider amount, Entergy Arkansas agreed not to include the White Bluff scrubber regulatory asset cost in the 2019 formula rate plan filing or future filings. Entergy Arkansas recorded a write-off in 2019 of the $11.2 million White Bluff scrubber regulatory asset. In December 2019, the APSC approved the settlement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2020.
Internal Restructuring
In November 2017, Entergy Arkansas filed an applicationagreement entered into with the APSC seeking authorizationin 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 undertakesell its retained share to third parties, it may sell such energy to its retail customers at a restructuringprice 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
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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 resultat 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 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 the transferevent 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 two outstanding series of first mortgage 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 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.
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Service Companies
Entergy Services, a limited liability company 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 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 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 Unit 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, 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 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. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses 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, 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 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 operationshas assumed the liabilities, of Old Entergy ArkansasLouisiana and Old Entergy Gulf States Louisiana.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 entity, which would ultimately be owned bysubsidiary, 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 existingaffiliate (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 holding company. of Entergy Utility Holding Company, LLC.
In July 2018, 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.
Entergy Arkansas filed a settlement, reached by all parties in the APSC proceeding, resolving all issues. The APSC approved the settlement agreement and restructuring in August 2018. Pursuant to the settlement agreement, Entergy Arkansas will credit retail customers $39.6 million over six years, beginning in 2019. Entergy Arkansas also received the required FERC and NRC approvals.Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated 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 assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas, Inc. contributed 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 is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Advanced Metering Infrastructure (AMI)Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light 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 Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
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-related services, to nuclear power plants owned by non-affiliated entities in the United States. 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.
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 operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
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 |
| Indian Point 3 (a) | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2025 (a) |
| Indian Point 2 (a) | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2024 (a) |
| Palisades (b) | | MISO | | 1971 | | Apr. 2007 | | Covert,
MI | | 811 MW - Pressurized Water | | 2031 (b) |
(a)Power operations ceased at the Indian Point 2 plant in April 2020. The fuel was permanently removed from the reactor vessel and placed in the spent fuel pool in May 2020. The Indian Point 3 plant is expected to cease operations on April 30, 2021. Entergy and Holtec jointly filed a license transfer application with the NRC in November 2019, requesting approval for the transfer of the Indian Point plants, along with their nuclear decommissioning trusts and decommissioning liabilities, from Entergy to Holtec. The NRC approved the license transfer application on November 23, 2020.
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(b)The Palisades plant is expected to cease operations on May 31, 2022. There is a contract to sell the plant to Holtec subject to NRC and other regulatory approvals.
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 operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
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. Both Big Rock Point and Indian Point 1 are under contract to be sold with their respective plants.
Non-nuclear Generating Stations
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) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| RS Cogen; 425 MW (c) | | Lake Charles, LA | | 50% | | 213 MW | | Gas/Steam |
| Nelson Unit 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 an interest in an unconsolidated joint venture. In December 2020, Entergy’s wholly-owned subsidiary with a direct interest in RS Cogen, LLC entered into a membership interest purchase agreement with a subsidiary of the other 50% equity partner to sell its 50% membership interest in the joint venture to the equity partner. The targeted closing date for the transaction is October 2022.
Independent System Operators
The 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 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. 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.See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 receives 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. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022 and transfer to Holtec thereafter.
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 Consumers Energy, the company from which Entergy purchased the Palisades plant, and NYISO and MISO. Substantially all the credit 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 NYISO market is highly competitive. Entergy Wholesale Commodities has numerous competitors in 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 York power market 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 most of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. Almost all of Palisades’ current output is contracted to Consumers Energy through May 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. When outdoor and cooling water temperatures are 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.
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,
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 plant owners. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment has been adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the Indian Point 3 and Palisades plants. Fuel procurement for the Entergy Wholesale Commodities segment was primarily limited to the requirements of the Palisades plant’s final refueling in 2020.
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 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. ENPM’s functions include origination of new energy and capacity transactions and generation scheduling.
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.
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Entergy provides plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.
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.
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 the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC 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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and conditions of service;
•service standards;
•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
•avoided cost payments to Qualifying Facilities;
•net energy metering;
•integrated resource planning;
•utility mergers and acquisitions and other changes of control; and
•the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory 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 retail ratemaking or other regulatory jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and purchase power contracts;
•procurement process to acquire over 50 MW;
•audits of the environmental adjustment charge, avoided cost payment to Qualifying Facilities, and energy efficiency rider;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
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, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other 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 the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects;
•utility service areas, including extensions into new areas;
•avoided cost payments to Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, 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 operators of Indian Point Energy Center, Palisades, and Big Rock Point.
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, 2020 of $192.0 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick, 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 Vermont Yankee spent fuel disposal contract was assigned to NorthStar as part of the sale of the plant in January 2019. The Pilgrim spent fuel disposal contract was transferred to Holtec as part of the sale of Entergy Nuclear Generation Company in August 2019. The owners of these plants previous to Entergy have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the 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. Specific steps were taken to discontinue the Yucca Mountain project, including 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. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the 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
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 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.
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. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2018, 2019, and 2020 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2020, Entergy’s subsidiaries won and collected on judgments against the government totaling approximately $800 million.
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 River Bend in 2005, at Grand Gulf in 2006, at Indian Point in 2008, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, 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. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. 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.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In October 2020, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and ANO 2 decommissioning trusts were adequately funded without further collections, and in December 2020, the APSC ordered zero collections for ANO 1 and ANO 2 decommissioning.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice.
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Entergy Corporation, Utility operating companies, and System Energy
In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal.
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 a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
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 January 2019, Entergy sold 100% of the membership interest in Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar. As a result of the sale, NorthStar assumed ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 9 to the financial statements for further discussion of Vermont Yankee decommissioning 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.
In August 2019, Entergy sold 100% of the equity interests in Entergy Nuclear Generation Company, LLC to a subsidiary of Holtec International. As a result of the sale, Holtec assumed ownership of Pilgrim and its decommissioning trust, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 14 to the financial statements for further discussion of the sale.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities 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. 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, which 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 transaction. See Note 14 to the financial statements for discussion of the FitzPatrick sale.
In March 2020 filings with the NRC were made reporting on decommissioning funding for all of Entergy subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the 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 16 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
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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 $137.6 million per reactor (with 97 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, 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.
NRC Reactor Oversight Process
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. The nuclear generating plants owned and operated by Entergy’s Utility and Entergy Wholesale Commodities businesses are currently in Column 1, except for Grand Gulf, which is currently in Column 2.
In November 2020 the NRC placed Grand Gulf in Column 2 based on the incidence of three unplanned plant scrams during the second and third quarters of 2020.Two of the scram events related to new turbine control system components that failed, and a third related to a feedwater valve positioner that failed, all of which had been replaced in a refueling outage that ended in May 2020. The NRC plans to conduct a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 2. As a consequence of two additional Grand Gulf scrams during the fourth quarter 2020, System Energy expects Grand Gulf to be placed into NRC Column 3 based on plant performance indicators for the four quarters ended December 31, 2020. This will involve an additional supplemental NRC inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 3.
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, 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, greenhouse gases, and significant modifications to existing facilities;
•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 permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
•New and existing source standards for greenhouse gas and other air 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. In December 2020 the EPA amended the NSR regulations to clarify when a physical change or change in the method of operation will constitute such a modification. Entergy has an established process for identifying modifications requiring additional permitting approval and is monitoring the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. Several years ago, however, the EPA implemented 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 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, including NSR requirements and air permits issued by the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ). In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 an additional request for similar information was received for the White Bluff facility. Entergy responded to all requests. None of these EPA requests for information alleged that the facilities were in violation of law.
In January 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. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims as well as other issues facing Entergy Arkansas’s fossil generation plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. In October 2019 the District Court requested supplemental briefing on several issues to be resolved prior to addressing the motion to approve the
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settlement; that briefing was completed in May 2020. For further information about the settlement, see “Regional Haze” discussed below.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is 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.
Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for construction and operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. 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 December 2020 the EPA designated East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. Challenges to these final designations must be filed within 60 days of publication in the Federal Register. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. Entergy will continue to monitor this situation.
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.
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Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions. In September 2016 the EPA finalized the CSAPR Update Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 the final rule requires reductions in summer nitrogen oxides (NOx) emissions. Several states, including Arkansas and Texas, filed a challenge to the Update Rule. In September 2019 the D.C. Circuit upheld the EPA’s underlying approach to the Update Rule, but determined that it was inconsistent with the Clean Air Act because it failed to include deadlines consistent with downwind states’ deadlines for attainment. The court remanded the rule to the EPA for further consideration, but did not vacate so the rule remains in effect pending the EPA’s further review. In October 2020 the EPA issued its proposal intended to address the D.C. Circuit’s remand. The draft rule proposes to finalize interstate transport obligations for 21 states. For nine states, including Arkansas, Mississippi, and Texas, the EPA proposes that additional emission reductions are not necessary. For 12 states, however, including Louisiana, the EPA proposes additional emission reductions through proposed reductions in the number of NOx emission allowances allocated to each state. Entergy, through its various trade associations, filed comments on the proposal and will continue to monitor the rulemaking and its potential impact on its facilities in Louisiana. If the October 2020 proposal is finalized, ozone season NOx emissions may become more expensive in Louisiana.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could 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 Energy and Environment, Division of Environmental Quality (ADEQ) prepared a state implementation plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. In April 2012 the EPA finalized a decision addressing the Arkansas Regional Haze SIP, in which it disapproved a large portion of the Arkansas 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 granted the stay pending settlement discussions and pending the State’s development of a SIP that, if approved by the EPA, would replace the FIP. The state had 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. The Part I SIP requires that Entergy address NOx impacts on visibility via compliance with the Cross-State Air Pollution Rule ozone-season emission trading program. Arkansas has finalized a Part II SIP which has been approved by the EPA but is currently pending a state court appeal. That appeal has been stayed pending the outcome of a federal court case, which may resolve many of the issues on appeal. The final Part II SIP requires that Entergy achieve SO2 emission reductions via the use of low-sulfur coal at both White Bluff and Independence within three years. The
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Part II SIP also requires that Entergy cease to use coal at White Bluff by December 31, 2028 and notes the current planning assumption that Entergy’s Independence units will cease to use coal by December 31, 2030.
In January 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. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement and in many cases also the Part II SIP, Entergy Arkansas, along with co-owners, will begin using only low-sulfur coal at Independence and White Bluff by mid-2021; cease to use coal at White Bluff and Independence by the end of 2028 and 2030, respectively; cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserve the option to develop new generating sources at each plant site; and commit to install or propose to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waive certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. The EPA, which is allowed to comment on such a settlement agreement, has stated that it has no objections to the settlement. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. Still pending before the court is a motion by the plaintiffs to approve the settlement, in support of which Entergy made a filing. The Arkansas Attorney General also filed an application before the APSC in December 2018 seeking an investigation into the effects of the settlement. The Arkansas Affordable Energy Coalition filed to support the Arkansas Attorney General’s application, and Entergy Arkansas filed ana motion to dismiss it. The application seekingremains pending before the APSC. In October 2019 the District Court requested supplemental briefing on several issues prior to addressing the motion to approve the settlement; that briefing concluded in May 2020.
In Louisiana, Entergy has worked with the Louisiana Department of Environmental Quality (LDEQ) and the EPA to revise the Louisiana SIP for regional haze, which had been disapproved in part in 2012. The LDEQ submitted a finding fromrevised SIP in February 2017. In May 2017 the APSC that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy ArkansasEPA 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 of January 22, 2021. The EPA issued final approval in December 2017. The EPA approval was appealed to the U.S. Court of Appeals for the Fifth Circuit. In October 2019 the Fifth Circuit affirmed the EPA’s SIP approval. A petition for rehearing filed by plaintiffs was denied by the Fifth Circuit. Plaintiffs did not petition for further review by the Supreme Court.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by 2021. Entergy received information collection requests from Arkansas and Louisiana requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, and Ninemile. Responses to the information requests have been submitted to the respective state agencies.
New and Existing Source Performance Standards for Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established
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national emissions performance rates for existing meters with advanced metersfossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests and will continue to monitor litigation challenging the rule. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that enable two-way data communication; designACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and buildgenerating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. The vacatur will not be effective until the court issues its mandate which is being held until after disposition of any petitions for rehearing. Entergy is currently reviewing the court’s opinion.
In 2018 the EPA proposed a securerevision to the new source performance standard on greenhouse gas emissions that primarily impacts new coal units and, reliable networktherefore, should not impact Entergy. In January 2021 the EPA finalized a pollutant-specific contribution finding for greenhouse gas emissions from new, modified, and reconstructed electric generating units. The rule establishes a three percent threshold for determining when a pollutant significantly contributes to support such communications;air pollution and implement support systems. AMI is intendedreaffirms the EPA’s position that the Clean Air Act Section 111(b) requires the EPA to serve asmake pollutant-specific significant contribution findings before promulgation of a new source performance standard. The EPA did not, however, finalize the foundation of Entergy Arkansas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $208 millionnew source performance standard on greenhouse gas emissions and identifiedintends to address the 2018 proposal in a future action.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of quantifiedlegislative and unquantified benefits. 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;
•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 federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and 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 local, state, and federal level to codify renewable portfolio standards, clean energy standards, 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;
•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 polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance risk;
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•the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds;
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in an economy-wide, responsible, and flexible manner. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020. In 2020, Entergy succeeded in achieving its initial climate commitment to reduce carbon dioxide cumulative emissions by 20% from 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 39.1 million tons in 2020 and 40.7 million tons in 2019. Since its original commitment in 2001, Entergy’s cumulative emissions are approximately 7.6% below its 2020 goal.
Entergy voluntarily conducted a climate scenario analysis and published a comprehensive report in March 2019. The report follows the framework and recommendations of the Task Force on Climate-related Disclosures, describing climate-related governance, strategy, risk management, and metrics and targets. Scenario analyses resulted in Entergy developing and publishing a new goal of reducing the Utility’s emission rate by 50 percent from 2000 levels by 2030. In September 2020, Entergy committed to achieving net-zero carbon emissions by 2050, while continuing its commitment to grid reliability and affordability for customers. In December 2020, Entergy published a report regarding this long-term commitment that describes its approach and technology point-of-view. Technology research and development, innovation, and advancement are critical to Entergy’s ability to meet this climate commitment.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s annual greenhouse gas emissions inventory is also third-party verified, and that certification is made available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 2020 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for nineteen consecutive years. Entergy also participated in the 2020 CDP and CDP Water evaluations, receiving a ‘B’ for both responses.
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 permit program, section 402, 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.
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Steam Electric Effluent Guidelines
The 2015 Steam Electric Effluent Limitations Guidelines (ELG) rule required, among other things, that there be no discharge of bottom ash transport water. In October 2020 the EPA issued its final rule revision on bottom ash transport water allowing the discharge of up to 10% system volume for certain purge waters, including storm events and non-routine operations. The final rule requires compliance as soon as possible beginning October 31, 2021, but no later than December 31, 2025. Several challenges to the final rule have been filed. Additionally, the Fifth Circuit Court of Appeals previously vacated and remanded the provisions of the rule related to legacy wastewater and leachate, which the EPA plans to address in a separate rulemaking. Despite the final rule and pending challenges, Entergy is implementing projects at its White Bluff and Independence plants to convert to zero-discharge systems to comply with the ELG rule and the coal combustion residuals restrictions on impoundments. Additionally, the Nelson Unit 6 facility is implementing operational and maintenance measures to minimize the potential for discharge of bottom ash transport water from the existing bottom ash handling system at the site, and is reviewing the effectiveness of these changes for compliance with the requirements of the October 2020 final rule.
Federal Jurisdiction of Waters of the United States
In February 2019 the EPA published its proposed revised definition of Waters of the United States, which proposes to narrow the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. The final rule was released in January 2020 and effective in June 2020. In October 2019 the EPA repealed the 2015 rule and re-codified the pre-existing regulations. That rule was effective late December 2019. Numerous challenges have been filed against both rules.
Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to 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, Indian Point, Palisades, Grand Gulf, 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.
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
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. 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 such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental 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 Resource Conservation and Recovery Act (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 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, 2020, Entergy has recorded asset retirement obligations related to CCR management of $20.1 million.
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 program.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. 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. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of one of its two recycle ponds, with the remaining pond being held in reserve during initial operation of the new bottom ash handling system. Closure of the remaining recycle pond at each site will commence as soon as possible, but no later than April 11, 2021, which is the deadline under the finalized CCR rule to commence closure of any unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Other Environmental Matters
Entergy Louisiana and Entergy Texas
Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, currently is 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 routed to a portion of the property for disposal. The same area also has 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. Removal actions addressed contaminated source material, soil, and sediment and included capping certain soil on and off-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. The EPA released the second Five Year Review in 2015. In that review, the EPA indicated that the remediation technique was insufficient and that Entergy would need to utilize other remediation technologies on the site. In July 2015, Entergy submitted a Focused Feasibility Study to the EPA outlining the potential remedies and suggesting installation of the new remedial method, a waterloo barrier. The estimated cost for this remedy is approximately $2 million, to be allocated between Entergy Louisiana and Entergy Texas. In early 2017 the EPA indicated that the waterloo barrier may not be necessary and requested revisions to the Focused Feasibility Study. The EPA released the third Five Year Review in late-2019 confirming that a new remedial method is not necessary but requiring continuation of the current groundwater monitoring. The site’s remedy includes monitored natural attenuation of groundwater, and institutional controls to restrict groundwater and land use. The EPA has determined that no additional actions are needed for the remedy to be protective over the long-term, and the remedy is protective of human health and the environment.
Entergy Arkansas, proposedEntergy Louisiana, Entergy New Orleans, and Entergy Texas
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, 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 15-year depreciable lifetransformer repair and scrapping facility from the 1930s until 2003. Both soil and groundwater contamination existed at the site. Entergy subsidiaries sent transformers to this facility. Entergy Arkansas, Entergy Louisiana, and Entergy Texas responded to an information request from the TCEQ. Entergy Louisiana and Entergy Texas 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 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. Current estimates, although variable depending on ultimate remediation design and performance, indicate that Entergy’s total share of remediation costs likely will be approximately $1.5 million to $2 million. Groundwater monitoring wells at the site were plugged and abandoned in December 2019 following receipt of a certificate of completion issued by the TCEQ. Site decommissioning activities are complete and final disposition of the property will be determined at a later time.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
letter seeking reimbursement for response costs totaling $4 million expended at the site. The demand letter is being evaluated and liability and PRP allocation of response costs are yet to be determined.
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 TCEQ and the National Response Center were immediately notified, and the 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, Entergy entered into the Voluntary Cleanup Program with the TCEQ. In November 2017, additional soil sampling was completed in the wetland area and, in February 2018, a site summary report of findings was submitted to the TCEQ. The TCEQ responded in June 2018 and requested an ecological exclusion criteria checklist/Tier II screening-level ecological risk assessment, and additional site assessment, additional soil samples, groundwater samples, and some additional diagrams and maps. In October 2018, Entergy submitted the requested information to the TCEQ. In January 2019 the TCEQ responded with another request for information. In March 2019, Entergy submitted the requested information to the TCEQ. In August 2019 the TCEQ responded with a request for additional information including an Affected Property Assessment Report (APAR) and water well survey. The TCEQ has agreed that the necessity of the water well survey is dependent on the results of the groundwater resampling that will occur. Groundwater sampling was completed in December 2019 and results were submitted to the TCEQ for review. Based on the groundwater sampling results, the TCEQ confirmed in February 2020 that a water well survey is not necessary and requested the APAR and an Ecological Risk Assessment by August 2020. Due to COVID-19 delays, the TCEQ extended the APAR and Ecological Risk Assessment submittal dates to December 2020, which Entergy timely met.
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.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, 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
Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2020, Entergy subsidiaries employed 13,400 people.
| | | | | |
| Utility: | |
| Entergy Arkansas | 1,244 | |
| Entergy Louisiana | 1,654 | |
| Entergy Mississippi | 750 | |
| Entergy New Orleans | 303 | |
| Entergy Texas | 658 | |
| System Energy | — | |
| Entergy Operations | 3,529 | |
| Entergy Services | 3,859 | |
| Entergy Nuclear Operations | 1,356 | |
| Other subsidiaries | 47 | |
| Total Entergy | 13,400 | |
Approximately 3,900 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, and Fire Professionals of America.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
| Gender (%) | 2020 | | 2019 |
| Female | 21 | | 20 |
| Male | 79 | | 80 |
| 100 | | 100 |
| | | | | | | | | | | |
| Race/Ethnicity (%) | 2020 | | 2019 |
| White | 78 | | 79 |
| Black/African American | 15 | | 15 |
| Hispanic/Latino | 3 | | 2 |
| Asian | 2 | | 2 |
| Other | 2 | | 2 |
| 100 | | 100 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion and belonging; and talent management.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Personnel Committee establishes priorities and reviews performance on a range of topics. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development and succession plans to align a high performing executive team with Entergy’s priorities. The Personnel Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on ethics and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. While the COVID-19 pandemic and historical hurricane season presented significant challenges, Entergy’s safety strategy and commitment to excellence showed results in 2020. Entergy employees achieved a total recordable incident rate of 0.40 in 2020 compared to 0.56 in 2019 and 0.48 in 2018. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases. This marked improvement in total recordable incident rate placed Entergy in top-decile in safety performance when benchmarked amongst peers within the Edison Electric Institute.
Organizational Health, including Diversity, Inclusion and Belonging
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (near top quartile). In addition to significantly improved scores, initial employee participation of 66 percent in 2014 rose to and remains at 90 percent in 2018-2020.
Entergy believes that a culture focused on diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. Among other actions, the primary focus of its 2020 actions was taking a stand against social injustice, reinforcing expectations, training and leading by example, starting at the top of the organization and cascading through management ranks.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the future, and reflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the new advanced meters,future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.
Availability of SEC filings and other information on Entergy’s website
Entergy electronically files reports with the three-year deploymentSEC, 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 SEC 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. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
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 annual and quarterly reports on Forms 10-K and 10-Q (including related filings in Inline XBRL format) and current reports on Form 8-K; 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 internet 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
See “RISK FACTOR SUMMARY” in Part I Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ 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 Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
In December 2019 a novel strain of coronavirus was reported to have surfaced in Wuhan, China. Since then, COVID-19 has spread throughout most countries in the world, including the United States. Public health officials in the United States have both recommended and mandated wearing of masks, precautions to mitigate the spread of COVID-19, including prohibitions on congregating in heavily-populated areas, mandated closure or limitations on the functions of non-essential business, and shelter-in-place orders or similar measures, including throughout Entergy’s service areas. While some of these mitigation measures have been lifted, it is unclear how long certain forms of mitigation measures will remain in place, whether they will be reinstated in the future, and how they will ultimately impact the general economy, Entergy’s customers, and its operations.
Entergy and its Utility operating companies have experienced a decline in commercial and industrial sales and an increase in arrearages and bad debt expense due to non-payment by customers, and expect such reduced levels of sales and increased arrearages and bad debt expense to continue, the extent and duration of which beganmanagement cannot predict. The Utility operating companies temporarily suspended disconnecting customers for non-payment of bills, and the suspension remains in January 2019. Deploymentplace at Entergy Arkansas, has been re-instituted at Entergy New Orleans, and could be re-instituted at the other Utility operating companies should their regulators mandate. While they are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is unknown. Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges, supply chain, vendor, and contractor disruptions; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed outages; delays in regulatory proceedings; workforce availability, health or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees telecommuting; increased late or uncollectible customer payments; volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and initiatives.
A sustained or further economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the communications network beganCOVID-19 pandemic on their customers. In addition, if the COVID-19 pandemic continues to create disruptions or turmoil in 2018. the credit or financial markets, or adversely impacts Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its
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liquidity needs, or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the outbreak, the impact of new variants of COVID-19, the timing, availability, distribution or effectiveness of a vaccine, anti-viral or other treatments for COVID-19, governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
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 can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. 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, including adjustment upon the initiative of a regulator or affected stakeholders.
In October 2017addition, regulators may initiate proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s 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 may 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. Traditional 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 these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and the Utility operating companies may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation of their assets and infrastructure or the quality of their service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements.
The base rates of Entergy Texas are established largely in traditional base rate case proceedings.Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs.These riders include a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment and certain non-fuel MISO charges, a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a generation cost recovery rider mechanism for the recovery of generation-related capital investments, and a fixed fuel factor mechanism for the recovery of MISO fuel and energy-related costs.Entergy Texas also is required to make a filing every three years,
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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 necessary and reasonable, and makes a prudence finding for each of the fuel-related contracts for the reconciliation period.Entergy Texas also is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Between base rate cases, Entergy Arkansas and Entergy Mississippi 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 issuedapproved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an order finding thatinitial five-year term.The initial five-year term expires in 2021. Entergy Arkansas has requested APSC approval of the extension of the formula rate plan tariff for an additional five years through 2026.If Entergy Arkansas’s AMI deployment is informula rate plan were terminated or not extended beyond the public interest and approving the settlement agreement subject to a minor modification.initial term, Entergy Arkansas could file an 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 recoveringterminated, it would revert to the AMI deploymentmore 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 plan was most recently extended through the test year 2019; certain modifications were made in that extension, including a decrease to the allowed return on equity and the quantified benefits throughaddition of a transmission cost recovery mechanism.The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC and as noted, for certain transmission investment, among other items.MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause.Entergy Louisiana has a pending request to extend its formula rate plan.plan with certain modifications, including implementation of a distribution investment recovery mechanism and use of end of period rate base.In the event that the electric formula rate plan is not renewed or extended, Entergy Arkansas will recoverLouisiana would revert to the undepreciated balance of its existing meters throughmore traditional rate case environment.
Entergy New Orleans previously operated under a regulatory asset to be amortized over 15 years, asformula rate plan that ended with the 2011 test year.Based on a settlement agreement approved by the APSC.City Council, with limited exceptions, the base rates of Entergy New Orleans were frozen until rates were implemented in connection with the base rate case filed by Entergy New Orleans in 2018.In November 2019 the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019.The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes.In November 2020 the City Council issued a resolution approving a settlement of the 2018 rate case.As part of this settlement, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle.See Note 2 to the financial statements for further discussion.
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 has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the
Part I Item 1A & 1B
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reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate request for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. System Energy has received FERC acceptance for billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
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 the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales could put upward pressure on rates, resulting in adverse regulatory actions to mitigate such effects on rates. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
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 or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may 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 and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
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.
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Entergy Corporation, Utility operating companies, and System Energy
There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
The Utility operating companies historically 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 had been approved by the FERC. The System Agreement terminated in its entirety on August 31, 2016.
There 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 existence. In the absence 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 few outstanding System Agreement proceedings at the FERC and at the D.C. Circuit that may require future adjustments, including challenges to the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
For further information regarding the regulatory proceedings relating to the System Agreement, see Note 2 to the 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. 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 capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or the cost of serving the Utility operating companies’ respective loads, and MISO market rules may change in ways that cause additional risk.
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. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from transmission projects of others, 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, the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits 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, or generally allow the retail regulator to direct the making of such 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 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 (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta), or the impact on customer bills of permitted storm cost recovery, could have material effects on Entergy and its Utility operating companies.
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. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills.
In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, 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
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity 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 owned or contractually controlled 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.
Certain of the Utility operating companies and System Energy 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.
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. Plant maintenance and upgrades are often scheduled during such planned outages, which typically extends the planned outage duration. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks 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 2020 and beyond. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium 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 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 and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, or shifting trade arrangements between countries. 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 changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
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 international sanctions or tariffs could further restrict the ability of such
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
suppliers to continue to supply fuel or provide such services at acceptable prices or at all. 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 and System Energy.
Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, suspend 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, 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 nuclear facilities. 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.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate 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 the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities.
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 increased costs, some of which costs may not be fully recoverable by the Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. 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
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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, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture 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 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 NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are 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 will 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 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 Louisiana, and System Energy and Note 8 to the financial statements.
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, which is referred to as Secondary Financial Protection, up to approximately $137.6 million per reactor. With 97 reactors currently
Part I Item 1A & 1B
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participating, this translates to a total public liability cap of approximately $14 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, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the 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 primary insurance level, up to a maximum of approximately $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.101 billion). The retrospective premium payment is currently limited to approximately $21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $137.6 million cap.
NEIL is a utility industry mutual insurance company, owned by its 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 NEIL surplus (reserve) be significantly depleted due toinsured losses. As of December 31, 2020, the maximum annual assessment amounts total $104 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential 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.
The 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 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. 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.
Under NRC regulations, nuclear plant owners 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 nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments 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.
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, or accelerate the timing for funding of, the obligations related to the decommissioning of the Utility operating companies, System Energy, or Entergy Wholesale Commodities nuclear power plants or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. 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, the impairment charges that resulted from such decision, and the planned sales of Palisades and Indian Point Energy Center (which, in each case, will include the transfer of the associated decommissioning trusts), 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.
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. These concerns have led to, and may 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 might lead to the shutdown of nuclear units, 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 and financial condition.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation)
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. 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, 2020, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 98% in 2021 and 99% in 2022 of its generation portfolio’s planned energy output, reflecting the planned shutdown and sale of the remaining 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.
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.
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.
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 “Market and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the closure (or sale) of its nuclear plants, Entergy Wholesale Commodities may enter into fewer forward sales contracts for output from such plants.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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. 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 $1.29 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. 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 is subject to changes as a result of restructuring initiatives at both the state and federal levels. 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, 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, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other 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 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 remaining assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure and sale of its nuclear power plants. Moreover, prior to the closure and 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, or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
If Entergy concludes that any of its nuclear power plants is unlikely to operate through its planned shutdown date, which conclusion would be based on a variety of factors, such a conclusion could result in a 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 remaining 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 - Impairment of Long-lived Assets” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
Production Cost Allocation Rider
Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.
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 historically hedged 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 was 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, which was approved in November 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.
Retail Rates - Gas
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 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
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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 the upper end of the earnings band 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 LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.
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 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.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power 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.
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.
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Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
Formula Rate Plan
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 was still appropriate or could 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 proceeding. In March 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. 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.
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.
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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Energy Efficiency Programs
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 and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. 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. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
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 Reliability Corporation (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
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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.
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.
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.
The PUCT determined that unrecovered costs that may 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 amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
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.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
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 Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in 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 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.
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Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city 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 over the period 2020-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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, 2020, is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,175 | | | 2,091 | | | 1,817 | | | 1,194 | | | 73 | | | — | |
| Entergy Louisiana | | 11,317 | | | 8,827 | | | 2,144 | | | 346 | | | — | | | — | |
| Entergy Mississippi | | 3,347 | | | 2,929 | | | — | | | 416 | | | — | | | 2 | |
| Entergy New Orleans | | 665 | | | 638 | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 2,260 | | | 2,005 | | | — | | | 255 | | | — | | | — | |
| System Energy | | 1,256 | | | — | | | 1,256 | | | — | | | — | | | — | |
| Total | | 24,020 | | | 16,490 | | | 5,217 | | | 2,211 | | | 73 | | | 29 | |
(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 21,591 MW over the previous decade.
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, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation 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 8,801 MW of new long-term resources and the deactivation of about 4,664 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.
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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 MISO reliability requirements as well as long-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:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•In October 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the facility is scheduled to be in service by early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020 and the facility is scheduled to be in service by the end of 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility.The facility was placed in service in December 2020;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas.In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals.Closing is expected to occur by the end of 2023.
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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’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s 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);
•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 Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf 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 petroleum 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, 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 10-year agreement 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;
•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;
•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 approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 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 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 received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
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•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas.The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP was seeking 300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
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; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; 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); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility is an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, owned by East Texas Electric Cooperative. Entergy Texas is currently seeking regulatory certification to move forward with the purchase of the facility. The facility has been in operation since January 2010.
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Power Through Program
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation that is to be installed at commercial and industrial customer premises. If approved, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.”
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-electric production facilities, combustion-turbine generators, pressurized and boiling water nuclear reactors, and inverter-based technologies operating in the MISO energy and ancillary services market. 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 facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of 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 Bulk Electric System reliability standards within the SERC Region.
Gas Property
As of December 31, 2020, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2020, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy 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 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 of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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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 2018-2020 were:
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| | | 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 |
| 2020 | | 47 | | | 1.92 | | | 29 | | | 0.57 | | | 3 | | | 2.54 | | | 8 | | | 4.36 | | | 13 | | | 2.48 | |
| 2019 | | 40 | | | 2.33 | | | 28 | | | 0.73 | | | 6 | | | 2.31 | | | 8 | | | 4.86 | | | 18 | | | 2.71 | |
| 2018 | | 39 | | | 2.84 | | | 27 | | | 0.84 | | | 9 | | | 2.24 | | | 8 | | | 5.23 | | | 17 | | | 3.71 | |
Actual 2020 and projected 2021 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:
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| | Natural Gas | | Nuclear | | Coal | | Purchased Power (d) | | MISO Purchases (e) |
| | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 |
| Entergy Arkansas (a) | 24 | % | | 35 | % | | 60 | % | | 51 | % | | 10 | % | | 13 | % | | 1 | % | | 1 | % | | 5 | % | | — | |
| Entergy Louisiana | 51 | % | | 59 | % | | 26 | % | | 27 | % | | 1 | % | | 2 | % | | 9 | % | | 12 | % | | 13 | % | | — | |
| Entergy Mississippi (b) | 73 | % | | 69 | % | | 14 | % | | 22 | % | | 4 | % | | 9 | % | | — | | | — | | | 9 | % | | — | |
| Entergy New Orleans (b) | 55 | % | | 56 | % | | 33 | % | | 40 | % | | 1 | % | | 2 | % | | 2 | % | | 2 | % | | 9 | % | | — | |
| Entergy Texas | 39 | % | | 60 | % | | 11 | % | | 13 | % | | 2 | % | | 6 | % | | 23 | % | | 21 | % | | 25 | % | | — | |
| System Energy (c) | — | | | — | | | 100 | % | | 100 | % | | — | | | — | | | — | | | — | | | — | | | — | |
| Utility (a) (b) | 47 | % | | 55 | % | | 29 | % | | 31 | % | | 3 | % | | 6 | % | | 8 | % | | 8 | % | | 13 | % | | — | |
(a)Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2020 and is expected to provide less than 1% of its generation in 2021.
(b)Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2020 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2021.
(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 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. The MISO purchases metric provided for 2020 is not projected for 2021.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2021, it is possible that various operational events including weather or pipeline maintenance may require the 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. Over 50% of the Utility operating companies’ power plants maintain some level of long-
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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 primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies 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 may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to seven one- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2021. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 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 2021. Coal will be transported to Arkansas via an existing transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2021.
Entergy Louisiana has committed to five one- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2021. 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 2021. Coal will be transported to Nelson primarily via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2021.
For the year 2020, coal transportation delivery rates to Entergy Arkansas-and Entergy Louisiana-operated coal-fired units were adequate to meet supply needs and obligations, and it is expected that delivery times in 2021 will continue to be consistent. Both Entergy Arkansas and Entergy 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 Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2021. Entergy 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, Entergy Arkansas, Entergy Louisiana, and System 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
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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.
Based upon currently planned fuel cycles, the Utility 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 or fixed prices through most of 2023. 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 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 seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with CenterPoint 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 CenterPoint 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.
Entergy Louisiana purchased natural gas for resale in 2020 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy 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 and interstate transmission of electricity, including 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.
System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
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 engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which was a rate schedule approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources were jointly operated by the Utility operating companies that were participating in the System Agreement. The System Agreement provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) would receive payments from those parties having generating reserves that were less than their allocated share of reserves (short companies). Such payments were 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 were 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 were required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
Although the System Agreement has terminated, certain of the Utility operating companies’ and their retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. The proceedings include challenges to the 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
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did 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 MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and 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 markets. 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. 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
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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 July 2001 a rate proceeding commenced by System Energy at the FERC in 1995 became final, with the FERC approving a prospective 10.94% return on equity. 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 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 complaints filed with the FERC 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 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
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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 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 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 two outstanding series of first mortgage 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 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.
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Service Companies
Entergy Services, a limited liability company 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 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 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 Unit 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, 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 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. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses 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, 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 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.
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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.
Entergy Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated 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 assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed 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 is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
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•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light 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 Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
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-related services, to nuclear power plants owned by non-affiliated entities in the United States. 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.
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 operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
Property
Nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:
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| Power Plant | | Market | | In Service Year | | Acquired | | Location | | Capacity - Reactor Type | | License Expiration Date |
| Indian Point 3 (a) | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2025 (a) |
| Indian Point 2 (a) | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2024 (a) |
| Palisades (b) | | MISO | | 1971 | | Apr. 2007 | | Covert,
MI | | 811 MW - Pressurized Water | | 2031 (b) |
(a)Power operations ceased at the Indian Point 2 plant in April 2020. The fuel was permanently removed from the reactor vessel and placed in the spent fuel pool in May 2020. The Indian Point 3 plant is expected to cease operations on April 30, 2021. Entergy and Holtec jointly filed a license transfer application with the NRC in November 2019, requesting approval for the transfer of the Indian Point plants, along with their nuclear decommissioning trusts and decommissioning liabilities, from Entergy to Holtec. The NRC approved the license transfer application on November 23, 2020.
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(b)The Palisades plant is expected to cease operations on May 31, 2022. There is a contract to sell the plant to Holtec subject to NRC and other regulatory approvals.
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 operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
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. Both Big Rock Point and Indian Point 1 are under contract to be sold with their respective plants.
Non-nuclear Generating Stations
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) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| RS Cogen; 425 MW (c) | | Lake Charles, LA | | 50% | | 213 MW | | Gas/Steam |
| Nelson Unit 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 an interest in an unconsolidated joint venture. In December 2020, Entergy’s wholly-owned subsidiary with a direct interest in RS Cogen, LLC entered into a membership interest purchase agreement with a subsidiary of the other 50% equity partner to sell its 50% membership interest in the joint venture to the equity partner. The targeted closing date for the transaction is October 2022.
Independent System Operators
The 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 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. 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.See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.
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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 receives 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. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022 and transfer to Holtec thereafter.
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 Consumers Energy, the company from which Entergy purchased the Palisades plant, and NYISO and MISO. Substantially all the credit 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 NYISO market is highly competitive. Entergy Wholesale Commodities has numerous competitors in 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 York power market 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 most of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. Almost all of Palisades’ current output is contracted to Consumers Energy through May 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. When outdoor and cooling water temperatures are 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.
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,
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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 plant owners. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment has been adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the Indian Point 3 and Palisades plants. Fuel procurement for the Entergy Wholesale Commodities segment was primarily limited to the requirements of the Palisades plant’s final refueling in 2020.
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 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. ENPM’s functions include origination of new energy and capacity transactions and generation scheduling.
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.
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Entergy provides plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.
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.
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 the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC 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 as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and conditions of service;
•service standards;
•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
•avoided cost payments to Qualifying Facilities;
•net energy metering;
•integrated resource planning;
•utility mergers and acquisitions and other changes of control; and
•the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory 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 retail ratemaking or other regulatory jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and purchase power contracts;
•procurement process to acquire over 50 MW;
•audits of the environmental adjustment charge, avoided cost payment to Qualifying Facilities, and energy efficiency rider;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
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•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
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, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other 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 the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects;
•utility service areas, including extensions into new areas;
•avoided cost payments to Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
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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 civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, 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 operators of Indian Point Energy Center, Palisades, and Big Rock Point.
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, 2020 of $192.0 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick, 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 Vermont Yankee spent fuel disposal contract was assigned to NorthStar as part of the sale of the plant in January 2019. The Pilgrim spent fuel disposal contract was transferred to Holtec as part of the sale of Entergy Nuclear Generation Company in August 2019. The owners of these plants previous to Entergy have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the 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. Specific steps were taken to discontinue the Yucca Mountain project, including 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. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the 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
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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 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.
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. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2018, 2019, and 2020 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2020, Entergy’s subsidiaries won and collected on judgments against the government totaling approximately $800 million.
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 River Bend in 2005, at Grand Gulf in 2006, at Indian Point in 2008, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, 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. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. 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.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In October 2020, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and ANO 2 decommissioning trusts were adequately funded without further collections, and in December 2020, the APSC ordered zero collections for ANO 1 and ANO 2 decommissioning.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice.
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In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal.
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 a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
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 January 2019, Entergy sold 100% of the membership interest in Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar. As a result of the sale, NorthStar assumed ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 9 to the financial statements for further discussion of Vermont Yankee decommissioning 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.
In August 2019, Entergy sold 100% of the equity interests in Entergy Nuclear Generation Company, LLC to a subsidiary of Holtec International. As a result of the sale, Holtec assumed ownership of Pilgrim and its decommissioning trust, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 14 to the financial statements for further discussion of the sale.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities 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. 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, which 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 transaction. See Note 14 to the financial statements for discussion of the FitzPatrick sale.
In March 2020 filings with the NRC were made reporting on decommissioning funding for all of Entergy subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the 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 16 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
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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 $137.6 million per reactor (with 97 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, 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.
NRC Reactor Oversight Process
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. The nuclear generating plants owned and operated by Entergy’s Utility and Entergy Wholesale Commodities businesses are currently in Column 1, except for Grand Gulf, which is currently in Column 2.
In November 2020 the NRC placed Grand Gulf in Column 2 based on the incidence of three unplanned plant scrams during the second and third quarters of 2020.Two of the scram events related to new turbine control system components that failed, and a third related to a feedwater valve positioner that failed, all of which had been replaced in a refueling outage that ended in May 2020. The NRC plans to conduct a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 2. As a consequence of two additional Grand Gulf scrams during the fourth quarter 2020, System Energy expects Grand Gulf to be placed into NRC Column 3 based on plant performance indicators for the four quarters ended December 31, 2020. This will involve an additional supplemental NRC inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 3.
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, 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, greenhouse gases, and significant modifications to existing facilities;
•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 permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
•New and existing source standards for greenhouse gas and other air 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. In December 2020 the EPA amended the NSR regulations to clarify when a physical change or change in the method of operation will constitute such a modification. Entergy has an established process for identifying modifications requiring additional permitting approval and is monitoring the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. Several years ago, however, the EPA implemented 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 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, including NSR requirements and air permits issued by the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ). In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 an additional request for similar information was received for the White Bluff facility. Entergy responded to all requests. None of these EPA requests for information alleged that the facilities were in violation of law.
In January 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. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims as well as other issues facing Entergy Arkansas’s fossil generation plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. In October 2019 the District Court requested supplemental briefing on several issues to be resolved prior to addressing the motion to approve the
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settlement; that briefing was completed in May 2020. For further information about the settlement, see “Regional Haze” discussed below.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is 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.
Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for construction and operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. 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 December 2020 the EPA designated East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. Challenges to these final designations must be filed within 60 days of publication in the Federal Register. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. Entergy will continue to monitor this situation.
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.
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Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions. In September 2016 the EPA finalized the CSAPR Update Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 the final rule requires reductions in summer nitrogen oxides (NOx) emissions. Several states, including Arkansas and Texas, filed a challenge to the Update Rule. In September 2019 the D.C. Circuit upheld the EPA’s underlying approach to the Update Rule, but determined that it was inconsistent with the Clean Air Act because it failed to include deadlines consistent with downwind states’ deadlines for attainment. The court remanded the rule to the EPA for further consideration, but did not vacate so the rule remains in effect pending the EPA’s further review. In October 2020 the EPA issued its proposal intended to address the D.C. Circuit’s remand. The draft rule proposes to finalize interstate transport obligations for 21 states. For nine states, including Arkansas, Mississippi, and Texas, the EPA proposes that additional emission reductions are not necessary. For 12 states, however, including Louisiana, the EPA proposes additional emission reductions through proposed reductions in the number of NOx emission allowances allocated to each state. Entergy, through its various trade associations, filed comments on the proposal and will continue to monitor the rulemaking and its potential impact on its facilities in Louisiana. If the October 2020 proposal is finalized, ozone season NOx emissions may become more expensive in Louisiana.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could 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 Energy and Environment, Division of Environmental Quality (ADEQ) prepared a state implementation plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. In April 2012 the EPA finalized a decision addressing the Arkansas Regional Haze SIP, in which it disapproved a large portion of the Arkansas 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 granted the stay pending settlement discussions and pending the State’s development of a SIP that, if approved by the EPA, would replace the FIP. The state had 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. The Part I SIP requires that Entergy address NOx impacts on visibility via compliance with the Cross-State Air Pollution Rule ozone-season emission trading program. Arkansas has finalized a Part II SIP which has been approved by the EPA but is currently pending a state court appeal. That appeal has been stayed pending the outcome of a federal court case, which may resolve many of the issues on appeal. The final Part II SIP requires that Entergy achieve SO2 emission reductions via the use of low-sulfur coal at both White Bluff and Independence within three years. The
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Part II SIP also requires that Entergy cease to use coal at White Bluff by December 31, 2028 and notes the current planning assumption that Entergy’s Independence units will cease to use coal by December 31, 2030.
In January 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. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement and in many cases also the Part II SIP, Entergy Arkansas, along with co-owners, will begin using only low-sulfur coal at Independence and White Bluff by mid-2021; cease to use coal at White Bluff and Independence by the end of 2028 and 2030, respectively; cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserve the option to develop new generating sources at each plant site; and commit to install or propose to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waive certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. The EPA, which is allowed to comment on such a settlement agreement, has stated that it has no objections to the settlement. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. Still pending before the court is a motion by the plaintiffs to approve the settlement, in support of which Entergy made a filing. The Arkansas Attorney General also filed an application before the APSC in December 2018 seeking an investigation into the effects of the settlement. The Arkansas Affordable Energy Coalition filed to support the Arkansas Attorney General’s application, and Entergy Arkansas filed a motion to dismiss it. The application remains pending before the APSC. In October 2019 the District Court requested supplemental briefing on several issues prior to addressing the motion to approve the settlement; that briefing concluded in May 2020.
In Louisiana, Entergy has worked with the Louisiana Department of Environmental Quality (LDEQ) and the EPA to revise the Louisiana SIP for regional haze, which had been 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 of January 22, 2021. The EPA issued final approval in December 2017. The EPA approval was appealed to the U.S. Court of Appeals for the Fifth Circuit. In October 2019 the Fifth Circuit affirmed the EPA’s SIP approval. A petition for rehearing filed by plaintiffs was denied by the Fifth Circuit. Plaintiffs did not petition for further review by the Supreme Court.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by 2021. Entergy received information collection requests from Arkansas and Louisiana requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, and Ninemile. Responses to the information requests have been submitted to the respective state agencies.
New and Existing Source Performance Standards for Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established
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national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests and will continue to monitor litigation challenging the rule. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. The vacatur will not be effective until the court issues its mandate which is being held until after disposition of any petitions for rehearing. Entergy is currently reviewing the court’s opinion.
In 2018 the EPA proposed a revision to the new source performance standard on greenhouse gas emissions that primarily impacts new coal units and, therefore, should not impact Entergy. In January 2021 the EPA finalized a pollutant-specific contribution finding for greenhouse gas emissions from new, modified, and reconstructed electric generating units. The rule establishes a three percent threshold for determining when a pollutant significantly contributes to air pollution and reaffirms the EPA’s position that the Clean Air Act Section 111(b) requires the EPA to make pollutant-specific significant contribution findings before promulgation of a new source performance standard. The EPA did not, however, finalize the new source performance standard on greenhouse gas emissions and intends to address the 2018 proposal in a future action.
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;
•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 federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and 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 local, state, and federal level to codify renewable portfolio standards, clean energy standards, 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;
•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 polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance risk;
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•the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds;
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in an economy-wide, responsible, and flexible manner. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020. In 2020, Entergy succeeded in achieving its initial climate commitment to reduce carbon dioxide cumulative emissions by 20% from 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 39.1 million tons in 2020 and 40.7 million tons in 2019. Since its original commitment in 2001, Entergy’s cumulative emissions are approximately 7.6% below its 2020 goal.
Entergy voluntarily conducted a climate scenario analysis and published a comprehensive report in March 2019. The report follows the framework and recommendations of the Task Force on Climate-related Disclosures, describing climate-related governance, strategy, risk management, and metrics and targets. Scenario analyses resulted in Entergy developing and publishing a new goal of reducing the Utility’s emission rate by 50 percent from 2000 levels by 2030. In September 2020, Entergy committed to achieving net-zero carbon emissions by 2050, while continuing its commitment to grid reliability and affordability for customers. In December 2020, Entergy published a report regarding this long-term commitment that describes its approach and technology point-of-view. Technology research and development, innovation, and advancement are critical to Entergy’s ability to meet this climate commitment.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s annual greenhouse gas emissions inventory is also third-party verified, and that certification is made available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 2020 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for nineteen consecutive years. Entergy also participated in the 2020 CDP and CDP Water evaluations, receiving a ‘B’ for both responses.
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 permit program, section 402, 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.
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Steam Electric Effluent Guidelines
The 2015 Steam Electric Effluent Limitations Guidelines (ELG) rule required, among other things, that there be no discharge of bottom ash transport water. In October 2020 the EPA issued its final rule revision on bottom ash transport water allowing the discharge of up to 10% system volume for certain purge waters, including storm events and non-routine operations. The final rule requires compliance as soon as possible beginning October 31, 2021, but no later than December 31, 2025. Several challenges to the final rule have been filed. Additionally, the Fifth Circuit Court of Appeals previously vacated and remanded the provisions of the rule related to legacy wastewater and leachate, which the EPA plans to address in a separate rulemaking. Despite the final rule and pending challenges, Entergy is implementing projects at its White Bluff and Independence plants to convert to zero-discharge systems to comply with the ELG rule and the coal combustion residuals restrictions on impoundments. Additionally, the Nelson Unit 6 facility is implementing operational and maintenance measures to minimize the potential for discharge of bottom ash transport water from the existing bottom ash handling system at the site, and is reviewing the effectiveness of these changes for compliance with the requirements of the October 2020 final rule.
Federal Jurisdiction of Waters of the United States
In February 2019 the EPA published its proposed revised definition of Waters of the United States, which proposes to narrow the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. The final rule was released in January 2020 and effective in June 2020. In October 2019 the EPA repealed the 2015 rule and re-codified the pre-existing regulations. That rule was effective late December 2019. Numerous challenges have been filed against both rules.
Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to 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, Indian Point, Palisades, Grand Gulf, 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.
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
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. 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 such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental 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 Resource Conservation and Recovery Act (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 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, 2020, Entergy has recorded asset retirement obligations related to CCR management of $20.1 million.
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 program.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. 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. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of one of its two recycle ponds, with the remaining pond being held in reserve during initial operation of the new bottom ash handling system. Closure of the remaining recycle pond at each site will commence as soon as possible, but no later than April 11, 2021, which is the deadline under the finalized CCR rule to commence closure of any unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
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Other Environmental Matters
Entergy Louisiana and Entergy Texas
Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, currently is 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 routed to a portion of the property for disposal. The same area also has 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. Removal actions addressed contaminated source material, soil, and sediment and included capping certain soil on and off-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. The EPA released the second Five Year Review in 2015. In that review, the EPA indicated that the remediation technique was insufficient and that Entergy would need to utilize other remediation technologies on the site. In July 2015, Entergy submitted a Focused Feasibility Study to the EPA outlining the potential remedies and suggesting installation of the new remedial method, a waterloo barrier. The estimated cost for this remedy is approximately $2 million, to be allocated between Entergy Louisiana and Entergy Texas. In early 2017 the EPA indicated that the waterloo barrier may not be necessary and requested revisions to the Focused Feasibility Study. The EPA released the third Five Year Review in late-2019 confirming that a new remedial method is not necessary but requiring continuation of the current groundwater monitoring. The site’s remedy includes monitored natural attenuation of groundwater, and institutional controls to restrict groundwater and land use. The EPA has determined that no additional actions are needed for the remedy to be protective over the long-term, and the remedy is protective of human health and the environment.
Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, 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 existed at the site. Entergy subsidiaries sent transformers to this facility. Entergy Arkansas, Entergy Louisiana, and Entergy Texas responded to an information request from the TCEQ. Entergy Louisiana and Entergy Texas 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 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. Current estimates, although variable depending on ultimate remediation design and performance, indicate that Entergy’s total share of remediation costs likely will be approximately $1.5 million to $2 million. Groundwater monitoring wells at the site were plugged and abandoned in December 2019 following receipt of a certificate of completion issued by the TCEQ. Site decommissioning activities are complete and final disposition of the property will be determined at a later time.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand
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letter seeking reimbursement for response costs totaling $4 million expended at the site. The demand letter is being evaluated and liability and PRP allocation of response costs are yet to be determined.
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 TCEQ and the National Response Center were immediately notified, and the 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, Entergy entered into the Voluntary Cleanup Program with the TCEQ. In November 2017, additional soil sampling was completed in the wetland area and, in February 2018, a site summary report of findings was submitted to the TCEQ. The TCEQ responded in June 2018 and requested an ecological exclusion criteria checklist/Tier II screening-level ecological risk assessment, and additional site assessment, additional soil samples, groundwater samples, and some additional diagrams and maps. In October 2018, Entergy submitted the requested information to the TCEQ. In January 2019 the TCEQ responded with another request for information. In March 2019, Entergy submitted the requested information to the TCEQ. In August 2019 the TCEQ responded with a request for additional information including an Affected Property Assessment Report (APAR) and water well survey. The TCEQ has agreed that the necessity of the water well survey is dependent on the results of the groundwater resampling that will occur. Groundwater sampling was completed in December 2019 and results were submitted to the TCEQ for review. Based on the groundwater sampling results, the TCEQ confirmed in February 2020 that a water well survey is not necessary and requested the APAR and an Ecological Risk Assessment by August 2020. Due to COVID-19 delays, the TCEQ extended the APAR and Ecological Risk Assessment submittal dates to December 2020, which Entergy timely met.
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.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, 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.
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Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2020, Entergy subsidiaries employed 13,400 people.
| | | | | |
| Utility: | |
| Entergy Arkansas | 1,244 | |
| Entergy Louisiana | 1,654 | |
| Entergy Mississippi | 750 | |
| Entergy New Orleans | 303 | |
| Entergy Texas | 658 | |
| System Energy | — | |
| Entergy Operations | 3,529 | |
| Entergy Services | 3,859 | |
| Entergy Nuclear Operations | 1,356 | |
| Other subsidiaries | 47 | |
| Total Entergy | 13,400 | |
Approximately 3,900 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, and Fire Professionals of America.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
| Gender (%) | 2020 | | 2019 |
| Female | 21 | | 20 |
| Male | 79 | | 80 |
| 100 | | 100 |
| | | | | | | | | | | |
| Race/Ethnicity (%) | 2020 | | 2019 |
| White | 78 | | 79 |
| Black/African American | 15 | | 15 |
| Hispanic/Latino | 3 | | 2 |
| Asian | 2 | | 2 |
| Other | 2 | | 2 |
| 100 | | 100 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion and belonging; and talent management.
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Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Personnel Committee establishes priorities and reviews performance on a range of topics. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development and succession plans to align a high performing executive team with Entergy’s priorities. The Personnel Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on ethics and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. While the COVID-19 pandemic and historical hurricane season presented significant challenges, Entergy’s safety strategy and commitment to excellence showed results in 2020. Entergy employees achieved a total recordable incident rate of 0.40 in 2020 compared to 0.56 in 2019 and 0.48 in 2018. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases. This marked improvement in total recordable incident rate placed Entergy in top-decile in safety performance when benchmarked amongst peers within the Edison Electric Institute.
Organizational Health, including Diversity, Inclusion and Belonging
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (near top quartile). In addition to significantly improved scores, initial employee participation of 66 percent in 2014 rose to and remains at 90 percent in 2018-2020.
Entergy believes that a culture focused on diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. Among other actions, the primary focus of its 2020 actions was taking a stand against social injustice, reinforcing expectations, training and leading by example, starting at the top of the organization and cascading through management ranks.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the future, and reflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.
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 SEC 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. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
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 annual and quarterly reports on Forms 10-K and 10-Q (including related filings in Inline XBRL format) and current reports on Form 8-K; 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 internet 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
See “RISK FACTOR SUMMARY” in Part I Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ 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 Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
In December 2019 a novel strain of coronavirus was reported to have surfaced in Wuhan, China. Since then, COVID-19 has spread throughout most countries in the world, including the United States. Public health officials in the United States have both recommended and mandated wearing of masks, precautions to mitigate the spread of COVID-19, including prohibitions on congregating in heavily-populated areas, mandated closure or limitations on the functions of non-essential business, and shelter-in-place orders or similar measures, including throughout Entergy’s service areas. While some of these mitigation measures have been lifted, it is unclear how long certain forms of mitigation measures will remain in place, whether they will be reinstated in the future, and how they will ultimately impact the general economy, Entergy’s customers, and its operations.
Entergy and its Utility operating companies have experienced a decline in commercial and industrial sales and an increase in arrearages and bad debt expense due to non-payment by customers, and expect such reduced levels of sales and increased arrearages and bad debt expense to continue, the extent and duration of which management cannot predict. The Utility operating companies temporarily suspended disconnecting customers for non-payment of bills, and the suspension remains in place at Entergy Arkansas, has been re-instituted at Entergy New Orleans, and could be re-instituted at the other Utility operating companies should their regulators mandate. While they are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is unknown. Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges, supply chain, vendor, and contractor disruptions; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed outages; delays in regulatory proceedings; workforce availability, health or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees telecommuting; increased late or uncollectible customer payments; volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and initiatives.
A sustained or further economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the COVID-19 pandemic on their customers. In addition, if the COVID-19 pandemic continues to create disruptions or turmoil in the credit or financial markets, or adversely impacts Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its
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Entergy Corporation, Utility operating companies, and System Energy
liquidity needs, or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the outbreak, the impact of new variants of COVID-19, the timing, availability, distribution or effectiveness of a vaccine, anti-viral or other treatments for COVID-19, governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
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 can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. 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, including adjustment upon the initiative of a regulator or affected stakeholders.
In addition, regulators may initiate proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s 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 may 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. Traditional 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 these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and the Utility operating companies may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation of their assets and infrastructure or the quality of their service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements.
The base rates of Entergy Texas are established largely in traditional base rate case proceedings.Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs.These riders include a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment and certain non-fuel MISO charges, a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a generation cost recovery rider mechanism for the recovery of generation-related capital investments, and a fixed fuel factor mechanism for the recovery of MISO fuel and energy-related costs.Entergy Texas also is required to make a filing every three years,
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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 necessary and reasonable, and makes a prudence finding for each of the fuel-related contracts for the reconciliation period.Entergy Texas also is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Between base rate cases, Entergy Arkansas and Entergy Mississippi 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. Entergy Arkansas has requested APSC approval of the extension of the formula rate plan tariff for an additional five years through 2026.If Entergy Arkansas’s formula rate plan were terminated or not extended beyond the initial term, Entergy Arkansas could file an 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 plan was most recently extended through the test year 2019; certain modifications were made in that extension, including a decrease to the allowed return on equity and the addition of a transmission cost recovery mechanism.The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC and as noted, for certain transmission investment, among other items.MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause.Entergy Louisiana has a pending request to extend its formula rate plan with certain modifications, including implementation of a distribution investment recovery mechanism and use of end of period rate base.In the event that the electric formula rate plan is not renewed or extended, Entergy Louisiana would revert to the more traditional rate case environment.
Entergy New Orleans previously operated under a formula rate plan that ended with the 2011 test year.Based on a settlement agreement approved by the City Council, with limited exceptions, the base rates of Entergy New Orleans were frozen until rates were implemented in connection with the base rate case filed by Entergy New Orleans in 2018.In November 2019 the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019.The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes.In November 2020 the City Council issued a resolution approving a settlement of the 2018 rate case.As part of this settlement, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle.See Note 2 to the financial statements for further discussion.
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 has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate request for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. System Energy has received FERC acceptance for billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
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 the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales could put upward pressure on rates, resulting in adverse regulatory actions to mitigate such effects on rates. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
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 or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may 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 and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
The Utility operating companies historically 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 had been approved by the FERC. The System Agreement terminated in its entirety on August 31, 2016.
There 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 existence. In the absence 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 few outstanding System Agreement proceedings at the FERC and at the D.C. Circuit that may require future adjustments, including challenges to the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
For further information regarding the regulatory proceedings relating to the System Agreement, see Note 2 to the 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. 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 capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or the cost of serving the Utility operating companies’ respective loads, and MISO market rules may change in ways that cause additional risk.
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. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from transmission projects of others, 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, the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits 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, or generally allow the retail regulator to direct the making of such 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 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 (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta), or the impact on customer bills of permitted storm cost recovery, could have material effects on Entergy and its Utility operating companies.
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. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills.
In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, 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
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costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity 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 owned or contractually controlled 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.
Certain of the Utility operating companies and System Energy 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.
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. Plant maintenance and upgrades are often scheduled during such planned outages, which typically extends the planned outage duration. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks 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 2020 and beyond. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium 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 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 and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, or shifting trade arrangements between countries. 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 changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
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 international sanctions or tariffs could further restrict the ability of such
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suppliers to continue to supply fuel or provide such services at acceptable prices or at all. 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 and System Energy.
Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, suspend 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, 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 nuclear facilities. 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.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate 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 the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities.
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 increased costs, some of which costs may not be fully recoverable by the Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. 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
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture 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 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 NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are 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 will 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 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 Louisiana, and System Energy and Note 8 to the financial statements.
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, which is referred to as Secondary Financial Protection, up to approximately $137.6 million per reactor. With 97 reactors currently
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
participating, this translates to a total public liability cap of approximately $14 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, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the 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 primary insurance level, up to a maximum of approximately $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.101 billion). The retrospective premium payment is currently limited to approximately $21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $137.6 million cap.
NEIL is a utility industry mutual insurance company, owned by its 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 NEIL surplus (reserve) be significantly depleted due toinsured losses. As of December 31, 2020, the maximum annual assessment amounts total $104 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential 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.
The 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 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. 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.
Under NRC regulations, nuclear plant owners 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 nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments 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.
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, or accelerate the timing for funding of, the obligations related to the decommissioning of the Utility operating companies, System Energy, or Entergy Wholesale Commodities nuclear power plants or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. 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, the impairment charges that resulted from such decision, and the planned sales of Palisades and Indian Point Energy Center (which, in each case, will include the transfer of the associated decommissioning trusts), 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.
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. These concerns have led to, and may 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 might lead to the shutdown of nuclear units, 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 and financial condition.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation)
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. 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, 2020, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 98% in 2021 and 99% in 2022 of its generation portfolio’s planned energy output, reflecting the planned shutdown and sale of the remaining 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.
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.
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.
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 “Market and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the closure (or sale) of its nuclear plants, Entergy Wholesale Commodities may enter into fewer forward sales contracts for output from such plants.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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. 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 $1.29 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. 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 is subject to changes as a result of restructuring initiatives at both the state and federal levels. 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, 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, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other 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 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 remaining assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure and sale of its nuclear power plants. Moreover, prior to the closure and 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, or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
If Entergy concludes that any of its nuclear power plants is unlikely to operate through its planned shutdown date, which conclusion would be based on a variety of factors, such a conclusion could result in a 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 remaining 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 - Impairment of Long-lived Assets” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
General Business
(Entergy Corporation, Entergy Arkansas, 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-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, Hurricane Isaac in 2012, and Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown events, 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The inability to raise capital on favorable terms, particularly during times of high interest rates, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in companies that experience extreme weather events, that rely on fossil fuels or offerings to fund fossil fuel projects, or due to risks related to climate change. Events beyond Entergy’s control 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 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.
Most of Entergy Corporation’s and its subsidiaries’ 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, 2020 based on power prices at that time, Entergy had liquidity exposure of $62 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $6 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, 2020, Entergy would have been required to provide approximately $30 million of additional cash or letters of credit under some of the agreements. As of December 31, 2020, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $22 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, and cash flows.
The Tax Cuts and Jobs Act of 2017 and CARES Act of 2020 significantly changed 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 interpretive
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation.
As further described in Note 3 to the financial statements, as a result of amortization of accumulated deferred income taxes and payment of such amounts to customers in 2019, Entergy’s net regulatory liability for income taxes balance is $1.6 billion as of December 31, 2020. Depending on the outcome of IRS examinations or tax positions and elections that Entergy may make, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense. Further, there may be other material effects resulting from the legislation that have not been identified.
See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act on 2018, 2019 and 2020 results of operations and financial condition, the provisions of the Tax Cuts and Jobs Act, and the uncertainties associated with accounting for the Tax Cuts and Jobs Act, and Note 2 to the financial statements for discussion of the regulatory proceedings that have considered the effects of the Tax Cuts and Jobs 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 execute on their business strategies, including their ability to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies, which could materially affect their future prospects, results of operations, and benefits that they anticipate from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, which are subject to business, regulatory, economic, and other risks and uncertainties, many of which are beyond their control. As a result, Entergy and its subsidiaries may be unable to fully achieve the anticipated results of such strategies.
Additionally, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring, or other strategic transactions. For example, Entergy has entered into an agreement to sell its equity interests in the subsidiary that owns the Palisades Nuclear Plant and the decommissioned Big Rock Point Nuclear Power Plant and an agreement to sell the equity interests of Indian Point 1, Indian Point 2, and Indian Point 3, in each case after each of the plants has been shut down and defueled. Also, a significant portion of Entergy’s utility business over the next several years includes the construction and/or purchase of a variety of generating units. These transactions and 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 or its subsidiaries’ financial condition or 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
Entergy Corporation, Utility operating companies, and System Energy
•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;
•Entergy may experience issues integrating businesses into its internal controls over financial reporting;
•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, 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 and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition or results of operations.
The completion of capital projects, including the construction of power generation facilities, and other capital improvements involve substantial risks. Should such 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 capital projects, including the 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, escalating costs for materials, labor, and environmental compliance, and reliance on suppliers for timely and satisfactory performance. Delays in obtaining permits, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under 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 the project or 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 capital projects, including the potential construction and/or purchase 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
Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
We rely on a large and changing workforce of team members, including employees, contractors and temporary staffing. Certain events, such as an aging workforce, mismatching of skill sets, failing to appropriately anticipate future workforce needs, or the unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base, and the time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, may increase. Failure to hire and adequately train replacement employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business, especially considering the workforce needs associated with nuclear generation facilities and new skills required to operate a modernized, technology-enabled power grid. If Entergy and its subsidiaries are unable to successfully attract, retain, and manage an appropriately qualified workforce, their results of operations, financial position, and cash flows could be negatively affected.
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 currently are 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 potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing air regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, 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
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 NERC, the 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. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the 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 businesses.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations and system reliability.
Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, mild temperatures in either season tend to decrease energy usage and resulting revenues. Higher consumption levels coupled with seasonal pricing differentials 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 including hurricanes or tropical storms, flooding events, or ice storms 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 reduced 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 weather and economic conditions, 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 grid demand. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and their replacement with more efficient ones, adoption of newer technologies including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales growth in the future. The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower 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, environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions, or achieving voluntary climate commitments 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, some 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 CO2 and other “greenhouse gases” under the Clean Air Act, the EPA, various environmental interest groups, and other organizations focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. Since that ruling, the EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and from new, existing, and significantly modified stationary sources of emissions, including electric generating units. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. In Louisiana, the Office of the Governor announced the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050 while the City Council of New Orleans passed a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk 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, clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing the company’s greenhouse gas emission rate. 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 attempt to deny or defer timely recovery of these costs. Future changes in regulation or policies governing the emission of CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy’s utility operating companies, their suppliers or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy’s utility operating companies are unable to fully recover the costs and investment in generation and (iv) could increase the difficulty that Entergy and its utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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, wildfires, wetland and barrier island erosion, risks of flooding and changes in weather conditions, (such as increases in precipitation, drought, or changes in average 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 the physical impacts of climate change, 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, more frequent and longer lasting outages, 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.
In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. Technology research and development, innovation, and advancement are critical to Entergy’s ability to achieve this commitment. Moreover, Entergy cannot predict the ultimate impact of achieving this objective, or the various implementation aspects, on its system reliability, or its results of operations, financial condition or 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, and Entergy Wholesale Commodities’ business operations. Entergy’s facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also 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.
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 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 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Market performance and other changes may decrease the value of benefit plan assets, which then could require additional 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 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 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 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 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.
Terrorist attacks, cyber attacks, system failures or data breaches of Entergy’s and its subsidiaries’ or our suppliers’ technology systems may adversely affect Entergy’s results of operations.
Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure, and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers and employees, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply chain activities. Any significant failure or malfunction of such information technology systems could result in loss of data or disruptions of operations.
There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. As an operator of critical infrastructure, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, cyber attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions. An actual act could affect Entergy’s ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct business.
Given the rapid technological advancements of existing and emerging threats, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
and controls. 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 could be unable to perform critical business functions that are essential to the company’s well-being and could result in a loss of its confidential, sensitive, and proprietary information, including personal information of its customers, employees, suppliers, and others in Entergy’s care.
Any such attacks, failures or data breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, results of operations or reputation. Although we purchase insurance coverage for cyber-attacks or data breaches, such insurance may not be adequate to cover all losses that might arise in connection with these events. Such events may also expose Entergy to an increased risk of litigation (and associated damages and fines).
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect 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 New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. 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.
(System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings.
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 expires in November 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. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a request in a separate proceeding for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. The LPSC has also authorized the filing of a prudence complaint at the FERC relating to Grand Gulf operations. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
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, see Notes 5 and 8 to the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy Corporation depends 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. Prior to providing funds to Entergy Corporation, such subsidiaries have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of Entergy Utility Holding Company and Entergy Texas, dividends and distributions on preferred securities. Any distributions from the Registrant Subsidiaries other than Entergy Texas and System Energy are paid directly to Entergy Utility Holding Company and are therefore subject to prior payment of distributions on its preferred securities.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Arkansas’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $10 million. Natural gas purchases for Entergy Arkansas for February 1st through 25th, 2021 are approximately $105 million compared to natural gas purchases for February 2020 of $10 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income decreased $17.7 million primarily due to lower volume/weather, a formula rate plan provision recorded in 2020 to reflect the 2019 historical year netting adjustment, and higher depreciation and amortization expenses, partially offset by higher retail electric price and lower other operation and maintenance expenses. See Note 2 to the financial statements for discussion of the 2019 historical year netting adjustment.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2020 to 2019:
| | | | | |
| Amount |
| (In Millions) |
| 2019 operating revenues | $2,259.6 | |
| Fuel, rider, and other revenues that do not significantly affect net income | (278.5) | |
| Volume/weather | (72.2) | |
| Retail electric price | 57.4 | |
| Return of unprotected excess accumulated deferred income taxes to customers | 118.2 | |
| 2020 operating revenues | $2,084.5 | |
Entergy Arkansas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The volume/weather variance is primarily due to a decrease of 1,069 GWh, or 5%, in billed electricity usage, including decreased commercial and industrial usage as a result of the COVID-19 pandemic, and the effect of less favorable weather on residential and commercial sales, partially offset by an increase in residential usage as a
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
result of the COVID-19 pandemic. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the COVID-19 pandemic.
The retail electric price variance is primarily due to the $56.5 million annual formula rate plan increase related to the 2020 projected test year included in the 2019 formula rate plan filing effective with the first billing cycle of January 2020. See Note 2 to the financial statements for further discussion of the formula rate plan filing.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a tax adjustment rider beginning in April 2018. In 2020, $8.1 million was returned to customers as compared to $126.3 million in 2019. There is no effect on net income as the reduction in operating revenues in each period was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
Other Income Statement Variances
Nuclear refueling outage expenses decreased primarily due to the amortization of lower costs associated with the most recent outages as compared to previous outages.
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $18.3 million in nuclear generation expenses primarily due to lower nuclear labor costs, including contract labor, in part as a result of the COVID-19 pandemic;
•a decrease of $13.2 million in non-nuclear generation expenses primarily due to lower long-term service agreement expenses;
•an $11.2 million write-off in 2019 of specific costs related to the potential construction of scrubbers at the White Bluff plant. See Note 2 to the financial statements for discussion of the write-off;
•higher nuclear insurance refunds of $7.8 million;
•a decrease of $5.9 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services; and
•a decrease of $5.8 million in energy efficiency costs.
The decrease was partially offset by the effects of recording in 2019 a final judgment to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $11.9 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.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other income increased primarily due to changes in decommissioning trust fund investment activity.
Other regulatory credits - net for 2020 includes a provision of $43.5 million to reflect the 2019 historical year netting adjustment included in the APSC’s December 2020 order in the 2020 formula rate plan proceeding. See Note 2 to the financial statements for discussion of the 2020 formula rate plan proceeding.
The effective income tax rates were 16.3% for 2020 and (21.6%) for 2019. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes. See Notes 2 and 3 to the financial statements for a discussion of the effects and regulatory activity regarding the Tax Cuts and Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of results of operations for 2019 compared to 2018.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 | |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $3,519 | | | $119 | | | $6,216 | | |
| | | | | | |
| Net cash provided by (used in): | | | | | | |
| Operating activities | 659,818 | | | 677,766 | | | 211,825 | | |
| Investing activities | (795,709) | | | (676,293) | | | (688,727) | | |
| Financing activities | 324,500 | | | 1,927 | | | 470,805 | | |
| Net increase (decrease) in cash and cash equivalents | 188,609 | | | 3,400 | | | (6,097) | | |
| | | | | | |
| Cash and cash equivalents at end of period | $192,128 | | | $3,519 | | | $119 | | |
2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities decreased $17.9 million in 2020 primarily due to:
•the timing of recovery of fuel and purchased power costs;
•lower collections of receivables from customers, in part due to the COVID-19 pandemic; and
•the timing of payments to vendors.
The decrease was partially offset by:
•a decrease in the return of unprotected excess accumulated deferred income taxes to customers in 2020 as compared to 2019. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act;
•$25 million in proceeds received from the DOE in 2020 resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•a decrease of $15.8 million in pension contributions in 2020. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Investing Activities
Net cash flow used in investing activities increased $119.4 million in 2020 primarily due to:
•an increase of $79.5 million in storm spending;
•an increase of $47.3 million in non-nuclear generation construction expenditures primarily due to increased spending on various projects in 2020;
•an increase of $39.4 million in nuclear construction expenditures primarily as a result of work performed in 2020 on various ANO 2 outage projects;
•an increase of $38.5 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; and
•an increase of $30.3 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Arkansas’s distribution system, including increased spending on advanced metering infrastructure.
The increase was partially offset by:
•a decrease of $56 million in transmission construction expenditures primarily due to a lower scope of work performed in 2020 as compared to 2019; and
•$55 million in proceeds received from the DOE in 2020 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.
Financing Activities
Net cash flow provided by financing activities increased $322.6 million in 2020 primarily due to:
•issuances of $100 million of 4.0% Series mortgage bonds in March 2020 and $675 million of 2.65% Series mortgage bonds in September 2020;
•money pool activity;
•a decrease of $41.6 million in net long-term repayments in 2020 on the Entergy Arkansas nuclear fuel company variable interest entity credit facility; and
•a decrease of $20 million in common equity distributions in 2020 in order to maintain Entergy Arkansas’s capital structure.
The increase was partially offset by:
•the issuance of $350 million of 4.20% Series mortgage bonds in March 2019;
•the repayment in October 2020 of $200 million of 4.90% Series mortgage bonds due December 2052; and
•the repayment in October 2020 of $125 million of 4.75% Series mortgage bonds due June 2063.
Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased by $21.6 million in 2020 compared to decreasing by $161.1 million in 2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio is primarily due to the net issuances of long-term debt in 2020.
| | | | | | | | | | | |
| | December 31,
2020 | | December 31,
2019 |
| Debt to capital | 54.8 | % | | 53.0 | % |
| Effect of excluding the securitization bonds | — | % | | — | % |
| Debt to capital, excluding securitization bonds (a) | 54.8 | % | | 53.0 | % |
| Effect of subtracting cash | (1.2 | %) | | — | % |
| Net debt to net capital, excluding securitization bonds (a) | 53.6 | % | | 53.0 | % |
(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, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas 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 Arkansas’s financial condition because the securitization bonds, which have been repaid as of December 31, 2020, were 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 distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Arkansas 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
•distribution and interest payments.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2022 | | 2023 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $340 | | | $355 | | | $430 | |
| Transmission | 40 | | | 45 | | | 190 | |
| Distribution | 95 | | | 255 | | | 420 | |
| Utility Support | 105 | | | 80 | | | 75 | |
| Total | $580 | | | $735 | | | $1,115 | |
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| | (In Millions) |
| Long-term debt (a) | $611 | | | $543 | | | $581 | | | $4,713 | | | $6,448 | |
| Operating leases (b) | $14 | | | $21 | | | $15 | | | $11 | | | $61 | |
| Finance leases (b) | $3 | | | $5 | | | $3 | | | $2 | | | $13 | |
| Purchase obligations (c) | $452 | | | $618 | | | $509 | | | $3,882 | | | $5,461 | |
(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)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 $66.6 million to its qualified pension plans and approximately $517 thousand to its other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. 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 $252 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 Arkansas includes specific investments in renewables such as the Searcy Solar Facility, Walnut Bend Solar Facility, and West Memphis Solar Facility; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; investments in ANO 1 and 2; software and security; 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 maturities in Note 5 to the financial statements.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Renewables
Searcy Solar Facility
In March 2019, Entergy Arkansas announced that it signed an agreement for the purchase of an approximately 100 MW solar energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. The purchase is contingent upon, among other things, obtaining necessary approvals from applicable federal and state regulatory and permitting agencies. The project is being constructed by a subsidiary of NextEra Energy Resources. Entergy Arkansas will purchase the facility upon mechanical completion and after the other purchase contingencies have been met. Closing is expected to occur by the end of 2021. In May 2019, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. In September 2019 other parties filed testimony largely supporting the resource acquisition but disputing Entergy Arkansas’s proposed method of cost recovery. Entergy Arkansas filed its rebuttal testimony in October 2019. In February 2020, Entergy Arkansas, the Attorney General, and the APSC general staff filed a partial settlement agreement asking the APSC to approve, based on the record in the proceeding, all issues except certain issues that are submitted to the APSC for determination. In April 2020 the APSC issued an order approving Entergy Arkansas’s acquisition of the Searcy Solar facility as being in the public interest, but declined to approve Entergy Arkansas’s preferred cost recovery rider mechanism, finding instead, based on the particular facts and circumstances presented, that the formula rate plan rider was a sufficient recovery mechanism for this resource.
Walnut Bend Solar Facility
In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar Facility is in the public interest. Entergy Arkansas requested a decision by the APSC by June 15, 2021 and primarily requests cost recovery through the formula rate plan rider. A procedural schedule was established with a hearing scheduled in April 2021. Closing is expected to occur in 2022.
West Memphis Solar Facility
In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar Facility is in the public interest. Entergy Arkansas requested a decision by the APSC by September 7, 2021 and primarily requests cost recovery through the formula rate plan rider. Closing is expected to occur in 2023.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Arkansas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
All debt and common and preferred membership interest issuances by Entergy Arkansas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s bond indentures and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | | 2017 |
| (In Thousands) |
| $3,110 | | ($21,634) | | ($182,738) | | ($166,137) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in September 2024. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2021. The $150 million credit facility includes fronting commitments for the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2020, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas 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, 2020, a $1 million letter of credit was outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for further discussion of the credit facilities.
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in September 2022. As of December 31, 2020, $12.2 million in loans were outstanding under the credit facility for the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorization from the FERC through July 2022 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and 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 FERC. The APSC has concurrent jurisdiction over Entergy Arkansas’s first mortgage bond/secured issuances. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through July 2022. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2022.
State and Local Rate Regulation and Fuel-Cost Recovery
Retail Rates
2018 Formula Rate Plan Filing
In July 2018, Entergy Arkansas filed with the APSC its 2018 formula rate plan filing to set its formula rate for the 2019 calendar year. The filing showed Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2019 test period to be below the formula rate plan bandwidth. Additionally, the filing included the first netting adjustment under the current formula rate plan for the historical test year 2017, reflecting the change in formula rate plan revenues associated with actual 2017 results when compared to the allowed rate of return on equity. The filing included a projected $73.4 millionrevenue deficiency for 2019 and a $95.6 million revenue deficiency for the 2017 historical test year, for a total revenue requirement of $169 million for this filing. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to four percent of total revenue, which originally was $65.4 million but was increased to $66.7 million based upon the APSC staff’s updated calculation of 2018 revenue. In October 2018, Entergy Arkansas and the parties to the proceeding filed joint motions to approve a partial settlement agreement as to certain factual issues and agreed to brief contested legal issues. In November 2018 the APSC held a hearing and was briefed on a contested legal issue. In December 2018 the APSC issued a decision related to the initial legal brief, approved the partial settlement agreement and $66.7 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan, with updated rates going into effect for the first billing cycle of January 2019.
2019 Formula Rate Plan Filing
In July 2019, Entergy Arkansas filed with the APSC its 2019 formula rate plan filing to set its formula rate for the 2020 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2020 and a netting adjustment for the historical year 2018. The total proposed formula rate plan rider revenue change designed to produce a target rate of return on common equity of 9.75% is $15.3 million, which is based upon a deficiency of approximately $61.9 million for the 2020 projected year, netted with a credit of approximately $46.6 million in the 2018 historical year netting adjustment. During 2018 Entergy Arkansas experienced higher-than expected sales volume, and actual costs were lower than forecasted. These changes, coupled with a reduced income tax rate resulting from the Tax Cuts and Jobs Act, resulted in the credit for the historical year netting adjustment. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflected the estimate of the historical year netting adjustment that was expected to be included in the 2019 filing. In 2019, Entergy Arkansas recorded additional provisions totaling $11.5 million to reflect the updated estimate of the historical year netting adjustment included in the 2019 filing. In October 2019 other parties in the proceeding filed their errors and objections requesting certain adjustments to Entergy Arkansas’s filing that would reduce or eliminate Entergy Arkansas’s proposed revenue change. Entergy Arkansas filed its response addressing the requested adjustments in October 2019. In its response, Entergy Arkansas accepted certain of the adjustments recommended by the General Staff of the APSC that would reduce the proposed formula rate plan rider revenue change to $14 million. Entergy Arkansas disputed the remaining adjustments proposed by the parties. In October 2019, Entergy Arkansas filed a unanimous settlement agreement with the other parties in the proceeding seeking APSC approval of a revised total formula rate plan rider revenue change of $10.1 million. In its July 2019 formula rate plan filing, Entergy Arkansas proposed to recover an $11.2 million regulatory asset, amortized over five years, associated with specific costs related to the potential construction of scrubbers at the White Bluff plant. Although Entergy Arkansas does not concede that the regulatory asset lacks merit, for purposes of reaching a settlement on the total formula rate plan rider amount, Entergy Arkansas agreed not to include the White Bluff scrubber regulatory asset cost in the 2019 formula rate plan filing or future filings. Entergy Arkansas recorded a write-off in 2019 of the $11.2 million White Bluff scrubber regulatory asset. In December 2019 the APSC approved the settlement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2020.
2020 Formula Rate Plan Filing
In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2021 projected year is 8.22% resulting in a revenue deficiency of $64.3 million. The earned rate of return on common equity for the 2019 historical year was 9.07% resulting in a $23.9 million netting adjustment. The total proposed revenue change for the 2021 projected year and 2019 historical year netting adjustment was $88.2 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $74.3 million. In October 2020 other parties in the proceeding filed their errors
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
and objections recommending certain adjustments, and Entergy Arkansas filed responsive testimony disputing these adjustments. As part of the formula rate plan tariff the calculation for the revenue constraint was updated based on actual revenues which had the effect of reducing the initially-proposed $74.3 million revenue requirement increase to $72.6 million. In October 2020, Entergy Arkansas filed with the APSC a unanimous settlement agreement reached with the other parties that resolved all but one issue. As a result of the settlement agreement, Entergy Arkansas’s requested revenue increase was $68.4 million, including a $44.5 million increase for the projected 2021 year and a $23.9 million netting adjustment. The remaining issue litigated concerned the methodology used to calculate the netting adjustment within the formula rate plan. In December 2020 the APSC issued an order rejecting the netting adjustment method used by Entergy Arkansas. Applying the approach ordered by the APSC changed the netting adjustment for the 2019 historical year from a $23.9 million deficiency to $43.5 million excess. Overall, the decision reduced Entergy Arkansas’s revenue adjustment for 2021 to $1 million. In December 2020, Entergy Arkansas filed a petition for rehearing of the APSC’s decision, and in January 2021 the APSC granted further consideration of Entergy Arkansas’s petition. Based on the progress of the proceeding to date, in December 2020, Entergy Arkansas recorded a regulatory liability of $43.5 million to reflect the netting adjustment for 2019, as included in the APSC’s December 2020 order, which would be returned to customers in 2021. Also with the formula rate plan filing, Entergy Arkansas is requesting an extension of the formula rate plan rider for a second five-year term. Decisions by the APSC on the netting adjustment rehearing and the extension are expected in March 2021.
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. In July 2018, Entergy Arkansas filed a settlement, reached by all parties in the APSC proceeding, resolving all issues. The APSC approved the settlement agreement and restructuring in August 2018. Pursuant to the settlement agreement, Entergy Arkansas will credit retail customers $39.6 million over six years, beginning in 2019. Entergy Arkansas also received the required FERC and NRC approvals.
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated 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 assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed 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 is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 in Note 2 to the financial statements.
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 upcoming energy cost rate redetermination filing that was made in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude from the redetermination of its 2014 energy cost rate $65.9 million of incremental fuel and replacement energy costs incurred in 2013 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 was available regarding various claims associated with the ANO stator incident. In February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in its deferred fuel balance. 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 regulatory 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
In March 2018, 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 $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it has initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.
In March 2019, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01882 per kWh to $0.01462 per kWh and became effective with the first billing cycle in April 2019. In March 2019 the Arkansas Attorney General filed a response to Entergy Arkansas’s annual adjustment and included with its filing a motion for investigation of alleged overcharges to customers in connection with the FERC’s October 2018 order in the opportunity sales proceeding. Entergy Arkansas filed its response to the Attorney General’s motion in April 2019 in which Entergy Arkansas stated its intent to initiate a proceeding to address recovery issues related to the October 2018 FERC order. In May 2019, Entergy Arkansas initiated the opportunity sales recovery proceeding, discussed below, and requested that the APSC establish that proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC October 2018 order and related FERC orders in the opportunity sales proceeding. In June 2019 the APSC granted Entergy Arkansas’s request and also denied the Attorney General’s motion in the energy cost recovery proceeding seeking an investigation into Entergy Arkansas’s annual energy cost recovery rider adjustment and referred the evaluation of such matters to the opportunity sales recovery proceeding.
In March 2020, Entergy Arkansas LLC and Subsidiariesfiled its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01462 per kWh to $0.01052 per kWh. The redetermined rate became effective with the first billing cycle in April 2020 through the normal operation of the tariff.
Management’s Financial Discussion and Analysis
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 allocated 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 prohibited 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 challenged sales made beginning in 2002 and requested refunds. In July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement 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 FERC subsequently ordered a hearing in the proceeding.
After a hearing, the ALJ issued an initial decision in December 2010. 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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. The FERC in its decision established further hearing procedures to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision. The hearing was held in May 2013 and the ALJ issued an initial decision in August 2013. 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 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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’ request to hold the appeal in abeyance pending final resolution of the related proceeding before 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’ appeal and held all of the appeals in abeyance pending final resolution of the related proceeding before the FERC.appeal.
The hearing required by the FERC’s April 2016 order was held in May 2017. In July 2017 the ALJ issued an initial decision addressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the calculation methodology. 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 decision. 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.
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 included interest, for its estimated increased costs and payment to the other Utility operating companies, and a deferred fuel regulatory asset of $75 million. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. The December 2018 compliance filing is pending FERC action. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
| | | | | | | | | | | |
| | Total refunds including interest |
| Payment/(Receipt) |
| | (In Millions) |
| Principal | Interest | Total |
| Entergy Arkansas | $68 | $67 | $135 |
| Entergy Louisiana | ($30) | ($29) | ($59) |
| Entergy Mississippi | ($18) | ($18) | ($36) |
| Entergy New Orleans | ($3) | ($4) | ($7) |
| Entergy Texas | ($17) | ($16) | ($33) |
Entergy Arkansas previously recognized a regulatory asset with a balance of $116 million as of December 31, 2018 for a portion of the payments due as a result of this proceeding.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and motion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC’s complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC’s new complaint.
In May 2019, Entergy Arkansas filed an application and supporting testimony with the APSC requesting approval of a special rider tariff to recover the costs of these payments from its retail customers over a 24-month period. The application requested that the APSC approve the rider to take effect within 30 days or, if suspended by the APSC as allowed by commission rule, approve the rider to take effect in the first billing cycle of the first month occurring 30 days after issuance of the APSC’s order approving the rider. In June 2019 the APSC suspended
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas’s tariff and granted Entergy Arkansas’s motion asking the APSC to establish the proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC’s October 2018 order and related FERC orders in the opportunity sales proceeding. In January 2020 the APSC adopted a procedural schedule with a hearing in April 2020. In January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed a joint motion seeking to dismiss Entergy Arkansas’s application alleging that the APSC, in a prior proceeding, ruled on the issues addressed in the application and determined that Entergy Arkansas’s requested relief violates the filed rate doctrine and the prohibition against retroactive ratemaking. Entergy Arkansas responded to the joint motion in February 2020 rebutting these arguments, including demonstrating that the claims in this proceeding differ substantially from those the APSC addressed previously and that the payment resulting from a FERC tariff violation for which Entergy Arkansas seeks retail cost recovery in this proceeding differs materially from the refunds resulting from a FERC tariff amendment that the APSC previously rejected on filed rate doctrine and the retroactive ratemaking grounds. In addition, in January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed testimony opposing the recovery by Entergy Arkansas of the opportunity sales payment but also claiming that certain components of the payment should be segregated and refunded to customers. In March 2020, Entergy Arkansas filed rebuttal testimony.
In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U. S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court scheduled a hearing for February 26, 2021 regarding issues addressed in the pre-trial conference report.
Net Metering Legislation
An Arkansas law was enacted effective July 2019 that, among other things, expands the definition of a “net metering customer” to include two additional types of customers: (1) customers that lease net metering facilities, subject to certain leasing arrangements, and (2) government entities or other entities exempt from state and federal income taxes that enter into a service contract for a net metering facility. The latter provision would allow eligible entities, many of whom are small and large general service customers, to purchase renewable energy directly from third party providers and receive bill credits for these purchases. The APSC was given authority under this law to address certain matters, such as cost shifting and the appropriate compensation for net metered energy and has initiated proceedings for this purpose. Because of the size and number of customers eligible under this new law, there is a risk of loss of load and the shifting of costs to customers. A hearing was held in December 2019, with utilities, cooperatives, the Arkansas Attorney General, industrial customers, and Entergy Arkansas advocating the need for establishment of a reasonable rate structure that takes into account impacts to non-net metering customers. customers; an additional hearing was conducted in February 2020 for purposes of public comment only. The APSC issued an order in June 2020, and in July 2020 several parties, including Entergy Arkansas, filed for rehearing on multiple
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
grounds, including for the reasons that it imposes an unreasonable rate structure and allows facilities to net meter that do not meet the statutory definition of net metering facilities. After granting the rehearing requests, the APSC issued an order in September 2020 largely upholding its June 2020 order. In October 2020, Entergy Arkansas and several other parties filed an appeal of the APSC’s September 2020 order.
Separately, as directed by the APSC general staff, the APSC opened a proceeding to compel utilities to amend their net metering tariffs to incorporate the provisions of the legislation that the APSC general staff considered “black letter law.” Entergy Arkansas, the Arkansas Attorney General, and other intervenors opposed this directive pending the development of the rules for implementation that are being considered in the separate net metering rulemaking docket. Nevertheless, reserving its rights, Entergy Arkansas has complied with the directive to amend its tariffs. Asserting procedural and due process violations, in January 2020, Entergy Arkansas and the Arkansas Attorney General separately appealed certain APSC orders in thisthe proceeding.
In April 2020, in light of the COVID-19 pandemic, the APSC issued an order requiring utilities, to the extent they had not already done so, to suspend service disconnections during the remaining pendency of the Arkansas Governor’s emergency declaration or until the APSC rescinds the directive. The order also authorizes utilities to establish a regulatory asset to record costs resulting from the suspension of service disconnections, directs that in future proceedings the APSC will consider whether the request for recovery of these regulatory assets is reasonable and necessary, and requires utilities to track and report the costs and any savings directly attributable to suspension of disconnects. In May 2020 the APSC approved Entergy Arkansas expanding deferred payment agreements to assist customers during the COVID-19 pandemic. Quarterly reporting began in August 2020 and the APSC ordered additional reporting in October 2020 regarding utilities’ transitional plans for ending the moratorium on service disconnects. In February 2021 the APSC issued an order finding that it is not in the public interest to immediately lift the moratorium on service disconnects, but to announce a target date of May 3, 2021. In March 2021 the APSC will issue an order either confirming the lifting of the moratorium on service disconnects or extending the moratorium. As of December 31, 2020, Entergy Arkansas recorded a regulatory asset of $10.5 million for costs associated with the COVID-19 pandemic.
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 Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Nuclear Matters
Entergy Arkansas owns and, 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 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,goals; the performance and capacity factors of these nuclear plants including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems and the Fukushima event;systems; 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 either ANO 1 or ANO 2, Entergy Arkansas may be required to
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ANO 1’s operating license expires in 2034 and ANO 2’s operating license expires in 2038.
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, 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.
In the first quarter 2019, 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 $126.2 million increase in its decommissioning cost liabilities, along with corresponding increases in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.
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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.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.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
Costs 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 2021 Qualified Pension Cost | | Impact on 2020 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $2,406 | | $46,791 |
| Rate of return on plan assets | | (0.25%) | | $2,914 | | $— |
| Rate of increase in compensation | | 0.25% | | $1,838 | | $8,922 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Qualified Pension Cost | | Impact on 2019 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $2,633 | | $43,030 |
| Rate of return on plan assets | | (0.25%) | | $2,803 | | $— |
| Rate of increase in compensation | | 0.25% | | $1,650 | | $7,967 |
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 2021 Postretirement Benefit Cost | | Impact on 2020 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $174 | | $6,576 |
| Health care cost trend | | 0.25% | | $225 | | $4,516 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Postretirement Benefit Cost | | Impact on 2019 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $343 | | $5,316 |
| Health care cost trend | | 0.25% | | $430 | | $3,474 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Costs and Employer Contributions
Total qualified pension cost for Entergy Arkansas in 20192020 was $44.4 million.$81.7 million, including $21.1 million in settlement costs. Entergy Arkansas anticipates 20202021 qualified pension cost to be $61.1$61.6 million. Entergy Arkansas contributed $75.9$60 million to its qualified pension plans in 20192020 and estimates pension contributions will be approximately $32.5$66.6 million in 2020,2021, although the 20202021 required pension contributions will be known with more certainty when the January 1, 20202021 valuations are completed, which is expected by April 1, 2020.2021.
Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 20192020 was $10.7$10.1 million. Entergy Arkansas expects 20202021 postretirement health care and life insurance benefit income of approximately $12.5$11.1 million. Entergy Arkansas contributed $1.3$2.2 million to its other postretirement plans in 20192020 and estimates 20202021 contributions will be approximately $509$517 thousand.
Entergy Arkansas, 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 member and Board of Directors of
Entergy Arkansas, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Arkansas, LLC and Subsidiaries (the “Company”) as of December 31, 20192020 and 2018,2019, the related consolidated statements of income, cash flows and changes in member’s equity (pages 317332 through 322336 and applicable items in pages 4951 through 236)238), for each of the three years in the period ended December 31, 2019,2020, 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, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2020, 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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Arkansas, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arkansas Public Service Commission (the “APSC”), which has jurisdiction with respect to the rates of electric companies in Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment;
regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the APSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses 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. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the APSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs, including costs related to the Opportunity Sales Proceeding and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the APSC and the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the APSC and the FERC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the APSC and the FERC for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the APSC’s and the FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, including the Opportunity Sales Proceeding, we inspected the Company’s filings with the APSC and the FERC, including the annual formula rate plan filing, and considered the filings with the APSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, including the Opportunity Sales Proceeding, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202026, 2021
We have served as the Company’s auditor since 2001.
|
| | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $2,259,594 |
| |
| $2,060,643 |
| |
| $2,139,919 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 458,907 |
| | 517,245 |
| | 402,777 |
|
| Purchased power | | 204,640 |
| | 252,390 |
| | 230,652 |
|
| Nuclear refueling outage expenses | | 68,769 |
| | 77,915 |
| | 83,968 |
|
| Other operation and maintenance | | 720,217 |
| | 724,831 |
| | 694,157 |
|
| Decommissioning | | 68,030 |
| | 60,420 |
| | 56,860 |
|
| Taxes other than income taxes | | 115,869 |
| | 104,771 |
| | 103,662 |
|
| Depreciation and amortization | | 307,351 |
| | 292,649 |
| | 277,146 |
|
| Other regulatory credits - net | | (11,186 | ) | | (14,807 | ) | | (16,074 | ) |
| TOTAL | | 1,932,597 |
| | 2,015,414 |
| | 1,833,148 |
|
| | | | | | | |
| OPERATING INCOME | | 326,997 |
| | 45,229 |
| | 306,771 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 15,499 |
| | 16,557 |
| | 18,452 |
|
| Interest and investment income | | 26,020 |
| | 25,406 |
| | 35,882 |
|
| Miscellaneous - net | | (18,566 | ) | | (14,874 | ) | | (13,967 | ) |
| TOTAL | | 22,953 |
| | 27,089 |
| | 40,367 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 140,087 |
| | 124,459 |
| | 122,075 |
|
| Allowance for borrowed funds used during construction | | (6,332 | ) | | (7,781 | ) | | (8,585 | ) |
| TOTAL | | 133,755 |
| | 116,678 |
| | 113,490 |
|
| | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | 216,195 |
| | (44,360 | ) | | 233,648 |
|
| | | | | | | |
| Income taxes | | (46,769 | ) | | (297,067 | ) | | 93,804 |
|
| | | | | | | |
| NET INCOME | | 262,964 |
| | 252,707 |
| | 139,844 |
|
| | | | | | | |
| Preferred dividend requirements | | — |
| | 1,249 |
| | 1,428 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | |
| $262,964 |
| |
| $251,458 |
| |
| $138,416 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $2,084,494 | | | $2,259,594 | | | $2,060,643 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 271,896 | | | 458,907 | | | 517,245 | |
| Purchased power | | 187,690 | | | 204,640 | | | 252,390 | |
| Nuclear refueling outage expenses | | 55,737 | | | 68,769 | | | 77,915 | |
| Other operation and maintenance | | 669,518 | | | 720,217 | | | 724,831 | |
| Decommissioning | | 73,319 | | | 68,030 | | | 60,420 | |
| Taxes other than income taxes | | 121,057 | | | 115,869 | | | 104,771 | |
| Depreciation and amortization | | 338,029 | | | 307,351 | | | 292,649 | |
| Other regulatory credits - net | | (35,310) | | | (11,186) | | | (14,807) | |
| TOTAL | | 1,681,936 | | | 1,932,597 | | | 2,015,414 | |
| | | | | | |
| OPERATING INCOME | | 402,558 | | | 326,997 | | | 45,229 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 15,019 | | | 15,499 | | | 16,557 | |
| Interest and investment income | | 35,579 | | | 26,020 | | | 25,406 | |
| Miscellaneous - net | | (21,908) | | | (18,566) | | | (14,874) | |
| TOTAL | | 28,690 | | | 22,953 | | | 27,089 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 144,834 | | | 140,087 | | | 124,459 | |
| Allowance for borrowed funds used during construction | | (6,595) | | | (6,332) | | | (7,781) | |
| TOTAL | | 138,239 | | | 133,755 | | | 116,678 | |
| | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | 293,009 | | | 216,195 | | | (44,360) | |
| | | | | | |
| Income taxes | | 47,777 | | | (46,769) | | | (297,067) | |
| | | | | | |
| NET INCOME | | 245,232 | | | 262,964 | | | 252,707 | |
| | | | | | |
| Preferred dividend requirements | | 0 | | | 0 | | | 1,249 | |
| | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | | $245,232 | | | $262,964 | | | $251,458 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
(Page left blank intentionally)
|
| | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
|
|
|
| |
| For the Years Ended December 31, |
| |
| 2019 |
| 2018 |
| 2017 |
| |
| (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $262,964 |
| |
| $252,707 |
| |
| $139,844 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 465,299 |
| | 443,698 |
| | 427,394 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 94,368 |
| | 129,524 |
| | 67,711 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | (58,077 | ) | | 4,294 |
| | (23,397 | ) |
| Fuel inventory | | (10,597 | ) | | 6,210 |
| | 3,402 |
|
| Accounts payable | | 3,059 |
| | (126,405 | ) | | 16,011 |
|
| Prepaid taxes and taxes accrued | | 24,942 |
| | 9,568 |
| | 40,127 |
|
| Interest accrued | | 3,895 |
| | 678 |
| | 1,635 |
|
| Deferred fuel costs | | 72,560 |
| | 43,869 |
| | 33,190 |
|
| Other working capital accounts | | 18,783 |
| | (30,118 | ) | | 15,087 |
|
| Provisions for estimated losses | | 14,901 |
| | 14,250 |
| | 16,047 |
|
| Other regulatory assets | | (131,873 | ) | | 32,460 |
| | (76,762 | ) |
| Other regulatory liabilities | | 39,293 |
| | (341,682 | ) | | 1,043,507 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | — |
| | — |
| | (1,047,837 | ) |
| Pension and other postretirement liabilities | | 5,831 |
| | (40,157 | ) | | (70,826 | ) |
| Other assets and liabilities | | (127,582 | ) | | (187,071 | ) | | (29,577 | ) |
| Net cash flow provided by operating activities | | 677,766 |
| | 211,825 |
| | 555,556 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (641,525 | ) | | (660,044 | ) | | (735,816 | ) |
| Allowance for equity funds used during construction | | 15,306 |
| | 17,013 |
| | 19,211 |
|
| Nuclear fuel purchases | | (54,344 | ) | | (99,417 | ) | | (151,424 | ) |
| Proceeds from sale of nuclear fuel | | 22,782 |
| | 54,810 |
| | 51,029 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 317,377 |
| | 300,801 |
| | 339,434 |
|
| Investment in nuclear decommissioning trust funds | | (336,519 | ) | | (315,163 | ) | | (352,138 | ) |
| Insurance proceeds | | — |
| | 14,790 |
| | — |
|
| Other | | 630 |
| | (1,517 | ) | | 392 |
|
| Net cash flow used in investing activities | | (676,293 | ) |
| (688,727 | ) |
| (829,312 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 834,038 |
| | 958,434 |
| | 294,656 |
|
| Retirement of long-term debt | | (548,952 | ) | | (690,488 | ) | | (175,560 | ) |
| Capital contribution from parent | | — |
| | 350,000 |
| | — |
|
| Redemption of preferred stock | | — |
| | (32,660 | ) | | — |
|
| Change in money pool payable - net | | (161,104 | ) | | 16,601 |
| | 114,905 |
|
| Changes in short-term borrowings - net | | — |
| | (49,974 | ) | | 49,974 |
|
| Distributions/dividends paid: | | |
| | |
| | |
|
| Common equity | | (115,000 | ) | | (91,751 | ) | | (15,000 | ) |
| Preferred stock | | — |
| | (1,606 | ) | | (1,428 | ) |
| Other | | (7,055 | ) | | 12,249 |
| | (8,084 | ) |
| Net cash flow provided by financing activities | | 1,927 |
| | 470,805 |
| | 259,463 |
|
| Net increase (decrease) in cash and cash equivalents | | 3,400 |
| | (6,097 | ) | | (14,293 | ) |
| Cash and cash equivalents at beginning of period | | 119 |
| | 6,216 |
| | 20,509 |
|
| Cash and cash equivalents at end of period | |
| $3,519 |
| |
| $119 |
| |
| $6,216 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $131,134 |
| |
| $118,731 |
| |
| $115,162 |
|
| Income taxes | |
| ($33,989 | ) | |
| $44,393 |
| |
| ($8,141 | ) |
| See Notes to Financial Statements. |
| |
|
| |
|
| |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $245,232 | | | $262,964 | | | $252,707 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 490,457 | | | 465,299 | | | 443,698 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 87,019 | | | 94,368 | | | 129,524 | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (24,507) | | | (58,077) | | | 4,294 | |
| Fuel inventory | | (10,066) | | | (10,597) | | | 6,210 | |
| Accounts payable | | (22,773) | | | 3,059 | | | (126,405) | |
| Prepaid taxes and taxes accrued | | 6 | | | 24,942 | | | 9,568 | |
| Interest accrued | | (43) | | | 3,895 | | | 678 | |
| Deferred fuel costs | | (1,186) | | | 72,560 | | | 43,869 | |
| Other working capital accounts | | (11,061) | | | 18,783 | | | (30,118) | |
| Provisions for estimated losses | | 6,289 | | | 14,901 | | | 14,250 | |
| Other regulatory assets | | (165,534) | | | (131,873) | | | 32,460 | |
| Other regulatory liabilities | | 106,878 | | | 39,293 | | | (341,682) | |
| | | | | | |
| Pension and other postretirement liabilities | | 42,576 | | | 5,831 | | | (40,157) | |
| Other assets and liabilities | | (83,469) | | | (127,582) | | | (187,071) | |
| Net cash flow provided by operating activities | | 659,818 | | | 677,766 | | | 211,825 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (775,595) | | | (641,525) | | | (660,044) | |
| Allowance for equity funds used during construction | | 15,019 | | | 15,306 | | | 17,013 | |
| Nuclear fuel purchases | | (100,678) | | | (54,344) | | | (99,417) | |
| Proceeds from sale of nuclear fuel | | 30,638 | | | 22,782 | | | 54,810 | |
| | | | | | |
| Proceeds from nuclear decommissioning trust fund sales | | 321,360 | | | 317,377 | | | 300,801 | |
| Investment in nuclear decommissioning trust funds | | (336,392) | | | (336,519) | | | (315,163) | |
| Payment for purchase of assets | | (5,988) | | | 0 | | | 0 | |
| Changes in money pool receivable - net | | (3,110) | | | 0 | | | 0 | |
| | | | | | |
| | | | | | |
| | | | | | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | 55,001 | | | 0 | | | 0 | |
| | | | | | |
| Insurance proceeds | | 0 | | | 0 | | | 14,790 | |
| Other | | 4,036 | | | 630 | | | (1,517) | |
| Net cash flow used in investing activities | | (795,709) | | | (676,293) | | | (688,727) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 1,071,121 | | | 834,038 | | | 958,434 | |
| Retirement of long-term debt | | (632,175) | | | (548,952) | | | (690,488) | |
| Capital contribution from parent | | 0 | | | 0 | | | 350,000 | |
| Redemption of preferred stock | | 0 | | | 0 | | | (32,660) | |
| Change in money pool payable - net | | (21,634) | | | (161,104) | | | 16,601 | |
| Changes in short-term borrowings - net | | 0 | | | 0 | | | (49,974) | |
| Distributions/dividends paid: | | | | | | |
| Common equity | | (95,000) | | | (115,000) | | | (91,751) | |
| Preferred stock | | 0 | | | 0 | | | (1,606) | |
| Other | | 2,188 | | | (7,055) | | | 12,249 | |
| Net cash flow provided by financing activities | | 324,500 | | | 1,927 | | | 470,805 | |
| Net increase (decrease) in cash and cash equivalents | | 188,609 | | | 3,400 | | | (6,097) | |
| Cash and cash equivalents at beginning of period | | 3,519 | | | 119 | | | 6,216 | |
| Cash and cash equivalents at end of period | | $192,128 | | | $3,519 | | | $119 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $140,735 | | | $131,134 | | | $118,731 | |
| Income taxes | | ($21,971) | | | ($33,989) | | | $44,393 | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $3,519 |
| |
| $118 |
|
| Temporary cash investments | | — |
| | 1 |
|
| Total cash and cash equivalents | | 3,519 |
| | 119 |
|
| Securitization recovery trust account | | 4,036 |
| | 4,666 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 117,679 |
| | 94,348 |
|
| Allowance for doubtful accounts | | (1,169 | ) | | (1,264 | ) |
| Associated companies | | 29,178 |
| | 48,184 |
|
| Other | | 117,653 |
| | 64,393 |
|
| Accrued unbilled revenues | | 108,489 |
| | 108,092 |
|
| Total accounts receivable | | 371,830 |
| | 313,753 |
|
| Deferred fuel costs | | — |
| | 19,235 |
|
| Fuel inventory - at average cost | | 33,745 |
| | 23,148 |
|
| Materials and supplies - at average cost | | 211,320 |
| | 196,314 |
|
| Deferred nuclear refueling outage costs | | 48,875 |
| | 78,966 |
|
| Prepayments and other | | 14,096 |
| | 14,553 |
|
| TOTAL | | 687,421 |
| | 650,754 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Decommissioning trust funds | | 1,101,283 |
| | 912,049 |
|
| Other | | 345 |
| | 5,480 |
|
| TOTAL | | 1,101,628 |
| | 917,529 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 12,293,483 |
| | 11,611,041 |
|
| Construction work in progress | | 197,775 |
| | 243,731 |
|
| Nuclear fuel | | 195,547 |
| | 220,602 |
|
| TOTAL UTILITY PLANT | | 12,686,805 |
| | 12,075,374 |
|
| Less - accumulated depreciation and amortization | | 5,019,826 |
| | 4,864,818 |
|
| UTILITY PLANT - NET | | 7,666,979 |
| | 7,210,556 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Other regulatory assets (includes securitization property of $1,706 as of December 31, 2019 and $14,329 as of December 31, 2018) | | 1,666,850 |
| | 1,534,977 |
|
| Deferred fuel costs | | 67,690 |
| | 67,294 |
|
| Other | | 15,065 |
| | 20,486 |
|
| TOTAL | | 1,749,605 |
| | 1,622,757 |
|
| | | | | |
| TOTAL ASSETS | |
| $11,205,633 |
| |
| $10,401,596 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2020 | | 2019 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $24,108 | | | $3,519 | |
| Temporary cash investments | | 168,020 | | | 0 | |
| Total cash and cash equivalents | | 192,128 | | | 3,519 | |
| Securitization recovery trust account | | 0 | | | 4,036 | |
| Accounts receivable: | | | | |
| Customer | | 183,719 | | | 117,679 | |
| Allowance for doubtful accounts | | (18,334) | | | (1,169) | |
| Associated companies | | 34,216 | | | 29,178 | |
| Other | | 35,845 | | | 117,653 | |
| Accrued unbilled revenues | | 109,000 | | | 108,489 | |
| Total accounts receivable | | 344,446 | | | 371,830 | |
| | | | |
| | | | |
| Fuel inventory - at average cost | | 43,811 | | | 33,745 | |
| Materials and supplies - at average cost | | 237,640 | | | 211,320 | |
| Deferred nuclear refueling outage costs | | 32,692 | | | 48,875 | |
| | | | |
| | | | |
| Prepayments and other | | 13,296 | | | 14,096 | |
| | | | |
| TOTAL | | 864,013 | | | 687,421 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Decommissioning trust funds | | 1,273,921 | | | 1,101,283 | |
| | | | |
| Other | | 341 | | | 345 | |
| TOTAL | | 1,274,262 | | | 1,101,628 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 12,905,322 | | | 12,293,483 | |
| | | | |
| Construction work in progress | | 234,213 | | | 197,775 | |
| Nuclear fuel | | 163,044 | | | 195,547 | |
| TOTAL UTILITY PLANT | | 13,302,579 | | | 12,686,805 | |
| Less - accumulated depreciation and amortization | | 5,255,355 | | | 5,019,826 | |
| UTILITY PLANT - NET | | 8,047,224 | | | 7,666,979 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets (includes securitization property of $0 as of December 31, 2020 and $1,706 as of December 31, 2019) | | 1,832,384 | | | 1,666,850 | |
| Deferred fuel costs | | 68,220 | | | 67,690 | |
| Other | | 14,028 | | | 15,065 | |
| TOTAL | | 1,914,632 | | | 1,749,605 | |
| | | | |
| TOTAL ASSETS | | $12,100,131 | | | $11,205,633 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | ENTERGY ARKANSAS, LLC AND SUBSIDIARIES | ENTERGY ARKANSAS, LLC AND SUBSIDIARIES | ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | LIABILITIES AND EQUITY |
| | | | | |
| | | December 31, | | | December 31, |
| | | 2019 | | 2018 | | | 2020 | | 2019 |
| | | (In Thousands) | | | (In Thousands) |
| | | | | | |
| CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | Currently maturing long-term debt | | $485,000 | | | $0 | |
| | Accounts payable: | | |
| | |
| Accounts payable: | | | | |
| Associated companies | |
| $111,785 |
| |
| $251,768 |
| Associated companies | | 59,448 | | | 111,785 | |
| Other | | 202,201 |
| | 187,387 |
| Other | | 208,591 | | | 202,201 | |
| Customer deposits | | 101,411 |
| | 99,053 |
| Customer deposits | | 98,506 | | | 101,411 | |
| Taxes accrued | | 81,831 |
| | 56,889 |
| Taxes accrued | | 81,837 | | | 81,831 | |
| | Interest accrued | | 22,788 |
| | 18,893 |
| Interest accrued | | 22,745 | | | 22,788 | |
| Deferred fuel costs | | 53,721 |
| | — |
| Deferred fuel costs | | 53,065 | | | 53,721 | |
| Current portion of unprotected excess accumulated deferred income taxes | | 9,296 |
| | 99,316 |
| Current portion of unprotected excess accumulated deferred income taxes | | 0 | | | 9,296 | |
| Other | | 38,760 |
| | 23,943 |
| Other | | 40,628 | | | 38,760 | |
| TOTAL | | 621,793 |
| | 737,249 |
| TOTAL | | 1,049,820 | | | 621,793 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 1,183,126 |
| | 1,085,545 |
| Accumulated deferred income taxes and taxes accrued | | 1,286,123 | | | 1,183,126 | |
| Accumulated deferred investment tax credits | | 31,701 |
| | 32,903 |
| Accumulated deferred investment tax credits | | 30,500 | | | 31,701 | |
| Regulatory liability for income taxes - net | | 478,174 |
| | 505,748 |
| Regulatory liability for income taxes - net | | 467,031 | | | 478,174 | |
| Other regulatory liabilities | | 559,555 |
| | 402,668 |
| Other regulatory liabilities | | 686,872 | | | 559,555 | |
| Decommissioning | | 1,242,616 |
| | 1,048,428 |
| Decommissioning | | 1,314,160 | | | 1,242,616 | |
| Accumulated provisions | | 63,880 |
| | 48,979 |
| Accumulated provisions | | 70,169 | | | 63,880 | |
| Pension and other postretirement liabilities | | 319,075 |
| | 313,295 |
| Pension and other postretirement liabilities | | 361,682 | | | 319,075 | |
| Long-term debt (includes securitization bonds of $6,772 as of December 31, 2019 and $20,898 as of December 31, 2018) | | 3,517,208 |
| | 3,225,759 |
| |
| Long-term debt (includes securitization bonds of $0 as of December 31, 2020 and $6,772 as of December 31, 2019) | | Long-term debt (includes securitization bonds of $0 as of December 31, 2020 and $6,772 as of December 31, 2019) | | 3,482,507 | | | 3,517,208 | |
| Other | | 62,568 |
| | 17,919 |
| Other | | 75,098 | | | 62,568 | |
| TOTAL | | 7,457,903 |
| | 6,681,244 |
| TOTAL | | 7,774,142 | | | 7,457,903 | |
| | | | | | | | | |
| Commitments and Contingencies | |
|
| |
|
| Commitments and Contingencies | | 0 | | 0 |
| | | | | | | |
| EQUITY | | |
| | |
| EQUITY | | | | |
| Member's equity | | 3,125,937 |
| | 2,983,103 |
| Member's equity | | 3,276,169 | | | 3,125,937 | |
| TOTAL | | 3,125,937 |
| | 2,983,103 |
| TOTAL | | 3,276,169 | | | 3,125,937 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $11,205,633 |
| |
| $10,401,596 |
| TOTAL LIABILITIES AND EQUITY | | $12,100,131 | | | $11,205,633 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| See Notes to Financial Statements. | | | | |
|
| | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY |
For the Years Ended December 31, 2020, 2019, 2018, and 20172018 |
| |
| |
| Member's Equity |
| (In Thousands) |
| |
Balance at December 31, 2016 |
| $2,253,317 |
|
Net income | 139,844 |
|
Common equity distributions | (15,000 | ) |
Preferred stock dividends | (1,428 | ) |
Other | 21 |
|
| Balance at December 31, 2017 |
| $2,376,754 |
|
| Net income | 252,707 |
|
| Capital contributions from parent | 350,000 |
|
| |
| Common equity distributions | (91,751(91,751) | ) |
| Non-cash contribution from parent | 94,335 |
|
| Preferred stock dividends | (1,249(1,249) | ) |
| Other | 2,307 |
|
| Balance at December 31, 2018 |
| $2,983,103 |
|
| Net income | 262,964 |
|
| |
| |
| Common equity distributions | (115,000(115,000) | ) |
Other | (5,130 | ) |
| |
| Other | (5,130) | |
| Balance at December 31, 2019 |
| $3,125,937 |
|
| Net income | 245,232 | |
| |
| |
| Common equity distributions | (95,000) | |
| |
| |
| |
| Balance at December 31, 2020 | $3,276,169 | |
| |
| See Notes to Financial Statements. | |
|
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | | |
| | | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | | | | | | | |
| Operating revenues | |
| $2,259,594 |
| |
| $2,060,643 |
| |
| $2,139,919 |
| |
| $2,086,608 |
| |
| $2,253,564 |
|
| Net income | |
| $262,964 |
| |
| $252,707 |
| |
| $139,844 |
| |
| $167,212 |
| |
| $74,272 |
|
| Total assets | |
| $11,205,633 |
| |
| $10,401,596 |
| |
| $10,134,029 |
| |
| $9,606,117 |
| |
| $8,747,774 |
|
| Long-term obligations (a) | |
| $3,517,208 |
| |
| $3,225,759 |
| |
| $2,983,749 |
| |
| $2,746,435 |
| |
| $2,691,189 |
|
| | | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund. |
| | | | | | | | | | | |
| | | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | | (Dollars In Millions) |
| | | | | | | | | | | |
| Electric Operating Revenues: | | |
| | |
| | |
| | |
| | |
|
| Residential | |
| $795 |
| |
| $807 |
| |
| $768 |
| |
| $789 |
| |
| $824 |
|
| Commercial | | 539 |
| | 426 |
| | 495 |
| | 495 |
| | 515 |
|
| Industrial | | 521 |
| | 434 |
| | 472 |
| | 446 |
| | 477 |
|
| Governmental | | 21 |
| | 17 |
| | 19 |
| | 18 |
| | 20 |
|
| Total billed retail | | 1,876 |
| | 1,684 |
| | 1,754 |
| | 1,748 |
| | 1,836 |
|
| Sales for resale: | | |
| | |
| | |
| | |
| | |
|
| Associated companies | | 118 |
| | 104 |
| | 128 |
| | 49 |
| | 128 |
|
| Non-associated companies | | 140 |
| | 145 |
| | 121 |
| | 118 |
| | 195 |
|
| Other | | 126 |
| | 128 |
| | 137 |
| | 172 |
| | 95 |
|
| Total | |
| $2,260 |
| |
| $2,061 |
| |
| $2,140 |
| |
| $2,087 |
| |
| $2,254 |
|
| | | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | | |
| | |
| | |
| | |
|
| Residential | | 7,996 |
| | 8,248 |
| | 7,298 |
| | 7,618 |
| | 8,016 |
|
| Commercial | | 5,822 |
| | 5,967 |
| | 5,825 |
| | 5,988 |
| | 6,020 |
|
| Industrial | | 7,759 |
| | 8,071 |
| | 7,528 |
| | 6,795 |
| | 6,889 |
|
| Governmental | | 241 |
| | 239 |
| | 237 |
| | 237 |
| | 235 |
|
| Total retail | | 21,818 |
| | 22,525 |
| | 20,888 |
| | 20,638 |
| | 21,160 |
|
| Sales for resale: | | |
| | |
| | |
| | |
| | |
|
| Associated companies | | 2,180 |
| | 1,773 |
| | 1,782 |
| | 1,609 |
| | 2,239 |
|
| Non-associated companies | | 7,206 |
| | 6,447 |
| | 6,549 |
| | 7,115 |
| | 7,980 |
|
| Total | | 31,204 |
| | 30,745 |
| | 29,219 |
| | 29,362 |
| | 31,379 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | | (In Thousands) |
| | | | | | | | | | |
| Operating revenues | | $2,084,494 | | | $2,259,594 | | | $2,060,643 | | | $2,139,919 | | | $2,086,608 | |
| Net income | | $245,232 | | | $262,964 | | | $252,707 | | | $139,844 | | | $167,212 | |
| Total assets | | $12,100,131 | | | $11,205,633 | | | $10,401,596 | | | $10,134,029 | | | $9,606,117 | |
| Long-term obligations (a) | | $3,482,507 | | | $3,517,208 | | | $3,225,759 | | | $2,983,749 | | | $2,746,435 | |
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund. |
| | | | | | | | | | |
| | | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | | | | | | | | | | |
| Residential | | $841 | | | $795 | | | $807 | | | $768 | | | $789 | |
| Commercial | | 466 | | | 539 | | | 426 | | | 495 | | | 495 | |
| Industrial | | 462 | | | 521 | | | 434 | | | 472 | | | 446 | |
| Governmental | | 18 | | | 21 | | | 17 | | | 19 | | | 18 | |
| Total billed retail | | 1,787 | | | 1,876 | | | 1,684 | | | 1,754 | | | 1,748 | |
| Sales for resale: | | | | | | | | | | |
| Associated companies | | 105 | | | 118 | | | 104 | | | 128 | | | 49 | |
| Non-associated companies | | 68 | | | 140 | | | 145 | | | 121 | | | 118 | |
| Other | | 124 | | | 126 | | | 128 | | | 137 | | | 172 | |
| Total | | $2,084 | | | $2,260 | | | $2,061 | | | $2,140 | | | $2,087 | |
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | | |
| Residential | | 7,584 | | | 7,996 | | | 8,248 | | | 7,298 | | | 7,618 | |
| Commercial | | 5,356 | | | 5,822 | | | 5,967 | | | 5,825 | | | 5,988 | |
| Industrial | | 7,586 | | | 7,759 | | | 8,071 | | | 7,528 | | | 6,795 | |
| Governmental | | 223 | | | 241 | | | 239 | | | 237 | | | 237 | |
| Total retail | | 20,749 | | | 21,818 | | | 22,525 | | | 20,888 | | | 20,638 | |
| Sales for resale: | | | | | | | | | | |
| Associated companies | | 1,659 | | | 2,180 | | | 1,773 | | | 1,782 | | | 1,609 | |
| Non-associated companies | | 4,198 | | | 7,206 | | | 6,447 | | | 6,549 | | | 7,115 | |
| Total | | 26,606 | | | 31,204 | | | 30,745 | | | 29,219 | | | 29,362 | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
Hurricane Laura, Hurricane Delta, and Hurricane Zeta
In August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.0 billion, including approximately $1.67 billion in capital costs and approximately $330 million in non-capital costs. This estimate includes all costs to restore power and repair or replace the damages from the hurricanes, except for the cost to repair or replace damage incurred to an Entergy Louisiana transmission line in southeast Louisiana, and the amount of that cost could be significant. The restoration plan for this transmission line and the related cost estimate is still being evaluated. Also, Entergy Louisiana’s revenues were adversely affected in 2020, primarily due to power outages resulting from the hurricanes. Entergy Louisiana is considering all reasonable avenues to recover storm-related costs from Hurricane Laura, Hurricane Delta, and Hurricane Zeta, including securitization. Storm cost recovery or financing will be subject to review by applicable regulatory authorities.
Entergy Louisiana recorded accounts payable and corresponding construction work in progress and regulatory assets for the estimated costs incurred that were necessary to return customers to service. Entergy Louisiana recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles. Because Entergy Louisiana has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments to facilitate issuance of shorter-term bonds to provide interim financing for restoration costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff filed a joint motion seeking approval to exclude from the derivation of Entergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta costs on an interim basis. In November 2020 the LPSC issued an order approving the joint motion, and Entergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana drew $257 million from its funded storm reserves.
In December 2020, Entergy Louisiana provided the LPSC with notification that it intends to initiate a storm cost recovery proceeding in the near future, which will permit the LPSC to retain any outside consultants and counsel needed to review the storm cost recovery application. In February 2021 the LPSC voted to retain outside counsel and consultants to assist in the review of Entergy Louisiana’s upcoming storm cost recovery application, which is expected to be filed in March 2021.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Louisiana’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $50 million to $60 million. Natural gas purchases for Entergy Louisiana for February 1st through 25th, 2021 are approximately $190 million compared to natural gas purchases for February 2020 of $39 million.
Results of Operations
20192020 Compared to 20182019
Net Income
Net income increased $15.9$390.8 million primarily due to the $382.8 million reduction in deferred income tax expense related to the basis of assets contributed in the 2015 Entergy Louisiana and Entergy Gulf States Louisiana business combination as a result of the resolution of the 2014-2015 IRS audit in the fourth quarter 2020 and the $58 million reduction in income tax expense resulting from an IRS settlement in the first quarter 2020 related to the uncertain tax position regarding the Hurricane Isaac Louisiana Act 55 financing, which also resulted in a $29 million ($21 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s agreement to share the savings with customers. Also contributing to the increase were higher retail electric price.price, lower other operation and maintenance expenses, and a lower effective income tax rate. The increase was partially offset by an income tax benefit recognized in 2018 as a result of the settlement of the 2012-2013 IRS audit, higher depreciation and amortization expenses, higher other operation and maintenance expenses, lower volume/weather, lower other income, higher interest expense, and higher interest expense.taxes other than income taxes. See Note 3 to the financial statements for further discussion of the tax audit resolution and the tax settlement.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 20192020 to 2018:
|
| | | | |
| Amount |
| (In Millions) |
20182019 operating revenues |
| $4,296.3 |
|
| Fuel, rider, and other revenues that do not significantly affect net income | (218.1(330.3) | ) |
Retail electric priceVolume/weather | 132.9(68.8) |
|
| Return of unprotected excess accumulated deferred income taxes to customers | 102.57.5 |
|
Volume/weatherRetail electric price | (28.4176.3 | ) |
20192020 operating revenues |
| $4,285.2 |
|
Entergy Louisiana’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The retail electric pricevolume/weather variance is primarily due to decreased commercial and industrial usage as a result of the COVID-19 pandemic, the effects of Hurricane Laura, Hurricane Delta, and Hurricane Zeta on sales, and the effect of less favorable weather on residential sales, partially offset by increased residential usage as a result of the COVID-19 pandemic. The decrease in industrial usage is partially offset by an increase in formula rate plan revenues effective September 2018demand from expansion projects, primarily in the transportation and an interim increase in formula rate plan revenues effective June 2019 due to the inclusionchemicals industries. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the first-year revenue requirement
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
COVID-19 pandemic. See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for the St. Charles Power Station, each as approved by the LPSC. See Note 2 to the financial statements for further discussion of the formula rate plan proceedings.storms.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through changes in the formula rate plan effective May 2018. In 2019, $38.62020, $31.1 million was returned to customers as compared to $141.1$38.6 million in 2018.2019. There was no effect on net income as the reduction in operating revenues was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
The volume/weatherretail electric price variance is primarily due to a decrease of 673 GWh, or 3%, in billed electricity usage for residential and commercial customers, including the effect of less favorable weather. The decrease was partially offset by an increase in industrial usage primarily due to an increase in demand from expansion projects, primarilyformula rate plan revenues effective June 2019 due to the inclusion of the first-year revenue requirement for the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and effective April 2020 due to the inclusion of the first-year revenue requirement for the Lake Charles Power Station and increases in formula rate plan revenues effective September 2019 and September 2020. See Note 2 to the chemicals and transportation industries.financial statements for further discussion of the formula rate plan proceedings.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other Income Statement Variances
Other operation and maintenance expenses increaseddecreased primarily due to:
•a $14.8 million gain in 2018 from the saledecrease of Willow Glen Power Station;
an increase of $12.7$10.2 million in information technology costsnuclear generation expenses primarily due to highera lower scope of work performed in 2020 as compared to 2019, in part as a result of the COVID-19 pandemic;
•a decrease of $9.5 million primarily due to contract costs in 2019 related to applications and infrastructure support, enhanced cyber security, and upgrades and maintenance;
an increase of $12.4 million in spending on initiatives to explore new customer products and services; and
an increase of $9.6 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2019 as compared to prior year.
The increase was partially offset by:
•a decrease of $8.5$6.8 million in loss provisions;
•higher nuclear insurance refunds of $5.9 million;
•a decrease of $5.8 million in energy efficiency costs due to the timing of recovery from customers; and
•a decrease of $4.3 million in non-nuclear generation expenses primarily due to a lower scope of work performed during plant outages in 20192020 as compared to 2018; and
the effects of recordingsame period in 2019, partially offset by increases resulting from the final judgmentJ. Wayne Leonard Power Station (formerly St. Charles Power Station) and the Lake Charles Power Station being placed in service.
The decrease was partially offset by:
•an increase of $4.1 million in compensation and benefits costs primarily due to resolve claimsan increase in net periodic pension and other postretirement benefits costs as a result of a decrease in the River Bend damages case againstdiscount rate used to value the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of $5.2 million of spent nuclear fuel storage costs previously recorded as other operationbenefit liabilities. See “Critical Accounting Estimates” below and maintenance expense. See Note 811 to the financial statements for afurther discussion of the spent nuclear fuel litigation.pension and other postretirement benefit costs; and
•several individually insignificant items.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes. Ad valorem taxes increased primarily due toresulting from higher property assessments.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station,Station), which was placed into service in May 2019.2019 and the Lake Charles Power Station, which was placed in service in March 2020.
Other regulatory charges (credits) include regulatory charges of $73.1$32.6 million recorded in 2018the fourth quarter 2020 due to reflecta settlement with the effects of a provisionIRS related to the uncertain tax position regarding Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing because the savings will be shared with customers and $29 million recorded in the first quarter 2020 due to a settlement reached inwith the formula rate plan extension proceedingIRS related to return the benefits ofuncertain tax position regarding Hurricane Isaac Louisiana Act 55 financing because the lower federal income tax rate in 2018 tosavings will be shared with customers. See Note 23 to the financial statements for further discussion of the formula rate plan extension proceeding.settlements and savings obligations.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other income decreased primarily due to:
•a decrease in the allowance for equity funds used during construction due to higher construction work in progress in 2019, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and the Lake Charles Power Station projects; and
•changes in decommissioning trust fund activity.
Interest expense increased primarily due to to:
•the issuances of $300 million of 4.20% Series mortgage bonds and $350 million of 2.90% Series mortgage bonds, each in March 2020;
•the issuance of $525 million of 4.20% Series mortgage bonds in March 2019.2019; and
•a decrease in the allowance for borrowed funds used during construction due to higher construction work in progress in 2019, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and Lake Charles Power Station projects.
The effective income tax rates were (54.6%) for 2020 and 15% for 2019 and (8.8%) for 2018.2019. The difference in the effective income tax rate versus the federal statutory rate of 15%21% for 2020 was primarily due to completion of the 2014-2015 IRS audit effectively settling the tax positions for those years. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxestaxes. See Notes 2 and book and tax differences related3 to the non-taxable income distributions earned on preferred membership interests. The difference infinancial statements for a discussion of the effective income tax rate of (8.8%) versuseffects and regulatory activity regarding the federal statutory rate of 21% for 2018 was primarily due to the amortization of excess accumulated deferred income taxesTax Cuts and an IRS audit settlement for the 2012-2013 tax returns.Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory rates of 21% to the effective income tax rates.
20182019 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended December 31, 20182019, filed with the SEC on February 21, 2020, for discussion of results of operations for 20182019 compared to 2017.2018.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $2,006 | | | $43,364 | | | $35,907 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 1,072,986 | | | 1,236,002 | | | 1,395,204 | |
| Investing activities | (1,944,671) | | | (1,653,634) | | | (1,878,208) | |
| Financing activities | 1,597,699 | | | 376,274 | | | 490,461 | |
| Net increase (decrease) in cash and cash equivalents | 726,014 | | | (41,358) | | | 7,457 | |
| | | | | |
| Cash and cash equivalents at end of period | $728,020 | | | $2,006 | | | $43,364 | |
Entergy Louisiana, LLC 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, 2018, and 2019 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 the regulatory proceedings that have considered the effects of the Act.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2019, 2018, and 2017 were as follows:
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $43,364 |
| |
| $35,907 |
| |
| $213,850 |
|
| | | | | | |
| Net cash provided by (used in): | | | |
| | |
|
| Operating activities | 1,236,002 |
| | 1,395,204 |
| | 1,337,545 |
|
| Investing activities | (1,653,634 | ) | | (1,878,208 | ) | | (1,787,409 | ) |
| Financing activities | 376,274 |
| | 490,461 |
| | 271,921 |
|
| Net increase (decrease) in cash and cash equivalents | (41,358 | ) | | 7,457 |
| | (177,943 | ) |
| �� | | | | | |
| Cash and cash equivalents at end of period |
| $2,006 |
| |
| $43,364 |
| |
| $35,907 |
|
20192020 Compared to 20182019
Operating Activities
Net cash flow provided by operating activities decreased $159.2$163 million in 20192020 primarily due to:
•an increase of $186.1 million in storm spending in 2020, primarily due to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration efforts. See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of storm restoration efforts;
•lower collections of receivables from customers, in part due to the COVID-19 pandemic;
•the timing of recovery of fuel and purchased power costs; and
•an increase of $21.5 million in interest paid.
The decrease was partially offset by:
•a decrease in $43.7 million in spending on nuclear refueling outages;
•the timing of payments to vendors; and
•income tax paymentsrefunds of $15.3$14.7 million in 20192020 compared to $105.2$15.3 million in income tax refundspayments in 2018.2019. Entergy Louisiana had income tax paymentsrefunds in 20192020 and income tax refundspayments in 20182019 in accordance with an intercompany tax allocation agreement. TheEntergy Louisiana had income tax refunds in 2018 resulted from the utilization of Entergy Louisiana’s net operating losses;
an increase of $65.2 million in spending on nuclear refueling outages;
the receipt of $58.6 million in 2018 from Entergy Arkansas2020 as a result of a compliance filing maderefund of an overpayment on a prior year state income tax return.
Investing Activities
Net cash flow used in responseinvesting activities increased $291 million in 2020 primarily due to:
•an increase of $709.7 million in storm spending 2020, primarily due to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration efforts, See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of storm restoration efforts;
•the FERC’s October 2018 orderpurchase of Washington Parish Energy Center in the Entergy Arkansas opportunity sales proceeding. The $58.6 million was credited to Entergy Louisiana customers in 2019.November 2020 for approximately $222 million. See Note 214 to the financial statements for further discussion of the opportunity sales proceeding;Washington Parish Energy Center purchase;
the timing of payments to vendors;
•an increase of $25.7 million in storm expenses in 2019;
an increase of $24.5 million in interest paid; and
the timing of collection of receivables from customers.
The decrease was partially offset by a decrease in return of unprotected excess accumulated deferred income taxes to customers and the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of the effects and the regulatory activity regarding the Tax Cuts and Jobs Act.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Investing Activities
Net cash flow used in investing activities decreased $224.6 million in 2019 primarily due to a decrease of $320 million in fossil-fueled generation expenditures, primarily due to lower spending on the St. Charles Power Station and Lake Charles Power Station projects in 2019 and money pool activity. The decrease was partially offset by:
an increase of $63.6 million in transmission expenditures primarily due to a higher scope of work performed in 2019 as compared to the same period in 2018;
an increase of $63.1$16.7 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Louisiana’s distribution system, including increased spending on advanced metering infrastructure; and
•money pool activity.
The increase was partially offset by:
•an increase of $46.5$302.2 million in net receipts from storm reserve escrow accounts;
•a decrease of $207.8 million in non-nuclear generation construction expenditures due to higher spending in 2019.2019 on the Lake Charles Power Station and J. Wayne Leonard Power Station (formerly St. Charles Power Station) projects;
•a decrease of $133.1 million in transmission construction expenditures primarily due to a lower scope of work performed on various projects in 2020 as compared to 2019;
Decreases•a decrease of $89.5 million in nuclear construction expenditures primarily due to a lower scope of work performed on various nuclear projects in 2020 as compared to 2019; and
•a decrease of $26.1 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.
Increases in Entergy Louisiana’s receivable from the money pool are a sourceuse of cash flow, and Entergy Louisiana’s receivable from the money pool decreasedincreased by $46.8$13.4 million in 20192020 compared to increasingdecreasing by $35.7 $46.8
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
million in 2018.2019. 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 decreased $114.2increased $1,221.4 million in 20192020 primarily due to:
•the issuance of $750 million$1.1 billion of 4.00%0.62% Series mortgage bonds in March 2018. A portionNovember 2020;
•the issuance of the proceeds was used to repay $375$350 million of 6.0%2.90% Series mortgage bonds in May 2018;
the issuance of $600and $300 million of 4.20% Series mortgage bonds, each in August 2018. A portionMarch 2020;
•the issuance of the proceeds was used to repay $300 million of 6.5%2.90% Series mortgage bonds and $300 million of 1.60% Series mortgage bonds, each in September 2018;November 2020; and
an increase•a decrease of $80$186.5 million in common equity distributions in 20192020 primarily due to maintain Entergy Louisiana’supcoming capital structure.expenditures.
The decreaseincrease was partially offset by:
•the issuance of $525 million of 4.20% Series mortgage bonds in March 2019;
•the repayment in August 2020 of $250 million of 3.95% Series mortgage bonds due October 2020;
•the repayment in December 2020 of $200 million of 5.25% Series mortgage bonds due July 2052;
•money pool activity;
•the repayment in December 2020 of $100 million of 4.70% Series mortgage bonds due June 2063; and
•net repayments of short-termlong-term borrowings of $43.5$62 million in 20182020 on the nuclear fuel company variable interest entities’ credit facilities.
IncreasesDecreases in Entergy Louisiana’s payable to the money pool are a sourceuse of cash flow, and Entergy Louisiana’s payable to the money pool increaseddecreased by $82.8 million in 2020 compared to increasing by $82.8 million in 2019.
See Note 5 to the financial statements for details of long-term debt.
20182019 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended December 31, 20182019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 20182019 compared to 2017.2018.
Capital Structure
Entergy Louisiana’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for Entergy Louisiana is primarily due to the net issuances of long-term debt in 2020.
| | | | | | | | | | | |
| | December 31,
2020 | | December 31,
2019 |
| Debt to capital | 54.8 | % | | 53.4 | % |
| Effect of excluding securitization bonds | 0.0 | % | | (0.1 | %) |
| Debt to capital, excluding securitization bonds (a) | 54.8 | % | | 53.3 | % |
| Effect of subtracting cash | (2.1 | %) | | (0.1 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 52.7 | % | | 53.2 | % |
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
|
| | | | | |
| | December 31,
2019 | | December 31,
2018 |
| Debt to capital | 53.4 | % | | 53.6 | % |
| Effect of excluding securitization bonds | (0.1 | %) | | (0.3 | %) |
| Debt to capital, excluding securitization bonds (a) | 53.3 | % | | 53.3 | % |
| Effect of subtracting cash | (0.1 | %) | | (0.1 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 53.2 | % | | 53.2 | % |
| |
(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, finance lease obligations, 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 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 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 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 distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Louisiana may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Louisiana 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
•distribution and interest payments.
Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2022 | | 2023 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $365 | | | $460 | | | $785 | |
| Transmission | 425 | | | 340 | | | 230 | |
| Distribution | 540 | | | 485 | | | 500 | |
| Utility Support | 160 | | | 130 | | | 115 | |
| Total | $1,490 | | | $1,415 | | | $1,630 | |
|
| | | | | | | | | | | |
| | 2020 | | 2021 | | 2022 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $580 |
| |
| $485 |
| |
| $320 |
|
| Transmission | 440 |
| | 445 |
| | 230 |
|
| Distribution | 300 |
| | 245 |
| | 190 |
|
| Utility Support | 300 |
| | 385 |
| | 390 |
|
| Total |
| $1,620 |
| |
| $1,560 |
| |
| $1,130 |
|
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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| | (In Millions) |
| Long-term debt (a) | $557 | | | $2,294 | | | $1,495 | | | $9,506 | | | $13,852 | |
| Operating leases (b) | $13 | | | $19 | | | $10 | | | $4 | | | $46 | |
| Finance leases (b) | $4 | | | $7 | | | $4 | | | $2 | | | $17 | |
| Purchase obligations (c) | $687 | | | $1,463 | | | $1,472 | | | $4,838 | | | $8,460 | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $640 |
| |
| $1,120 |
| |
| $1,550 |
| |
| $8,662 |
| |
| $11,972 |
|
| Operating leases (b) |
| $11 |
| |
| $17 |
| |
| $8 |
| |
| $3 |
| |
| $39 |
|
| Finance leases (b) |
| $4 |
| |
| $7 |
| |
| $5 |
| |
| $3 |
| |
| $19 |
|
| Purchase obligations (c) |
| $731 |
| |
| $1,423 |
| |
| $1,521 |
| |
| $5,905 |
| |
| $9,580 |
|
(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)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.
| |
(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) | 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 $38.8$59.9 million to its qualified pension plans and approximately $18.5$15.6 million to its other postretirement health care and life insurance plans in 2020,2021, although the 20202021 required pension contributions will be known with more certainty when the January 1, 20202021 valuations are completed, which is expected by April 1, 2020.2021. 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 $808.4 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 the Washington Parish Energy Center and Lake Charles Power Station, each discussed below; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhancemaintain reliability and improve service to customers, including investment to support advanced metering;meters and related investments; resource planning, including potential generation and renewables projects; system improvements; investments in River Bend and Waterford 3; software and security; 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 estimatedEstimated 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.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 an agreement with a subsidiary of Calpine Corporation for the construction and purchase 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. 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. In April 2018 the parties reached a settlement recommending certification and cost recovery through the additional capacity mechanism of the formula rate plan, consistent with prior LPSC precedent with respect to the certification and recovery of plants previously acquired by Entergy Louisiana. The LPSC issued an order approving the settlement in May 2018. Construction is in progress and commercial operation is expected to occur by the end of 2020.
Sources of Capital
Entergy Louisiana’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•storm reserve escrow accounts;
•debt or preferred membership interest issuances;issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Louisiana may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest 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. 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.
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | | 2017 |
| (In Thousands) |
| $13,426 | | ($82,826) | | $46,843 | | $11,173 |
|
| | | | | | |
| 2019 | | 2018 | | 2017 | | 2016 |
| (In Thousands) |
| ($82,826) | | $46,843 | | $11,173 | | $22,503 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Louisiana has a credit facility in the amount of $350 million scheduled to expire in September 2024. The credit facility includes fronting commitments for the issuance of letters of credit against $15 million of the borrowing capacity of the facility. As of December 31, 2019,2020, there were no cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy Louisiana 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, 2019, a $12.32020, $2.2 million letterin letters of credit waswere outstanding under Entergy Louisiana’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
The Entergy Louisiana nuclear fuel company variable interest entities have two separate credit facilities, each in the amount of $105 million and scheduled to expire in September 2021.2022. As of December 31, 2019, $70.32020, $18.9 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, 2019, $49.92020, $39.3 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 obtained authorizations from the FERC through November 2020July 2022 for the following:
•short-term borrowings not to exceed an aggregate amount of $450 million at any time outstanding;
•long-term borrowings and security issuances; and
•borrowings by its nuclear fuel company variable interest entities.
See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.
Hurricane Isaac
In 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 Louisiana to 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 ProjectRetail Rates - Gas
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 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
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 the upper end of the earnings band 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 LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2007, 2015.
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 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.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power 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.
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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
Formula Rate Plan
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 was still appropriate or could 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 proceeding. In March 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. 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.
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.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Energy Efficiency Programs
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 and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. 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. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
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 Reliability Corporation (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
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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.
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.
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.
The PUCT determined that unrecovered costs that may 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 amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
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.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
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 Louisiana announced that it intendedholds non-exclusive franchises to pursueprovide electric service in approximately 175 incorporated municipalities and in the solid fuel repoweringunincorporated areas of a 538 MW unit at its Little Gypsy plant. In March 2009 the LPSC voted in favorapproximately 59 parishes of a motion directingLouisiana. Entergy Louisiana holds non-exclusive franchises to temporarily suspendprovide natural gas service to customers in the repowering projectCity of Baton Rouge and based upon an analysisin 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 Mississippi has received from the MPSC certificates of the project’s economic viability,public convenience and necessity to make a recommendation regarding whetherprovide electric service to proceed with the project. This action was based uponareas within 45 counties, including a number of factors includingmunicipalities, 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.
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Entergy New Orleans provides electric and gas service in the recent declineCity of New Orleans pursuant to indeterminate permits set forth in naturalcity ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas prices,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 over the period 2020-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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, 2020, is indicated below:
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| | | Owned and Leased Capability MW(a) |
| Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,175 | | | 2,091 | | | 1,817 | | | 1,194 | | | 73 | | | — | |
| Entergy Louisiana | | 11,317 | | | 8,827 | | | 2,144 | | | 346 | | | — | | | — | |
| Entergy Mississippi | | 3,347 | | | 2,929 | | | — | | | 416 | | | — | | | 2 | |
| Entergy New Orleans | | 665 | | | 638 | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 2,260 | | | 2,005 | | | — | | | 255 | | | — | | | — | |
| System Energy | | 1,256 | | | — | | | 1,256 | | | — | | | — | | | — | |
| Total | | 24,020 | | | 16,490 | | | 5,217 | | | 2,211 | | | 73 | | | 29 | |
(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 21,591 MW over the previous decade.
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, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation 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 8,801 MW of new long-term resources and the deactivation of about 4,664 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.
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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 MISO reliability requirements as well as environmental concerns,long-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:
•Entergy Louisiana’s construction of the unknown costs980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Texas’s construction of carbon legislationthe 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•In October 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and changesthe facility is scheduled to be in service by early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the capital/financial markets. purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020 and the facility is scheduled to be in service by the end of 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility.The facility was placed in service in December 2020;
•In April 2009,June 2020, Entergy Louisiana compliedArkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the LPSC’s directive and recommendedAPSC seeking a finding 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 moretransaction is in the public interest and prudent.requesting all necessary approvals. Closing is expected to occur by the end of 2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas.In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals.Closing is expected to occur by the end of 2023.
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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’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s 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);
•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 Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf 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 petroleum 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, 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 10-year agreement 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;
•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;
•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 approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 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 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 received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
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•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas.The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP was seeking 300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
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; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; 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); and Entergy Mississippi’s October 2009,2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility is an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, owned by East Texas Electric Cooperative. Entergy Texas is currently seeking regulatory certification to move forward with the purchase of the facility. The facility has been in operation since January 2010.
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Power Through Program
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation that is to be installed at commercial and industrial customer premises. If approved, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.”
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-electric production facilities, combustion-turbine generators, pressurized and boiling water nuclear reactors, and inverter-based technologies operating in the MISO energy and ancillary services market. 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 facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of 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 Bulk Electric System reliability standards within the SERC Region.
Gas Property
As of December 31, 2020, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2020, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy 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 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 of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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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 2018-2020 were:
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| | | 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 |
| 2020 | | 47 | | | 1.92 | | | 29 | | | 0.57 | | | 3 | | | 2.54 | | | 8 | | | 4.36 | | | 13 | | | 2.48 | |
| 2019 | | 40 | | | 2.33 | | | 28 | | | 0.73 | | | 6 | | | 2.31 | | | 8 | | | 4.86 | | | 18 | | | 2.71 | |
| 2018 | | 39 | | | 2.84 | | | 27 | | | 0.84 | | | 9 | | | 2.24 | | | 8 | | | 5.23 | | | 17 | | | 3.71 | |
Actual 2020 and projected 2021 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:
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| | Natural Gas | | Nuclear | | Coal | | Purchased Power (d) | | MISO Purchases (e) |
| | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 |
| Entergy Arkansas (a) | 24 | % | | 35 | % | | 60 | % | | 51 | % | | 10 | % | | 13 | % | | 1 | % | | 1 | % | | 5 | % | | — | |
| Entergy Louisiana | 51 | % | | 59 | % | | 26 | % | | 27 | % | | 1 | % | | 2 | % | | 9 | % | | 12 | % | | 13 | % | | — | |
| Entergy Mississippi (b) | 73 | % | | 69 | % | | 14 | % | | 22 | % | | 4 | % | | 9 | % | | — | | | — | | | 9 | % | | — | |
| Entergy New Orleans (b) | 55 | % | | 56 | % | | 33 | % | | 40 | % | | 1 | % | | 2 | % | | 2 | % | | 2 | % | | 9 | % | | — | |
| Entergy Texas | 39 | % | | 60 | % | | 11 | % | | 13 | % | | 2 | % | | 6 | % | | 23 | % | | 21 | % | | 25 | % | | — | |
| System Energy (c) | — | | | — | | | 100 | % | | 100 | % | | — | | | — | | | — | | | — | | | — | | | — | |
| Utility (a) (b) | 47 | % | | 55 | % | | 29 | % | | 31 | % | | 3 | % | | 6 | % | | 8 | % | | 8 | % | | 13 | % | | — | |
(a)Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2020 and is expected to provide less than 1% of its generation in 2021.
(b)Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2020 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2021.
(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 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. The MISO purchases metric provided for 2020 is not projected for 2021.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2021, it is possible that various operational events including weather or pipeline maintenance may require the 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. Over 50% of the Utility operating companies’ power plants maintain some level of long-
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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 primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies 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 may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to seven one- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2021. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 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 2021. Coal will be transported to Arkansas via an existing transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2021.
Entergy Louisiana has committed to five one- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2021. 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 2021. Coal will be transported to Nelson primarily via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2021.
For the year 2020, coal transportation delivery rates to Entergy Arkansas-and Entergy Louisiana-operated coal-fired units were adequate to meet supply needs and obligations, and it is expected that delivery times in 2021 will continue to be consistent. Both Entergy Arkansas and Entergy 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 Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2021. Entergy 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, Entergy Arkansas, Entergy Louisiana, and System 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
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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.
Based upon currently planned fuel cycles, the Utility 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 or fixed prices through most of 2023. 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 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 seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with CenterPoint 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 CenterPoint 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.
Entergy Louisiana purchased natural gas for resale in 2020 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy 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 and interstate transmission of electricity, including 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.
System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
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 engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which was a rate schedule approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources were jointly operated by the Utility operating companies that were participating in the System Agreement. The System Agreement provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) would receive payments from those parties having generating reserves that were less than their allocated share of reserves (short companies). Such payments were 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 were 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 were required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
Although the System Agreement has terminated, certain of the Utility operating companies’ and their retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. The proceedings include challenges to the 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
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did 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 MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and 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 markets. 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. 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
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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 July 2001 a rate proceeding commenced by System Energy at the FERC in 1995 became final, with the FERC approving a prospective 10.94% return on equity. 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 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 complaints filed with the FERC 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 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
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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 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 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 two outstanding series of first mortgage 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 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.
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Service Companies
Entergy Services, a limited liability company 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 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 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 Unit 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, 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 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. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses 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, 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 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.
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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.
Entergy Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated 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 assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed 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 is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
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•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light 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 Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
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-related services, to nuclear power plants owned by non-affiliated entities in the United States. 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.
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 operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
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 |
| Indian Point 3 (a) | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2025 (a) |
| Indian Point 2 (a) | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2024 (a) |
| Palisades (b) | | MISO | | 1971 | | Apr. 2007 | | Covert,
MI | | 811 MW - Pressurized Water | | 2031 (b) |
(a)Power operations ceased at the Indian Point 2 plant in April 2020. The fuel was permanently removed from the reactor vessel and placed in the spent fuel pool in May 2020. The Indian Point 3 plant is expected to cease operations on April 30, 2021. Entergy and Holtec jointly filed a license transfer application with the NRC in November 2019, requesting approval for the transfer of the Indian Point plants, along with their nuclear decommissioning trusts and decommissioning liabilities, from Entergy to Holtec. The NRC approved the license transfer application on November 23, 2020.
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(b)The Palisades plant is expected to cease operations on May 31, 2022. There is a contract to sell the plant to Holtec subject to NRC and other regulatory approvals.
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 operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
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. Both Big Rock Point and Indian Point 1 are under contract to be sold with their respective plants.
Non-nuclear Generating Stations
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) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| RS Cogen; 425 MW (c) | | Lake Charles, LA | | 50% | | 213 MW | | Gas/Steam |
| Nelson Unit 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 an interest in an unconsolidated joint venture. In December 2020, Entergy’s wholly-owned subsidiary with a direct interest in RS Cogen, LLC entered into a membership interest purchase agreement with a subsidiary of the other 50% equity partner to sell its 50% membership interest in the joint venture to the equity partner. The targeted closing date for the transaction is October 2022.
Independent System Operators
The 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 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. 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.See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.
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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 receives 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. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022 and transfer to Holtec thereafter.
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 Consumers Energy, the company from which Entergy purchased the Palisades plant, and NYISO and MISO. Substantially all the credit 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 NYISO market is highly competitive. Entergy Wholesale Commodities has numerous competitors in 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 York power market 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 most of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. Almost all of Palisades’ current output is contracted to Consumers Energy through May 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. When outdoor and cooling water temperatures are 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.
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,
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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 plant owners. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment has been adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the Indian Point 3 and Palisades plants. Fuel procurement for the Entergy Wholesale Commodities segment was primarily limited to the requirements of the Palisades plant’s final refueling in 2020.
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 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. ENPM’s functions include origination of new energy and capacity transactions and generation scheduling.
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.
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Entergy provides plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.
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.
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 the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC 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 as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and conditions of service;
•service standards;
•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
•avoided cost payments to Qualifying Facilities;
•net energy metering;
•integrated resource planning;
•utility mergers and acquisitions and other changes of control; and
•the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory 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 retail ratemaking or other regulatory jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and purchase power contracts;
•procurement process to acquire over 50 MW;
•audits of the environmental adjustment charge, avoided cost payment to Qualifying Facilities, and energy efficiency rider;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
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•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
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, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other 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 the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects;
•utility service areas, including extensions into new areas;
•avoided cost payments to Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
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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 civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, 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 operators of Indian Point Energy Center, Palisades, and Big Rock Point.
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, 2020 of $192.0 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick, 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 Vermont Yankee spent fuel disposal contract was assigned to NorthStar as part of the sale of the plant in January 2019. The Pilgrim spent fuel disposal contract was transferred to Holtec as part of the sale of Entergy Nuclear Generation Company in August 2019. The owners of these plants previous to Entergy have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the 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. Specific steps were taken to discontinue the Yucca Mountain project, including 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. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the 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
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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 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.
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. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2018, 2019, and 2020 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2020, Entergy’s subsidiaries won and collected on judgments against the government totaling approximately $800 million.
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 River Bend in 2005, at Grand Gulf in 2006, at Indian Point in 2008, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, 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. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. 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.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In October 2020, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and ANO 2 decommissioning trusts were adequately funded without further collections, and in December 2020, the APSC ordered zero collections for ANO 1 and ANO 2 decommissioning.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking permission to canceladjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the Little Gypsy repowering projectongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice.
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In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal.
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 a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
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 January 2019, Entergy sold 100% of the membership interest in Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar. As a result of the sale, NorthStar assumed ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 9 to the financial statements for further discussion of Vermont Yankee decommissioning 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.
In August 2019, Entergy sold 100% of the equity interests in Entergy Nuclear Generation Company, LLC to a subsidiary of Holtec International. As a result of the sale, Holtec assumed ownership of Pilgrim and its decommissioning trust, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 14 to the financial statements for further discussion of the sale.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities 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. 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, which 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 transaction. See Note 14 to the financial statements for discussion of the FitzPatrick sale.
In March 2020 filings with the NRC were made reporting on decommissioning funding for all of Entergy subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the 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 16 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
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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 $137.6 million per reactor (with 97 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, 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.
NRC Reactor Oversight Process
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. The nuclear generating plants owned and operated by Entergy’s Utility and Entergy Wholesale Commodities businesses are currently in Column 1, except for Grand Gulf, which is currently in Column 2.
In November 2020 the NRC placed Grand Gulf in Column 2 based on the incidence of three unplanned plant scrams during the second and third quarters of 2020.Two of the scram events related to new turbine control system components that failed, and a third related to a feedwater valve positioner that failed, all of which had been replaced in a refueling outage that ended in May 2020. The NRC plans to conduct a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 2. As a consequence of two additional Grand Gulf scrams during the fourth quarter 2020, System Energy expects Grand Gulf to be placed into NRC Column 3 based on plant performance indicators for the four quarters ended December 31, 2020. This will involve an additional supplemental NRC inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 3.
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, 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, greenhouse gases, and significant modifications to existing facilities;
•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 permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
•New and existing source standards for greenhouse gas and other air 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. In December 2020 the EPA amended the NSR regulations to clarify when a physical change or change in the method of operation will constitute such a modification. Entergy has an established process for identifying modifications requiring additional permitting approval and is monitoring the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. Several years ago, however, the EPA implemented 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 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, including NSR requirements and air permits issued by the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ). In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 an additional request for similar information was received for the White Bluff facility. Entergy responded to all requests. None of these EPA requests for information alleged that the facilities were in violation of law.
In January 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. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims as well as other issues facing Entergy Arkansas’s fossil generation plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. In October 2019 the District Court requested supplemental briefing on several issues to be resolved prior to addressing the motion to approve the
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settlement; that briefing was completed in May 2020. For further information about the settlement, see “Regional Haze” discussed below.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is 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.
Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for construction and operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. 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 December 2020 the EPA designated East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. Challenges to these final designations must be filed within 60 days of publication in the Federal Register. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. Entergy will continue to monitor this situation.
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.
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Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions. In September 2016 the EPA finalized the CSAPR Update Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 the final rule requires reductions in summer nitrogen oxides (NOx) emissions. Several states, including Arkansas and Texas, filed a challenge to the Update Rule. In September 2019 the D.C. Circuit upheld the EPA’s underlying approach to the Update Rule, but determined that it was inconsistent with the Clean Air Act because it failed to include deadlines consistent with downwind states’ deadlines for attainment. The court remanded the rule to the EPA for further consideration, but did not vacate so the rule remains in effect pending the EPA’s further review. In October 2020 the EPA issued its proposal intended to address the D.C. Circuit’s remand. The draft rule proposes to finalize interstate transport obligations for 21 states. For nine states, including Arkansas, Mississippi, and Texas, the EPA proposes that additional emission reductions are not necessary. For 12 states, however, including Louisiana, the EPA proposes additional emission reductions through proposed reductions in the number of NOx emission allowances allocated to each state. Entergy, through its various trade associations, filed comments on the proposal and will continue to monitor the rulemaking and its potential impact on its facilities in Louisiana. If the October 2020 proposal is finalized, ozone season NOx emissions may become more expensive in Louisiana.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could 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 Energy and Environment, Division of Environmental Quality (ADEQ) prepared a state implementation plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. In April 2012 the EPA finalized a decision addressing the Arkansas Regional Haze SIP, in which it disapproved a large portion of the Arkansas 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 granted the stay pending settlement discussions and pending the State’s development of a SIP that, if approved by the EPA, would replace the FIP. The state had 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. The Part I SIP requires that Entergy address NOx impacts on visibility via compliance with the Cross-State Air Pollution Rule ozone-season emission trading program. Arkansas has finalized a Part II SIP which has been approved by the EPA but is currently pending a state court appeal. That appeal has been stayed pending the outcome of a federal court case, which may resolve many of the issues on appeal. The final Part II SIP requires that Entergy achieve SO2 emission reductions via the use of low-sulfur coal at both White Bluff and Independence within three years. The
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Part II SIP also requires that Entergy cease to use coal at White Bluff by December 31, 2028 and notes the current planning assumption that Entergy’s Independence units will cease to use coal by December 31, 2030.
In January 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. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement and in many cases also the Part II SIP, Entergy Arkansas, along with co-owners, will begin using only low-sulfur coal at Independence and White Bluff by mid-2021; cease to use coal at White Bluff and Independence by the end of 2028 and 2030, respectively; cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserve the option to develop new generating sources at each plant site; and commit to install or propose to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waive certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. The EPA, which is allowed to comment on such a settlement agreement, has stated that it has no objections to the settlement. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. Still pending before the court is a motion by the plaintiffs to approve the settlement, in support of which Entergy made a filing. The Arkansas Attorney General also filed an application before the APSC in December 2018 seeking projectan investigation into the effects of the settlement. The Arkansas Affordable Energy Coalition filed to support the Arkansas Attorney General’s application, and Entergy Arkansas filed a motion to dismiss it. The application remains pending before the APSC. In October 2019 the District Court requested supplemental briefing on several issues prior to addressing the motion to approve the settlement; that briefing concluded in May 2020.
In Louisiana, Entergy has worked with the Louisiana Department of Environmental Quality (LDEQ) and the EPA to revise the Louisiana SIP for regional haze, which had been 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 of January 22, 2021. The EPA issued final approval in December 2017. The EPA approval was appealed to the U.S. Court of Appeals for the Fifth Circuit. In October 2019 the Fifth Circuit affirmed the EPA’s SIP approval. A petition for rehearing filed by plaintiffs was denied by the Fifth Circuit. Plaintiffs did not petition for further review by the Supreme Court.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by 2021. Entergy received information collection requests from Arkansas and Louisiana requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, and Ninemile. Responses to the information requests have been submitted to the respective state agencies.
New and Existing Source Performance Standards for Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established
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national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests and will continue to monitor litigation challenging the rule. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. The vacatur will not be effective until the court issues its mandate which is being held until after disposition of any petitions for rehearing. Entergy is currently reviewing the court’s opinion.
In 2018 the EPA proposed a revision to the new source performance standard on greenhouse gas emissions that primarily impacts new coal units and, therefore, should not impact Entergy. In January 2021 the EPA finalized a pollutant-specific contribution finding for greenhouse gas emissions from new, modified, and reconstructed electric generating units. The rule establishes a three percent threshold for determining when a pollutant significantly contributes to air pollution and reaffirms the EPA’s position that the Clean Air Act Section 111(b) requires the EPA to make pollutant-specific significant contribution findings before promulgation of a new source performance standard. The EPA did not, however, finalize the new source performance standard on greenhouse gas emissions and intends to address the 2018 proposal in a future action.
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 recoveryimplications. These initiatives include:
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•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 federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and 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 local, state, and federal level to codify renewable portfolio standards, clean energy standards, 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;
•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 polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance risk;
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•the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds;
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in an economy-wide, responsible, and flexible manner. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020. In 2020, Entergy succeeded in achieving its initial climate commitment to reduce carbon dioxide cumulative emissions by 20% from 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 39.1 million tons in 2020 and 40.7 million tons in 2019. Since its original commitment in 2001, Entergy’s cumulative emissions are approximately 7.6% below its 2020 goal.
Entergy voluntarily conducted a five-year period. climate scenario analysis and published a comprehensive report in March 2019. The report follows the framework and recommendations of the Task Force on Climate-related Disclosures, describing climate-related governance, strategy, risk management, and metrics and targets. Scenario analyses resulted in Entergy developing and publishing a new goal of reducing the Utility’s emission rate by 50 percent from 2000 levels by 2030. In September 2020, Entergy committed to achieving net-zero carbon emissions by 2050, while continuing its commitment to grid reliability and affordability for customers. In December 2020, Entergy published a report regarding this long-term commitment that describes its approach and technology point-of-view. Technology research and development, innovation, and advancement are critical to Entergy’s ability to meet this climate commitment.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s annual greenhouse gas emissions inventory is also third-party verified, and that certification is made available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 2020 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for nineteen consecutive years. Entergy also participated in the 2020 CDP and CDP Water evaluations, receiving a ‘B’ for both responses.
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 permit program, section 402, 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.
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Steam Electric Effluent Guidelines
The 2015 Steam Electric Effluent Limitations Guidelines (ELG) rule required, among other things, that there be no discharge of bottom ash transport water. In October 2020 the EPA issued its final rule revision on bottom ash transport water allowing the discharge of up to 10% system volume for certain purge waters, including storm events and non-routine operations. The final rule requires compliance as soon as possible beginning October 31, 2021, but no later than December 31, 2025. Several challenges to the final rule have been filed. Additionally, the Fifth Circuit Court of Appeals previously vacated and remanded the provisions of the rule related to legacy wastewater and leachate, which the EPA plans to address in a separate rulemaking. Despite the final rule and pending challenges, Entergy is implementing projects at its White Bluff and Independence plants to convert to zero-discharge systems to comply with the ELG rule and the coal combustion residuals restrictions on impoundments. Additionally, the Nelson Unit 6 facility is implementing operational and maintenance measures to minimize the potential for discharge of bottom ash transport water from the existing bottom ash handling system at the site, and is reviewing the effectiveness of these changes for compliance with the requirements of the October 2020 final rule.
Federal Jurisdiction of Waters of the United States
In February 2019 the EPA published its proposed revised definition of Waters of the United States, which proposes to narrow the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. The final rule was released in January 2020 and effective in June 2020. In October 2019 the EPA repealed the 2015 rule and re-codified the pre-existing regulations. That rule was effective late December 2019. Numerous challenges have been filed against both rules.
Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to 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, Indian Point, Palisades, Grand Gulf, 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.
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
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. 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 such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental 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 Resource Conservation and Recovery Act (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 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, 2020, Entergy has recorded asset retirement obligations related to CCR management of $20.1 million.
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 program.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. 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. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of one of its two recycle ponds, with the remaining pond being held in reserve during initial operation of the new bottom ash handling system. Closure of the remaining recycle pond at each site will commence as soon as possible, but no later than April 11, 2021, which is the deadline under the finalized CCR rule to commence closure of any unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
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Other Environmental Matters
Entergy Louisiana and Entergy Texas
Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, currently is 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 routed to a portion of the property for disposal. The same area also has 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. Removal actions addressed contaminated source material, soil, and sediment and included capping certain soil on and off-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 2010,2005 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. The EPA released the second Five Year Review in 2015. In that review, the EPA indicated that the remediation technique was insufficient and that Entergy would need to utilize other remediation technologies on the site. In July 2015, Entergy submitted a Focused Feasibility Study to the EPA outlining the potential remedies and suggesting installation of the new remedial method, a waterloo barrier. The estimated cost for this remedy is approximately $2 million, to be allocated between Entergy Louisiana and Entergy Texas. In early 2017 the EPA indicated that the waterloo barrier may not be necessary and requested revisions to the Focused Feasibility Study. The EPA released the third Five Year Review in late-2019 confirming that a new remedial method is not necessary but requiring continuation of the current groundwater monitoring. The site’s remedy includes monitored natural attenuation of groundwater, and institutional controls to restrict groundwater and land use. The EPA has determined that no additional actions are needed for the remedy to be protective over the long-term, and the remedy is protective of human health and the environment.
Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, 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 existed at the site. Entergy subsidiaries sent transformers to this facility. Entergy Arkansas, Entergy Louisiana, and Entergy Texas responded to an information request from the TCEQ. Entergy Louisiana and Entergy Texas 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 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. Current estimates, although variable depending on ultimate remediation design and performance, indicate that Entergy’s total share of remediation costs likely will be approximately $1.5 million to $2 million. Groundwater monitoring wells at the site were plugged and abandoned in December 2019 following receipt of a certificate of completion issued by the TCEQ. Site decommissioning activities are complete and final disposition of the property will be determined at a later time.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand
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letter seeking reimbursement for response costs totaling $4 million expended at the site. The demand letter is being evaluated and liability and PRP allocation of response costs are yet to be determined.
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 TCEQ and the National Response Center were immediately notified, and the 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, Entergy entered into the Voluntary Cleanup Program with the TCEQ. In November 2017, additional soil sampling was completed in the wetland area and, in February 2018, a site summary report of findings was submitted to the TCEQ. The TCEQ responded in June 2018 and requested an ecological exclusion criteria checklist/Tier II screening-level ecological risk assessment, and additional site assessment, additional soil samples, groundwater samples, and some additional diagrams and maps. In October 2018, Entergy submitted the requested information to the TCEQ. In January 2019 the TCEQ responded with another request for information. In March 2019, Entergy submitted the requested information to the TCEQ. In August 2019 the TCEQ responded with a request for additional information including an Affected Property Assessment Report (APAR) and water well survey. The TCEQ has agreed that the necessity of the water well survey is dependent on the results of the groundwater resampling that will occur. Groundwater sampling was completed in December 2019 and results were submitted to the TCEQ for review. Based on the groundwater sampling results, the TCEQ confirmed in February 2020 that a water well survey is not necessary and requested the APAR and an Ecological Risk Assessment by August 2020. Due to COVID-19 delays, the TCEQ extended the APAR and Ecological Risk Assessment submittal dates to December 2020, which Entergy timely met.
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.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, 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.
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Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2020, Entergy subsidiaries employed 13,400 people.
| | | | | |
| Utility: | |
| Entergy Arkansas | 1,244 | |
| Entergy Louisiana | 1,654 | |
| Entergy Mississippi | 750 | |
| Entergy New Orleans | 303 | |
| Entergy Texas | 658 | |
| System Energy | — | |
| Entergy Operations | 3,529 | |
| Entergy Services | 3,859 | |
| Entergy Nuclear Operations | 1,356 | |
| Other subsidiaries | 47 | |
| Total Entergy | 13,400 | |
Approximately 3,900 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, and Fire Professionals of America.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
| Gender (%) | 2020 | | 2019 |
| Female | 21 | | 20 |
| Male | 79 | | 80 |
| 100 | | 100 |
| | | | | | | | | | | |
| Race/Ethnicity (%) | 2020 | | 2019 |
| White | 78 | | 79 |
| Black/African American | 15 | | 15 |
| Hispanic/Latino | 3 | | 2 |
| Asian | 2 | | 2 |
| Other | 2 | | 2 |
| 100 | | 100 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion and belonging; and talent management.
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Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Personnel Committee establishes priorities and reviews performance on a range of topics. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development and succession plans to align a high performing executive team with Entergy’s priorities. The Personnel Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on ethics and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. While the COVID-19 pandemic and historical hurricane season presented significant challenges, Entergy’s safety strategy and commitment to excellence showed results in 2020. Entergy employees achieved a total recordable incident rate of 0.40 in 2020 compared to 0.56 in 2019 and 0.48 in 2018. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases. This marked improvement in total recordable incident rate placed Entergy in top-decile in safety performance when benchmarked amongst peers within the Edison Electric Institute.
Organizational Health, including Diversity, Inclusion and Belonging
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (near top quartile). In addition to significantly improved scores, initial employee participation of 66 percent in 2014 rose to and remains at 90 percent in 2018-2020.
Entergy believes that a culture focused on diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. Among other actions, the primary focus of its 2020 actions was taking a stand against social injustice, reinforcing expectations, training and leading by example, starting at the top of the organization and cascading through management ranks.
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Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the future, and reflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.
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 SEC 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. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
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 annual and quarterly reports on Forms 10-K and 10-Q (including related filings in Inline XBRL format) and current reports on Form 8-K; 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 internet 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.
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RISK FACTORS
See “RISK FACTOR SUMMARY” in Part I Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ 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 Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
In December 2019 a novel strain of coronavirus was reported to have surfaced in Wuhan, China. Since then, COVID-19 has spread throughout most countries in the world, including the United States. Public health officials in the United States have both recommended and mandated wearing of masks, precautions to mitigate the spread of COVID-19, including prohibitions on congregating in heavily-populated areas, mandated closure or limitations on the functions of non-essential business, and shelter-in-place orders or similar measures, including throughout Entergy’s service areas. While some of these mitigation measures have been lifted, it is unclear how long certain forms of mitigation measures will remain in place, whether they will be reinstated in the future, and how they will ultimately impact the general economy, Entergy’s customers, and its operations.
Entergy and its Utility operating companies have experienced a decline in commercial and industrial sales and an increase in arrearages and bad debt expense due to non-payment by customers, and expect such reduced levels of sales and increased arrearages and bad debt expense to continue, the extent and duration of which management cannot predict. The Utility operating companies temporarily suspended disconnecting customers for non-payment of bills, and the suspension remains in place at Entergy Arkansas, has been re-instituted at Entergy New Orleans, and could be re-instituted at the other Utility operating companies should their regulators mandate. While they are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is unknown. Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges, supply chain, vendor, and contractor disruptions; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed outages; delays in regulatory proceedings; workforce availability, health or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees telecommuting; increased late or uncollectible customer payments; volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and initiatives.
A sustained or further economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the COVID-19 pandemic on their customers. In addition, if the COVID-19 pandemic continues to create disruptions or turmoil in the credit or financial markets, or adversely impacts Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its
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liquidity needs, or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the outbreak, the impact of new variants of COVID-19, the timing, availability, distribution or effectiveness of a vaccine, anti-viral or other treatments for COVID-19, governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
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 can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. 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, including adjustment upon the initiative of a regulator or affected stakeholders.
In addition, regulators may initiate proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s 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 may 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. Traditional 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 these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and the Utility operating companies may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation of their assets and infrastructure or the quality of their service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements.
The base rates of Entergy Texas are established largely in traditional base rate case proceedings.Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs.These riders include a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment and certain non-fuel MISO charges, a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a generation cost recovery rider mechanism for the recovery of generation-related capital investments, and a fixed fuel factor mechanism for the recovery of MISO fuel and energy-related costs.Entergy Texas also is required to make a filing every three years,
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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 necessary and reasonable, and makes a prudence finding for each of the fuel-related contracts for the reconciliation period.Entergy Texas also is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Between base rate cases, Entergy Arkansas and Entergy Mississippi 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. Entergy Arkansas has requested APSC approval of the extension of the formula rate plan tariff for an additional five years through 2026.If Entergy Arkansas’s formula rate plan were terminated or not extended beyond the initial term, Entergy Arkansas could file an 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 staffin connection with the full electric base rate cases filed by those companies in February 2013.The formula rate plan was most recently extended through the test year 2019; certain modifications were made in that extension, including a decrease to the allowed return on equity and intervenorsthe addition of a transmission cost recovery mechanism.The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC and as noted, for certain transmission investment, among other items.MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause.Entergy Louisiana has a pending request to extend its formula rate plan with certain modifications, including implementation of a distribution investment recovery mechanism and use of end of period rate base.In the event that the electric formula rate plan is not renewed or extended, Entergy Louisiana would revert to the more traditional rate case environment.
Entergy New Orleans previously operated under a formula rate plan that ended with the 2011 test year.Based on a settlement agreement approved by the City Council, with limited exceptions, the base rates of Entergy New Orleans were frozen until rates were implemented in connection with the base rate case filed testimony. by Entergy New Orleans in 2018.In November 2019 the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019.The LPSC staff (1)resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes.In November 2020 the City Council issued a resolution approving a settlement of the 2018 rate case.As part of this settlement, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle.See Note 2 to the financial statements for further discussion.
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 has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the
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reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate request for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. System Energy has received FERC acceptance for billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
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 the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales could put upward pressure on rates, resulting in adverse regulatory actions to mitigate such effects on rates. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
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 or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may 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 and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
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.
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Entergy Corporation, Utility operating companies, and System Energy
There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
The Utility operating companies historically 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 had been approved by the FERC. The System Agreement terminated in its entirety on August 31, 2016.
There 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 was prudenthad been in existence. In the absence of the System Agreement, there remains uncertainty around the effectiveness of governance processes and the potential absence of federal authority to moveresolve certain issues among the projectUtility operating companies and their retail regulators.
In addition, although the System Agreement terminated in its entirety in August 2016, there are a few outstanding System Agreement proceedings at the FERC and at the D.C. Circuit that may require future adjustments, including challenges to the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
For further information regarding the regulatory proceedings relating to the System Agreement, see Note 2 to the 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. 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 capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or the cost of serving the Utility operating companies’ respective loads, and MISO market rules may change in ways that cause additional risk.
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. In addition to the cash and financing-related risks arising from long-term suspensionthe potential additional cost allocation to cancellationthe Utility operating companies from transmission projects of others, 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, the
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allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits 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, or generally allow the retail regulator to direct the making of such 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 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 (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta), or the impact on customer bills of permitted storm cost recovery, could have material effects on Entergy and its Utility operating companies.
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. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills.
In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, 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
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costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity 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 owned or contractually controlled 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.
Certain of the Utility operating companies and System Energy 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.
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. Plant maintenance and upgrades are often scheduled during such planned outages, which typically extends the planned outage duration. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks 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 2020 and beyond. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium 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 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 and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, or shifting trade arrangements between countries. 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 changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
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 international sanctions or tariffs could further restrict the ability of such
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suppliers to continue to supply fuel or provide such services at acceptable prices or at all. 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 and System Energy.
Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, suspend 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, 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 nuclear facilities. 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.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate 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 the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities.
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 increased costs, some of which costs may not be fully recoverable by the Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. 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
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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, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture 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 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 NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are 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 will 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 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 Louisiana, and System Energy and Note 8 to the financial statements.
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, which is referred to as Secondary Financial Protection, up to approximately $137.6 million per reactor. With 97 reactors currently
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participating, this translates to a total public liability cap of approximately $14 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, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the 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 primary insurance level, up to a maximum of approximately $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.101 billion). The retrospective premium payment is currently limited to approximately $21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $137.6 million cap.
NEIL is a utility industry mutual insurance company, owned by its 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 NEIL surplus (reserve) be significantly depleted due toinsured losses. As of December 31, 2020, the maximum annual assessment amounts total $104 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential 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.
The 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 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. 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.
Under NRC regulations, nuclear plant owners 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 nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent
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decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments 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.
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, or accelerate the timing for funding of, the obligations related to the decommissioning of the Utility operating companies, System Energy, or Entergy Wholesale Commodities nuclear power plants or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. 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 suspendexit the merchant power business, the impairment charges that resulted from such decision, and the planned sales of Palisades and Indian Point Energy Center (which, in each case, will include the transfer of the associated decommissioning trusts), 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.
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. These concerns have led to, and may 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 might lead to the shutdown of nuclear units, 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 and financial condition.
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Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation)
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. 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, 2020, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 98% in 2021 and 99% in 2022 of its generation portfolio’s planned energy output, reflecting the planned shutdown and sale of the remaining 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 longer-termgenerating 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.
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.
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.
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 “Market and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the closure (or sale) of its nuclear plants, Entergy Wholesale Commodities may enter into fewer forward sales contracts for output from such plants.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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. 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 $1.29 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. 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 is subject to changes as a result of restructuring initiatives at both the state and federal levels. 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, 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, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other 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 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 remaining assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure and sale of its nuclear power plants. Moreover, prior to the closure and 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, or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
If Entergy concludes that any of its nuclear power plants is unlikely to operate through its planned shutdown date, which conclusion would be based on a variety of factors, such a conclusion could result in a 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 remaining 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 - Impairment of Long-lived Assets” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
General Business
(Entergy Corporation, Entergy Arkansas, 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-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, Hurricane Isaac in 2012, and Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown events, 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The inability to raise capital on favorable terms, particularly during times of high interest rates, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in companies that experience extreme weather events, that rely on fossil fuels or offerings to fund fossil fuel projects, or due to risks related to climate change. Events beyond Entergy’s control 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 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.
Most of Entergy Corporation’s and its subsidiaries’ 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, 2020 based on power prices at that time, Entergy had liquidity exposure of $62 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $6 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, 2020, Entergy would have been required to provide approximately $30 million of additional cash or letters of credit under some of the agreements. As of December 31, 2020, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $22 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, and cash flows.
The Tax Cuts and Jobs Act of 2017 and CARES Act of 2020 significantly changed 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 interpretive
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation.
As further described in Note 3 to the financial statements, as a result of amortization of accumulated deferred income taxes and payment of such amounts to customers in 2019, Entergy’s net regulatory liability for income taxes balance is $1.6 billion as of December 31, 2020. Depending on the outcome of IRS examinations or tax positions and elections that Entergy may make, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense. Further, there may be other material effects resulting from the legislation that have not been identified.
See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act on 2018, 2019 and 2020 results of operations and financial condition, the provisions of the Tax Cuts and Jobs Act, and the uncertainties associated with accounting for the Tax Cuts and Jobs Act, and Note 2 to the financial statements for discussion of the regulatory proceedings that have considered the effects of the Tax Cuts and Jobs 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 execute on their business strategies, including their ability to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies, which could materially affect their future prospects, results of operations, and benefits that they anticipate from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, which are subject to business, regulatory, economic, and other risks and uncertainties, many of which are beyond their control. As a result, Entergy and its subsidiaries may be unable to fully achieve the anticipated results of such strategies.
Additionally, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring, or other strategic transactions. For example, Entergy has entered into an agreement to sell its equity interests in the subsidiary that owns the Palisades Nuclear Plant and the decommissioned Big Rock Point Nuclear Power Plant and an agreement to sell the equity interests of Indian Point 1, Indian Point 2, and Indian Point 3, in each case after each of the plants has been shut down and defueled. Also, a significant portion of Entergy’s utility business over the next several years includes the construction and/or purchase of a variety of generating units. These transactions and 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 or its subsidiaries’ financial condition or 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
Entergy Corporation, Utility operating companies, and System Energy
•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;
•Entergy may experience issues integrating businesses into its internal controls over financial reporting;
•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, 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 and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition or results of operations.
The completion of capital projects, including the construction of power generation facilities, and other capital improvements involve substantial risks. Should such 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 capital projects, including the 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, escalating costs for materials, labor, and environmental compliance, and reliance on suppliers for timely and satisfactory performance. Delays in obtaining permits, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under 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 the project or 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 capital projects, including the potential construction and/or purchase 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
Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
We rely on a large and changing workforce of team members, including employees, contractors and temporary staffing. Certain events, such as an aging workforce, mismatching of skill sets, failing to appropriately anticipate future workforce needs, or the unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base, and the time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, may increase. Failure to hire and adequately train replacement employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business, especially considering the workforce needs associated with nuclear generation facilities and new skills required to operate a modernized, technology-enabled power grid. If Entergy and its subsidiaries are unable to successfully attract, retain, and manage an appropriately qualified workforce, their results of operations, financial position, and cash flows could be negatively affected.
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 currently are 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 potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing air regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, 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
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 NERC, the 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. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the 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 businesses.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations and system reliability.
Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, mild temperatures in either season tend to decrease energy usage and resulting revenues. Higher consumption levels coupled with seasonal pricing differentials 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 including hurricanes or tropical storms, flooding events, or ice storms 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 reduced 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 weather and economic conditions, 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 grid demand. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and their replacement with more efficient ones, adoption of newer technologies including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales growth in the future. The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower 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, environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions, or achieving voluntary climate commitments 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, some 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 CO2 and other “greenhouse gases” under the Clean Air Act, the EPA, various environmental interest groups, and other organizations focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. Since that ruling, the EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and from new, existing, and significantly modified stationary sources of emissions, including electric generating units. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. In Louisiana, the Office of the Governor announced the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050 while the City Council of New Orleans passed a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk 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, clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing the company’s greenhouse gas emission rate. 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 attempt to deny or defer timely recovery of these costs. Future changes in regulation or policies governing the emission of CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy’s utility operating companies, their suppliers or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy’s utility operating companies are unable to fully recover the costs and investment in generation and (iv) could increase the difficulty that Entergy and its utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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, wildfires, wetland and barrier island erosion, risks of flooding and changes in weather conditions, (such as increases in precipitation, drought, or changes in average 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 the physical impacts of climate change, 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, more frequent and longer lasting outages, 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.
In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. Technology research and development, innovation, and advancement are critical to Entergy’s ability to achieve this commitment. Moreover, Entergy cannot predict the ultimate impact of achieving this objective, or the various implementation aspects, on its system reliability, or its results of operations, financial condition or 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, and Entergy Wholesale Commodities’ business operations. Entergy’s facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also 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.
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 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 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Market performance and other changes may decrease the value of benefit plan assets, which then could require additional 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 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 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 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 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.
Terrorist attacks, cyber attacks, system failures or data breaches of Entergy’s and its subsidiaries’ or our suppliers’ technology systems may adversely affect Entergy’s results of operations.
Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure, and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers and employees, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply chain activities. Any significant failure or malfunction of such information technology systems could result in loss of data or disruptions of operations.
There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. As an operator of critical infrastructure, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, cyber attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions. An actual act could affect Entergy’s ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct business.
Given the rapid technological advancements of existing and emerging threats, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
and controls. 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 could be unable to perform critical business functions that are essential to the company’s well-being and could result in a loss of its confidential, sensitive, and proprietary information, including personal information of its customers, employees, suppliers, and others in Entergy’s care.
Any such attacks, failures or data breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, results of operations or reputation. Although we purchase insurance coverage for cyber-attacks or data breaches, such insurance may not be adequate to cover all losses that might arise in connection with these events. Such events may also expose Entergy to an increased risk of litigation (and associated damages and fines).
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect 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 New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. 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.
(System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings.
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 expires in November 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. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a request in a separate proceeding for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. The LPSC has also authorized the filing of a prudence complaint at the FERC relating to Grand Gulf operations. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
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, see Notes 5 and 8 to the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy Corporation depends 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. Prior to providing funds to Entergy Corporation, such subsidiaries have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of Entergy Utility Holding Company and Entergy Texas, dividends and distributions on preferred securities. Any distributions from the Registrant Subsidiaries other than Entergy Texas and System Energy are paid directly to Entergy Utility Holding Company and are therefore subject to prior payment of distributions on its preferred securities.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Arkansas’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $10 million. Natural gas purchases for Entergy Arkansas for February 1st through 25th, 2021 are approximately $105 million compared to natural gas purchases for February 2020 of $10 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income decreased $17.7 million primarily due to lower volume/weather, a formula rate plan provision recorded in 2020 to reflect the 2019 historical year netting adjustment, and higher depreciation and amortization expenses, partially offset by higher retail electric price and lower other operation and maintenance expenses. See Note 2 to the financial statements for discussion of the 2019 historical year netting adjustment.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2020 to 2019:
| | | | | |
| Amount |
| (In Millions) |
| 2019 operating revenues | $2,259.6 | |
| Fuel, rider, and other revenues that do not significantly affect net income | (278.5) | |
| Volume/weather | (72.2) | |
| Retail electric price | 57.4 | |
| Return of unprotected excess accumulated deferred income taxes to customers | 118.2 | |
| 2020 operating revenues | $2,084.5 | |
Entergy Arkansas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The volume/weather variance is primarily due to a decrease of 1,069 GWh, or 5%, in billed electricity usage, including decreased commercial and industrial usage as a result of the COVID-19 pandemic, and the effect of less favorable weather on residential and commercial sales, partially offset by an increase in residential usage as a
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
result of the COVID-19 pandemic. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the COVID-19 pandemic.
The retail electric price variance is primarily due to the $56.5 million annual formula rate plan increase related to the 2020 projected test year included in the 2019 formula rate plan filing effective with the first billing cycle of January 2020. See Note 2 to the financial statements for further discussion of the formula rate plan filing.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a tax adjustment rider beginning in April 2018. In 2020, $8.1 million was not imprudent; (2) indicated that, except for $0.8returned to customers as compared to $126.3 million in compensation-related2019. There is no effect on net income as the reduction in operating revenues in each period was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
Other Income Statement Variances
Nuclear refueling outage expenses decreased primarily due to the amortization of lower costs associated with the most recent outages as compared to previous outages.
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $18.3 million in nuclear generation expenses primarily due to lower nuclear labor costs, including contract labor, in part as a result of the COVID-19 pandemic;
•a decrease of $13.2 million in non-nuclear generation expenses primarily due to lower long-term service agreement expenses;
•an $11.2 million write-off in 2019 of specific costs related to the potential construction of scrubbers at the White Bluff plant. See Note 2 to the financial statements for discussion of the write-off;
•higher nuclear insurance refunds of $7.8 million;
•a decrease of $5.9 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services; and
•a decrease of $5.8 million in energy efficiency costs.
The decrease was partially offset by the effects of recording in 2019 a final judgment to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $11.9 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.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other income increased primarily due to changes in decommissioning trust fund investment activity.
Other regulatory credits - net for 2020 includes a provision of $43.5 million to reflect the 2019 historical year netting adjustment included in the APSC’s December 2020 order in the 2020 formula rate plan proceeding. See Note 2 to the financial statements for discussion of the 2020 formula rate plan proceeding.
The effective income tax rates were 16.3% for 2020 and (21.6%) for 2019. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes. See Notes 2 and 3 to the financial statements for a discussion of the effects and regulatory activity regarding the Tax Cuts and Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of results of operations for 2019 compared to 2018.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 | |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $3,519 | | | $119 | | | $6,216 | | |
| | | | | | |
| Net cash provided by (used in): | | | | | | |
| Operating activities | 659,818 | | | 677,766 | | | 211,825 | | |
| Investing activities | (795,709) | | | (676,293) | | | (688,727) | | |
| Financing activities | 324,500 | | | 1,927 | | | 470,805 | | |
| Net increase (decrease) in cash and cash equivalents | 188,609 | | | 3,400 | | | (6,097) | | |
| | | | | | |
| Cash and cash equivalents at end of period | $192,128 | | | $3,519 | | | $119 | | |
2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities decreased $17.9 million in 2020 primarily due to:
•the timing of recovery of fuel and purchased power costs;
•lower collections of receivables from customers, in part due to the COVID-19 pandemic; and
•the timing of payments to vendors.
The decrease was partially offset by:
•a decrease in the return of unprotected excess accumulated deferred income taxes to customers in 2020 as compared to 2019. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act;
•$25 million in proceeds received from the DOE in 2020 resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•a decrease of $15.8 million in pension contributions in 2020. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Investing Activities
Net cash flow used in investing activities increased $119.4 million in 2020 primarily due to:
•an increase of $79.5 million in storm spending;
•an increase of $47.3 million in non-nuclear generation construction expenditures primarily due to increased spending on various projects in 2020;
•an increase of $39.4 million in nuclear construction expenditures primarily as a result of work performed in 2020 on various ANO 2 outage projects;
•an increase of $38.5 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; and
•an increase of $30.3 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Arkansas’s distribution system, including increased spending on advanced metering infrastructure.
The increase was partially offset by:
•a decrease of $56 million in transmission construction expenditures primarily due to a lower scope of work performed in 2020 as compared to 2019; and
•$55 million in proceeds received from the DOE in 2020 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.
Financing Activities
Net cash flow provided by financing activities increased $322.6 million in 2020 primarily due to:
•issuances of $100 million of 4.0% Series mortgage bonds in March 2020 and $675 million of 2.65% Series mortgage bonds in September 2020;
•money pool activity;
•a decrease of $41.6 million in net long-term repayments in 2020 on the Entergy Arkansas nuclear fuel company variable interest entity credit facility; and
•a decrease of $20 million in common equity distributions in 2020 in order to maintain Entergy Arkansas’s capital structure.
The increase was partially offset by:
•the issuance of $350 million of 4.20% Series mortgage bonds in March 2019;
•the repayment in October 2020 of $200 million of 4.90% Series mortgage bonds due December 2052; and
•the repayment in October 2020 of $125 million of 4.75% Series mortgage bonds due June 2063.
Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased by $21.6 million in 2020 compared to decreasing by $161.1 million in 2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio is primarily due to the net issuances of long-term debt in 2020.
| | | | | | | | | | | |
| | December 31,
2020 | | December 31,
2019 |
| Debt to capital | 54.8 | % | | 53.0 | % |
| Effect of excluding the securitization bonds | — | % | | — | % |
| Debt to capital, excluding securitization bonds (a) | 54.8 | % | | 53.0 | % |
| Effect of subtracting cash | (1.2 | %) | | — | % |
| Net debt to net capital, excluding securitization bonds (a) | 53.6 | % | | 53.0 | % |
(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, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas 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 Arkansas’s financial condition because the securitization bonds, which have been repaid as of December 31, 2020, were 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 distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Arkansas 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
•distribution and interest payments.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2022 | | 2023 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $340 | | | $355 | | | $430 | |
| Transmission | 40 | | | 45 | | | 190 | |
| Distribution | 95 | | | 255 | | | 420 | |
| Utility Support | 105 | | | 80 | | | 75 | |
| Total | $580 | | | $735 | | | $1,115 | |
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| | (In Millions) |
| Long-term debt (a) | $611 | | | $543 | | | $581 | | | $4,713 | | | $6,448 | |
| Operating leases (b) | $14 | | | $21 | | | $15 | | | $11 | | | $61 | |
| Finance leases (b) | $3 | | | $5 | | | $3 | | | $2 | | | $13 | |
| Purchase obligations (c) | $452 | | | $618 | | | $509 | | | $3,882 | | | $5,461 | |
(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)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 $66.6 million to its qualified pension plans and approximately $517 thousand to its other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. 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 $252 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 Arkansas includes specific investments in renewables such as the Searcy Solar Facility, Walnut Bend Solar Facility, and West Memphis Solar Facility; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; investments in ANO 1 and 2; software and security; 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 maturities in Note 5 to the financial statements.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Renewables
Searcy Solar Facility
In March 2019, Entergy Arkansas announced that it signed an agreement for the purchase of an approximately 100 MW solar energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. The purchase is contingent upon, among other things, obtaining necessary approvals from applicable federal and state regulatory and permitting agencies. The project is being constructed by a subsidiary of NextEra Energy Resources. Entergy Arkansas will purchase the facility upon mechanical completion and after the other purchase contingencies have been met. Closing is expected to occur by the end of 2021. In May 2019, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. In September 2019 other parties filed testimony largely supporting the resource acquisition but disputing Entergy Arkansas’s proposed method of cost recovery. Entergy Arkansas filed its rebuttal testimony in October 2019. In February 2020, Entergy Arkansas, the Attorney General, and the APSC general staff filed a partial settlement agreement asking the APSC to approve, based on the record in the proceeding, all issues except certain issues that are submitted to the APSC for determination. In April 2020 the APSC issued an order approving Entergy Arkansas’s acquisition of the Searcy Solar facility as being in the public interest, but declined to approve Entergy Arkansas’s preferred cost recovery rider mechanism, finding instead, based on the particular facts and circumstances presented, that the formula rate plan rider was a sufficient recovery mechanism for this resource.
Walnut Bend Solar Facility
In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar Facility is in the public interest. Entergy Arkansas requested a decision by the APSC by June 15, 2021 and primarily requests cost recovery through the formula rate plan rider. A procedural schedule was established with a hearing scheduled in April 2021. Closing is expected to occur in 2022.
West Memphis Solar Facility
In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar Facility is in the public interest. Entergy Arkansas requested a decision by the APSC by September 7, 2021 and primarily requests cost recovery through the formula rate plan rider. Closing is expected to occur in 2023.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Arkansas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
All debt and common and preferred membership interest issuances by Entergy Arkansas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s bond indentures and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | | 2017 |
| (In Thousands) |
| $3,110 | | ($21,634) | | ($182,738) | | ($166,137) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in September 2024. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2021. The $150 million credit facility includes fronting commitments for the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2020, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas 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, 2020, a $1 million letter of credit was outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for further discussion of the credit facilities.
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in September 2022. As of December 31, 2020, $12.2 million in loans were outstanding under the credit facility for the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorization from the FERC through July 2022 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and 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 FERC. The APSC has concurrent jurisdiction over Entergy Arkansas’s first mortgage bond/secured issuances. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through July 2022. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2022.
State and Local Rate Regulation and Fuel-Cost Recovery
Retail Rates
2018 Formula Rate Plan Filing
In July 2018, Entergy Arkansas filed with the APSC its 2018 formula rate plan filing to set its formula rate for the 2019 calendar year. The filing showed Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2019 test period to be below the formula rate plan bandwidth. Additionally, the filing included the first netting adjustment under the current formula rate plan for the historical test year 2017, reflecting the change in formula rate plan revenues associated with actual 2017 results when compared to the allowed rate of return on equity. The filing included a projected $73.4 millionrevenue deficiency for 2019 and a $95.6 million revenue deficiency for the 2017 historical test year, for a total revenue requirement of $169 million for this filing. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to four percent of total revenue, which originally was $65.4 million but was increased to $66.7 million based upon the APSC staff’s updated calculation of 2018 revenue. In October 2018, Entergy Arkansas and the parties to the proceeding filed joint motions to approve a partial settlement agreement as to certain factual issues and agreed to brief contested legal issues. In November 2018 the APSC held a hearing and was briefed on a contested legal issue. In December 2018 the APSC issued a decision related to the initial legal brief, approved the partial settlement agreement and $66.7 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan, with updated rates going into effect for the first billing cycle of January 2019.
2019 Formula Rate Plan Filing
In July 2019, Entergy Arkansas filed with the APSC its 2019 formula rate plan filing to set its formula rate for the 2020 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2020 and a netting adjustment for the historical year 2018. The total proposed formula rate plan rider revenue change designed to produce a target rate of return on common equity of 9.75% is $15.3 million, which is based upon a deficiency of approximately $61.9 million for the 2020 projected year, netted with a credit of approximately $46.6 million in the 2018 historical year netting adjustment. During 2018 Entergy Arkansas experienced higher-than expected sales volume, and actual costs were lower than forecasted. These changes, coupled with a reduced income tax rate resulting from the Tax Cuts and Jobs Act, resulted in the credit for the historical year netting adjustment. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflected the estimate of the historical year netting adjustment that was expected to be included in the 2019 filing. In 2019, Entergy Arkansas recorded additional provisions totaling $11.5 million to reflect the updated estimate of the historical year netting adjustment included in the 2019 filing. In October 2019 other parties in the proceeding filed their errors and objections requesting certain adjustments to Entergy Arkansas’s filing that would reduce or eliminate Entergy Arkansas’s proposed revenue change. Entergy Arkansas filed its response addressing the requested adjustments in October 2019. In its response, Entergy Arkansas accepted certain of the adjustments recommended by the General Staff of the APSC that would reduce the proposed formula rate plan rider revenue change to $14 million. Entergy Arkansas disputed the remaining adjustments proposed by the parties. In October 2019, Entergy Arkansas filed a unanimous settlement agreement with the other parties in the proceeding seeking APSC approval of a revised total formula rate plan rider revenue change of $10.1 million. In its July 2019 formula rate plan filing, Entergy Arkansas proposed to recover an $11.2 million regulatory asset, amortized over five years, associated with specific costs related to the potential construction of scrubbers at the White Bluff plant. Although Entergy Arkansas does not concede that the regulatory asset lacks merit, for purposes of reaching a settlement on the total formula rate plan rider amount, Entergy Arkansas agreed not to include the White Bluff scrubber regulatory asset cost in the 2019 formula rate plan filing or future filings. Entergy Arkansas recorded a write-off in 2019 of the $11.2 million White Bluff scrubber regulatory asset. In December 2019 the APSC approved the settlement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2020.
2020 Formula Rate Plan Filing
In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2021 projected year is 8.22% resulting in a revenue deficiency of $64.3 million. The earned rate of return on common equity for the 2019 historical year was 9.07% resulting in a $23.9 million netting adjustment. The total proposed revenue change for the 2021 projected year and 2019 historical year netting adjustment was $88.2 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $74.3 million. In October 2020 other parties in the proceeding filed their errors
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
and objections recommending certain adjustments, and Entergy Arkansas filed responsive testimony disputing these adjustments. As part of the formula rate plan tariff the calculation for the revenue constraint was updated based on actual revenues which had the effect of reducing the initially-proposed $74.3 million revenue requirement increase to $72.6 million. In October 2020, Entergy Arkansas filed with the APSC a unanimous settlement agreement reached with the other parties that resolved all but one issue. As a result of the settlement agreement, Entergy Arkansas’s requested revenue increase was $68.4 million, including a $44.5 million increase for the projected 2021 year and a $23.9 million netting adjustment. The remaining issue litigated concerned the methodology used to calculate the netting adjustment within the formula rate plan. In December 2020 the APSC issued an order rejecting the netting adjustment method used by Entergy Arkansas. Applying the approach ordered by the APSC changed the netting adjustment for the 2019 historical year from a $23.9 million deficiency to $43.5 million excess. Overall, the decision reduced Entergy Arkansas’s revenue adjustment for 2021 to $1 million. In December 2020, Entergy Arkansas filed a petition for rehearing of the APSC’s decision, and in January 2021 the APSC granted further consideration of Entergy Arkansas’s petition. Based on the progress of the proceeding to date, in December 2020, Entergy Arkansas recorded a regulatory liability of $43.5 million to reflect the netting adjustment for 2019, as included in the APSC’s December 2020 order, which would be returned to customers in 2021. Also with the formula rate plan filing, Entergy Arkansas is requesting an extension of the formula rate plan rider for a second five-year term. Decisions by the APSC on the netting adjustment rehearing and the extension are expected in March 2021.
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. In July 2018, Entergy Arkansas filed a settlement, reached by all parties in the APSC proceeding, resolving all issues. The APSC approved the settlement agreement and restructuring in August 2018. Pursuant to the settlement agreement, Entergy Arkansas will credit retail customers $39.6 million over six years, beginning in 2019. Entergy Arkansas also received the required FERC and NRC approvals.
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated 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 assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed 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 is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 in Note 2 to the financial statements.
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 upcoming energy cost rate redetermination filing that was made in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude from the redetermination of its 2014 energy cost rate $65.9 million of incremental fuel and replacement energy costs incurred in 2013 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 was available regarding various claims associated with the ANO stator incident. In February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in its deferred fuel balance. 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 regulatory 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 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.
In March 2018, 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 $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be deemed prudent;collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it has initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.
In March 2019, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01882 per kWh to $0.01462 per kWh and became effective with the first billing cycle in April 2019. In March 2019 the Arkansas Attorney General filed a response to Entergy Arkansas’s annual adjustment and included with its filing a motion for investigation of alleged overcharges to customers in connection with the FERC’s October 2018 order in the opportunity sales proceeding. Entergy Arkansas filed its response to the Attorney General’s motion in April 2019 in which Entergy Arkansas stated its intent to initiate a proceeding to address recovery issues related to the October 2018 FERC order. In May 2019, Entergy Arkansas initiated the opportunity sales recovery proceeding, discussed below, and requested that the APSC establish that proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC October 2018 order and related FERC orders in the opportunity sales proceeding. In June 2019 the APSC granted Entergy Arkansas’s request and also denied the Attorney General’s motion in the energy cost recovery proceeding seeking an investigation into Entergy Arkansas’s annual energy cost recovery rider adjustment and referred the evaluation of such matters to the opportunity sales recovery proceeding.
In March 2020, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01462 per kWh to $0.01052 per kWh. The redetermined rate became effective with the first billing cycle in April 2020 through the normal operation of the tariff.
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 allocated 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 prohibited 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 challenged sales made beginning in 2002 and requested refunds. In July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement 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 FERC subsequently ordered a hearing in the proceeding.
After a hearing, the ALJ issued an initial decision in December 2010. 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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. The FERC in its decision established further hearing procedures to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision. The hearing was held in May 2013 and the ALJ issued an initial decision in August 2013. 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 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’ request to hold the appeal in abeyance pending final resolution of the related proceeding before 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’ appeal.
The hearing required by the FERC’s April 2016 order was held in May 2017. In July 2017 the ALJ issued an initial decision addressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the calculation methodology. 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 decision. 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.
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 included interest, for its estimated increased costs and payment to the other Utility operating companies, and a deferred fuel regulatory asset of $75 million. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. The December 2018 compliance filing is pending FERC action. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
| | | | | | | | | | | |
| | Total refunds including interest |
| Payment/(Receipt) |
| | (In Millions) |
| Principal | Interest | Total |
| Entergy Arkansas | $68 | $67 | $135 |
| Entergy Louisiana | ($30) | ($29) | ($59) |
| Entergy Mississippi | ($18) | ($18) | ($36) |
| Entergy New Orleans | ($3) | ($4) | ($7) |
| Entergy Texas | ($17) | ($16) | ($33) |
Entergy Arkansas previously recognized a regulatory asset with a balance of $116 million as of December 31, 2018 for a portion of the payments due as a result of this proceeding.
As described above, the FERC’s opportunity sales orders have been appealed to the D.C. Circuit. In February 2020 all of the appeals were consolidated and in April 2020 the D.C. Circuit established a briefing schedule. Briefing was completed in September 2020 and oral argument was heard in December 2020.
In February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and motion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC’s complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC’s new complaint. In December 2019 the LPSC requested rehearing of the FERC’s November 2019 order, and in July 2020 the FERC issued an order dismissing the LPSC’s request for rehearing. In September 2020 the LPSC appealed to the D.C. Circuit the FERC’s orders dismissing the new opportunity sales complaint. In November 2020 the D.C. Circuit issued an order establishing that briefing will occur in January 2021 through April 2021.
In May 2019, Entergy Arkansas filed an application and supporting testimony with the APSC requesting approval of a special rider tariff to recover the costs of these payments from its retail customers over a 24-month period. The application requested that the APSC approve the rider to take effect within 30 days or, if suspended by the APSC as allowed by commission rule, approve the rider to take effect in the first billing cycle of the first month occurring 30 days after issuance of the APSC’s order approving the rider. In June 2019 the APSC suspended
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas’s tariff and granted Entergy Arkansas’s motion asking the APSC to establish the proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC’s October 2018 order and related FERC orders in the opportunity sales proceeding. In January 2020 the APSC adopted a procedural schedule with a hearing in April 2020. In January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed a joint motion seeking to dismiss Entergy Arkansas’s application alleging that the APSC, in a prior proceeding, ruled on the issues addressed in the application and determined that Entergy Arkansas’s requested relief violates the filed rate doctrine and the prohibition against retroactive ratemaking. Entergy Arkansas responded to the joint motion in February 2020 rebutting these arguments, including demonstrating that the claims in this proceeding differ substantially from those the APSC addressed previously and that the payment resulting from a FERC tariff violation for which Entergy Arkansas seeks retail cost recovery in this proceeding differs materially from the refunds resulting from a FERC tariff amendment that the APSC previously rejected on filed rate doctrine and the retroactive ratemaking grounds. In addition, in January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed testimony opposing the recovery by Entergy Arkansas of the opportunity sales payment but also claiming that certain components of the payment should be segregated and refunded to customers. In March 2020, Entergy Arkansas filed rebuttal testimony.
In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U. S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court scheduled a hearing for February 26, 2021 regarding issues addressed in the pre-trial conference report.
Net Metering Legislation
An Arkansas law was enacted effective July 2019 that, among other things, expands the definition of a “net metering customer” to include two additional types of customers: (1) customers that lease net metering facilities, subject to certain leasing arrangements, and (2) government entities or other entities exempt from state and federal income taxes that enter into a service contract for a net metering facility. The latter provision would allow eligible entities, many of whom are small and large general service customers, to purchase renewable energy directly from third party providers and receive bill credits for these purchases. The APSC was given authority under this law to address certain matters, such as cost shifting and the appropriate compensation for net metered energy and has initiated proceedings for this purpose. Because of the size and number of customers eligible under this new law, there is a risk of loss of load and the shifting of costs to customers. A hearing was held in December 2019, with utilities, cooperatives, the Arkansas Attorney General, industrial customers, and Entergy Arkansas advocating the need for establishment of a reasonable rate structure that takes into account impacts to non-net metering customers; an additional hearing was conducted in February 2020 for purposes of public comment only. The APSC issued an order in June 2020, and in July 2020 several parties, including Entergy Arkansas, filed for rehearing on multiple
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
grounds, including for the reasons that it imposes an unreasonable rate structure and allows facilities to net meter that do not meet the statutory definition of net metering facilities. After granting the rehearing requests, the APSC issued an order in September 2020 largely upholding its June 2020 order. In October 2020, Entergy Arkansas and several other parties filed an appeal of the APSC’s September 2020 order.
Separately, as directed by the APSC general staff, the APSC opened a proceeding to compel utilities to amend their net metering tariffs to incorporate the provisions of the legislation that the APSC general staff considered “black letter law.” Entergy Arkansas, the Arkansas Attorney General, and other intervenors opposed this directive pending the development of the rules for implementation that are being considered in the separate net metering rulemaking docket. Nevertheless, reserving its rights, Entergy Arkansas has complied with the directive to amend its tariffs. Asserting procedural and due process violations, in January 2020, Entergy Arkansas and the Arkansas Attorney General separately appealed certain APSC orders in the proceeding.
COVID-19 Orders
In April 2020, in light of the COVID-19 pandemic, the APSC issued an order requiring utilities, to the extent they had not already done so, to suspend service disconnections during the remaining pendency of the Arkansas Governor’s emergency declaration or until the APSC rescinds the directive. The order also authorizes utilities to establish a regulatory asset to record costs resulting from the suspension of service disconnections, directs that in future proceedings the APSC will consider whether the request for recovery of these regulatory assets is reasonable and necessary, and requires utilities to track and report the costs and any savings directly attributable to suspension of disconnects. In May 2020 the APSC approved Entergy Arkansas expanding deferred payment agreements to assist customers during the COVID-19 pandemic. Quarterly reporting began in August 2020 and the APSC ordered additional reporting in October 2020 regarding utilities’ transitional plans for ending the moratorium on service disconnects. In February 2021 the APSC issued an order finding that it is not in the public interest to immediately lift the moratorium on service disconnects, but to announce a target date of May 3, 2021. In March 2021 the APSC will issue an order either confirming the lifting of the moratorium on service disconnects or extending the moratorium. As of December 31, 2020, Entergy Arkansas recorded a regulatory asset of $10.5 million for costs associated with the COVID-19 pandemic.
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 Arkansas owns and, 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 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; the performance and capacity factors of these nuclear plants including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; 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 either ANO 1 or ANO 2, Entergy Arkansas may be required to
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ANO 1’s operating license expires in 2034 and ANO 2’s operating license expires in 2038.
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, 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.
In the first quarter 2019, 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 $126.2 million increase in its decommissioning cost liabilities, along with corresponding increases in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.
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.
Impairment of Long-lived Assets
See “Impairment of Long-lived Assets” 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.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
Costs 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 2021 Qualified Pension Cost | | Impact on 2020 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $2,406 | | $46,791 |
| Rate of return on plan assets | | (0.25%) | | $2,914 | | $— |
| Rate of increase in compensation | | 0.25% | | $1,838 | | $8,922 |
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 2021 Postretirement Benefit Cost | | Impact on 2020 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $174 | | $6,576 |
| Health care cost trend | | 0.25% | | $225 | | $4,516 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Arkansas in 2020 was $81.7 million, including $21.1 million in settlement costs. Entergy Arkansas anticipates 2021 qualified pension cost to be $61.6 million. Entergy Arkansas contributed $60 million to its qualified pension plans in 2020 and estimates pension contributions will be approximately $66.6 million in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021.
Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 2020 was $10.1 million. Entergy Arkansas expects 2021 postretirement health care and life insurance benefit income of approximately $11.1 million. Entergy Arkansas contributed $2.2 million to its other postretirement plans in 2020 and estimates 2021 contributions will be approximately $517 thousand.
Entergy Arkansas, 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 member and Board of Directors of
Entergy Arkansas, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Arkansas, LLC and Subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of income, cash flows and changes in member’s equity (pages 332 through 336 and applicable items in pages 51 through 238), for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Arkansas, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arkansas Public Service Commission (the “APSC”), which has jurisdiction with respect to the rates of electric companies in Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment;
regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the APSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses 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. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the APSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs, including costs related to the Opportunity Sales Proceeding and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the APSC and the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the APSC and the FERC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the APSC and the FERC for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the APSC’s and the FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, including the Opportunity Sales Proceeding, we inspected the Company’s filings with the APSC and the FERC, including the annual formula rate plan filing, and considered the filings with the APSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, including the Opportunity Sales Proceeding, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2021
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $2,084,494 | | | $2,259,594 | | | $2,060,643 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 271,896 | | | 458,907 | | | 517,245 | |
| Purchased power | | 187,690 | | | 204,640 | | | 252,390 | |
| Nuclear refueling outage expenses | | 55,737 | | | 68,769 | | | 77,915 | |
| Other operation and maintenance | | 669,518 | | | 720,217 | | | 724,831 | |
| Decommissioning | | 73,319 | | | 68,030 | | | 60,420 | |
| Taxes other than income taxes | | 121,057 | | | 115,869 | | | 104,771 | |
| Depreciation and amortization | | 338,029 | | | 307,351 | | | 292,649 | |
| Other regulatory credits - net | | (35,310) | | | (11,186) | | | (14,807) | |
| TOTAL | | 1,681,936 | | | 1,932,597 | | | 2,015,414 | |
| | | | | | |
| OPERATING INCOME | | 402,558 | | | 326,997 | | | 45,229 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 15,019 | | | 15,499 | | | 16,557 | |
| Interest and investment income | | 35,579 | | | 26,020 | | | 25,406 | |
| Miscellaneous - net | | (21,908) | | | (18,566) | | | (14,874) | |
| TOTAL | | 28,690 | | | 22,953 | | | 27,089 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 144,834 | | | 140,087 | | | 124,459 | |
| Allowance for borrowed funds used during construction | | (6,595) | | | (6,332) | | | (7,781) | |
| TOTAL | | 138,239 | | | 133,755 | | | 116,678 | |
| | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | 293,009 | | | 216,195 | | | (44,360) | |
| | | | | | |
| Income taxes | | 47,777 | | | (46,769) | | | (297,067) | |
| | | | | | |
| NET INCOME | | 245,232 | | | 262,964 | | | 252,707 | |
| | | | | | |
| Preferred dividend requirements | | 0 | | | 0 | | | 1,249 | |
| | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | | $245,232 | | | $262,964 | | | $251,458 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $245,232 | | | $262,964 | | | $252,707 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 490,457 | | | 465,299 | | | 443,698 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 87,019 | | | 94,368 | | | 129,524 | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (24,507) | | | (58,077) | | | 4,294 | |
| Fuel inventory | | (10,066) | | | (10,597) | | | 6,210 | |
| Accounts payable | | (22,773) | | | 3,059 | | | (126,405) | |
| Prepaid taxes and taxes accrued | | 6 | | | 24,942 | | | 9,568 | |
| Interest accrued | | (43) | | | 3,895 | | | 678 | |
| Deferred fuel costs | | (1,186) | | | 72,560 | | | 43,869 | |
| Other working capital accounts | | (11,061) | | | 18,783 | | | (30,118) | |
| Provisions for estimated losses | | 6,289 | | | 14,901 | | | 14,250 | |
| Other regulatory assets | | (165,534) | | | (131,873) | | | 32,460 | |
| Other regulatory liabilities | | 106,878 | | | 39,293 | | | (341,682) | |
| | | | | | |
| Pension and other postretirement liabilities | | 42,576 | | | 5,831 | | | (40,157) | |
| Other assets and liabilities | | (83,469) | | | (127,582) | | | (187,071) | |
| Net cash flow provided by operating activities | | 659,818 | | | 677,766 | | | 211,825 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (775,595) | | | (641,525) | | | (660,044) | |
| Allowance for equity funds used during construction | | 15,019 | | | 15,306 | | | 17,013 | |
| Nuclear fuel purchases | | (100,678) | | | (54,344) | | | (99,417) | |
| Proceeds from sale of nuclear fuel | | 30,638 | | | 22,782 | | | 54,810 | |
| | | | | | |
| Proceeds from nuclear decommissioning trust fund sales | | 321,360 | | | 317,377 | | | 300,801 | |
| Investment in nuclear decommissioning trust funds | | (336,392) | | | (336,519) | | | (315,163) | |
| Payment for purchase of assets | | (5,988) | | | 0 | | | 0 | |
| Changes in money pool receivable - net | | (3,110) | | | 0 | | | 0 | |
| | | | | | |
| | | | | | |
| | | | | | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | 55,001 | | | 0 | | | 0 | |
| | | | | | |
| Insurance proceeds | | 0 | | | 0 | | | 14,790 | |
| Other | | 4,036 | | | 630 | | | (1,517) | |
| Net cash flow used in investing activities | | (795,709) | | | (676,293) | | | (688,727) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 1,071,121 | | | 834,038 | | | 958,434 | |
| Retirement of long-term debt | | (632,175) | | | (548,952) | | | (690,488) | |
| Capital contribution from parent | | 0 | | | 0 | | | 350,000 | |
| Redemption of preferred stock | | 0 | | | 0 | | | (32,660) | |
| Change in money pool payable - net | | (21,634) | | | (161,104) | | | 16,601 | |
| Changes in short-term borrowings - net | | 0 | | | 0 | | | (49,974) | |
| Distributions/dividends paid: | | | | | | |
| Common equity | | (95,000) | | | (115,000) | | | (91,751) | |
| Preferred stock | | 0 | | | 0 | | | (1,606) | |
| Other | | 2,188 | | | (7,055) | | | 12,249 | |
| Net cash flow provided by financing activities | | 324,500 | | | 1,927 | | | 470,805 | |
| Net increase (decrease) in cash and cash equivalents | | 188,609 | | | 3,400 | | | (6,097) | |
| Cash and cash equivalents at beginning of period | | 3,519 | | | 119 | | | 6,216 | |
| Cash and cash equivalents at end of period | | $192,128 | | | $3,519 | | | $119 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $140,735 | | | $131,134 | | | $118,731 | |
| Income taxes | | ($21,971) | | | ($33,989) | | | $44,393 | |
| See Notes to Financial Statements. | | | | | | |
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2020 | | 2019 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $24,108 | | | $3,519 | |
| Temporary cash investments | | 168,020 | | | 0 | |
| Total cash and cash equivalents | | 192,128 | | | 3,519 | |
| Securitization recovery trust account | | 0 | | | 4,036 | |
| Accounts receivable: | | | | |
| Customer | | 183,719 | | | 117,679 | |
| Allowance for doubtful accounts | | (18,334) | | | (1,169) | |
| Associated companies | | 34,216 | | | 29,178 | |
| Other | | 35,845 | | | 117,653 | |
| Accrued unbilled revenues | | 109,000 | | | 108,489 | |
| Total accounts receivable | | 344,446 | | | 371,830 | |
| | | | |
| | | | |
| Fuel inventory - at average cost | | 43,811 | | | 33,745 | |
| Materials and supplies - at average cost | | 237,640 | | | 211,320 | |
| Deferred nuclear refueling outage costs | | 32,692 | | | 48,875 | |
| | | | |
| | | | |
| Prepayments and other | | 13,296 | | | 14,096 | |
| | | | |
| TOTAL | | 864,013 | | | 687,421 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Decommissioning trust funds | | 1,273,921 | | | 1,101,283 | |
| | | | |
| Other | | 341 | | | 345 | |
| TOTAL | | 1,274,262 | | | 1,101,628 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 12,905,322 | | | 12,293,483 | |
| | | | |
| Construction work in progress | | 234,213 | | | 197,775 | |
| Nuclear fuel | | 163,044 | | | 195,547 | |
| TOTAL UTILITY PLANT | | 13,302,579 | | | 12,686,805 | |
| Less - accumulated depreciation and amortization | | 5,255,355 | | | 5,019,826 | |
| UTILITY PLANT - NET | | 8,047,224 | | | 7,666,979 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets (includes securitization property of $0 as of December 31, 2020 and $1,706 as of December 31, 2019) | | 1,832,384 | | | 1,666,850 | |
| Deferred fuel costs | | 68,220 | | | 67,690 | |
| Other | | 14,028 | | | 15,065 | |
| TOTAL | | 1,914,632 | | | 1,749,605 | |
| | | | |
| TOTAL ASSETS | | $12,100,131 | | | $11,205,633 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2020 | | 2019 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $485,000 | | | $0 | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | 59,448 | | | 111,785 | |
| Other | | 208,591 | | | 202,201 | |
| Customer deposits | | 98,506 | | | 101,411 | |
| Taxes accrued | | 81,837 | | | 81,831 | |
| | | | |
| Interest accrued | | 22,745 | | | 22,788 | |
| Deferred fuel costs | | 53,065 | | | 53,721 | |
| Current portion of unprotected excess accumulated deferred income taxes | | 0 | | | 9,296 | |
| Other | | 40,628 | | | 38,760 | |
| TOTAL | | 1,049,820 | | | 621,793 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 1,286,123 | | | 1,183,126 | |
| Accumulated deferred investment tax credits | | 30,500 | | | 31,701 | |
| Regulatory liability for income taxes - net | | 467,031 | | | 478,174 | |
| Other regulatory liabilities | | 686,872 | | | 559,555 | |
| Decommissioning | | 1,314,160 | | | 1,242,616 | |
| Accumulated provisions | | 70,169 | | | 63,880 | |
| Pension and other postretirement liabilities | | 361,682 | | | 319,075 | |
| Long-term debt (includes securitization bonds of $0 as of December 31, 2020 and $6,772 as of December 31, 2019) | | 3,482,507 | | | 3,517,208 | |
| Other | | 75,098 | | | 62,568 | |
| TOTAL | | 7,774,142 | | | 7,457,903 | |
| | | | |
| Commitments and Contingencies | | 0 | | 0 |
| | | | |
| | | | |
| | | | |
| EQUITY | | | | |
| Member's equity | | 3,276,169 | | | 3,125,937 | |
| TOTAL | | 3,276,169 | | | 3,125,937 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $12,100,131 | | | $11,205,633 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY |
| For the Years Ended December 31, 2020, 2019, and 2018 |
| |
| |
| Member's Equity |
| (In Thousands) |
| |
| Balance at December 31, 2017 | $2,376,754 | |
| Net income | 252,707 | |
| Capital contributions from parent | 350,000 | |
| |
| Common equity distributions | (91,751) | |
| Non-cash contribution from parent | 94,335 | |
| Preferred stock dividends | (1,249) | |
| Other | 2,307 | |
| Balance at December 31, 2018 | $2,983,103 | |
| Net income | 262,964 | |
| |
| |
| Common equity distributions | (115,000) | |
| |
| |
| Other | (5,130) | |
| Balance at December 31, 2019 | $3,125,937 | |
| Net income | 245,232 | |
| |
| |
| Common equity distributions | (95,000) | |
| |
| |
| |
| Balance at December 31, 2020 | $3,276,169 | |
| |
| See Notes to Financial Statements. | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | | (In Thousands) |
| | | | | | | | | | |
| Operating revenues | | $2,084,494 | | | $2,259,594 | | | $2,060,643 | | | $2,139,919 | | | $2,086,608 | |
| Net income | | $245,232 | | | $262,964 | | | $252,707 | | | $139,844 | | | $167,212 | |
| Total assets | | $12,100,131 | | | $11,205,633 | | | $10,401,596 | | | $10,134,029 | | | $9,606,117 | |
| Long-term obligations (a) | | $3,482,507 | | | $3,517,208 | | | $3,225,759 | | | $2,983,749 | | | $2,746,435 | |
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund. |
| | | | | | | | | | |
| | | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | | | | | | | | | | |
| Residential | | $841 | | | $795 | | | $807 | | | $768 | | | $789 | |
| Commercial | | 466 | | | 539 | | | 426 | | | 495 | | | 495 | |
| Industrial | | 462 | | | 521 | | | 434 | | | 472 | | | 446 | |
| Governmental | | 18 | | | 21 | | | 17 | | | 19 | | | 18 | |
| Total billed retail | | 1,787 | | | 1,876 | | | 1,684 | | | 1,754 | | | 1,748 | |
| Sales for resale: | | | | | | | | | | |
| Associated companies | | 105 | | | 118 | | | 104 | | | 128 | | | 49 | |
| Non-associated companies | | 68 | | | 140 | | | 145 | | | 121 | | | 118 | |
| Other | | 124 | | | 126 | | | 128 | | | 137 | | | 172 | |
| Total | | $2,084 | | | $2,260 | | | $2,061 | | | $2,140 | | | $2,087 | |
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | | |
| Residential | | 7,584 | | | 7,996 | | | 8,248 | | | 7,298 | | | 7,618 | |
| Commercial | | 5,356 | | | 5,822 | | | 5,967 | | | 5,825 | | | 5,988 | |
| Industrial | | 7,586 | | | 7,759 | | | 8,071 | | | 7,528 | | | 6,795 | |
| Governmental | | 223 | | | 241 | | | 239 | | | 237 | | | 237 | |
| Total retail | | 20,749 | | | 21,818 | | | 22,525 | | | 20,888 | | | 20,638 | |
| Sales for resale: | | | | | | | | | | |
| Associated companies | | 1,659 | | | 2,180 | | | 1,773 | | | 1,782 | | | 1,609 | |
| Non-associated companies | | 4,198 | | | 7,206 | | | 6,447 | | | 6,549 | | | 7,115 | |
| Total | | 26,606 | | | 31,204 | | | 30,745 | | | 29,219 | | | 29,362 | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
Hurricane Laura, Hurricane Delta, and Hurricane Zeta
In August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.0 billion, including approximately $1.67 billion in capital costs and approximately $330 million in non-capital costs. This estimate includes all costs to restore power and repair or replace the damages from the hurricanes, except for the cost to repair or replace damage incurred to an Entergy Louisiana transmission line in southeast Louisiana, and the amount of that cost could be significant. The restoration plan for this transmission line and the related cost estimate is still being evaluated. Also, Entergy Louisiana’s revenues were adversely affected in 2020, primarily due to power outages resulting from the hurricanes. Entergy Louisiana is considering all reasonable avenues to recover storm-related costs from Hurricane Laura, Hurricane Delta, and Hurricane Zeta, including securitization. Storm cost recovery or financing will be subject to review by applicable regulatory authorities.
Entergy Louisiana recorded accounts payable and corresponding construction work in progress and regulatory assets for the estimated costs incurred that were necessary to return customers to service. Entergy Louisiana recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles. Because Entergy Louisiana has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments to facilitate issuance of shorter-term bonds to provide interim financing for restoration costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff filed a joint motion seeking approval to exclude from the derivation of Entergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta costs on an interim basis. In November 2020 the LPSC issued an order approving the joint motion, and Entergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana drew $257 million from its funded storm reserves.
In December 2020, Entergy Louisiana provided the LPSC with notification that it intends to initiate a storm cost recovery proceeding in the near future, which will permit the LPSC to retain any outside consultants and counsel needed to review the storm cost recovery application. In February 2021 the LPSC voted to retain outside counsel and consultants to assist in the review of Entergy Louisiana’s upcoming storm cost recovery application, which is expected to be filed in March 2021.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
(3) recommended recovery from customers over ten years but stated that
See the LPSC may want to consider 15 years; (4) allowed“February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for recoverya discussion of carrying costs and earning a return on project costs, but at a reduced rate approximatingthe February 2021 winter storms. Entergy Louisiana’s preliminary estimate for the cost of debt, while also acknowledging that the LPSC may consider ordering no return;mobilizing crews and (5) indicated that Entergy Louisiana should be directedrestoring power is approximately $50 million 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$60 million. Natural gas purchases for Entergy Louisiana for February 1st through 25th, 2021 are approximately $190 million compared to recover $200natural gas purchases for February 2020 of $39 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income increased $390.8 million asprimarily due to the $382.8 million reduction in deferred income tax expense related to the basis of March 31, 2011, and carrying costs on that amount on specified terms thereafter. The settlement also provides forassets contributed in the 2015 Entergy Louisiana to recover the approved project costs by securitization. In April 2011,and Entergy Gulf States Louisiana filed an application with the LPSC to authorize the securitizationbusiness combination as a result of the investment recovery costs associatedresolution of the 2014-2015 IRS audit in the fourth quarter 2020 and the $58 million reduction in income tax expense resulting from an IRS settlement in the first quarter 2020 related to the uncertain tax position regarding the Hurricane Isaac Louisiana Act 55 financing, which also resulted in a $29 million ($21 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s agreement to share the savings with customers. Also contributing to the projectincrease were higher retail electric price, lower other operation and to issuemaintenance expenses, and a financing orderlower effective income tax rate. The increase was partially offset by which Entergy Louisiana could accomplish such securitization. In August 2011 the LPSC issued an order approving the settlementhigher depreciation and also issued a financing order for the securitization.amortization expenses, lower volume/weather, lower other income, higher interest expense, and higher taxes other than income taxes. See Note 53 to the financial statements for afurther discussion of the September 2011 issuancetax audit resolution and the tax settlement.
Operating Revenues
Following is an analysis of the securitization bonds.change in operating revenues comparing 2020 to 2019:
| | | | | |
| Amount |
| (In Millions) |
| 2019 operating revenues | $4,285.2 | |
| Fuel, rider, and other revenues that do not significantly affect net income | (330.3) | |
| Volume/weather | (68.8) | |
| Return of unprotected excess accumulated deferred income taxes to customers | 7.5 | |
| Retail electric price | 176.3 | |
| 2020 operating revenues | $4,069.9 | |
State
Entergy Louisiana’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and Local Rate Regulationother costs such that the revenues and Fuel-Cost Recoveryexpenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
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,volume/weather variance is primarily responsible for approvaldue to decreased commercial and industrial usage as a result of the rates charged to customers.
Retail Rates - Electric
Filings withCOVID-19 pandemic, the LPSC
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 returneffects of Hurricane Laura, Hurricane Delta, and Hurricane Zeta 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 formula rate plan revenue of $9.7 million,sales, 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 $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 staff 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. In July 2018, Entergy Louisiana and the LPSC staff filed an unopposed joint report setting forth a correction to the annualization calculation, the effect of which wasless favorable weather on residential sales, partially offset by increased residential usage as a net $3.5 million revenue requirement reductionresult of the COVID-19 pandemic. The decrease in industrial usage is partially offset by an increase in demand from expansion projects, primarily in the transportation and indicating that there are no outstanding issues withchemicals industries. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the 2016 formula rate plan report, the supplemental report, or the interim updates. In September 2018 the LPSC approved the unopposed joint report.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Formula Rate Plan Extension Through 2019 Test Year
In August 2017, Entergy Louisiana filed a request withThe return of unprotected excess accumulated deferred income taxes to customers resulted from the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications to its terms. In April 2018, the LPSC approved an unopposed joint motion filed by Entergy Louisiana and the LPSC staff that settles the matter and extendsreturn of unprotected excess accumulated deferred income taxes through changes in the formula rate plan effective May 2018. In 2020, $31.1 million was returned to customers as compared to $38.6 million in 2019. There was no effect on net income as the reduction in operating revenues was offset by a reduction in income tax expense. See Note 2 to the financial statements for three years, providing for rates through at least August 2021. In additionfurther discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
The retail electric price variance is primarily due to retaining the major features of the traditional formula rate plan, some of the more substantive features of the extended formula rate plan include:
a mid-point reset ofan increase in formula rate plan revenues effective June 2019 due to a 9.95% earned return on common equitythe inclusion of the first-year revenue requirement for the 2017 test year and for theJ. Wayne Leonard Power Station (formerly St. Charles Power Station when it enters commercial operation;
a 9.8% target earned return on common equityStation) and effective April 2020 due to the inclusion of the first-year revenue requirement for the 2018Lake Charles Power Station and 2019 test years;
narrowing of the common equity bandwidth to plus or minus 60 basis points around the earned return on common equity;
a cap on potential revenue increase of $35 million for the 2018 evaluation period, and $70 million for the cumulative 2018 and 2019 evaluation periods, on formula rate plan cost of service rate increases (the cap excludes rate changes associated with the transmission recovery mechanism described below and rate changes associated with additional capacity);
a framework for the flow back of certain tax benefits created by the Tax Act to customers; and
a transmission recovery mechanism providing for the opportunity to recover certain transmission related expenditures in excess of $100 million for projects placed in service up to one month prior to rate change outside of sharing that is designed to operate in a fashion similar to the additional capacity mechanism.
Entergy Louisiana has indicated its intent to seek an extension of its formula rate plan on terms similar to the existing terms.
2017 Formula Rate Plan Filing
In June 2018, Entergy Louisiana filed its formula rate plan evaluation report for its 2017 calendar year operations. The 2017 test year evaluation report produced an earned return on equity of 8.16%, due in large part to revenue-neutral realignments to other recovery mechanisms. Without these realignments, the evaluation report produces an earned return on equity of 9.88% and a resulting base rider formula rate plan revenue increase of $4.8 million. Excluding the Tax Act credits provided for by the tax reform adjustment mechanisms, total formula rate plan revenues wereeffective September 2019 and September 2020. See Note 2 to the financial statements for further increased by discussion of the formula rate plan proceedings.
Other Income Statement Variances
Other operation and maintenance expenses decreased primarily due to:
•a totaldecrease of $98$10.2 million in nuclear generation expenses primarily due to a lower scope of work performed in 2020 as compared to 2019, in part as a result of the evaluation reportCOVID-19 pandemic;
•a decrease of $9.5 million primarily due to adjustmentscontract costs in 2019 related to initiatives to explore new customer products and services;
•a decrease of $6.8 million in loss provisions;
•higher nuclear insurance refunds of $5.9 million;
•a decrease of $5.8 million in energy efficiency costs due to the additional capacitytiming of recovery from customers; and MISO cost recovery mechanisms
•a decrease of $4.3 million in non-nuclear generation expenses primarily due to a lower scope of work performed during plant outages in 2020 as compared to the same period in 2019, partially offset by increases resulting from the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and the Lake Charles Power Station being placed in service.
The decrease was partially offset by:
•an increase of $4.1 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefits costs as a result of a decrease in the discount rate used to value the benefit liabilities. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs; and
•several individually insignificant items.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher property assessments.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station), which was placed into service in May 2019 and the Lake Charles Power Station, which was placed in service in March 2020.
Other regulatory charges (credits) include regulatory charges of $32.6 million recorded in the fourth quarter 2020 due to a settlement with the IRS related to the uncertain tax position regarding Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing because the savings will be shared with customers and $29 million recorded in the first quarter 2020 due to a settlement with the IRS related to the uncertain tax position regarding Hurricane Isaac Louisiana Act 55 financing because the savings will be shared with customers. See Note 3 to the financial statements for further discussion of the formula rate plan,settlements and implementation of the transmission recovery mechanism. In August 2018, Entergy Louisiana filed a supplemental formula rate plan evaluation report to reflect changes from the 2016 test year formula rate plan proceedings, a decrease to the transmission recovery mechanism to reflect lower actual capital additions, and a decrease to evaluation period expenses to reflect the terms of a new power sales agreement. Based on the August 2018 update, Entergy Louisiana recognized a total decrease in formula rate plan revenue of approximately $17.6 million. Results of the updated 2017 evaluation report filing were implemented with the September 2018 billing month subject to refund and review by the LPSC staff and intervenors. In accordance with the terms of the formula rate plan, in September 2018 the LPSC staff and intervenors submitted their responses to Entergy Louisiana’s original formula rate plan evaluation report and supplemental compliance updates. The LPSC staff asserted objections/reservations regarding 1) Entergy Louisiana’s proposed rate adjustments associated with the return of excess accumulated deferred income taxes pursuant to the Tax Act and the treatment of accumulated deferred income taxes related to reductions of rate base; 2) Entergy Louisiana’s reservation regarding treatment of a regulatory asset related to certain special orders by the LPSC; and 3) test year expenses billed from Entergy Services to Entergy Louisiana. Intervenors also objected to Entergy Louisiana’s treatment of the regulatory asset related to certain special orders by the LPSC. A procedural schedule has not yet been established to resolve these issues.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Louisiana also included
•a decrease in its filing a presentation of an initial proposalthe allowance for equity funds used during construction due to combinehigher construction work in progress in 2019, including the legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana residential rates, which combination, if approved, would be accomplished on a revenue-neutral basis intended not to affect the rates of other customer classes.
Commercial operation atJ. Wayne Leonard Power Station (formerly St. Charles Power Station) and the Lake Charles Power Station commencedprojects; and
•changes in May 2019. In Maydecommissioning trust fund activity.
Interest expense increased primarily due to:
•the issuances of $300 million of 4.20% Series mortgage bonds and $350 million of 2.90% Series mortgage bonds, each in March 2020;
•the issuance of $525 million of 4.20% Series mortgage bonds in March 2019; and
•a decrease in the allowance for borrowed funds used during construction due to higher construction work in progress in 2019, Entergy Louisiana filed an update to its 2017 formula rate plan evaluation report to includeincluding the estimated first-year revenue requirement of $109.5 million associated with theJ. Wayne Leonard Power Station (formerly St. Charles Power Station. Station) and Lake Charles Power Station projects.
The resulting interim adjustmenteffective income tax rates were (54.6%) for 2020 and 15% for 2019. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2020 was primarily due to rates becamecompletion of the 2014-2015 IRS audit effectively settling the tax positions for those years. The difference in the effective withincome tax rate versus the first billing cyclefederal statutory rate of June 2019.
2018 Formula Rate Plan Filing
In May21% for 2019 Entergy Louisiana filed its formula rate plan evaluation report for its 2018 calendar year operations. The 2018 test year evaluation report produced an earned return on common equity of 10.61% leading to a base rider formula rate plan revenue decrease of $8.9 million. While base rider formula rate plan revenue will decrease as a result of this filing, overall formula rate plan revenues will increase by approximately $118.7 million. This outcome iswas primarily driven by a reductiondue to the credits previously flowed throughamortization of excess accumulated deferred income taxes. See Notes 2 and 3 to the tax reform adjustment mechanismfinancial statements for a discussion of the effects and an increase inregulatory activity regarding the transmission recovery mechanism, partially offset by reductions inTax Cuts and Jobs Act. See Note 3 to the additional capacity mechanism revenue requirements and extraordinary cost items. The filing is subject to review byfinancial statements for a reconciliation of the LPSC. Resulting rates were implemented in September 2019, subject to refund.
Entergy Louisiana also included in its filing a presentation of an initial proposal to combine the legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana residential rates, which combination, if approved, would be accomplished on a revenue-neutral basis intended not to affect thefederal statutory rates of other customer classes. Entergy Louisiana contemplates that any combination of residential rates resulting from this request would be implemented with the results of the 2019 test year formula rate plan filing.
Several parties intervened in the proceeding and the LPSC staff filed its report of objections/reservations in accordance with the applicable provisions of the formula rate plan. In its report the LPSC staff re-urged reservations with respect21% to the outstanding issues from the 2017 test year formula rate plan filing and disputed the inclusioneffective income tax rates.
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of certain affiliate costs for test years 2017 and 2018. The LPSC staff objected to Entergy Louisiana’s proposal to combine residential rates but proposed the setting of a status conference to establish a procedural schedule to more fully address the issue. The LPSC staff also reserved its right to object to the treatment of the sale of Willow Glen reflectedOperations” in the evaluation report and to the August 2019 compliance update, which was made primarily to update the capital additions reflected in the formula rate plan’s transmission recovery mechanism, based on limited time to review it. Additionally, since the completion of certain transmission projects, the LPSC staff has issued supplemental data requests addressing the prudenceItem 7 of Entergy Louisiana’s expenditures in connectionAnnual Report on Form 10-K for the year ended December 31, 2019, filed with those projects. Entergy Louisiana is in the processSEC on February 21, 2020, for discussion of respondingresults of operations for 2019 compared to those requests.2018.
Investigation of Costs Billed by Entergy Services
In November
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 the LPSC issued a notice of proceeding initiating an investigation into costs incurred by Entergy Services that are included in the retail rates of Entergy Louisiana. As stated in the notice of proceeding, the LPSC observed an increase in capital construction-related costs incurred by Entergy Services. Discovery was issued and included efforts to seek highly detailed information on a broad range of matters unrelated to the scope of the audit. There has been no further activity in the investigation since May 2019.were as follows:
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $2,006 | | | $43,364 | | | $35,907 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 1,072,986 | | | 1,236,002 | | | 1,395,204 | |
| Investing activities | (1,944,671) | | | (1,653,634) | | | (1,878,208) | |
| Financing activities | 1,597,699 | | | 376,274 | | | 490,461 | |
| Net increase (decrease) in cash and cash equivalents | 726,014 | | | (41,358) | | | 7,457 | |
| | | | | |
| Cash and cash equivalents at end of period | $728,020 | | | $2,006 | | | $43,364 | |
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
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
staff filed testimony recommending potential project
Operating Activities
Net cash flow provided by operating activities decreased $163 million in 2020 primarily due to:
•an increase of $186.1 million in storm spending in 2020, primarily due to Hurricane Laura, Hurricane Delta, and replacementHurricane Zeta restoration efforts. See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of storm restoration efforts;
•lower collections of receivables from customers, in part due to the COVID-19 pandemic;
•the timing of recovery of fuel and purchased power cost disallowancescosts; and
•an increase of up$21.5 million in interest paid.
The decrease was partially offset by:
•a decrease in $43.7 million in spending on nuclear refueling outages;
•the timing of payments to $71vendors; and
•income tax refunds of $14.7 million citingin 2020 compared to $15.3 million in income tax payments in 2019. Entergy Louisiana had income tax refunds in 2020 and income tax payments in 2019 in accordance with an intercompany tax allocation agreement. Entergy Louisiana had income tax refunds in 2020 as a needresult of a refund of an overpayment on a prior year state income tax return.
Investing Activities
Net cash flow used in investing activities increased $291 million in 2020 primarily due to:
•an increase of $709.7 million in storm spending 2020, primarily due to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration efforts, See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of storm restoration efforts;
•the purchase of Washington Parish Energy Center in November 2020 for approximately $222 million. See Note 14 to the financial statements 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. 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 becausediscussion of the uncertainty at the time associated with the resolutionWashington Parish Energy Center purchase;
•an increase 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$16.7 million in capital costs. Additionally,distribution construction expenditures primarily due to investment in the ALJ concluded thatreliability and infrastructure of Entergy Louisiana did not sufficiently justify the incurrenceLouisiana’s distribution system, including increased spending on advanced metering infrastructure; and
•money pool activity.
The increase was partially offset by:
•an increase of $2$302.2 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 progressnet receipts from storm reserve escrow accounts;
•a decrease of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77$207.8 million in charges, including non-nuclear generation construction expenditures due to higher spending in 2019 on the Lake Charles Power Station and J. Wayne Leonard Power Station (formerly St. Charles Power Station) projects;
•a $45decrease of $133.1 million asset write-offin transmission construction expenditures primarily due to a lower scope of work performed on various projects in 2020 as compared to 2019;
•a decrease of $89.5 million in nuclear construction expenditures primarily due to a lower scope of work performed on various nuclear projects in 2020 as compared to 2019; and
•a $32 million regulatory charge, to reflect that a portiondecrease 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$26.1 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the settlement approved bytiming and pricing of fuel reload requirements in the LPSC was made to customersUtility business, material, and service deliveries, and the timing of cash payments during the nuclear fuel cycle.
Increases in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outsidereceivable from the money pool are a use 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 staffcash flow, and Entergy Louisiana in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.
Advanced Metering Infrastructure (AMI)
In November 2016, Entergy Louisiana filed an application seeking a findingLouisiana’s receivable from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure ismoney pool increased by $13.4 million in the public interest. Entergy Louisiana proposed2020 compared 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 and identified a number of quantified and unquantified benefits. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which began in 2019. Deployment of the communications network began in 2018. 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. Entergy Louisiana will recover the undepreciated balance of its existing meters through a regulatory asset to be amortized at current depreciation rates, as approveddecreasing by the LPSC.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
million in 2019. 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 $1,221.4 million in 2020 primarily due to:
•the issuance of $1.1 billion of 0.62% Series mortgage bonds in November 2020;
•the issuance of $350 million of 2.90% Series mortgage bonds and $300 million of 4.20% Series mortgage bonds, each in March 2020;
•the issuance of $300 million of 2.90% Series mortgage bonds and $300 million of 1.60% Series mortgage bonds, each in November 2020; and
•a decrease of $186.5 million in common equity distributions in 2020 primarily due to upcoming capital expenditures.
The increase was partially offset by:
•the issuance of $525 million of 4.20% Series mortgage bonds in March 2019;
•the repayment in August 2020 of $250 million of 3.95% Series mortgage bonds due October 2020;
•the repayment in December 2020 of $200 million of 5.25% Series mortgage bonds due July 2052;
•money pool activity;
•the repayment in December 2020 of $100 million of 4.70% Series mortgage bonds due June 2063; and
•net repayments of long-term borrowings of $62 million in 2020 on the nuclear fuel company variable interest entities’ credit facilities.
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 $82.8 million in 2020 compared to increasing by $82.8 million in 2019.
See Note 5 to the financial statements for details of long-term debt.
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
Entergy Louisiana’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for Entergy Louisiana is primarily due to the net issuances of long-term debt in 2020.
| | | | | | | | | | | |
| | December 31,
2020 | | December 31,
2019 |
| Debt to capital | 54.8 | % | | 53.4 | % |
| Effect of excluding securitization bonds | 0.0 | % | | (0.1 | %) |
| Debt to capital, excluding securitization bonds (a) | 54.8 | % | | 53.3 | % |
| Effect of subtracting cash | (2.1 | %) | | (0.1 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 52.7 | % | | 53.2 | % |
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
(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, finance lease obligations, 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 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 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 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 distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Louisiana may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Louisiana 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
•distribution and interest payments.
Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2022 | | 2023 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $365 | | | $460 | | | $785 | |
| Transmission | 425 | | | 340 | | | 230 | |
| Distribution | 540 | | | 485 | | | 500 | |
| Utility Support | 160 | | | 130 | | | 115 | |
| Total | $1,490 | | | $1,415 | | | $1,630 | |
In addition to the planned spending in the table above, Entergy Louisiana also expects to pay for $845 million of capital investments in 2021 related to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration work that have been accrued as of December 31, 2020.
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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| | (In Millions) |
| Long-term debt (a) | $557 | | | $2,294 | | | $1,495 | | | $9,506 | | | $13,852 | |
| Operating leases (b) | $13 | | | $19 | | | $10 | | | $4 | | | $46 | |
| Finance leases (b) | $4 | | | $7 | | | $4 | | | $2 | | | $17 | |
| Purchase obligations (c) | $687 | | | $1,463 | | | $1,472 | | | $4,838 | | | $8,460 | |
(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)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 $59.9 million to its qualified pension plans and approximately $15.6 million to its other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. See “Critical Accounting Estimates- 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 Louisiana includes specific investments such as transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to maintain reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; investments in River Bend and Waterford 3; software and security; 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.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly.
Sources of Capital
Entergy Louisiana’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•storm reserve escrow accounts;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Louisiana may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest 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. 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.
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | | 2017 |
| (In Thousands) |
| $13,426 | | ($82,826) | | $46,843 | | $11,173 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Louisiana has a credit facility in the amount of $350 million scheduled to expire in September 2024. The credit facility includes fronting commitments for the issuance of letters of credit against $15 million of the borrowing capacity of the facility. As of December 31, 2020, there were no cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy Louisiana 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, 2020, $2.2 million in letters of credit were outstanding under Entergy Louisiana’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
The Entergy Louisiana nuclear fuel company variable interest entities have two separate credit facilities, each in the amount of $105 million and scheduled to expire in September 2022. As of December 31, 2020, $18.9 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, 2020, $39.3 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 obtained authorizations from the FERC through July 2022 for the following:
•short-term borrowings not to exceed an aggregate amount of $450 million at any time outstanding;
•long-term borrowings and security issuances; and
•borrowings by its nuclear fuel company variable interest entities.
See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.
Hurricane Isaac
In 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 Louisiana to 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.
Retail Rates - Gas
2016 Rate Stabilization Plan Filing
In January 2017, Entergy Louisiana filedaccordance with the LPSC itssettlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2016.2012, 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 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
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investment associated with these projects. The filingrider 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 the evaluation report for test year 2016 reflectedupper end of the earnings band as an earned return on common equityoffset to the revenue requirement of 6.37%. In April 2017the 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 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.
2017 Rate Stabilization Plan Filing
In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2017. The filing2015. Implementation 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. In April 2018, Entergy Louisiana filed a supplemental evaluation report for the test year ended September 2017, reflecting the effects of the Tax Act, including a proposal to use the unprotected excess accumulated deferred income taxes to offset approximately $1.4 million of storm restoration deferred operation and maintenance costs incurred by Entergy Louisiana in connection with the August 2016 flooding disaster in its gas service area. The supplemental filing reflects an earned return on common equity of 10.79%. As-filed rates from the supplemental filing were implemented, subject to refund, with customers receiving a cost reduction of approximately $0.7 million effectiveinfrastructure rider commenced with bills rendered on and after the first billing cycle of May 2018,April 2015.
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 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 $0.2consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power 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.
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.
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Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
Formula Rate Plan
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 was still appropriate or could 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 proceeding. In March 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. 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.
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.
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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Energy Efficiency Programs
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 and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. 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. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
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 Reliability Corporation (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
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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.
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.
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.
The PUCT determined that unrecovered costs that may 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 amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
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.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
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 Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in 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 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.
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Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city 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 over the period 2020-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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, 2020, is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,175 | | | 2,091 | | | 1,817 | | | 1,194 | | | 73 | | | — | |
| Entergy Louisiana | | 11,317 | | | 8,827 | | | 2,144 | | | 346 | | | — | | | — | |
| Entergy Mississippi | | 3,347 | | | 2,929 | | | — | | | 416 | | | — | | | 2 | |
| Entergy New Orleans | | 665 | | | 638 | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 2,260 | | | 2,005 | | | — | | | 255 | | | — | | | — | |
| System Energy | | 1,256 | | | — | | | 1,256 | | | — | | | — | | | — | |
| Total | | 24,020 | | | 16,490 | | | 5,217 | | | 2,211 | | | 73 | | | 29 | |
(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 21,591 MW over the previous decade.
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, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation 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 8,801 MW of new long-term resources and the deactivation of about 4,664 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.
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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 MISO reliability requirements as well as long-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:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•In October 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the facility is scheduled to be in service by early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020 and the facility is scheduled to be in service by the end of 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility.The facility was placed in service in December 2020;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas.In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals.Closing is expected to occur by the end of 2023.
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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’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s 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);
•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 Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf 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 petroleum 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, 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 10-year agreement 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;
•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;
•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 approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 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 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 received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
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•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas.The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP was seeking 300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
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; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; 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); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility is an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, owned by East Texas Electric Cooperative. Entergy Texas is currently seeking regulatory certification to move forward with the purchase of the facility. The facility has been in operation since January 2010.
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Power Through Program
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation that is to be installed at commercial and industrial customer premises. If approved, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.”
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-electric production facilities, combustion-turbine generators, pressurized and boiling water nuclear reactors, and inverter-based technologies operating in the MISO energy and ancillary services market. 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 facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of 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 Bulk Electric System reliability standards within the SERC Region.
Gas Property
As of December 31, 2020, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2020, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy 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 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 of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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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 2018-2020 were:
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| | | 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 |
| 2020 | | 47 | | | 1.92 | | | 29 | | | 0.57 | | | 3 | | | 2.54 | | | 8 | | | 4.36 | | | 13 | | | 2.48 | |
| 2019 | | 40 | | | 2.33 | | | 28 | | | 0.73 | | | 6 | | | 2.31 | | | 8 | | | 4.86 | | | 18 | | | 2.71 | |
| 2018 | | 39 | | | 2.84 | | | 27 | | | 0.84 | | | 9 | | | 2.24 | | | 8 | | | 5.23 | | | 17 | | | 3.71 | |
Actual 2020 and projected 2021 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:
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| | Natural Gas | | Nuclear | | Coal | | Purchased Power (d) | | MISO Purchases (e) |
| | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 |
| Entergy Arkansas (a) | 24 | % | | 35 | % | | 60 | % | | 51 | % | | 10 | % | | 13 | % | | 1 | % | | 1 | % | | 5 | % | | — | |
| Entergy Louisiana | 51 | % | | 59 | % | | 26 | % | | 27 | % | | 1 | % | | 2 | % | | 9 | % | | 12 | % | | 13 | % | | — | |
| Entergy Mississippi (b) | 73 | % | | 69 | % | | 14 | % | | 22 | % | | 4 | % | | 9 | % | | — | | | — | | | 9 | % | | — | |
| Entergy New Orleans (b) | 55 | % | | 56 | % | | 33 | % | | 40 | % | | 1 | % | | 2 | % | | 2 | % | | 2 | % | | 9 | % | | — | |
| Entergy Texas | 39 | % | | 60 | % | | 11 | % | | 13 | % | | 2 | % | | 6 | % | | 23 | % | | 21 | % | | 25 | % | | — | |
| System Energy (c) | — | | | — | | | 100 | % | | 100 | % | | — | | | — | | | — | | | — | | | — | | | — | |
| Utility (a) (b) | 47 | % | | 55 | % | | 29 | % | | 31 | % | | 3 | % | | 6 | % | | 8 | % | | 8 | % | | 13 | % | | — | |
(a)Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2020 and is expected to provide less than 1% of its generation in 2021.
(b)Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2020 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2021.
(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 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. The MISO purchases metric provided for 2020 is not projected for 2021.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2021, it is possible that various operational events including weather or pipeline maintenance may require the 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. Over 50% of the Utility operating companies’ power plants maintain some level of long-
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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 primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies 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 may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to seven one- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2021. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 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 2021. Coal will be transported to Arkansas via an existing transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2021.
Entergy Louisiana has committed to five one- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2021. 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 2021. Coal will be transported to Nelson primarily via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2021.
For the year 2020, coal transportation delivery rates to Entergy Arkansas-and Entergy Louisiana-operated coal-fired units were adequate to meet supply needs and obligations, and it is expected that delivery times in 2021 will continue to be consistent. Both Entergy Arkansas and Entergy 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 Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2021. Entergy 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, Entergy Arkansas, Entergy Louisiana, and System 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
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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.
Based upon currently planned fuel cycles, the Utility 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 or fixed prices through most of 2023. 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 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 seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with CenterPoint 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 CenterPoint 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.
Entergy Louisiana purchased natural gas for resale in 2020 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy 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 and interstate transmission of electricity, including 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.
System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
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 engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which was a rate schedule approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources were jointly operated by the Utility operating companies that were participating in the System Agreement. The System Agreement provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) would receive payments from those parties having generating reserves that were less than their allocated share of reserves (short companies). Such payments were 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 were 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 were required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
Although the System Agreement has terminated, certain of the Utility operating companies’ and their retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. The proceedings include challenges to the 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
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did 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 MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and 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 markets. 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. 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
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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 July 2001 a rate proceeding commenced by System Energy at the FERC in 1995 became final, with the FERC approving a prospective 10.94% return on equity. 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 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 complaints filed with the FERC 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 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
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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 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 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 two outstanding series of first mortgage 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 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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Service Companies
Entergy Services, a limited liability company 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 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 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 Unit 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, 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 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. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses 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, 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 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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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.
Entergy Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated 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 assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed 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 is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light 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 Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
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-related services, to nuclear power plants owned by non-affiliated entities in the United States. 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.
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 operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
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 |
| Indian Point 3 (a) | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2025 (a) |
| Indian Point 2 (a) | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2024 (a) |
| Palisades (b) | | MISO | | 1971 | | Apr. 2007 | | Covert,
MI | | 811 MW - Pressurized Water | | 2031 (b) |
(a)Power operations ceased at the Indian Point 2 plant in April 2020. The fuel was permanently removed from the reactor vessel and placed in the spent fuel pool in May 2020. The Indian Point 3 plant is expected to cease operations on April 30, 2021. Entergy and Holtec jointly filed a license transfer application with the NRC in November 2019, requesting approval for the transfer of the Indian Point plants, along with their nuclear decommissioning trusts and decommissioning liabilities, from Entergy to Holtec. The NRC approved the license transfer application on November 23, 2020.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
(b)The Palisades plant is expected to cease operations on May 31, 2022. There is a contract to sell the plant to Holtec subject to NRC and other regulatory approvals.
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 operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
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. Both Big Rock Point and Indian Point 1 are under contract to be sold with their respective plants.
Non-nuclear Generating Stations
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) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| RS Cogen; 425 MW (c) | | Lake Charles, LA | | 50% | | 213 MW | | Gas/Steam |
| Nelson Unit 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 an interest in an unconsolidated joint venture. In December 2020, Entergy’s wholly-owned subsidiary with a direct interest in RS Cogen, LLC entered into a membership interest purchase agreement with a subsidiary of the other 50% equity partner to sell its 50% membership interest in the joint venture to the equity partner. The targeted closing date for the transaction is October 2022.
Independent System Operators
The 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 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. 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.See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 receives 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. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022 and transfer to Holtec thereafter.
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 Consumers Energy, the company from which Entergy purchased the Palisades plant, and NYISO and MISO. Substantially all the credit 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 NYISO market is highly competitive. Entergy Wholesale Commodities has numerous competitors in 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 York power market 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 most of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. Almost all of Palisades’ current output is contracted to Consumers Energy through May 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. When outdoor and cooling water temperatures are 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.
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,
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 plant owners. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment has been adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the Indian Point 3 and Palisades plants. Fuel procurement for the Entergy Wholesale Commodities segment was primarily limited to the requirements of the Palisades plant’s final refueling in 2020.
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 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. ENPM’s functions include origination of new energy and capacity transactions and generation scheduling.
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.
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Entergy provides plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.
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.
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 the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC 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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and conditions of service;
•service standards;
•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
•avoided cost payments to Qualifying Facilities;
•net energy metering;
•integrated resource planning;
•utility mergers and acquisitions and other changes of control; and
•the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory 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 retail ratemaking or other regulatory jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and purchase power contracts;
•procurement process to acquire over 50 MW;
•audits of the environmental adjustment charge, avoided cost payment to Qualifying Facilities, and energy efficiency rider;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
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, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other 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 the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects;
•utility service areas, including extensions into new areas;
•avoided cost payments to Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, 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 operators of Indian Point Energy Center, Palisades, and Big Rock Point.
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, 2020 of $192.0 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick, 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 Vermont Yankee spent fuel disposal contract was assigned to NorthStar as part of the sale of the plant in January 2019. The Pilgrim spent fuel disposal contract was transferred to Holtec as part of the sale of Entergy Nuclear Generation Company in August 2019. The owners of these plants previous to Entergy have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the 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. Specific steps were taken to discontinue the Yucca Mountain project, including 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. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the 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
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 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.
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. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2018, 2019, and 2020 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2020, Entergy’s subsidiaries won and collected on judgments against the government totaling approximately $800 million.
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 River Bend in 2005, at Grand Gulf in 2006, at Indian Point in 2008, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, 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. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. 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.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In October 2020, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and ANO 2 decommissioning trusts were adequately funded without further collections, and in December 2020, the APSC ordered zero collections for ANO 1 and ANO 2 decommissioning.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice.
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In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal.
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 a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
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 January 2019, Entergy sold 100% of the membership interest in Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar. As a result of the sale, NorthStar assumed ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 9 to the financial statements for further discussion of Vermont Yankee decommissioning 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.
In August 2019, Entergy sold 100% of the equity interests in Entergy Nuclear Generation Company, LLC to a subsidiary of Holtec International. As a result of the sale, Holtec assumed ownership of Pilgrim and its decommissioning trust, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 14 to the financial statements for further discussion of the sale.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities 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. 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, which 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 transaction. See Note 14 to the financial statements for discussion of the FitzPatrick sale.
In March 2020 filings with the NRC were made reporting on decommissioning funding for all of Entergy subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the 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 16 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
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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 $137.6 million per reactor (with 97 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, 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.
NRC Reactor Oversight Process
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. The nuclear generating plants owned and operated by Entergy’s Utility and Entergy Wholesale Commodities businesses are currently in Column 1, except for Grand Gulf, which is currently in Column 2.
In November 2020 the NRC placed Grand Gulf in Column 2 based on the incidence of three unplanned plant scrams during the second and third quarters of 2020.Two of the scram events related to new turbine control system components that failed, and a third related to a feedwater valve positioner that failed, all of which had been replaced in a refueling outage that ended in May 2020. The NRC plans to conduct a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 2. As a consequence of two additional Grand Gulf scrams during the fourth quarter 2020, System Energy expects Grand Gulf to be placed into NRC Column 3 based on plant performance indicators for the four quarters ended December 31, 2020. This will involve an additional supplemental NRC inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 3.
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, 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, greenhouse gases, and significant modifications to existing facilities;
•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 permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
•New and existing source standards for greenhouse gas and other air 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. In December 2020 the EPA amended the NSR regulations to clarify when a physical change or change in the method of operation will constitute such a modification. Entergy has an established process for identifying modifications requiring additional permitting approval and is monitoring the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. Several years ago, however, the EPA implemented 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 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, including NSR requirements and air permits issued by the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ). In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 an additional request for similar information was received for the White Bluff facility. Entergy responded to all requests. None of these EPA requests for information alleged that the facilities were in violation of law.
In January 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. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims as well as other issues facing Entergy Arkansas’s fossil generation plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. In October 2019 the District Court requested supplemental briefing on several issues to be resolved prior to addressing the motion to approve the
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settlement; that briefing was completed in May 2020. For further information about the settlement, see “Regional Haze” discussed below.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is 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.
Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for construction and operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. 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 December 2020 the EPA designated East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. Challenges to these final designations must be filed within 60 days of publication in the Federal Register. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. Entergy will continue to monitor this situation.
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.
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Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions. In September 2016 the EPA finalized the CSAPR Update Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 the final rule requires reductions in summer nitrogen oxides (NOx) emissions. Several states, including Arkansas and Texas, filed a challenge to the Update Rule. In September 2019 the D.C. Circuit upheld the EPA’s underlying approach to the Update Rule, but determined that it was inconsistent with the Clean Air Act because it failed to include deadlines consistent with downwind states’ deadlines for attainment. The court remanded the rule to the EPA for further consideration, but did not vacate so the rule remains in effect pending the EPA’s further review. In October 2020 the EPA issued its proposal intended to address the D.C. Circuit’s remand. The draft rule proposes to finalize interstate transport obligations for 21 states. For nine states, including Arkansas, Mississippi, and Texas, the EPA proposes that additional emission reductions are not necessary. For 12 states, however, including Louisiana, the EPA proposes additional emission reductions through proposed reductions in the number of NOx emission allowances allocated to each state. Entergy, through its various trade associations, filed comments on the proposal and will continue to monitor the rulemaking and its potential impact on its facilities in Louisiana. If the October 2020 proposal is finalized, ozone season NOx emissions may become more expensive in Louisiana.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could 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 Energy and Environment, Division of Environmental Quality (ADEQ) prepared a state implementation plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. In April 2012 the EPA finalized a decision addressing the Arkansas Regional Haze SIP, in which it disapproved a large portion of the Arkansas 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 granted the stay pending settlement discussions and pending the State’s development of a SIP that, if approved by the EPA, would replace the FIP. The state had 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. The Part I SIP requires that Entergy address NOx impacts on visibility via compliance with the Cross-State Air Pollution Rule ozone-season emission trading program. Arkansas has finalized a Part II SIP which has been approved by the EPA but is currently pending a state court appeal. That appeal has been stayed pending the outcome of a federal court case, which may resolve many of the issues on appeal. The final Part II SIP requires that Entergy achieve SO2 emission reductions via the use of low-sulfur coal at both White Bluff and Independence within three years. The
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Part II SIP also requires that Entergy cease to use coal at White Bluff by December 31, 2028 and notes the current planning assumption that Entergy’s Independence units will cease to use coal by December 31, 2030.
In January 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. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement and in many cases also the Part II SIP, Entergy Arkansas, along with co-owners, will begin using only low-sulfur coal at Independence and White Bluff by mid-2021; cease to use coal at White Bluff and Independence by the end of 2028 and 2030, respectively; cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserve the option to develop new generating sources at each plant site; and commit to install or propose to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waive certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. The EPA, which is allowed to comment on such a settlement agreement, has stated that it has no objections to the settlement. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. Still pending before the court is a motion by the plaintiffs to approve the settlement, in support of which Entergy made a filing. The Arkansas Attorney General also filed an application before the APSC in December 2018 seeking an investigation into the effects of the settlement. The Arkansas Affordable Energy Coalition filed to support the Arkansas Attorney General’s application, and Entergy Arkansas filed a motion to dismiss it. The application remains pending before the APSC. In October 2019 the District Court requested supplemental briefing on several issues prior to addressing the motion to approve the settlement; that briefing concluded in May 2020.
In Louisiana, Entergy has worked with the Louisiana Department of Environmental Quality (LDEQ) and the EPA to revise the Louisiana SIP for regional haze, which had been 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 of January 22, 2021. The EPA issued final approval in December 2017. The EPA approval was appealed to the U.S. Court of Appeals for the Fifth Circuit. In October 2019 the Fifth Circuit affirmed the EPA’s SIP approval. A petition for rehearing filed by plaintiffs was denied by the Fifth Circuit. Plaintiffs did not petition for further review by the Supreme Court.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by 2021. Entergy received information collection requests from Arkansas and Louisiana requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, and Ninemile. Responses to the information requests have been submitted to the respective state agencies.
New and Existing Source Performance Standards for Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established
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national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests and will continue to monitor litigation challenging the rule. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. The vacatur will not be effective until the court issues its mandate which is being held until after disposition of any petitions for rehearing. Entergy is currently reviewing the court’s opinion.
In 2018 the EPA proposed a revision to the new source performance standard on greenhouse gas emissions that primarily impacts new coal units and, therefore, should not impact Entergy. In January 2021 the EPA finalized a pollutant-specific contribution finding for greenhouse gas emissions from new, modified, and reconstructed electric generating units. The rule establishes a three percent threshold for determining when a pollutant significantly contributes to air pollution and reaffirms the EPA’s position that the Clean Air Act Section 111(b) requires the EPA to make pollutant-specific significant contribution findings before promulgation of a new source performance standard. The EPA did not, however, finalize the new source performance standard on greenhouse gas emissions and intends to address the 2018 proposal in a future action.
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;
•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 federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and 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 local, state, and federal level to codify renewable portfolio standards, clean energy standards, 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;
•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 polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance risk;
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•the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds;
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in an economy-wide, responsible, and flexible manner. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020. In 2020, Entergy succeeded in achieving its initial climate commitment to reduce carbon dioxide cumulative emissions by 20% from 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 39.1 million tons in 2020 and 40.7 million tons in 2019. Since its original commitment in 2001, Entergy’s cumulative emissions are approximately 7.6% below its 2020 goal.
Entergy voluntarily conducted a climate scenario analysis and published a comprehensive report in March 2019. The report follows the framework and recommendations of the Task Force on Climate-related Disclosures, describing climate-related governance, strategy, risk management, and metrics and targets. Scenario analyses resulted in Entergy developing and publishing a new goal of reducing the Utility’s emission rate by 50 percent from 2000 levels by 2030. In September 2020, Entergy committed to achieving net-zero carbon emissions by 2050, while continuing its commitment to grid reliability and affordability for customers. In December 2020, Entergy published a report regarding this long-term commitment that describes its approach and technology point-of-view. Technology research and development, innovation, and advancement are critical to Entergy’s ability to meet this climate commitment.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s annual greenhouse gas emissions inventory is also third-party verified, and that certification is made available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 2020 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for nineteen consecutive years. Entergy also participated in the 2020 CDP and CDP Water evaluations, receiving a ‘B’ for both responses.
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 permit program, section 402, 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.
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Steam Electric Effluent Guidelines
The 2015 Steam Electric Effluent Limitations Guidelines (ELG) rule required, among other things, that there be no discharge of bottom ash transport water. In October 2020 the EPA issued its final rule revision on bottom ash transport water allowing the discharge of up to 10% system volume for certain purge waters, including storm events and non-routine operations. The final rule requires compliance as soon as possible beginning October 31, 2021, but no later than December 31, 2025. Several challenges to the final rule have been filed. Additionally, the Fifth Circuit Court of Appeals previously vacated and remanded the provisions of the rule related to legacy wastewater and leachate, which the EPA plans to address in a separate rulemaking. Despite the final rule and pending challenges, Entergy is implementing projects at its White Bluff and Independence plants to convert to zero-discharge systems to comply with the ELG rule and the coal combustion residuals restrictions on impoundments. Additionally, the Nelson Unit 6 facility is implementing operational and maintenance measures to minimize the potential for discharge of bottom ash transport water from the existing bottom ash handling system at the site, and is reviewing the effectiveness of these changes for compliance with the requirements of the October 2020 final rule.
Federal Jurisdiction of Waters of the United States
In February 2019 the EPA published its proposed revised definition of Waters of the United States, which proposes to narrow the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. The final rule was released in January 2020 and effective in June 2020. In October 2019 the EPA repealed the 2015 rule and re-codified the pre-existing regulations. That rule was effective late December 2019. Numerous challenges have been filed against both rules.
Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to 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, Indian Point, Palisades, Grand Gulf, 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.
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
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. 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 such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental 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 Resource Conservation and Recovery Act (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 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, 2020, Entergy has recorded asset retirement obligations related to CCR management of $20.1 million.
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 program.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. 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. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of one of its two recycle ponds, with the remaining pond being held in reserve during initial operation of the new bottom ash handling system. Closure of the remaining recycle pond at each site will commence as soon as possible, but no later than April 11, 2021, which is the deadline under the finalized CCR rule to commence closure of any unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
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Other Environmental Matters
Entergy Louisiana and Entergy Texas
Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, currently is 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 routed to a portion of the property for disposal. The same area also has 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. Removal actions addressed contaminated source material, soil, and sediment and included capping certain soil on and off-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. The EPA released the second Five Year Review in 2015. In that review, the EPA indicated that the remediation technique was insufficient and that Entergy would need to utilize other remediation technologies on the site. In July 2015, Entergy submitted a Focused Feasibility Study to the EPA outlining the potential remedies and suggesting installation of the new remedial method, a waterloo barrier. The estimated cost for this remedy is approximately $2 million, to be allocated between Entergy Louisiana and Entergy Texas. In early 2017 the EPA indicated that the waterloo barrier may not be necessary and requested revisions to the Focused Feasibility Study. The EPA released the third Five Year Review in late-2019 confirming that a new remedial method is not necessary but requiring continuation of the current groundwater monitoring. The site’s remedy includes monitored natural attenuation of groundwater, and institutional controls to restrict groundwater and land use. The EPA has determined that no additional actions are needed for the remedy to be protective over the long-term, and the remedy is protective of human health and the environment.
Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, 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 existed at the site. Entergy subsidiaries sent transformers to this facility. Entergy Arkansas, Entergy Louisiana, and Entergy Texas responded to an information request from the TCEQ. Entergy Louisiana and Entergy Texas 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 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. Current estimates, although variable depending on ultimate remediation design and performance, indicate that Entergy’s total share of remediation costs likely will be approximately $1.5 million to $2 million. Groundwater monitoring wells at the site were plugged and abandoned in December 2019 following receipt of a certificate of completion issued by the TCEQ. Site decommissioning activities are complete and final disposition of the property will be determined at a later time.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand
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letter seeking reimbursement for response costs totaling $4 million expended at the site. The demand letter is being evaluated and liability and PRP allocation of response costs are yet to be determined.
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 TCEQ and the National Response Center were immediately notified, and the 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, Entergy entered into the Voluntary Cleanup Program with the TCEQ. In November 2017, additional soil sampling was completed in the wetland area and, in February 2018, a site summary report of findings was submitted to the TCEQ. The TCEQ responded in June 2018 and requested an ecological exclusion criteria checklist/Tier II screening-level ecological risk assessment, and additional site assessment, additional soil samples, groundwater samples, and some additional diagrams and maps. In October 2018, Entergy submitted the requested information to the TCEQ. In January 2019 the TCEQ responded with another request for information. In March 2019, Entergy submitted the requested information to the TCEQ. In August 2019 the TCEQ responded with a request for additional information including an Affected Property Assessment Report (APAR) and water well survey. The TCEQ has agreed that the necessity of the water well survey is dependent on the results of the groundwater resampling that will occur. Groundwater sampling was completed in December 2019 and results were submitted to the TCEQ for review. Based on the groundwater sampling results, the TCEQ confirmed in February 2020 that a water well survey is not necessary and requested the APAR and an Ecological Risk Assessment by August 2020. Due to COVID-19 delays, the TCEQ extended the APAR and Ecological Risk Assessment submittal dates to December 2020, which Entergy timely met.
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.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, 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.
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Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2020, Entergy subsidiaries employed 13,400 people.
| | | | | |
| Utility: | |
| Entergy Arkansas | 1,244 | |
| Entergy Louisiana | 1,654 | |
| Entergy Mississippi | 750 | |
| Entergy New Orleans | 303 | |
| Entergy Texas | 658 | |
| System Energy | — | |
| Entergy Operations | 3,529 | |
| Entergy Services | 3,859 | |
| Entergy Nuclear Operations | 1,356 | |
| Other subsidiaries | 47 | |
| Total Entergy | 13,400 | |
Approximately 3,900 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, and Fire Professionals of America.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
| Gender (%) | 2020 | | 2019 |
| Female | 21 | | 20 |
| Male | 79 | | 80 |
| 100 | | 100 |
| | | | | | | | | | | |
| Race/Ethnicity (%) | 2020 | | 2019 |
| White | 78 | | 79 |
| Black/African American | 15 | | 15 |
| Hispanic/Latino | 3 | | 2 |
| Asian | 2 | | 2 |
| Other | 2 | | 2 |
| 100 | | 100 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion and belonging; and talent management.
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Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Personnel Committee establishes priorities and reviews performance on a range of topics. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development and succession plans to align a high performing executive team with Entergy’s priorities. The Personnel Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on ethics and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. While the COVID-19 pandemic and historical hurricane season presented significant challenges, Entergy’s safety strategy and commitment to excellence showed results in 2020. Entergy employees achieved a total recordable incident rate of 0.40 in 2020 compared to 0.56 in 2019 and 0.48 in 2018. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases. This marked improvement in total recordable incident rate placed Entergy in top-decile in safety performance when benchmarked amongst peers within the Edison Electric Institute.
Organizational Health, including Diversity, Inclusion and Belonging
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (near top quartile). In addition to significantly improved scores, initial employee participation of 66 percent in 2014 rose to and remains at 90 percent in 2018-2020.
Entergy believes that a culture focused on diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. Among other actions, the primary focus of its 2020 actions was taking a stand against social injustice, reinforcing expectations, training and leading by example, starting at the top of the organization and cascading through management ranks.
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Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the future, and reflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.
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 SEC 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. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
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 annual and quarterly reports on Forms 10-K and 10-Q (including related filings in Inline XBRL format) and current reports on Form 8-K; 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 internet 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.
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RISK FACTORS
See “RISK FACTOR SUMMARY” in Part I Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ 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 Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
In December 2019 a novel strain of coronavirus was reported to have surfaced in Wuhan, China. Since then, COVID-19 has spread throughout most countries in the world, including the United States. Public health officials in the United States have both recommended and mandated wearing of masks, precautions to mitigate the spread of COVID-19, including prohibitions on congregating in heavily-populated areas, mandated closure or limitations on the functions of non-essential business, and shelter-in-place orders or similar measures, including throughout Entergy’s service areas. While some of these mitigation measures have been lifted, it is unclear how long certain forms of mitigation measures will remain in place, whether they will be reinstated in the future, and how they will ultimately impact the general economy, Entergy’s customers, and its operations.
Entergy and its Utility operating companies have experienced a decline in commercial and industrial sales and an increase in arrearages and bad debt expense due to non-payment by customers, and expect such reduced levels of sales and increased arrearages and bad debt expense to continue, the extent and duration of which management cannot predict. The Utility operating companies temporarily suspended disconnecting customers for non-payment of bills, and the suspension remains in place at Entergy Arkansas, has been re-instituted at Entergy New Orleans, and could be re-instituted at the other Utility operating companies should their regulators mandate. While they are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is unknown. Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges, supply chain, vendor, and contractor disruptions; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed outages; delays in regulatory proceedings; workforce availability, health or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees telecommuting; increased late or uncollectible customer payments; volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and initiatives.
A sustained or further economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the COVID-19 pandemic on their customers. In addition, if the COVID-19 pandemic continues to create disruptions or turmoil in the credit or financial markets, or adversely impacts Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its
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liquidity needs, or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the outbreak, the impact of new variants of COVID-19, the timing, availability, distribution or effectiveness of a vaccine, anti-viral or other treatments for COVID-19, governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
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 can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. 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, including adjustment upon the initiative of a regulator or affected stakeholders.
In addition, regulators may initiate proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s 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 may 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. Traditional 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 these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and the Utility operating companies may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation of their assets and infrastructure or the quality of their service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements.
The base rates of Entergy Texas are established largely in traditional base rate case proceedings.Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs.These riders include a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment and certain non-fuel MISO charges, a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a generation cost recovery rider mechanism for the recovery of generation-related capital investments, and a fixed fuel factor mechanism for the recovery of MISO fuel and energy-related costs.Entergy Texas also is required to make a filing every three years,
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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 necessary and reasonable, and makes a prudence finding for each of the fuel-related contracts for the reconciliation period.Entergy Texas also is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Between base rate cases, Entergy Arkansas and Entergy Mississippi 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. Entergy Arkansas has requested APSC approval of the extension of the formula rate plan tariff for an additional five years through 2026.If Entergy Arkansas’s formula rate plan were terminated or not extended beyond the initial term, Entergy Arkansas could file an 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 plan was most recently extended through the test year 2019; certain modifications were made in that extension, including a decrease to the allowed return on equity and the addition of a transmission cost recovery mechanism.The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC and as noted, for certain transmission investment, among other items.MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause.Entergy Louisiana has a pending request to extend its formula rate plan with certain modifications, including implementation of a distribution investment recovery mechanism and use of end of period rate base.In the event that the electric formula rate plan is not renewed or extended, Entergy Louisiana would revert to the more traditional rate case environment.
Entergy New Orleans previously operated under a formula rate plan that ended with the 2011 test year.Based on a settlement agreement approved by the City Council, with limited exceptions, the base rates of Entergy New Orleans were frozen until rates were implemented in connection with the base rate case filed by Entergy New Orleans in 2018.In November 2019 the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019.The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes.In November 2020 the City Council issued a resolution approving a settlement of the 2018 rate case.As part of this settlement, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle.See Note 2 to the financial statements for further discussion.
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 has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the
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reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate request for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. System Energy has received FERC acceptance for billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
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 the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales could put upward pressure on rates, resulting in adverse regulatory actions to mitigate such effects on rates. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
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 or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may 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 and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
The Utility operating companies historically 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 had been approved by the FERC. The System Agreement terminated in its entirety on August 31, 2016.
There 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 existence. In the absence 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 few outstanding System Agreement proceedings at the FERC and at the D.C. Circuit that may require future adjustments, including challenges to the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
For further information regarding the regulatory proceedings relating to the System Agreement, see Note 2 to the 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. 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 capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or the cost of serving the Utility operating companies’ respective loads, and MISO market rules may change in ways that cause additional risk.
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. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from transmission projects of others, 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, the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits 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, or generally allow the retail regulator to direct the making of such 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 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 (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta), or the impact on customer bills of permitted storm cost recovery, could have material effects on Entergy and its Utility operating companies.
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. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills.
In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, 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
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity 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 owned or contractually controlled 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.
Certain of the Utility operating companies and System Energy 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.
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. Plant maintenance and upgrades are often scheduled during such planned outages, which typically extends the planned outage duration. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks 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 2020 and beyond. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium 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 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 and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, or shifting trade arrangements between countries. 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 changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
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 international sanctions or tariffs could further restrict the ability of such
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
suppliers to continue to supply fuel or provide such services at acceptable prices or at all. 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 and System Energy.
Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, suspend 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, 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 nuclear facilities. 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.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate 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 the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities.
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 increased costs, some of which costs may not be fully recoverable by the Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. 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
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture 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 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 NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are 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 will 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 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 Louisiana, and System Energy and Note 8 to the financial statements.
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, which is referred to as Secondary Financial Protection, up to approximately $137.6 million per reactor. With 97 reactors currently
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
participating, this translates to a total public liability cap of approximately $14 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, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the 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 primary insurance level, up to a maximum of approximately $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.101 billion). The retrospective premium payment is currently limited to approximately $21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $137.6 million cap.
NEIL is a utility industry mutual insurance company, owned by its 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 NEIL surplus (reserve) be significantly depleted due toinsured losses. As of December 31, 2020, the maximum annual assessment amounts total $104 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential 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.
The 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 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. 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.
Under NRC regulations, nuclear plant owners 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 nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments 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.
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, or accelerate the timing for funding of, the obligations related to the decommissioning of the Utility operating companies, System Energy, or Entergy Wholesale Commodities nuclear power plants or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. 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, the impairment charges that resulted from such decision, and the planned sales of Palisades and Indian Point Energy Center (which, in each case, will include the transfer of the associated decommissioning trusts), 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.
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. These concerns have led to, and may 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 might lead to the shutdown of nuclear units, 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 and financial condition.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation)
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. 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, 2020, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 98% in 2021 and 99% in 2022 of its generation portfolio’s planned energy output, reflecting the planned shutdown and sale of the remaining 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.
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.
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.
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 “Market and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the closure (or sale) of its nuclear plants, Entergy Wholesale Commodities may enter into fewer forward sales contracts for output from such plants.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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. 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 $1.29 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. 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 is subject to changes as a result of restructuring initiatives at both the state and federal levels. 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, 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, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other 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 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 remaining assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure and sale of its nuclear power plants. Moreover, prior to the closure and 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, or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
If Entergy concludes that any of its nuclear power plants is unlikely to operate through its planned shutdown date, which conclusion would be based on a variety of factors, such a conclusion could result in a 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 remaining 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 - Impairment of Long-lived Assets” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
General Business
(Entergy Corporation, Entergy Arkansas, 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-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, Hurricane Isaac in 2012, and Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown events, 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The inability to raise capital on favorable terms, particularly during times of high interest rates, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in companies that experience extreme weather events, that rely on fossil fuels or offerings to fund fossil fuel projects, or due to risks related to climate change. Events beyond Entergy’s control 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 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.
Most of Entergy Corporation’s and its subsidiaries’ 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, 2020 based on power prices at that time, Entergy had liquidity exposure of $62 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $6 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, 2020, Entergy would have been required to provide approximately $30 million of additional cash or letters of credit under some of the agreements. As of December 31, 2020, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $22 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, and cash flows.
The Tax Cuts and Jobs Act of 2017 and CARES Act of 2020 significantly changed 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 interpretive
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation.
As further described in Note 3 to the financial statements, as a result of amortization of accumulated deferred income taxes and payment of such amounts to customers in 2019, Entergy’s net regulatory liability for income taxes balance is $1.6 billion as of December 31, 2020. Depending on the outcome of IRS examinations or tax positions and elections that Entergy may make, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense. Further, there may be other material effects resulting from the legislation that have not been identified.
See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act on 2018, 2019 and 2020 results of operations and financial condition, the provisions of the Tax Cuts and Jobs Act, and the uncertainties associated with accounting for the Tax Cuts and Jobs Act, and Note 2 to the financial statements for discussion of the regulatory proceedings that have considered the effects of the Tax Cuts and Jobs 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 execute on their business strategies, including their ability to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies, which could materially affect their future prospects, results of operations, and benefits that they anticipate from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, which are subject to business, regulatory, economic, and other risks and uncertainties, many of which are beyond their control. As a result, Entergy and its subsidiaries may be unable to fully achieve the anticipated results of such strategies.
Additionally, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring, or other strategic transactions. For example, Entergy has entered into an agreement to sell its equity interests in the subsidiary that owns the Palisades Nuclear Plant and the decommissioned Big Rock Point Nuclear Power Plant and an agreement to sell the equity interests of Indian Point 1, Indian Point 2, and Indian Point 3, in each case after each of the plants has been shut down and defueled. Also, a significant portion of Entergy’s utility business over the next several years includes the construction and/or purchase of a variety of generating units. These transactions and 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 or its subsidiaries’ financial condition or 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
Entergy Corporation, Utility operating companies, and System Energy
•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;
•Entergy may experience issues integrating businesses into its internal controls over financial reporting;
•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, 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 and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition or results of operations.
The completion of capital projects, including the construction of power generation facilities, and other capital improvements involve substantial risks. Should such 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 capital projects, including the 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, escalating costs for materials, labor, and environmental compliance, and reliance on suppliers for timely and satisfactory performance. Delays in obtaining permits, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under 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 the project or 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 capital projects, including the potential construction and/or purchase 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
Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
We rely on a large and changing workforce of team members, including employees, contractors and temporary staffing. Certain events, such as an aging workforce, mismatching of skill sets, failing to appropriately anticipate future workforce needs, or the unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base, and the time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, may increase. Failure to hire and adequately train replacement employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business, especially considering the workforce needs associated with nuclear generation facilities and new skills required to operate a modernized, technology-enabled power grid. If Entergy and its subsidiaries are unable to successfully attract, retain, and manage an appropriately qualified workforce, their results of operations, financial position, and cash flows could be negatively affected.
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 currently are 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 potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing air regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, 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
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 NERC, the 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. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the 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 businesses.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations and system reliability.
Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, mild temperatures in either season tend to decrease energy usage and resulting revenues. Higher consumption levels coupled with seasonal pricing differentials 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 including hurricanes or tropical storms, flooding events, or ice storms 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 reduced 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 weather and economic conditions, 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 grid demand. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and their replacement with more efficient ones, adoption of newer technologies including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales growth in the future. The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial
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customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower 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, environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions, or achieving voluntary climate commitments 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, some 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 CO2 and other “greenhouse gases” under the Clean Air Act, the EPA, various environmental interest groups, and other organizations focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. Since that ruling, the EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and from new, existing, and significantly modified stationary sources of emissions, including electric generating units. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. In Louisiana, the Office of the Governor announced the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050 while the City Council of New Orleans passed a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk 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, clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing the company’s greenhouse gas emission rate. 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 attempt to deny or defer timely recovery of these costs. Future changes in regulation or policies governing the emission of CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy’s utility operating companies, their suppliers or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy’s utility operating companies are unable to fully recover the costs and investment in generation and (iv) could increase the difficulty that Entergy and its utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these
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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, wildfires, wetland and barrier island erosion, risks of flooding and changes in weather conditions, (such as increases in precipitation, drought, or changes in average 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 the physical impacts of climate change, 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, more frequent and longer lasting outages, 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.
In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. Technology research and development, innovation, and advancement are critical to Entergy’s ability to achieve this commitment. Moreover, Entergy cannot predict the ultimate impact of achieving this objective, or the various implementation aspects, on its system reliability, or its results of operations, financial condition or 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, and Entergy Wholesale Commodities’ business operations. Entergy’s facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also 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.
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 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 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.
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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 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Market performance and other changes may decrease the value of benefit plan assets, which then could require additional 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 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 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 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 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.
Terrorist attacks, cyber attacks, system failures or data breaches of Entergy’s and its subsidiaries’ or our suppliers’ technology systems may adversely affect Entergy’s results of operations.
Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure, and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers and employees, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply chain activities. Any significant failure or malfunction of such information technology systems could result in loss of data or disruptions of operations.
There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. As an operator of critical infrastructure, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, cyber attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions. An actual act could affect Entergy’s ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct business.
Given the rapid technological advancements of existing and emerging threats, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
and controls. 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 could be unable to perform critical business functions that are essential to the company’s well-being and could result in a loss of its confidential, sensitive, and proprietary information, including personal information of its customers, employees, suppliers, and others in Entergy’s care.
Any such attacks, failures or data breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, results of operations or reputation. Although we purchase insurance coverage for cyber-attacks or data breaches, such insurance may not be adequate to cover all losses that might arise in connection with these events. Such events may also expose Entergy to an increased risk of litigation (and associated damages and fines).
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect 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 New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. 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.
(System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings.
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 expires in November 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. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a request in a separate proceeding for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. The LPSC has also authorized the filing of a prudence complaint at the FERC relating to Grand Gulf operations. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
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, see Notes 5 and 8 to the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy Corporation depends 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. Prior to providing funds to Entergy Corporation, such subsidiaries have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of Entergy Utility Holding Company and Entergy Texas, dividends and distributions on preferred securities. Any distributions from the Registrant Subsidiaries other than Entergy Texas and System Energy are paid directly to Entergy Utility Holding Company and are therefore subject to prior payment of distributions on its preferred securities.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Arkansas’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $10 million. Natural gas purchases for Entergy Arkansas for February 1st through 25th, 2021 are approximately $105 million compared to natural gas purchases for February 2020 of $10 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income decreased $17.7 million primarily due to lower volume/weather, a formula rate plan provision recorded in 2020 to reflect the 2019 historical year netting adjustment, and higher depreciation and amortization expenses, partially offset by higher retail electric price and lower other operation and maintenance expenses. See Note 2 to the financial statements for discussion of the 2019 historical year netting adjustment.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2020 to 2019:
| | | | | |
| Amount |
| (In Millions) |
| 2019 operating revenues | $2,259.6 | |
| Fuel, rider, and other revenues that do not significantly affect net income | (278.5) | |
| Volume/weather | (72.2) | |
| Retail electric price | 57.4 | |
| Return of unprotected excess accumulated deferred income taxes to customers | 118.2 | |
| 2020 operating revenues | $2,084.5 | |
Entergy Arkansas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The volume/weather variance is primarily due to a decrease of 1,069 GWh, or 5%, in billed electricity usage, including decreased commercial and industrial usage as a result of the COVID-19 pandemic, and the effect of less favorable weather on residential and commercial sales, partially offset by an increase in residential usage as a
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
result of the COVID-19 pandemic. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the COVID-19 pandemic.
The retail electric price variance is primarily due to the $56.5 million annual formula rate plan increase related to the 2020 projected test year included in the 2019 formula rate plan filing effective with bills rendered on and after the first billing cycle of January 2020. See Note 2 to the financial statements for further discussion of the formula rate plan filing.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a tax adjustment rider beginning in April 2018. In 2020, $8.1 million was returned to customers as compared to $126.3 million in 2019. There is no effect on net income as the reduction in operating revenues in each period was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
Other Income Statement Variances
Nuclear refueling outage expenses decreased primarily due to the amortization of lower costs associated with the most recent outages as compared to previous outages.
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $18.3 million in nuclear generation expenses primarily due to lower nuclear labor costs, including contract labor, in part as a result of the COVID-19 pandemic;
•a decrease of $13.2 million in non-nuclear generation expenses primarily due to lower long-term service agreement expenses;
•an $11.2 million write-off in 2019 of specific costs related to the potential construction of scrubbers at the White Bluff plant. See Note 2 to the financial statements for discussion of the write-off;
•higher nuclear insurance refunds of $7.8 million;
•a decrease of $5.9 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services; and
•a decrease of $5.8 million in energy efficiency costs.
The decrease was partially offset by the effects of recording in 2019 a final judgment to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $11.9 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.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other income increased primarily due to changes in decommissioning trust fund investment activity.
Other regulatory credits - net for 2020 includes a provision of $43.5 million to reflect the 2019 historical year netting adjustment included in the APSC’s December 2020 order in the 2020 formula rate plan proceeding. See Note 2 to the financial statements for discussion of the 2020 formula rate plan proceeding.
The effective income tax rates were 16.3% for 2020 and (21.6%) for 2019. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes. See Notes 2 and 3 to the financial statements for a discussion of the effects and regulatory activity regarding the Tax Cuts and Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of results of operations for 2019 compared to 2018.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 | |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $3,519 | | | $119 | | | $6,216 | | |
| | | | | | |
| Net cash provided by (used in): | | | | | | |
| Operating activities | 659,818 | | | 677,766 | | | 211,825 | | |
| Investing activities | (795,709) | | | (676,293) | | | (688,727) | | |
| Financing activities | 324,500 | | | 1,927 | | | 470,805 | | |
| Net increase (decrease) in cash and cash equivalents | 188,609 | | | 3,400 | | | (6,097) | | |
| | | | | | |
| Cash and cash equivalents at end of period | $192,128 | | | $3,519 | | | $119 | | |
2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities decreased $17.9 million in 2020 primarily due to:
•the timing of recovery of fuel and purchased power costs;
•lower collections of receivables from customers, in part due to the COVID-19 pandemic; and
•the timing of payments to vendors.
The decrease was partially offset by:
•a decrease in the return of unprotected excess accumulated deferred income taxes to customers in 2020 as compared to 2019. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act;
•$25 million in proceeds received from the DOE in 2020 resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•a decrease of $15.8 million in pension contributions in 2020. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Investing Activities
Net cash flow used in investing activities increased $119.4 million in 2020 primarily due to:
•an increase of $79.5 million in storm spending;
•an increase of $47.3 million in non-nuclear generation construction expenditures primarily due to increased spending on various projects in 2020;
•an increase of $39.4 million in nuclear construction expenditures primarily as a result of work performed in 2020 on various ANO 2 outage projects;
•an increase of $38.5 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; and
•an increase of $30.3 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Arkansas’s distribution system, including increased spending on advanced metering infrastructure.
The increase was partially offset by:
•a decrease of $56 million in transmission construction expenditures primarily due to a lower scope of work performed in 2020 as compared to 2019; and
•$55 million in proceeds received from the DOE in 2020 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.
Financing Activities
Net cash flow provided by financing activities increased $322.6 million in 2020 primarily due to:
•issuances of $100 million of 4.0% Series mortgage bonds in March 2020 and $675 million of 2.65% Series mortgage bonds in September 2020;
•money pool activity;
•a decrease of $41.6 million in net long-term repayments in 2020 on the Entergy Arkansas nuclear fuel company variable interest entity credit facility; and
•a decrease of $20 million in common equity distributions in 2020 in order to maintain Entergy Arkansas’s capital structure.
The increase was partially offset by:
•the issuance of $350 million of 4.20% Series mortgage bonds in March 2019;
•the repayment in October 2020 of $200 million of 4.90% Series mortgage bonds due December 2052; and
•the repayment in October 2020 of $125 million of 4.75% Series mortgage bonds due June 2063.
Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased by $21.6 million in 2020 compared to decreasing by $161.1 million in 2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio is primarily due to the net issuances of long-term debt in 2020.
| | | | | | | | | | | |
| | December 31,
2020 | | December 31,
2019 |
| Debt to capital | 54.8 | % | | 53.0 | % |
| Effect of excluding the securitization bonds | — | % | | — | % |
| Debt to capital, excluding securitization bonds (a) | 54.8 | % | | 53.0 | % |
| Effect of subtracting cash | (1.2 | %) | | — | % |
| Net debt to net capital, excluding securitization bonds (a) | 53.6 | % | | 53.0 | % |
(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, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas 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 Arkansas’s financial condition because the securitization bonds, which have been repaid as of December 31, 2020, were 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 distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Arkansas 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
•distribution and interest payments.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2022 | | 2023 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $340 | | | $355 | | | $430 | |
| Transmission | 40 | | | 45 | | | 190 | |
| Distribution | 95 | | | 255 | | | 420 | |
| Utility Support | 105 | | | 80 | | | 75 | |
| Total | $580 | | | $735 | | | $1,115 | |
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| | (In Millions) |
| Long-term debt (a) | $611 | | | $543 | | | $581 | | | $4,713 | | | $6,448 | |
| Operating leases (b) | $14 | | | $21 | | | $15 | | | $11 | | | $61 | |
| Finance leases (b) | $3 | | | $5 | | | $3 | | | $2 | | | $13 | |
| Purchase obligations (c) | $452 | | | $618 | | | $509 | | | $3,882 | | | $5,461 | |
(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)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 $66.6 million to its qualified pension plans and approximately $517 thousand to its other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. 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 $252 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 Arkansas includes specific investments in renewables such as the Searcy Solar Facility, Walnut Bend Solar Facility, and West Memphis Solar Facility; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; investments in ANO 1 and 2; software and security; 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 maturities in Note 5 to the financial statements.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Renewables
Searcy Solar Facility
In March 2019, Entergy Arkansas announced that it signed an agreement for the purchase of an approximately 100 MW solar energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. The purchase is contingent upon, among other things, obtaining necessary approvals from applicable federal and state regulatory and permitting agencies. The project is being constructed by a subsidiary of NextEra Energy Resources. Entergy Arkansas will purchase the facility upon mechanical completion and after the other purchase contingencies have been met. Closing is expected to occur by the end of 2021. In May 2019, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. In September 2019 other parties filed testimony largely supporting the resource acquisition but disputing Entergy Arkansas’s proposed method of cost recovery. Entergy Arkansas filed its rebuttal testimony in October 2019. In February 2020, Entergy Arkansas, the Attorney General, and the APSC general staff filed a partial settlement agreement asking the APSC to approve, based on the record in the proceeding, all issues except certain issues that are submitted to the APSC for determination. In April 2020 the APSC issued an order approving Entergy Arkansas’s acquisition of the Searcy Solar facility as being in the public interest, but declined to approve Entergy Arkansas’s preferred cost recovery rider mechanism, finding instead, based on the particular facts and circumstances presented, that the formula rate plan rider was a sufficient recovery mechanism for this resource.
Walnut Bend Solar Facility
In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar Facility is in the public interest. Entergy Arkansas requested a decision by the APSC by June 15, 2021 and primarily requests cost recovery through the formula rate plan rider. A procedural schedule was established with a hearing scheduled in April 2021. Closing is expected to occur in 2022.
West Memphis Solar Facility
In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar Facility is in the public interest. Entergy Arkansas requested a decision by the APSC by September 7, 2021 and primarily requests cost recovery through the formula rate plan rider. Closing is expected to occur in 2023.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Arkansas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
All debt and common and preferred membership interest issuances by Entergy Arkansas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s bond indentures and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | | 2017 |
| (In Thousands) |
| $3,110 | | ($21,634) | | ($182,738) | | ($166,137) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in September 2024. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2021. The $150 million credit facility includes fronting commitments for the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2020, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas 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, 2020, a $1 million letter of credit was outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for further discussion of the credit facilities.
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in September 2022. As of December 31, 2020, $12.2 million in loans were outstanding under the credit facility for the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorization from the FERC through July 2022 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and 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 FERC. The APSC has concurrent jurisdiction over Entergy Arkansas’s first mortgage bond/secured issuances. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through July 2022. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2022.
State and Local Rate Regulation and Fuel-Cost Recovery
Retail Rates
2018 Formula Rate Plan Filing
In July 2018, Entergy Arkansas filed with the APSC its 2018 formula rate plan filing to set its formula rate for the 2019 calendar year. The filing showed Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2019 test period to be below the formula rate plan bandwidth. Additionally, the filing included the first netting adjustment under the current formula rate plan for the historical test year 2017, reflecting the change in formula rate plan revenues associated with actual 2017 results when compared to the allowed rate of return on equity. The filing included a projected $73.4 millionrevenue deficiency for 2019 and a $95.6 million revenue deficiency for the 2017 historical test year, for a total revenue requirement of $169 million for this filing. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is
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subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to four percent of total revenue, which originally was $65.4 million but was increased to $66.7 million based upon the APSC staff’s updated calculation of 2018 revenue. In October 2018, Entergy Arkansas and the parties to the proceeding filed joint motions to approve a partial settlement agreement as to certain factual issues and agreed to brief contested legal issues. In November 2018 the APSC held a hearing and was briefed on a contested legal issue. In December 2018 the APSC issued a decision related to the initial legal brief, approved the partial settlement agreement and $66.7 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan, with updated rates going into effect for the first billing cycle of January 2019.
2019 Formula Rate Plan Filing
In July 2019, Entergy Arkansas filed with the APSC its 2019 formula rate plan filing to set its formula rate for the 2020 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2020 and a netting adjustment for the historical year 2018. The total proposed formula rate plan rider revenue change designed to produce a target rate of return on common equity of 9.75% is $15.3 million, which is based upon a deficiency of approximately $61.9 million for the 2020 projected year, netted with a credit of approximately $46.6 million in the 2018 historical year netting adjustment. During 2018 Entergy Arkansas experienced higher-than expected sales volume, and actual costs were lower than forecasted. These changes, coupled with a reduced income tax rate resulting from the Tax Cuts and Jobs Act, resulted in the credit for the historical year netting adjustment. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflected the estimate of the historical year netting adjustment that was expected to be included in the 2019 filing. In 2019, Entergy Arkansas recorded additional provisions totaling $11.5 million to reflect the updated estimate of the historical year netting adjustment included in the 2019 filing. In October 2019 other parties in the LPSC staff issuedproceeding filed their errors and objections requesting certain adjustments to Entergy Arkansas’s filing that would reduce or eliminate Entergy Arkansas’s proposed revenue change. Entergy Arkansas filed its report findingresponse addressing the requested adjustments in October 2019. In its response, Entergy Arkansas accepted certain of the adjustments recommended by the General Staff of the APSC that would reduce the proposed formula rate plan rider revenue change to $14 million. Entergy Arkansas disputed the remaining adjustments proposed by the parties. In October 2019, Entergy Arkansas filed a unanimous settlement agreement with the other parties in the proceeding seeking APSC approval of a revised total formula rate plan rider revenue change of $10.1 million. In its July 2019 formula rate plan filing, Entergy Arkansas proposed to recover an $11.2 million regulatory asset, amortized over five years, associated with specific costs related to the potential construction of scrubbers at the White Bluff plant. Although Entergy Arkansas does not concede that the regulatory asset lacks merit, for purposes of reaching a settlement on the total formula rate plan rider amount, Entergy Arkansas agreed not to include the White Bluff scrubber regulatory asset cost in the 2019 formula rate plan filing or future filings. Entergy Arkansas recorded a write-off in 2019 of the $11.2 million White Bluff scrubber regulatory asset. In December 2019 the APSC approved the settlement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2020.
2020 Formula Rate Plan Filing
In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Louisiana’sArkansas’s earned rate of return on common equity for the 2021 projected year is 8.22% resulting in a revenue deficiency of $64.3 million. The earned rate of return on common equity for the 2019 historical year was 9.07% resulting in a $23.9 million netting adjustment. The total proposed revenue change for the 2021 projected year and 2019 historical year netting adjustment was $88.2 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $74.3 million. In October 2020 other parties in the proceeding filed their errors
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and objections recommending certain adjustments, and Entergy Arkansas filed responsive testimony disputing these adjustments. As part of the formula rate plan tariff the calculation for the revenue constraint was updated based on actual revenues which had the effect of reducing the initially-proposed $74.3 million revenue requirement increase to $72.6 million. In October 2020, Entergy Arkansas filed with the APSC a unanimous settlement agreement reached with the other parties that resolved all but one issue. As a result of the settlement agreement, Entergy Arkansas’s requested revenue increase was $68.4 million, including a $44.5 million increase for the projected 2021 year and a $23.9 million netting adjustment. The remaining issue litigated concerned the methodology used to calculate the netting adjustment within the formula rate plan. In December 2020 the APSC issued an order rejecting the netting adjustment method used by Entergy Arkansas. Applying the approach ordered by the APSC changed the netting adjustment for the 2019 historical year from a $23.9 million deficiency to $43.5 million excess. Overall, the decision reduced Entergy Arkansas’s revenue adjustment for 2021 to $1 million. In December 2020, Entergy Arkansas filed a petition for rehearing of the APSC’s decision, and in January 2021 the APSC granted further consideration of Entergy Arkansas’s petition. Based on the progress of the proceeding to date, in December 2020, Entergy Arkansas recorded a regulatory liability of $43.5 million to reflect the netting adjustment for 2019, as included in the APSC’s December 2020 order, which would be returned to customers in 2021. Also with the formula rate plan filing, Entergy Arkansas is requesting an extension of the formula rate plan rider for a second five-year term. Decisions by the APSC on the netting adjustment rehearing and the extension are expected in March 2021.
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. In July 2018, Entergy Arkansas filed a settlement, reached by all parties in the APSC proceeding, resolving all issues. The APSC approved the settlement agreement and restructuring in August 2018. Pursuant to the settlement agreement, Entergy Arkansas will credit retail customers $39.6 million over six years, beginning in 2019. Entergy Arkansas also received the required FERC and NRC approvals.
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated 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 assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed 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 is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
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Management’s Financial Discussion and Analysis
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 in Note 2 to the financial statements.
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 upcoming energy cost rate redetermination filing that was made in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude from the redetermination of its 2014 energy cost rate $65.9 million of incremental fuel and replacement energy costs incurred in 2013 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 was available regarding various claims associated with the ANO stator incident. In February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in its deferred fuel balance. 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 regulatory 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 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.
In March 2018, 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 $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate stabilization plan but recommendingbecame effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an additionalorder declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the
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proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of $0.7 millionEntergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it has initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.
In March 2019, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01882 per kWh to $0.01462 per kWh and became effective with the first billing cycle in April 2019. In March 2019 the Arkansas Attorney General filed a response to Entergy Arkansas’s annual adjustment and included with its filing a motion for investigation of alleged overcharges to customers in connection with the FERC’s October 2018 order in the opportunity sales proceeding. Entergy Arkansas filed its response to the Attorney General’s motion in April 2019 in which Entergy Arkansas stated its intent to initiate a proceeding to address recovery issues related to the Tax Act. A procedural schedule has not been established.October 2018 FERC order. In May 2019, Entergy Arkansas initiated the opportunity sales recovery proceeding, discussed below, and requested that the APSC establish that proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC October 2018 order and related FERC orders in the opportunity sales proceeding. In June 2019 the APSC granted Entergy Arkansas’s request and also denied the Attorney General’s motion in the energy cost recovery proceeding seeking an investigation into Entergy Arkansas’s annual energy cost recovery rider adjustment and referred the evaluation of such matters to the opportunity sales recovery proceeding.
2018 Rate Stabilization Plan Filing
In March 2020, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01462 per kWh to $0.01052 per kWh. The redetermined rate became effective with the first billing cycle in April 2020 through the normal operation of the tariff.
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 allocated 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 prohibited 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 challenged sales made beginning in 2002 and requested refunds. In July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement 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 FERC subsequently ordered a hearing in the proceeding.
After a hearing, the ALJ issued an initial decision in December 2010. 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 2019, Entergy Louisiana2011 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
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Management’s Financial Discussion and Analysis
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. The FERC in its decision established further hearing procedures to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision. The hearing was held in May 2013 and the ALJ issued an initial decision in August 2013. 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 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’ request to hold the appeal in abeyance pending final resolution of the related proceeding before 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’ appeal.
The hearing required by the FERC’s April 2016 order was held in May 2017. In July 2017 the ALJ issued an initial decision addressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the calculation methodology. 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 decision. 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.
Based on testimony previously submitted in the case and its gas rate stabilization planassessment of the April 2016 FERC orders, in the first quarter 2016, Entergy Arkansas recorded a liability of $87 million, which included interest, for its estimated increased costs and payment to the other Utility operating companies, and a deferred fuel regulatory asset of $75 million. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in
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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.
In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the test year endedincreased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 30, 2018.2000 should be included in the calculation of Entergy Arkansas’s payment. The filingFERC affirmed on other grounds the ALJ’s rejection of the evaluation reportLPSC’s claim that certain joint account sales should be accounted for the test year 2018 reflected an earned return on common equity of 2.69%. This earned return is below the earning sharing bandas part of the gas rate stabilization plan and results in a rate increasecalculation of $2.8 million. Entergy LouisianaArkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. The December 2018 compliance filing is pending FERC action. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
| | | | | | | | | | | |
| | Total refunds including interest |
| Payment/(Receipt) |
| | (In Millions) |
| Principal | Interest | Total |
| Entergy Arkansas | $68 | $67 | $135 |
| Entergy Louisiana | ($30) | ($29) | ($59) |
| Entergy Mississippi | ($18) | ($18) | ($36) |
| Entergy New Orleans | ($3) | ($4) | ($7) |
| Entergy Texas | ($17) | ($16) | ($33) |
Entergy Arkansas previously recognized a regulatory asset with a balance of $116 million as of December 31, 2018 for a portion of the payments due as a result of this proceeding.
As described above, the FERC’s opportunity sales orders have been appealed to the D.C. Circuit. In February 2020 all of the appeals were consolidated and in April 2020 the D.C. Circuit established a briefing schedule. Briefing was completed in September 2020 and oral argument was heard in December 2020.
In February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and rates were implemented duringmotion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC’s complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC’s new complaint. In December 2019 the LPSC requested rehearing of the FERC’s November 2019 order, and in July 2020 the FERC issued an order dismissing the LPSC’s request for rehearing. In September 2020 the LPSC appealed to the D.C. Circuit the FERC’s orders dismissing the new opportunity sales complaint. In November 2020 the D.C. Circuit issued an order establishing that briefing will occur in January 2021 through April 2021.
In May 2019, Entergy Arkansas filed an application and supporting testimony with the APSC requesting approval of a special rider tariff to recover the costs of these payments from its retail customers over a 24-month period. The application requested that the APSC approve the rider to take effect within 30 days or, if suspended by the APSC as allowed by commission rule, approve the rider to take effect in the first billing cycle of Maythe first month occurring 30 days after issuance of the APSC’s order approving the rider. In June 2019 the APSC suspended
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Entergy Arkansas’s tariff and granted Entergy Arkansas’s motion asking the APSC to establish the proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC’s October 2018 order and related FERC orders in the opportunity sales proceeding. In January 2020 the APSC adopted a procedural schedule with a hearing in April 2020. In January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed a joint motion seeking to dismiss Entergy Arkansas’s application alleging that the APSC, in a prior proceeding, ruled on the issues addressed in the application and determined that Entergy Arkansas’s requested relief violates the filed rate doctrine and the prohibition against retroactive ratemaking. Entergy Arkansas responded to the joint motion in February 2020 rebutting these arguments, including demonstrating that the claims in this proceeding differ substantially from those the APSC addressed previously and that the payment resulting from a FERC tariff violation for which Entergy Arkansas seeks retail cost recovery in this proceeding differs materially from the refunds resulting from a FERC tariff amendment that the APSC previously rejected on filed rate doctrine and the retroactive ratemaking grounds. In addition, in January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed testimony opposing the recovery by Entergy Arkansas of the opportunity sales payment but also claiming that certain components of the payment should be segregated and refunded to customers. In March 2020, Entergy Arkansas filed rebuttal testimony.
In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U. S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court scheduled a hearing for February 26, 2021 regarding issues addressed in the pre-trial conference report.
Net Metering Legislation
An Arkansas law was enacted effective July 2019 that, among other things, expands the definition of a “net metering customer” to include two additional types of customers: (1) customers that lease net metering facilities, subject to refundcertain leasing arrangements, and final LPSC review.(2) government entities or other entities exempt from state and federal income taxes that enter into a service contract for a net metering facility. The latter provision would allow eligible entities, many of whom are small and large general service customers, to purchase renewable energy directly from third party providers and receive bill credits for these purchases. The APSC was given authority under this law to address certain matters, such as cost shifting and the appropriate compensation for net metered energy and has initiated proceedings for this purpose. Because of the size and number of customers eligible under this new law, there is a risk of loss of load and the shifting of costs to customers. A hearing was held in December 2019, with utilities, cooperatives, the Arkansas Attorney General, industrial customers, and Entergy Arkansas advocating the need for establishment of a reasonable rate structure that takes into account impacts to non-net metering customers; an additional hearing was conducted in February 2020 for purposes of public comment only. The APSC issued an order in June 2020, and in July 2020 several parties, including Entergy Arkansas, filed for rehearing on multiple
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grounds, including for the reasons that it imposes an unreasonable rate structure and allows facilities to net meter that do not meet the statutory definition of net metering facilities. After granting the rehearing requests, the APSC issued an order in September 2020 largely upholding its June 2020 order. In October 2020, Entergy Arkansas and several other parties filed an appeal of the APSC’s September 2020 order.
Separately, as directed by the APSC general staff, the APSC opened a proceeding to compel utilities to amend their net metering tariffs to incorporate the provisions of the legislation that the APSC general staff considered “black letter law.” Entergy Arkansas, the Arkansas Attorney General, and other intervenors opposed this directive pending the development of the rules for implementation that are being considered in the separate net metering rulemaking docket. Nevertheless, reserving its rights, Entergy Arkansas has complied with the directive to amend its tariffs. Asserting procedural and due process violations, in January 2020, Entergy Arkansas and the Arkansas Attorney General separately appealed certain APSC orders in the proceeding.
COVID-19 Orders
In April 2020, in light of the COVID-19 pandemic, the APSC issued an order requiring utilities, to the extent they had not already done so, to suspend service disconnections during the remaining pendency of the Arkansas Governor’s emergency declaration or until the APSC rescinds the directive. The order also authorizes utilities to establish a regulatory asset to record costs resulting from the suspension of service disconnections, directs that in future proceedings the APSC will consider whether the request for recovery of these regulatory assets is reasonable and necessary, and requires utilities to track and report the costs and any savings directly attributable to suspension of disconnects. In May 2020 the APSC approved Entergy Arkansas expanding deferred payment agreements to assist customers during the COVID-19 pandemic. Quarterly reporting began in August 2020 and the APSC ordered additional reporting in October 2020 regarding utilities’ transitional plans for ending the moratorium on service disconnects. In February 2021 the APSC issued an order finding that it is not in the public interest to immediately lift the moratorium on service disconnects, but to announce a target date of May 3, 2021. In March 2021 the APSC will issue an order either confirming the lifting of the moratorium on service disconnects or extending the moratorium. As of December 31, 2020, Entergy Arkansas recorded a regulatory asset of $10.5 million for costs associated with the COVID-19 pandemic.
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 Arkansas owns and, 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 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; the performance and capacity factors of these nuclear plants including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; 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 either ANO 1 or ANO 2, Entergy Arkansas may be required to
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ANO 1’s operating license expires in 2034 and ANO 2’s operating license expires in 2038.
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, 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.
In the first quarter 2019, 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 $126.2 million increase in its discovery phase.decommissioning cost liabilities, along with corresponding increases in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.
Gas 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.
Impairment of Long-lived Assets
See “Impairment of Long-lived Assets” 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.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
Costs 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 2021 Qualified Pension Cost | | Impact on 2020 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $2,406 | | $46,791 |
| Rate of return on plan assets | | (0.25%) | | $2,914 | | $— |
| Rate of increase in compensation | | 0.25% | | $1,838 | | $8,922 |
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 2021 Postretirement Benefit Cost | | Impact on 2020 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $174 | | $6,576 |
| Health care cost trend | | 0.25% | | $225 | | $4,516 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Arkansas in 2020 was $81.7 million, including $21.1 million in settlement costs. Entergy Arkansas anticipates 2021 qualified pension cost to be $61.6 million. Entergy Arkansas contributed $60 million to its qualified pension plans in 2020 and estimates pension contributions will be approximately $66.6 million in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021.
Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 2020 was $10.1 million. Entergy Arkansas expects 2021 postretirement health care and life insurance benefit income of approximately $11.1 million. Entergy Arkansas contributed $2.2 million to its other postretirement plans in 2020 and estimates 2021 contributions will be approximately $517 thousand.
Entergy Arkansas, 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 member and Board of Directors of
Entergy Arkansas, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Arkansas, LLC and Subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of income, cash flows and changes in member’s equity (pages 332 through 336 and applicable items in pages 51 through 238), for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate Stabilization Plan Extension Requestand Regulatory Matters —Entergy Arkansas, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arkansas Public Service Commission (the “APSC”), which has jurisdiction with respect to the rates of electric companies in Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment;
regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the APSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses 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. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the APSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs, including costs related to the Opportunity Sales Proceeding and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the APSC and the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the APSC and the FERC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the APSC and the FERC for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the APSC’s and the FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, including the Opportunity Sales Proceeding, we inspected the Company’s filings with the APSC and the FERC, including the annual formula rate plan filing, and considered the filings with the APSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, including the Opportunity Sales Proceeding, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2021
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $2,084,494 | | | $2,259,594 | | | $2,060,643 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 271,896 | | | 458,907 | | | 517,245 | |
| Purchased power | | 187,690 | | | 204,640 | | | 252,390 | |
| Nuclear refueling outage expenses | | 55,737 | | | 68,769 | | | 77,915 | |
| Other operation and maintenance | | 669,518 | | | 720,217 | | | 724,831 | |
| Decommissioning | | 73,319 | | | 68,030 | | | 60,420 | |
| Taxes other than income taxes | | 121,057 | | | 115,869 | | | 104,771 | |
| Depreciation and amortization | | 338,029 | | | 307,351 | | | 292,649 | |
| Other regulatory credits - net | | (35,310) | | | (11,186) | | | (14,807) | |
| TOTAL | | 1,681,936 | | | 1,932,597 | | | 2,015,414 | |
| | | | | | |
| OPERATING INCOME | | 402,558 | | | 326,997 | | | 45,229 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 15,019 | | | 15,499 | | | 16,557 | |
| Interest and investment income | | 35,579 | | | 26,020 | | | 25,406 | |
| Miscellaneous - net | | (21,908) | | | (18,566) | | | (14,874) | |
| TOTAL | | 28,690 | | | 22,953 | | | 27,089 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 144,834 | | | 140,087 | | | 124,459 | |
| Allowance for borrowed funds used during construction | | (6,595) | | | (6,332) | | | (7,781) | |
| TOTAL | | 138,239 | | | 133,755 | | | 116,678 | |
| | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | 293,009 | | | 216,195 | | | (44,360) | |
| | | | | | |
| Income taxes | | 47,777 | | | (46,769) | | | (297,067) | |
| | | | | | |
| NET INCOME | | 245,232 | | | 262,964 | | | 252,707 | |
| | | | | | |
| Preferred dividend requirements | | 0 | | | 0 | | | 1,249 | |
| | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | | $245,232 | | | $262,964 | | | $251,458 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $245,232 | | | $262,964 | | | $252,707 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 490,457 | | | 465,299 | | | 443,698 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 87,019 | | | 94,368 | | | 129,524 | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (24,507) | | | (58,077) | | | 4,294 | |
| Fuel inventory | | (10,066) | | | (10,597) | | | 6,210 | |
| Accounts payable | | (22,773) | | | 3,059 | | | (126,405) | |
| Prepaid taxes and taxes accrued | | 6 | | | 24,942 | | | 9,568 | |
| Interest accrued | | (43) | | | 3,895 | | | 678 | |
| Deferred fuel costs | | (1,186) | | | 72,560 | | | 43,869 | |
| Other working capital accounts | | (11,061) | | | 18,783 | | | (30,118) | |
| Provisions for estimated losses | | 6,289 | | | 14,901 | | | 14,250 | |
| Other regulatory assets | | (165,534) | | | (131,873) | | | 32,460 | |
| Other regulatory liabilities | | 106,878 | | | 39,293 | | | (341,682) | |
| | | | | | |
| Pension and other postretirement liabilities | | 42,576 | | | 5,831 | | | (40,157) | |
| Other assets and liabilities | | (83,469) | | | (127,582) | | | (187,071) | |
| Net cash flow provided by operating activities | | 659,818 | | | 677,766 | | | 211,825 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (775,595) | | | (641,525) | | | (660,044) | |
| Allowance for equity funds used during construction | | 15,019 | | | 15,306 | | | 17,013 | |
| Nuclear fuel purchases | | (100,678) | | | (54,344) | | | (99,417) | |
| Proceeds from sale of nuclear fuel | | 30,638 | | | 22,782 | | | 54,810 | |
| | | | | | |
| Proceeds from nuclear decommissioning trust fund sales | | 321,360 | | | 317,377 | | | 300,801 | |
| Investment in nuclear decommissioning trust funds | | (336,392) | | | (336,519) | | | (315,163) | |
| Payment for purchase of assets | | (5,988) | | | 0 | | | 0 | |
| Changes in money pool receivable - net | | (3,110) | | | 0 | | | 0 | |
| | | | | | |
| | | | | | |
| | | | | | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | 55,001 | | | 0 | | | 0 | |
| | | | | | |
| Insurance proceeds | | 0 | | | 0 | | | 14,790 | |
| Other | | 4,036 | | | 630 | | | (1,517) | |
| Net cash flow used in investing activities | | (795,709) | | | (676,293) | | | (688,727) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 1,071,121 | | | 834,038 | | | 958,434 | |
| Retirement of long-term debt | | (632,175) | | | (548,952) | | | (690,488) | |
| Capital contribution from parent | | 0 | | | 0 | | | 350,000 | |
| Redemption of preferred stock | | 0 | | | 0 | | | (32,660) | |
| Change in money pool payable - net | | (21,634) | | | (161,104) | | | 16,601 | |
| Changes in short-term borrowings - net | | 0 | | | 0 | | | (49,974) | |
| Distributions/dividends paid: | | | | | | |
| Common equity | | (95,000) | | | (115,000) | | | (91,751) | |
| Preferred stock | | 0 | | | 0 | | | (1,606) | |
| Other | | 2,188 | | | (7,055) | | | 12,249 | |
| Net cash flow provided by financing activities | | 324,500 | | | 1,927 | | | 470,805 | |
| Net increase (decrease) in cash and cash equivalents | | 188,609 | | | 3,400 | | | (6,097) | |
| Cash and cash equivalents at beginning of period | | 3,519 | | | 119 | | | 6,216 | |
| Cash and cash equivalents at end of period | | $192,128 | | | $3,519 | | | $119 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $140,735 | | | $131,134 | | | $118,731 | |
| Income taxes | | ($21,971) | | | ($33,989) | | | $44,393 | |
| See Notes to Financial Statements. | | | | | | |
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2020 | | 2019 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $24,108 | | | $3,519 | |
| Temporary cash investments | | 168,020 | | | 0 | |
| Total cash and cash equivalents | | 192,128 | | | 3,519 | |
| Securitization recovery trust account | | 0 | | | 4,036 | |
| Accounts receivable: | | | | |
| Customer | | 183,719 | | | 117,679 | |
| Allowance for doubtful accounts | | (18,334) | | | (1,169) | |
| Associated companies | | 34,216 | | | 29,178 | |
| Other | | 35,845 | | | 117,653 | |
| Accrued unbilled revenues | | 109,000 | | | 108,489 | |
| Total accounts receivable | | 344,446 | | | 371,830 | |
| | | | |
| | | | |
| Fuel inventory - at average cost | | 43,811 | | | 33,745 | |
| Materials and supplies - at average cost | | 237,640 | | | 211,320 | |
| Deferred nuclear refueling outage costs | | 32,692 | | | 48,875 | |
| | | | |
| | | | |
| Prepayments and other | | 13,296 | | | 14,096 | |
| | | | |
| TOTAL | | 864,013 | | | 687,421 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Decommissioning trust funds | | 1,273,921 | | | 1,101,283 | |
| | | | |
| Other | | 341 | | | 345 | |
| TOTAL | | 1,274,262 | | | 1,101,628 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 12,905,322 | | | 12,293,483 | |
| | | | |
| Construction work in progress | | 234,213 | | | 197,775 | |
| Nuclear fuel | | 163,044 | | | 195,547 | |
| TOTAL UTILITY PLANT | | 13,302,579 | | | 12,686,805 | |
| Less - accumulated depreciation and amortization | | 5,255,355 | | | 5,019,826 | |
| UTILITY PLANT - NET | | 8,047,224 | | | 7,666,979 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets (includes securitization property of $0 as of December 31, 2020 and $1,706 as of December 31, 2019) | | 1,832,384 | | | 1,666,850 | |
| Deferred fuel costs | | 68,220 | | | 67,690 | |
| Other | | 14,028 | | | 15,065 | |
| TOTAL | | 1,914,632 | | | 1,749,605 | |
| | | | |
| TOTAL ASSETS | | $12,100,131 | | | $11,205,633 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2020 | | 2019 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $485,000 | | | $0 | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | 59,448 | | | 111,785 | |
| Other | | 208,591 | | | 202,201 | |
| Customer deposits | | 98,506 | | | 101,411 | |
| Taxes accrued | | 81,837 | | | 81,831 | |
| | | | |
| Interest accrued | | 22,745 | | | 22,788 | |
| Deferred fuel costs | | 53,065 | | | 53,721 | |
| Current portion of unprotected excess accumulated deferred income taxes | | 0 | | | 9,296 | |
| Other | | 40,628 | | | 38,760 | |
| TOTAL | | 1,049,820 | | | 621,793 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 1,286,123 | | | 1,183,126 | |
| Accumulated deferred investment tax credits | | 30,500 | | | 31,701 | |
| Regulatory liability for income taxes - net | | 467,031 | | | 478,174 | |
| Other regulatory liabilities | | 686,872 | | | 559,555 | |
| Decommissioning | | 1,314,160 | | | 1,242,616 | |
| Accumulated provisions | | 70,169 | | | 63,880 | |
| Pension and other postretirement liabilities | | 361,682 | | | 319,075 | |
| Long-term debt (includes securitization bonds of $0 as of December 31, 2020 and $6,772 as of December 31, 2019) | | 3,482,507 | | | 3,517,208 | |
| Other | | 75,098 | | | 62,568 | |
| TOTAL | | 7,774,142 | | | 7,457,903 | |
| | | | |
| Commitments and Contingencies | | 0 | | 0 |
| | | | |
| | | | |
| | | | |
| EQUITY | | | | |
| Member's equity | | 3,276,169 | | | 3,125,937 | |
| TOTAL | | 3,276,169 | | | 3,125,937 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $12,100,131 | | | $11,205,633 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY |
| For the Years Ended December 31, 2020, 2019, and 2018 |
| |
| |
| Member's Equity |
| (In Thousands) |
| |
| Balance at December 31, 2017 | $2,376,754 | |
| Net income | 252,707 | |
| Capital contributions from parent | 350,000 | |
| |
| Common equity distributions | (91,751) | |
| Non-cash contribution from parent | 94,335 | |
| Preferred stock dividends | (1,249) | |
| Other | 2,307 | |
| Balance at December 31, 2018 | $2,983,103 | |
| Net income | 262,964 | |
| |
| |
| Common equity distributions | (115,000) | |
| |
| |
| Other | (5,130) | |
| Balance at December 31, 2019 | $3,125,937 | |
| Net income | 245,232 | |
| |
| |
| Common equity distributions | (95,000) | |
| |
| |
| |
| Balance at December 31, 2020 | $3,276,169 | |
| |
| See Notes to Financial Statements. | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | | (In Thousands) |
| | | | | | | | | | |
| Operating revenues | | $2,084,494 | | | $2,259,594 | | | $2,060,643 | | | $2,139,919 | | | $2,086,608 | |
| Net income | | $245,232 | | | $262,964 | | | $252,707 | | | $139,844 | | | $167,212 | |
| Total assets | | $12,100,131 | | | $11,205,633 | | | $10,401,596 | | | $10,134,029 | | | $9,606,117 | |
| Long-term obligations (a) | | $3,482,507 | | | $3,517,208 | | | $3,225,759 | | | $2,983,749 | | | $2,746,435 | |
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund. |
| | | | | | | | | | |
| | | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | | | | | | | | | | |
| Residential | | $841 | | | $795 | | | $807 | | | $768 | | | $789 | |
| Commercial | | 466 | | | 539 | | | 426 | | | 495 | | | 495 | |
| Industrial | | 462 | | | 521 | | | 434 | | | 472 | | | 446 | |
| Governmental | | 18 | | | 21 | | | 17 | | | 19 | | | 18 | |
| Total billed retail | | 1,787 | | | 1,876 | | | 1,684 | | | 1,754 | | | 1,748 | |
| Sales for resale: | | | | | | | | | | |
| Associated companies | | 105 | | | 118 | | | 104 | | | 128 | | | 49 | |
| Non-associated companies | | 68 | | | 140 | | | 145 | | | 121 | | | 118 | |
| Other | | 124 | | | 126 | | | 128 | | | 137 | | | 172 | |
| Total | | $2,084 | | | $2,260 | | | $2,061 | | | $2,140 | | | $2,087 | |
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | | |
| Residential | | 7,584 | | | 7,996 | | | 8,248 | | | 7,298 | | | 7,618 | |
| Commercial | | 5,356 | | | 5,822 | | | 5,967 | | | 5,825 | | | 5,988 | |
| Industrial | | 7,586 | | | 7,759 | | | 8,071 | | | 7,528 | | | 6,795 | |
| Governmental | | 223 | | | 241 | | | 239 | | | 237 | | | 237 | |
| Total retail | | 20,749 | | | 21,818 | | | 22,525 | | | 20,888 | | | 20,638 | |
| Sales for resale: | | | | | | | | | | |
| Associated companies | | 1,659 | | | 2,180 | | | 1,773 | | | 1,782 | | | 1,609 | |
| Non-associated companies | | 4,198 | | | 7,206 | | | 6,447 | | | 6,549 | | | 7,115 | |
| Total | | 26,606 | | | 31,204 | | | 30,745 | | | 29,219 | | | 29,362 | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
Hurricane Laura, Hurricane Delta, and Hurricane Zeta
In August 2019,2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.0 billion, including approximately $1.67 billion in capital costs and approximately $330 million in non-capital costs. This estimate includes all costs to restore power and repair or replace the damages from the hurricanes, except for the cost to repair or replace damage incurred to an Entergy Louisiana submittedtransmission line in southeast Louisiana, and the amount of that cost could be significant. The restoration plan for this transmission line and the related cost estimate is still being evaluated. Also, Entergy Louisiana’s revenues were adversely affected in 2020, primarily due to power outages resulting from the hurricanes. Entergy Louisiana is considering all reasonable avenues to recover storm-related costs from Hurricane Laura, Hurricane Delta, and Hurricane Zeta, including securitization. Storm cost recovery or financing will be subject to review by applicable regulatory authorities.
Entergy Louisiana recorded accounts payable and corresponding construction work in progress and regulatory assets for the estimated costs incurred that were necessary to return customers to service. Entergy Louisiana recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles. Because Entergy Louisiana has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
In October 2020, Entergy Louisiana filed an application toat the LPSC seeking extensionapproval of the gas rate stabilization plancertain ratemaking adjustments to facilitate issuance of shorter-term bonds to provide interim financing for the 2019-2021 test years on the same terms as those approved for the 2018 test year. The LPSC established a procedural schedule to address this requestrestoration costs associated with a hearing scheduled in May 2020.Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff recently submittedfiled a joint stipulation that recommendsmotion seeking approval to exclude from the derivation of the requested extension with certain modifications to the current terms, including a 9.8% evaluation periodEntergy Louisiana’s capital structure and cost rate of debt for common equityratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and provisions forHurricane Zeta costs on an interim basis. In November 2020 the return of the excess accumulated deferred income tax to customers on a dollar for dollar basis in a manner consistent with IRS normalization rules. The LPSC approvedissued an order approving the joint stipulationmotion, and Entergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in January 2020.November 2020, Entergy Louisiana drew $257 million from its funded storm reserves.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Louisiana’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $50 million to $60 million. Natural gas purchases for Entergy Louisiana for February 1st through 25th, 2021 are approximately $190 million compared to natural gas purchases for February 2020 of $39 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income increased $390.8 million primarily due to the $382.8 million reduction in deferred income tax expense related to the basis of assets contributed in the 2015 Entergy Louisiana and Entergy Gulf States Louisiana business combination as a result of the resolution of the 2014-2015 IRS audit in the fourth quarter 2020 and the $58 million reduction in income tax expense resulting from an IRS settlement in the first quarter 2020 related to the uncertain tax position regarding the Hurricane Isaac Louisiana Act 55 financing, which also resulted in a $29 million ($21 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s agreement to share the savings with customers. Also contributing to the increase were higher retail electric price, lower other operation and maintenance expenses, and a lower effective income tax rate. The increase was partially offset by higher depreciation and amortization expenses, lower volume/weather, lower other income, higher interest expense, and higher taxes other than income taxes. See Note 3 to the financial statements for further discussion of the tax audit resolution and the tax settlement.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2020 to 2019:
| | | | | |
| Amount |
| (In Millions) |
| 2019 operating revenues | $4,285.2 | |
| Fuel, rider, and other revenues that do not significantly affect net income | (330.3) | |
| Volume/weather | (68.8) | |
| Return of unprotected excess accumulated deferred income taxes to customers | 7.5 | |
| Retail electric price | 176.3 | |
| 2020 operating revenues | $4,069.9 | |
Entergy Louisiana’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The volume/weather variance is primarily due to decreased commercial and industrial usage as a result of the COVID-19 pandemic, the effects of Hurricane Laura, Hurricane Delta, and Hurricane Zeta on sales, and the effect of less favorable weather on residential sales, partially offset by increased residential usage as a result of the COVID-19 pandemic. The decrease in industrial usage is partially offset by an increase in demand from expansion projects, primarily in the transportation and chemicals industries. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
COVID-19 pandemic. See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of the storms.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through changes in the formula rate plan effective May 2018. In 2020, $31.1 million was returned to customers as compared to $38.6 million in 2019. There was no effect on net income as the reduction in operating revenues was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
The retail electric price variance is primarily due to an increase in formula rate plan revenues effective June 2019 due to the inclusion of the first-year revenue requirement for the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and effective April 2020 due to the inclusion of the first-year revenue requirement for the Lake Charles Power Station and increases in formula rate plan revenues effective September 2019 and September 2020. See Note 2 to the financial statements for further discussion of the formula rate plan proceedings.
Other Income Statement Variances
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $10.2 million in nuclear generation expenses primarily due to a lower scope of work performed in 2020 as compared to 2019, in part as a result of the COVID-19 pandemic;
•a decrease of $9.5 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services;
•a decrease of $6.8 million in loss provisions;
•higher nuclear insurance refunds of $5.9 million;
•a decrease of $5.8 million in energy efficiency costs due to the timing of recovery from customers; and
•a decrease of $4.3 million in non-nuclear generation expenses primarily due to a lower scope of work performed during plant outages in 2020 as compared to the same period in 2019, partially offset by increases resulting from the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and the Lake Charles Power Station being placed in service.
The decrease was partially offset by:
•an increase of $4.1 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefits costs as a result of a decrease in the discount rate used to value the benefit liabilities. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs; and
•several individually insignificant items.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher property assessments.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station), which was placed into service in May 2019 and the Lake Charles Power Station, which was placed in service in March 2020.
Other regulatory charges (credits) include regulatory charges of $32.6 million recorded in the fourth quarter 2020 due to a settlement with the IRS related to the uncertain tax position regarding Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing because the savings will be shared with customers and $29 million recorded in the first quarter 2020 due to a settlement with the IRS related to the uncertain tax position regarding Hurricane Isaac Louisiana Act 55 financing because the savings will be shared with customers. See Note 3 to the financial statements for further discussion of the settlements and savings obligations.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other income decreased primarily due to:
•a decrease in the allowance for equity funds used during construction due to higher construction work in progress in 2019, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and the Lake Charles Power Station projects; and
•changes in decommissioning trust fund activity.
Interest expense increased primarily due to:
•the issuances of $300 million of 4.20% Series mortgage bonds and $350 million of 2.90% Series mortgage bonds, each in March 2020;
•the issuance of $525 million of 4.20% Series mortgage bonds in March 2019; and
•a decrease in the allowance for borrowed funds used during construction due to higher construction work in progress in 2019, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and Lake Charles Power Station projects.
The effective income tax rates were (54.6%) for 2020 and 15% for 2019. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2020 was primarily due to completion of the 2014-2015 IRS audit effectively settling the tax positions for those years. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes. See Notes 2 and 3 to the financial statements for a discussion of the effects and regulatory activity regarding the Tax Cuts and Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory rates of 21% to the effective income tax rates.
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of results of operations for 2019 compared to 2018.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $2,006 | | | $43,364 | | | $35,907 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 1,072,986 | | | 1,236,002 | | | 1,395,204 | |
| Investing activities | (1,944,671) | | | (1,653,634) | | | (1,878,208) | |
| Financing activities | 1,597,699 | | | 376,274 | | | 490,461 | |
| Net increase (decrease) in cash and cash equivalents | 726,014 | | | (41,358) | | | 7,457 | |
| | | | | |
| Cash and cash equivalents at end of period | $728,020 | | | $2,006 | | | $43,364 | |
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities decreased $163 million in 2020 primarily due to:
•an increase of $186.1 million in storm spending in 2020, primarily due to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration efforts. See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of storm restoration efforts;
•lower collections of receivables from customers, in part due to the COVID-19 pandemic;
•the timing of recovery of fuel and purchased power costs; and
•an increase of $21.5 million in interest paid.
The decrease was partially offset by:
•a decrease in $43.7 million in spending on nuclear refueling outages;
•the timing of payments to vendors; and
•income tax refunds of $14.7 million in 2020 compared to $15.3 million in income tax payments in 2019. Entergy Louisiana had income tax refunds in 2020 and income tax payments in 2019 in accordance with an intercompany tax allocation agreement. Entergy Louisiana had income tax refunds in 2020 as a result of a refund of an overpayment on a prior year state income tax return.
Investing Activities
Net cash flow used in investing activities increased $291 million in 2020 primarily due to:
•an increase of $709.7 million in storm spending 2020, primarily due to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration efforts, See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of storm restoration efforts;
•the purchase of Washington Parish Energy Center in November 2020 for approximately $222 million. See Note 14 to the financial statements for further discussion of the Washington Parish Energy Center purchase;
•an increase of $16.7 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Louisiana’s distribution system, including increased spending on advanced metering infrastructure; and
•money pool activity.
The increase was partially offset by:
•an increase of $302.2 million in net receipts from storm reserve escrow accounts;
•a decrease of $207.8 million in non-nuclear generation construction expenditures due to higher spending in 2019 on the Lake Charles Power Station and J. Wayne Leonard Power Station (formerly St. Charles Power Station) projects;
•a decrease of $133.1 million in transmission construction expenditures primarily due to a lower scope of work performed on various projects in 2020 as compared to 2019;
•a decrease of $89.5 million in nuclear construction expenditures primarily due to a lower scope of work performed on various nuclear projects in 2020 as compared to 2019; and
•a decrease of $26.1 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.
Increases in Entergy Louisiana’s receivable from the money pool are a use of cash flow, and Entergy Louisiana’s receivable from the money pool increased by $13.4 million in 2020 compared to decreasing by $46.8
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
million in 2019. 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 $1,221.4 million in 2020 primarily due to:
•the issuance of $1.1 billion of 0.62% Series mortgage bonds in November 2020;
•the issuance of $350 million of 2.90% Series mortgage bonds and $300 million of 4.20% Series mortgage bonds, each in March 2020;
•the issuance of $300 million of 2.90% Series mortgage bonds and $300 million of 1.60% Series mortgage bonds, each in November 2020; and
•a decrease of $186.5 million in common equity distributions in 2020 primarily due to upcoming capital expenditures.
The increase was partially offset by:
•the issuance of $525 million of 4.20% Series mortgage bonds in March 2019;
•the repayment in August 2020 of $250 million of 3.95% Series mortgage bonds due October 2020;
•the repayment in December 2020 of $200 million of 5.25% Series mortgage bonds due July 2052;
•money pool activity;
•the repayment in December 2020 of $100 million of 4.70% Series mortgage bonds due June 2063; and
•net repayments of long-term borrowings of $62 million in 2020 on the nuclear fuel company variable interest entities’ credit facilities.
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 $82.8 million in 2020 compared to increasing by $82.8 million in 2019.
See Note 5 to the financial statements for details of long-term debt.
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
Entergy Louisiana’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for Entergy Louisiana is primarily due to the net issuances of long-term debt in 2020.
| | | | | | | | | | | |
| | December 31,
2020 | | December 31,
2019 |
| Debt to capital | 54.8 | % | | 53.4 | % |
| Effect of excluding securitization bonds | 0.0 | % | | (0.1 | %) |
| Debt to capital, excluding securitization bonds (a) | 54.8 | % | | 53.3 | % |
| Effect of subtracting cash | (2.1 | %) | | (0.1 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 52.7 | % | | 53.2 | % |
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
(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, finance lease obligations, 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 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 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 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 distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Louisiana may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Louisiana 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
•distribution and interest payments.
Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2022 | | 2023 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $365 | | | $460 | | | $785 | |
| Transmission | 425 | | | 340 | | | 230 | |
| Distribution | 540 | | | 485 | | | 500 | |
| Utility Support | 160 | | | 130 | | | 115 | |
| Total | $1,490 | | | $1,415 | | | $1,630 | |
In addition to the planned spending in the table above, Entergy Louisiana also expects to pay for $845 million of capital investments in 2021 related to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration work that have been accrued as of December 31, 2020.
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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| | (In Millions) |
| Long-term debt (a) | $557 | | | $2,294 | | | $1,495 | | | $9,506 | | | $13,852 | |
| Operating leases (b) | $13 | | | $19 | | | $10 | | | $4 | | | $46 | |
| Finance leases (b) | $4 | | | $7 | | | $4 | | | $2 | | | $17 | |
| Purchase obligations (c) | $687 | | | $1,463 | | | $1,472 | | | $4,838 | | | $8,460 | |
(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)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 $59.9 million to its qualified pension plans and approximately $15.6 million to its other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. See “Critical Accounting Estimates- 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 Louisiana includes specific investments such as transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to maintain reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; investments in River Bend and Waterford 3; software and security; 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.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly.
Sources of Capital
Entergy Louisiana’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•storm reserve escrow accounts;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Louisiana may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest 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. 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.
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | | 2017 |
| (In Thousands) |
| $13,426 | | ($82,826) | | $46,843 | | $11,173 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Louisiana has a credit facility in the amount of $350 million scheduled to expire in September 2024. The credit facility includes fronting commitments for the issuance of letters of credit against $15 million of the borrowing capacity of the facility. As of December 31, 2020, there were no cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy Louisiana 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, 2020, $2.2 million in letters of credit were outstanding under Entergy Louisiana’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
The Entergy Louisiana nuclear fuel company variable interest entities have two separate credit facilities, each in the amount of $105 million and scheduled to expire in September 2022. As of December 31, 2020, $18.9 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, 2020, $39.3 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 obtained authorizations from the FERC through July 2022 for the following:
•short-term borrowings not to exceed an aggregate amount of $450 million at any time outstanding;
•long-term borrowings and security issuances; and
•borrowings by its nuclear fuel company variable interest entities.
See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.
Hurricane Isaac
In 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 Louisiana to 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
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 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 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 StabilizationRegulation 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
2017 Formula Rate Plan Filing
In JanuaryJune 2018, Entergy Louisiana filed its formula rate plan evaluation report for its 2017 calendar year operations. The 2017 test year evaluation report produced an earned return on equity of 8.16%, due in large part to revenue-neutral realignments to other recovery mechanisms. Without these realignments, the evaluation report produces an earned return on equity of 9.88% and a resulting base rider formula rate plan revenue increase of $4.8 million. Excluding the Tax Act credits provided for by the tax reform adjustment mechanisms, total formula rate plan revenues were further increased by a total of $98 million as a result of the evaluation report due to adjustments to the additional capacity and MISO cost recovery mechanisms of the formula rate plan, and implementation of the transmission recovery mechanism. In August 2018, Entergy Louisiana filed a supplemental formula rate plan
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
evaluation report to reflect changes from the 2016 test year formula rate plan proceedings, a decrease to the transmission recovery mechanism to reflect lower actual capital additions, and a decrease to evaluation period expenses to reflect the terms of a new power sales agreement. Based on the August 2018 update, Entergy Louisiana recognized a total decrease in formula rate plan revenue of approximately $17.6 million. Results of the updated 2017 evaluation report filing were implemented with the September 2018 billing month subject to refund and review by the LPSC staff and intervenors. In accordance with the terms of the formula rate plan, in September 2018 the LPSC staff and intervenors submitted their responses to Entergy Louisiana’s original formula rate plan evaluation report and supplemental compliance updates. The LPSC staff asserted objections/reservations regarding 1) Entergy Louisiana’s proposed rate adjustments associated with the return of excess accumulated deferred income taxes pursuant to the Tax Act and the treatment of accumulated deferred income taxes related to reductions of rate base; 2) Entergy Louisiana’s reservation regarding treatment of a regulatory asset related to certain special orders by the LPSC; and 3) test year expenses billed from Entergy Services to Entergy Louisiana. Intervenors also objected to Entergy Louisiana’s treatment of the regulatory asset related to certain special orders by the LPSC. A procedural schedule has not yet been established to resolve these issues.
Entergy Louisiana also included in its filing a presentation of an initial proposal to combine the legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana residential rates, which combination, if approved, would be accomplished on a revenue-neutral basis intended not to affect the rates of other customer classes.
Commercial operation at J. Wayne Leonard Power Station (formerly St. Charles Power Station) commenced in May 2019. In May 2019, Entergy Louisiana filed an update to its 2017 formula rate plan evaluation report to include the estimated first-year revenue requirement of $109.5 million associated with the J. Wayne Leonard Power Station. The resulting interim adjustment to rates became effective with the first billing cycle of June 2019. In June 2020, Entergy Louisiana submitted information to the LPSC to review the prudence of Entergy Louisiana’s management of the project. In August 2020 discovery commenced and a procedural schedule was established with a hearing in July 2021.
2018 Formula Rate Plan Filing
In May 2019, Entergy Louisiana filed its formula rate plan evaluation report for its 2018 calendar year operations. The 2018 test year evaluation report produced an earned return on common equity of 10.61% leading to a base rider formula rate plan revenue decrease of $8.9 million. While base rider formula rate plan revenue will decrease as a result of this filing, overall formula rate plan revenues will increase by approximately $118.7 million. This outcome is primarily driven by a reduction to the credits previously flowed through the tax reform adjustment mechanism and an increase in the transmission recovery mechanism, partially offset by reductions in the additional capacity mechanism revenue requirements and extraordinary cost items. The filing is subject to review by the LPSC. Resulting rates were implemented in September 2019, subject to refund.
Entergy Louisiana also included in its filing a presentation of an initial proposal to combine the legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana residential rates, which combination, if approved, would be accomplished on a revenue-neutral basis intended not to affect the rates of other customer classes. Entergy Louisiana contemplates that any combination of residential rates resulting from this request would be implemented with the results of the 2019 test year formula rate plan filing.
Several parties intervened in the proceeding and the LPSC staff filed its report of objections/reservations in accordance with the applicable provisions of the formula rate plan. In its report the LPSC staff re-urged reservations with respect to the outstanding issues from the 2017 test year formula rate plan filing and disputed the inclusion of certain affiliate costs for test years 2017 and 2018. The LPSC staff objected to Entergy Louisiana’s proposal to combine residential rates but proposed the setting of a status conference to establish a procedural schedule to more fully address the issue. The LPSC staff also reserved its right to object to the treatment of the sale of Willow Glen reflected in the evaluation report and to the August 2019 compliance update, which was made primarily to update the capital additions reflected in the formula rate plan’s transmission recovery mechanism,
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
based on limited time to review it. Additionally, since the completion of certain transmission projects, the LPSC staff issued supplemental data requests addressing the prudence of Entergy Louisiana’s expenditures in connection with those projects. Entergy Louisiana has responded to all such requests.
Commercial operation at Lake Charles Power Station commenced in March 2020. In March 2020, Entergy Louisiana filed an update to its 2018 formula rate plan evaluation report to include the estimated first-year revenue requirement of $108 million associated with the Lake Charles Power Station. The resulting interim adjustment to rates became effective with the first billing cycle of April 2020.
In an effort to narrow the remaining issues in formula rate plan test years 2017 and 2018, Entergy Louisiana provided notice to the parties in October 2020 that it was withdrawing its request to combine residential rates. Entergy Louisiana noted that the withdrawal is without prejudice to Entergy Louisiana’s right to seek to combine residential rates in a future proceeding.
2019 Formula Rate Plan Filing
In May 2020, Entergy Louisiana filed with the LPSC its gasformula rate stabilization plan for the test year ended September 30, 2019. The filing of the evaluation report for theits 2019 calendar year operations. The 2019 test year 2019 reflectedevaluation report produced an earned return on common equity of 10.78%9.66%. As such, no change to base rider formula rate plan revenue is required. Although base rider formula rate plan revenue will not change as a result of this filing, overall formula rate plan revenues will increase by approximately $103 million. This earned return exceedsoutcome is driven by the earning sharing bandremoval of prior year credits associated with the sale of the gasWillow Glen Power Station and an increase in the transmission recovery mechanism. Also contributing to the overall change is an increase in legacy formula rate stabilization plan leadingrevenue requirements driven by legacy Entergy Louisiana capacity cost true-ups and higher annualized legacy Entergy Gulf States Louisiana revenues due to higher billing determinants, offset by reductions in MISO cost recovery mechanism and tax reform adjustment mechanism revenue requirements. In August 2020 the LPSC staff submitted a list of items for which it needs additional information to confirm the accuracy and compliance of the 2019 test year evaluation report. The LPSC staff objected to a proposed revenue neutral adjustment regarding a certain rider as being beyond the scope of permitted formula rate reductionplan adjustments. Rates reflected in the May 2020 filing, with the exception of the revenue neutral rider adjustment, and as updated in an August 2020 filing, were implemented in September 2020, subject to refund. Entergy Louisiana is in the process of providing additional information and details on the May 2020 filing as requested by the LPSC staff.
In November 2020, Entergy Louisiana accepted ownership of the Washington Parish Energy Center and filed an update to its 2019 formula rate plan evaluation report to include the estimated first-year revenue requirement of $35 million associated with the Washington Parish Energy Center. The resulting interim adjustment to rates became effective with the first billing cycle of December 2020. In January 2021, Entergy Louisiana filed an update to its 2019 formula rate plan evaluation report to include the implementation of a scheduled step-up in its nuclear decommissioning revenue requirement and a true-up for under-collections of nuclear decommissioning expenses. The total rate adjustment would increase formula rate plan revenues by approximately $256 thousand.$1.2 million. The resulting interim adjustment to rates became effective with the first billing cycle of February 2021.
Request for Extension and Modification of Formula Rate Plan
In May 2020, Entergy Louisiana filed with the LPSC its application for authority to extend its formula rate plan. In its application, Entergy Louisiana seeks to maintain a 9.8% return on equity, with a bandwidth of 60 basis points above and below the midpoint, with a first-year midpoint reset. Entergy Louisiana also seeks to maintain its existing additional capacity mechanism, tax reform adjustment mechanism, transmission recovery mechanism, and the MISO cost recovery mechanism. Entergy Louisiana also seeks to add a distribution cost recovery mechanism which operates in substantially the same manner as the transmission recovery mechanism, seeks to utilize end of period rate base to calculate cost of service, and requests a deferral of certain expenses incurred for outside of right-of-way vegetation programs. Settlement discussions are ongoing.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Investigation of Costs Billed by Entergy Services
In November 2018 the LPSC issued a notice of proceeding initiating an investigation into costs incurred by Entergy Services that are included in the retail rates of Entergy Louisiana. As stated in the notice of proceeding, the LPSC observed an increase in capital construction-related costs incurred by Entergy Services. Discovery was issued and included efforts to seek highly detailed information on a broad range of matters unrelated to the scope of the audit. There has been no further activity in the investigation since May 2019.
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 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 July 2014 the LPSC authorized its staff to initiate an audit of the fuel adjustment clause filings by Entergy Gulf States Louisiana, whose business was combined with Entergy Louisiana in 2015. The audit includes a review of the reasonableness of charges flowed through Entergy Gulf States Louisiana’s fuel adjustment clause for the period from 2010 through 2013. In January 2019, the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $900,000, plus interest, to customers based upon the imputation of a claim of vendor fault in servicing its nuclear plant. Entergy Louisiana recorded a provision in first quarter 2019 for the potential outcome of the audit. In August 2019, Entergy Louisiana filed direct testimony challenging the basis for the LPSC staff’s recommended disallowance and providing an alternative calculation of replacement power costs should it be determined that a disallowance is appropriate. Entergy Louisiana’s calculation would require no refund to customers.
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. In January 2019 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $7.3 million, plus interest, to customers based upon the imputation of a claim of vendor fault in servicing its nuclear plant. Entergy Louisiana recorded a provision in the first quarter 2019 for the potential outcome of the audit. In August 2019, Entergy Louisiana filed direct testimony challenging the basis for the LPSC staff’s recommended disallowance and providing an alternative calculation of replacement power costs should it be determined that a disallowance is appropriate. Entergy Louisiana’s calculation would require a refund to customers of approximately $4.3 million, plus interest, as compared to the LPSC staff’s recommendation of $7.3 million, plus interest. Responsive testimony was filed by the LPSC staff and intervenors in September 2019; all parties either agreed with or did not oppose Entergy Louisiana’s alternative calculation of replacement power costs.
In November 2019 the pending LPSC proceedings for the 2010-2013 Entergy Louisiana and Entergy Gulf States Louisiana audits were consolidated to facilitate a settlement of both fuel audits. In December 2019 an unopposed settlement was reached that requires a refund to legacy Entergy Louisiana customers of approximately $2.3 million, including interest, and no refund to legacy Entergy Gulf States Louisiana customers. The LPSC approved the settlement in January 2020. A one-time refund was made in February 2020.
In June 2016 the LPSC issued notice of audits of Entergy Louisiana’s fuel adjustment clause filings for the period 2014 through 2015 and purchased gas adjustment clause filings for the period 20142012 through 2015. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also includeincludes a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includesaudits include 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.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
purchased gas adjustment clause for the period from 2012 through 2015. Regarding the fuel adjustment clause filing, the LPSC staff issued a report in January 2021 that did not recommend a disallowance for the period 2014 through 2015 recoveries, but did propose various reporting requirements. Entergy Louisiana is currently reviewing the LPSC staff recommendations regarding reporting requirements. Regarding the purchased gas adjustment clause filings, the LPSC staff issued a report in February 2020 that did not recommend a disallowance for the period 2012 through 2015 recoveries. The LPSC issued an order in September 2020 accepting the LPSC staff’s report.
In May 2018 the LPSC staff provided notice of audits of Entergy Louisiana’s purchased gas adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2016 through 2017. In February 2020 the LPSC staff issued an audit report recommending a disallowance of approximately $29 thousand Entergy Louisiana submitted a letter disputing the basis of the proposed disallowance but indicated that due to the amount at issue it would not oppose the recommended refund. The LPSC staff and Entergy Louisiana submitted a joint report noting each party’s position on the substantive issues in the matter and recommending resolution of the matters. The LPSC issued an order in September 2020 resolving the matter and ordering a refund of approximately $29 thousand. In January 2021 the LPSC issued a notice closing the matter.
In March 2020 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2016 through 2019. Discovery commenced in September 2018. No report2020 and is ongoing.
COVID-19 Orders
In April 2020 the LPSC issued an order authorizing utilities to record as a regulatory asset expenses incurred from the suspension of audit has been issued.disconnections and collection of late fees imposed by LPSC orders associated with the COVID-19 pandemic. In addition, utilities may seek future recovery, subject to LPSC review and approval, of losses and expenses incurred due to compliance with the LPSC’s COVID-19 orders. The suspension of late fees and disconnects for non-pay was extended until the first billing cycle after July 16, 2020. In January 2021, Entergy Louisiana resumed disconnections for customers in all customer classes with past-due balances that have not made payment arrangements. Utilities seeking to recover the regulatory asset must formally petition the LPSC to do so, identifying the direct and indirect costs for which recovery is sought. Any such request is subject to LPSC review and approval. As of December 31, 2020, Entergy Louisiana recorded a regulatory asset of $48.8 million for costs associated with the COVID-19 pandemic.
Net Metering Rulemaking
In September 2019 the LPSC issued an order modifying its rules regarding net metering installations. Among other things, the rule provides for 2-channel billing for net metering with excess energy put to the grid being compensated at the utility’s avoided cost. However, the rule does provide that net meter installations in place as of December 31, 2019 will be subject to 1:1 net metering with excess energy put to the grid being compensated at the full retail rate for a period of 15 years (through December 31, 2034), after which those installations will be subject to 2-channel billing. The rule also eliminates the existing limit on the cumulative number of net meter installations.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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, includinggoals; the financial requirements to address emerging issues like stress corrosion crackingperformance and capacity factors of certain materials within the plant systems and the Fukushima event;these nuclear 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 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 expires in 2044 and River Bend’s operating license expires in 2045.
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
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 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.
Entergy Louisiana, LLC 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 the first quarter 2018, Entergy 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 an $85.4 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 second quarter 2019, 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 $147.5 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 useful life of the unit.
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.
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.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 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
Entergy Louisiana, 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 2021 Qualified Pension Cost | | Impact on 2020 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $3,053 | | $52,030 |
| Rate of return on plan assets | | (0.25%) | | $3,338 | | $— |
| Rate of increase in compensation | | 0.25% | | $2,313 | | $11,706 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Qualified Pension Cost | | Impact on 2019 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $3,308 | | $47,877 |
| Rate of return on plan assets | | (0.25%) | | $3,201 | | $— |
| Rate of increase in compensation | | 0.25% | | $2,095 | | $10,727 |
Entergy Louisiana, LLC 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 2021 Postretirement Benefit Cost | | Impact on 2020 Accumulated postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $872 | | $8,226 |
| Health care cost trend | | 0.25% | | $964 | | $5,853 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Postretirement Benefit Cost | | Impact on 2019 Accumulated postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $715 | | $7,953 |
| Health care cost trend | | 0.25% | | $989 | | $5,985 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Louisiana in 20192020 was $48.6 million.$70.6 million, including $8.1 million in settlement costs. Entergy Louisiana anticipates 20202021 qualified pension cost to be $63.4$65.1 million. Entergy Louisiana contributed $65$55.4 million to its qualified pension plans in 20192020 and estimates pension contributions will be approximately $38.8$59.9 million in 2020,2021, although the 20202021 required pension contributions will be known with more certainty when the January 1, 20202021 valuations are completed, which is expected by April 1, 2020.2021.
Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 20192020 were $7.3$5.6 million. Entergy Louisiana expects 20202021 postretirement health care and life insurance benefit costs of approximately $8.7$5.4 million. Entergy Louisiana contributed $14.3$16.1 million to its other postretirement plans in 20192020 and estimates that 20202021 contributions will be approximately $18.5$15.6 million.
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 Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 member 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, 20192020 and 2018,2019, the related consolidated statements of income, comprehensive income, cash flows, and changes in equity (pages 343357 through 348362 and applicable items in pages 4951 through 236)238), for each of the three years in the period ended December 31, 2019,2020, 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, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2020, 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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which they relate.
Rate and Regulatory Matters —Entergy Louisiana, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Louisiana Public Service Commission (the “LPSC”), which has jurisdiction with respect to the rates of electric companies in Louisiana, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying
the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the LPSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses 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. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the LPSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the LPSC and the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the LPSC and the FERC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the LPSC and the FERC for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the LPSC’s and the FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected the Company’s filings with the LPSC and the FERC, including the annual formula rate plan filing, and considered the filings with the LPSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202026, 2021
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $4,019,063 | | | $4,223,027 | | | $4,232,541 | |
| Natural gas | | 50,799 | | | 62,148 | | | 63,779 | |
| TOTAL | | 4,069,862 | | | 4,285,175 | | | 4,296,320 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 700,152 | | | 845,108 | | | 915,410 | |
| Purchased power | | 596,480 | | | 810,462 | | | 960,272 | |
| Nuclear refueling outage expenses | | 55,305 | | | 54,170 | | | 51,626 | |
| Other operation and maintenance | | 969,630 | | | 994,637 | | | 959,185 | |
| Decommissioning | | 65,225 | | | 59,346 | | | 53,736 | |
| Taxes other than income taxes | | 208,902 | | | 194,222 | | | 183,745 | |
| Depreciation and amortization | | 609,931 | | | 535,791 | | | 492,179 | |
| Other regulatory charges (credits) - net | | (584) | | | (105,203) | | | 4,396 | |
| TOTAL | | 3,205,041 | | | 3,388,533 | | | 3,620,549 | |
| | | | | | |
| OPERATING INCOME | | 864,821 | | | 896,642 | | | 675,771 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 38,151 | | | 74,023 | | | 79,922 | |
| Interest and investment income | | 225,627 | | | 231,985 | | | 141,882 | |
| Miscellaneous - net | | (116,366) | | | (115,427) | | | (27,530) | |
| TOTAL | | 147,412 | | | 190,581 | | | 194,274 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 331,352 | | | 309,493 | | | 288,658 | |
| Allowance for borrowed funds used during construction | | (19,147) | | | (35,430) | | | (39,616) | |
| TOTAL | | 312,205 | | | 274,063 | | | 249,042 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 700,028 | | | 813,160 | | | 621,003 | |
| | | | | | |
| Income taxes | | (382,324) | | | 121,623 | | | (54,611) | |
| | | | | | |
| NET INCOME | | $1,082,352 | | | $691,537 | | | $675,614 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $4,223,027 |
| |
| $4,232,541 |
| |
| $4,246,020 |
|
| Natural gas | | 62,148 |
| | 63,779 |
| | 54,530 |
|
| TOTAL | | 4,285,175 |
| | 4,296,320 |
| | 4,300,550 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 845,108 |
| | 915,410 |
| | 912,060 |
|
| Purchased power | | 810,462 |
| | 960,272 |
| | 980,070 |
|
| Nuclear refueling outage expenses | | 54,170 |
| | 51,626 |
| | 52,074 |
|
| Other operation and maintenance | | 994,637 |
| | 959,185 |
| | 941,604 |
|
| Decommissioning | | 59,346 |
| | 53,736 |
| | 49,457 |
|
| Taxes other than income taxes | | 194,222 |
| | 183,745 |
| | 175,359 |
|
| Depreciation and amortization | | 535,791 |
| | 492,179 |
| | 467,369 |
|
| Other regulatory charges (credits) - net | | (105,203 | ) | | 4,396 |
| | (152,080 | ) |
| TOTAL | | 3,388,533 |
| | 3,620,549 |
| | 3,425,913 |
|
| | | | | | | |
| OPERATING INCOME | | 896,642 |
| | 675,771 |
| | 874,637 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 74,023 |
| | 79,922 |
| | 51,485 |
|
| Interest and investment income | | 231,985 |
| | 141,882 |
| | 164,550 |
|
| Miscellaneous - net | | (115,427 | ) | | (27,530 | ) | | (39,756 | ) |
| TOTAL | | 190,581 |
| | 194,274 |
| | 176,279 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 309,493 |
| | 288,658 |
| | 275,185 |
|
| Allowance for borrowed funds used during construction | | (35,430 | ) | | (39,616 | ) | | (25,914 | ) |
| TOTAL | | 274,063 |
| | 249,042 |
| | 249,271 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 813,160 |
| | 621,003 |
| | 801,645 |
|
| | | | | | | |
| Income taxes | | 121,623 |
| | (54,611 | ) | | 485,298 |
|
| | | | | | | |
| NET INCOME | |
| $691,537 |
| |
| $675,614 |
| |
| $316,347 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | | |
| Net Income | | $1,082,352 | | | $691,537 | | | $675,614 | |
| | | | | | |
| Other comprehensive income (loss) | | | | | | |
| Pension and other postretirement liabilities | | | | | | |
| (net of tax expense (benefit) of ($83), $3,781, and $17,743) | | (235) | | | 10,715 | | | 50,296 | |
| Other comprehensive income (loss) | | (235) | | | 10,715 | | | 50,296 | |
| | | | | | |
| Comprehensive Income | | $1,082,117 | | | $702,252 | | | $725,910 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| Net Income | |
| $691,537 |
| |
| $675,614 |
| |
| $316,347 |
|
| | | | | | | |
| Other comprehensive income | | |
| | |
| | |
|
| Pension and other postretirement liabilities | | |
| | |
| | |
|
| (net of tax expense of $3,781, $17,743, and $234) | | 10,715 |
| | 50,296 |
| | 2,042 |
|
| Other comprehensive income | | 10,715 |
| | 50,296 |
| | 2,042 |
|
| | | | | | | |
| Comprehensive Income | |
| $702,252 |
| |
| $725,910 |
| |
| $318,389 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $1,082,352 | | | $691,537 | | | $675,614 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 783,616 | | | 685,062 | | | 662,390 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | (356,256) | | | 196,533 | | | 174,063 | |
| Changes in working capital: | | | | | | |
| Receivables | | (79,451) | | | 13,942 | | | 89,701 | |
| Fuel inventory | | (9,067) | | | (7,195) | | | 5,310 | |
| Accounts payable | | 160,659 | | | (33,375) | | | 11,372 | |
| Prepaid taxes and taxes accrued | | 50,576 | | | (38,827) | | | 12,711 | |
| Interest accrued | | 4,505 | | | 4,294 | | | 7,922 | |
| Deferred fuel costs | | (57,895) | | | 24,234 | | | (40,036) | |
| Other working capital accounts | | (76,284) | | | (62,536) | | | (5,809) | |
| Changes in provisions for estimated losses | | (295,480) | | | 9,664 | | | 8,307 | |
| Changes in other regulatory assets | | (410,855) | | | (210,134) | | | 40,765 | |
| Changes in other regulatory liabilities | | 71,698 | | | (35,881) | | | (125,185) | |
| | | | | | |
| Changes in pension and other postretirement liabilities | | 12,199 | | | 35,162 | | | (106,269) | |
| Other | | 192,669 | | | (36,478) | | | (15,652) | |
| Net cash flow provided by operating activities | | 1,072,986 | | | 1,236,002 | | | 1,395,204 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (1,960,787) | | | (1,673,194) | | | (1,805,641) | |
| Allowance for equity funds used during construction | | 38,151 | | | 74,023 | | | 79,922 | |
| Nuclear fuel purchases | | (92,831) | | | (85,984) | | | (111,329) | |
| Proceeds from the sale of nuclear fuel | | 44,511 | | | 11,596 | | | 53,603 | |
| | | | | | |
| | | | | | |
| Payments to storm reserve escrow account | | (1,488) | | | (6,353) | | | (4,770) | |
| Receipts from storm reserve escrow account | | 297,363 | | | 0 | | | 4 | |
| Changes in securitization account | | 951 | | | (32) | | | (1,655) | |
| Proceeds from nuclear decommissioning trust fund sales | | 347,021 | | | 412,559 | | | 1,055,690 | |
| Investment in nuclear decommissioning trust funds | | (372,227) | | | (442,501) | | | (1,097,204) | |
| Changes in money pool receivable - net | | (13,426) | | | 46,843 | | | (35,672) | |
| Proceeds from sale of assets | | 0 | | | 0 | | | 11,987 | |
| Payment for purchase of assets | | (236,999) | | | 0 | | | (26,623) | |
| | | | | | |
| Insurance proceeds | | 0 | | | 7,040 | | | 3,480 | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | 5,090 | | | 2,369 | | | 0 | |
| Net cash flow used in investing activities | | (1,944,671) | | | (1,653,634) | | | (1,878,208) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 3,675,083 | | | 2,691,133 | | | 2,319,799 | |
| | | | | | |
| Retirement of long-term debt | | (1,962,635) | | | (2,199,053) | | | (1,664,354) | |
| | | | | | |
| | | | | | |
| Change in money pool payable - net | | (82,826) | | | 82,826 | | | 0 | |
| Changes in short-term borrowings - net | | 0 | | | 0 | | | (43,540) | |
| Distributions paid: | | | | | | |
| Common equity | | (21,500) | | | (208,000) | | | (128,000) | |
| | | | | | |
| Other | | (10,423) | | | 9,368 | | | 6,556 | |
| Net cash flow provided by financing activities | | 1,597,699 | | | 376,274 | | | 490,461 | |
| Net increase (decrease) in cash and cash equivalents | | 726,014 | | | (41,358) | | | 7,457 | |
| Cash and cash equivalents at beginning of period | | 2,006 | | | 43,364 | | | 35,907 | |
| Cash and cash equivalents at end of period | | $728,020 | | | $2,006 | | | $43,364 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $318,352 | | | $296,842 | | | $272,335 | |
| Income taxes | | ($14,714) | | | $15,272 | | | ($105,157) | |
| | | | | | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $691,537 |
| |
| $675,614 |
| |
| $316,347 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 685,062 |
| | 662,390 |
| | 621,018 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 196,533 |
| | 174,063 |
| | 575,804 |
|
| Changes in working capital: | | |
| | |
| | |
|
| Receivables | | 13,942 |
| | 89,701 |
| | (53,829 | ) |
| Fuel inventory | | (7,195 | ) | | 5,310 |
| | 11,010 |
|
| Accounts payable | | (33,375 | ) | | 11,372 |
| | 58,880 |
|
| Prepaid taxes and taxes accrued | | (38,827 | ) | | 12,711 |
| | 128,261 |
|
| Interest accrued | | 4,294 |
| | 7,922 |
| | (70 | ) |
| Deferred fuel costs | | 24,234 |
| | (40,036 | ) | | 23,236 |
|
| Other working capital accounts | | (62,536 | ) | | (5,809 | ) | | (30,911 | ) |
| Changes in provisions for estimated losses | | 9,664 |
| | 8,307 |
| | (8,324 | ) |
| Changes in other regulatory assets | | (210,134 | ) | | 40,765 |
| | 492,696 |
|
| Changes in other regulatory liabilities | | (35,881 | ) | | (125,185 | ) | | 605,453 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | — |
| | — |
| | (1,207,808 | ) |
| Changes in pension and other postretirement liabilities | | 35,162 |
| | (106,269 | ) | | (32,309 | ) |
| Other | | (36,478 | ) | | (15,652 | ) | | (161,909 | ) |
| Net cash flow provided by operating activities | | 1,236,002 |
| | 1,395,204 |
| | 1,337,545 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (1,673,194 | ) | | (1,805,641 | ) | | (1,662,835 | ) |
| Allowance for equity funds used during construction | | 74,023 |
| | 79,922 |
| | 51,485 |
|
| Insurance proceeds | | 7,040 |
| | 3,480 |
| | 5,305 |
|
| Nuclear fuel purchases | | (85,984 | ) | | (111,329 | ) | | (197,829 | ) |
| Proceeds from the sale of nuclear fuel | | 11,596 |
| | 53,603 |
| | 42,634 |
|
| Payments to storm reserve escrow account | | (6,353 | ) | | (4,770 | ) | | (2,110 | ) |
| Receipts from storm reserve escrow account | | — |
| | 4 |
| | 8,835 |
|
| Changes in securitization account | | (32 | ) | | (1,655 | ) | | 880 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 412,559 |
| | 1,055,690 |
| | 231,293 |
|
| Investment in nuclear decommissioning trust funds | | (442,501 | ) | | (1,097,204 | ) | | (266,592 | ) |
| Changes in money pool receivable - net | | 46,843 |
| | (35,672 | ) | | 11,330 |
|
| Proceeds from sale of assets | | — |
| | 11,987 |
| | — |
|
| Payment for purchase of assets | | — |
| | (26,623 | ) | | (9,805 | ) |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | 2,369 |
| | — |
| | — |
|
| Net cash flow used in investing activities | | (1,653,634 | ) | | (1,878,208 | ) | | (1,787,409 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 2,691,133 |
| | 2,319,799 |
| | 733,344 |
|
| Retirement of long-term debt | | (2,199,053 | ) | | (1,664,354 | ) | | (407,736 | ) |
| Change in money pool payable - net | | 82,826 |
| | — |
| | — |
|
| Changes in short-term borrowings - net | | — |
| | (43,540 | ) | | 39,746 |
|
| Distributions paid: | | |
| | |
| | |
|
| Common equity | | (208,000 | ) | | (128,000 | ) | | (91,250 | ) |
| Other | | 9,368 |
| | 6,556 |
| | (2,183 | ) |
| Net cash flow provided by financing activities | | 376,274 |
| | 490,461 |
| | 271,921 |
|
| Net increase (decrease) in cash and cash equivalents | | (41,358 | ) | | 7,457 |
| | (177,943 | ) |
| Cash and cash equivalents at beginning of period | | 43,364 |
| | 35,907 |
| | 213,850 |
|
| Cash and cash equivalents at end of period | |
| $2,006 |
| |
| $43,364 |
| |
| $35,907 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $296,842 |
| |
| $272,335 |
| |
| $266,871 |
|
| Income taxes | |
| $15,272 |
| |
| ($105,157 | ) | |
| ($234,199 | ) |
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2020 | | 2019 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $1,303 | | | $488 | |
| Temporary cash investments | | 726,717 | | | 1,518 | |
| Total cash and cash equivalents | | 728,020 | | | 2,006 | |
| | | | |
| Accounts receivable: | | | | |
| Customer | | 317,905 | | | 194,869 | |
| Allowance for doubtful accounts | | (45,693) | | | (1,902) | |
| Associated companies | | 81,624 | | | 77,212 | |
| Other | | 41,760 | | | 42,179 | |
| Accrued unbilled revenues | | 178,840 | | | 169,201 | |
| Total accounts receivable | | 574,436 | | | 481,559 | |
| | | | |
| Deferred fuel costs | | 2,250 | | | 0 | |
| Fuel inventory | | 50,680 | | | 41,613 | |
| Materials and supplies - at average cost | | 437,933 | | | 354,020 | |
| Deferred nuclear refueling outage costs | | 48,407 | | | 56,743 | |
| Prepaid taxes | | 0 | | | 7,959 | |
| | | | |
| Prepayments and other | | 36,813 | | | 37,837 | |
| TOTAL | | 1,878,539 | | | 981,737 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Investment in affiliate preferred membership interests | | 1,390,587 | | | 1,390,587 | |
| Decommissioning trust funds | | 1,794,042 | | | 1,563,812 | |
| Storm reserve escrow account | | 0 | | | 295,875 | |
| Non-utility property - at cost (less accumulated depreciation) | | 323,110 | | | 312,896 | |
| Other | | 13,399 | | | 13,476 | |
| TOTAL | | 3,521,138 | | | 3,576,646 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 25,619,789 | | | 22,620,365 | |
| Natural gas | | 262,744 | | | 235,678 | |
| | | | |
| Construction work in progress | | 667,281 | | | 1,383,603 | |
| Nuclear fuel | | 210,128 | | | 267,779 | |
| TOTAL UTILITY PLANT | | 26,759,942 | | | 24,507,425 | |
| Less - accumulated depreciation and amortization | | 9,372,224 | | | 9,118,524 | |
| UTILITY PLANT - NET | | 17,387,718 | | | 15,388,901 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets (includes securitization property of $5,088 as of December 31, 2020 and $27,596 as of December 31, 2019) | | 1,726,066 | | | 1,315,211 | |
| Deferred fuel costs | | 168,122 | | | 168,122 | |
| Other | | 23,924 | | | 33,491 | |
| TOTAL | | 1,918,112 | | | 1,516,824 | |
| | | | |
| TOTAL ASSETS | | $24,705,507 | | | $21,464,108 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $488 |
| |
| $252 |
|
| Temporary cash investments | | 1,518 |
| | 43,112 |
|
| Total cash and cash equivalents | | 2,006 |
| | 43,364 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 194,869 |
| | 199,903 |
|
| Allowance for doubtful accounts | | (1,902 | ) | | (1,813 | ) |
| Associated companies | | 77,212 |
| | 123,363 |
|
| Other | | 42,179 |
| | 60,879 |
|
| Accrued unbilled revenues | | 169,201 |
| | 167,052 |
|
| Total accounts receivable | | 481,559 |
| | 549,384 |
|
| Fuel inventory | | 41,613 |
| | 34,418 |
|
| Materials and supplies - at average cost | | 354,020 |
| | 324,627 |
|
| Deferred nuclear refueling outage costs | | 56,743 |
| | 24,406 |
|
| Prepaid taxes | | 7,959 |
| | — |
|
| Prepayments and other | | 37,837 |
| | 38,715 |
|
| TOTAL | | 981,737 |
| | 1,014,914 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Investment in affiliate preferred membership interests | | 1,390,587 |
| | 1,390,587 |
|
| Decommissioning trust funds | | 1,563,812 |
| | 1,284,996 |
|
| Storm reserve escrow account | | 295,875 |
| | 289,525 |
|
| Non-utility property - at cost (less accumulated depreciation) | | 312,896 |
| | 286,555 |
|
| Other | | 13,476 |
| | 14,927 |
|
| TOTAL | | 3,576,646 |
| | 3,266,590 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 22,620,365 |
| | 20,532,312 |
|
| Natural gas | | 235,678 |
| | 211,421 |
|
| Construction work in progress | | 1,383,603 |
| | 1,864,582 |
|
| Nuclear fuel | | 267,779 |
| | 298,022 |
|
| TOTAL UTILITY PLANT | | 24,507,425 |
| | 22,906,337 |
|
| Less - accumulated depreciation and amortization | | 9,118,524 |
| | 8,837,596 |
|
| UTILITY PLANT - NET | | 15,388,901 |
| | 14,068,741 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Other regulatory assets (includes securitization property of $27,596 as of December 31, 2019 and $49,753 as of December 31, 2018) | | 1,315,211 |
| | 1,105,077 |
|
| Deferred fuel costs | | 168,122 |
| | 168,122 |
|
| Other | | 33,491 |
| | 28,371 |
|
| TOTAL | | 1,516,824 |
| | 1,301,570 |
|
| | | | | |
| TOTAL ASSETS | |
| $21,464,108 |
| |
| $19,651,815 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2020 | | 2019 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $240,000 | | | $320,002 | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | 103,148 | | | 187,615 | |
| Other | | 1,450,008 | | | 357,206 | |
| Customer deposits | | 152,612 | | | 153,097 | |
| Taxes accrued | | 42,617 | | | 0 | |
| | | | |
| Interest accrued | | 92,249 | | | 87,744 | |
| Deferred fuel costs | | 0 | | | 55,645 | |
| | | | |
| | | | |
| | | | |
| Current portion of unprotected excess accumulated deferred income taxes | | 31,138 | | | 31,138 | |
| Other | | 62,968 | | | 64,668 | |
| TOTAL | | 2,174,740 | | | 1,257,115 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 2,138,522 | | | 2,464,513 | |
| Accumulated deferred investment tax credits | | 107,317 | | | 112,128 | |
| Regulatory liability for income taxes - net | | 447,628 | | | 500,083 | |
| Other regulatory liabilities | | 918,293 | | | 794,140 | |
| Decommissioning | | 1,573,307 | | | 1,497,349 | |
| Accumulated provisions | | 24,939 | | | 320,419 | |
| Pension and other postretirement liabilities | | 692,728 | | | 677,619 | |
| Long-term debt (includes securitization bonds of $10,278 as of December 31, 2020 and $33,220 as of December 31, 2019) | | 8,787,451 | | | 6,983,667 | |
| | | | |
| Other | | 382,894 | | | 459,957 | |
| TOTAL | | 15,073,079 | | | 13,809,875 | |
| | | | |
| Commitments and Contingencies | | 0 | | 0 |
| | | | |
| EQUITY | | | | |
| | | | |
Member’s equity | | 7,453,361 | | | 6,392,556 | |
| Accumulated other comprehensive income | | 4,327 | | | 4,562 | |
| TOTAL | | 7,457,688 | | | 6,397,118 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $24,705,507 | | | $21,464,108 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $320,002 |
| |
| $2 |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 187,615 |
| | 102,749 |
|
| Other | | 357,206 |
| | 390,367 |
|
| Customer deposits | | 153,097 |
| | 155,314 |
|
| Taxes accrued | | — |
| | 30,868 |
|
| Interest accrued | | 87,744 |
| | 83,450 |
|
| Deferred fuel costs | | 55,645 |
| | 31,411 |
|
| Current portion of unprotected excess accumulated deferred income taxes | | 31,138 |
| | 31,457 |
|
| Other | | 64,668 |
| | 49,202 |
|
| TOTAL | | 1,257,115 |
| | 874,820 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 2,464,513 |
| | 2,226,721 |
|
| Accumulated deferred investment tax credits | | 112,128 |
| | 116,999 |
|
| Regulatory liability for income taxes - net | | 500,083 |
| | 581,001 |
|
| Other regulatory liabilities | | 794,140 |
| | 748,784 |
|
| Decommissioning | | 1,497,349 |
| | 1,280,272 |
|
| Accumulated provisions | | 320,419 |
| | 310,755 |
|
| Pension and other postretirement liabilities | | 677,619 |
| | 643,171 |
|
| Long-term debt (includes securitization bonds of $33,220 as of December 31, 2019 and $55,682 as of December 31, 2018) | | 6,983,667 |
| | 6,805,766 |
|
| Other | | 459,957 |
| | 160,608 |
|
| TOTAL | | 13,809,875 |
| | 12,874,077 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| EQUITY | | |
| | |
|
| Member’s equity | | 6,392,556 |
| | 5,909,071 |
|
| Accumulated other comprehensive income (loss) | | 4,562 |
| | (6,153 | ) |
| TOTAL | | 6,397,118 |
| | 5,902,918 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $21,464,108 |
| |
| $19,651,815 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2020, 2019, and 2018 |
| | | | | |
| | | | Common Equity | | |
| | | | Member’s Equity | | Accumulated Other Comprehensive Income (Loss) | | Total |
| | | (In Thousands) |
| | | | | | | |
| Balance at December 31, 2017 | | | $5,355,204 | | | ($46,400) | | | $5,308,804 | |
| Net income | | | 675,614 | | | 0 | | | 675,614 | |
| | | | | | | |
| Other comprehensive income | | | 0 | | | 50,296 | | | 50,296 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Distributions declared on common equity | | | (128,000) | | | 0 | | | (128,000) | |
| | | | | | | |
| Reclassification pursuant to ASU 2018-02 | | | 6,262 | | | (10,049) | | | (3,787) | |
| Other | | | (9) | | | 0 | | | (9) | |
| Balance at December 31, 2018 | | | $5,909,071 | | | ($6,153) | | | $5,902,918 | |
| Net income | | | 691,537 | | | 0 | | | 691,537 | |
| | | | | | | |
| Other comprehensive income | | | 0 | | | 10,715 | | | 10,715 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Distributions declared on common equity | | | (208,000) | | | 0 | | | (208,000) | |
| | | | | | | |
| | | | | | | |
| Other | | | (52) | | | 0 | | | (52) | |
| Balance at December 31, 2019 | | | $6,392,556 | | | $4,562 | | | $6,397,118 | |
| Net income | | | 1,082,352 | | | 0 | | | 1,082,352 | |
| Other comprehensive loss | | | 0 | | | (235) | | | (235) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Distributions declared on common equity | | | (21,500) | | | 0 | | | (21,500) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Other | | | (47) | | | 0 | | | (47) | |
| Balance at December 31, 2020 | | | $7,453,361 | | | $4,327 | | | $7,457,688 | |
| | | | | | | |
| See Notes to Financial Statements. | | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2019, 2018, and 2017 |
| | | | | |
| | | Common Equity | | |
| | | Member’s Equity | | Accumulated Other Comprehensive Income (Loss) | | Total |
| | (In Thousands) |
| | | | | | | |
| 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 |
|
| Net income | | 675,614 |
| | — |
| | 675,614 |
|
| Other comprehensive income | | — |
| | 50,296 |
| | 50,296 |
|
| Distributions declared on common equity | | (128,000 | ) | | — |
| | (128,000 | ) |
| Reclassification pursuant to ASU 2018-02 | | 6,262 |
| | (10,049 | ) | | (3,787 | ) |
| Other | | (9 | ) | | — |
| | (9 | ) |
| Balance at December 31, 2018 | |
| $5,909,071 |
| |
| ($6,153 | ) | |
| $5,902,918 |
|
| Net income | | 691,537 |
| | — |
| | 691,537 |
|
| Other comprehensive income | | — |
| | 10,715 |
| | 10,715 |
|
| Distributions declared on common equity | | (208,000 | ) | | — |
| | (208,000 | ) |
| Other | | (52 | ) | | — |
| | (52 | ) |
| Balance at December 31, 2019 | |
| $6,392,556 |
| |
| $4,562 |
| |
| $6,397,118 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | |
| | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | (In Thousands) |
| | | | | | | | | |
| Operating revenues | $4,069,862 | | | $4,285,175 | | | $4,296,320 | | | $4,300,550 | | | $4,177,048 | |
| Net income | $1,082,352 | | | $691,537 | | | $675,614 | | | $316,347 | | | $622,047 | |
| Total assets | $24,705,507 | | | $21,464,108 | | | $19,651,815 | | | $18,448,864 | | | $17,701,271 | |
| Long-term obligations (a) | $8,787,451 | | | $6,983,667 | | | $6,805,766 | | | $5,469,069 | | | $5,612,593 | |
| | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt). | | | | |
| | | | | | | | | |
| | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | (Dollars In Millions) |
| | | | | | | | | |
| Electric Operating Revenues: | | | | | | | | | |
| Residential | $1,270 | | | $1,271 | | | $1,244 | | | $1,198 | | | $1,196 | |
| Commercial | 887 | | | 947 | | | 941 | | | 956 | | | 930 | |
| Industrial | 1,314 | | | 1,451 | | | 1,462 | | | 1,534 | | | 1,350 | |
| Governmental | 69 | | | 71 | | | 69 | | | 69 | | | 67 | |
| Total billed retail | 3,540 | | | 3,740 | | | 3,716 | | | 3,757 | | | 3,543 | |
| Sales for resale: | | | | | | | | | |
| Associated companies | 276 | | | 273 | | | 295 | | | 278 | | | 368 | |
| Non-associated companies | 58 | | | 60 | | | 62 | | | 64 | | | 50 | |
| Other | 145 | | | 150 | | | 160 | | | 147 | | | 165 | |
| Total | $4,019 | | | $4,223 | | | $4,233 | | | $4,246 | | | $4,126 | |
| | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | |
| Residential | 13,771 | | | 14,046 | | | 14,494 | | | 13,357 | | | 13,810 | |
| Commercial | 10,465 | | | 11,353 | | | 11,578 | | | 11,342 | | | 11,478 | |
| Industrial | 28,881 | | | 29,801 | | | 29,255 | | | 29,754 | | | 28,517 | |
| Governmental | 779 | | | 827 | | | 823 | | | 790 | | | 794 | |
| Total retail | 53,896 | | | 56,027 | | | 56,150 | | | 55,243 | | | 54,599 | |
| Sales for resale: | | | | | | | | | |
| Associated companies | 5,585 | | | 4,813 | | | 5,498 | | | 4,793 | | | 7,345 | |
| Non-associated companies | 2,365 | | | 1,924 | | | 1,762 | | | 1,711 | | | 1,690 | |
| Total | 61,846 | | | 62,764 | | | 63,410 | | | 61,747 | | | 63,634 | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $4,285,175 |
| |
| $4,296,320 |
| |
| $4,300,550 |
| |
| $4,177,048 |
| |
| $4,417,146 |
|
| Net income |
| $691,537 |
| |
| $675,614 |
| |
| $316,347 |
| |
| $622,047 |
| |
| $446,639 |
|
| Total assets |
| $21,464,108 |
| |
| $19,651,815 |
| |
| $18,448,864 |
| |
| $17,701,271 |
| |
| $16,387,447 |
|
| Long-term obligations (a) |
| $6,983,667 |
| |
| $6,805,766 |
| |
| $5,469,069 |
| |
| $5,612,593 |
| |
| $4,806,790 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt). | | | | |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $1,271 |
| |
| $1,244 |
| |
| $1,198 |
| |
| $1,196 |
| |
| $1,292 |
|
| Commercial | 947 |
| | 941 |
| | 956 |
| | 930 |
| | 989 |
|
| Industrial | 1,451 |
| | 1,462 |
| | 1,534 |
| | 1,350 |
| | 1,420 |
|
| Governmental | 71 |
| | 69 |
| | 69 |
| | 67 |
| | 67 |
|
| Total billed retail | 3,740 |
| | 3,716 |
| | 3,757 |
| | 3,543 |
| | 3,768 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 273 |
| | 295 |
| | 278 |
| | 368 |
| | 406 |
|
| Non-associated companies | 60 |
| | 62 |
| | 64 |
| | 50 |
| | 36 |
|
| Other | 150 |
| | 160 |
| | 147 |
| | 165 |
| | 152 |
|
| Total |
| $4,223 |
| |
| $4,233 |
| |
| $4,246 |
| |
| $4,126 |
| |
| $4,362 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | |
| | |
| | |
| | |
| | |
|
| Residential | 14,046 |
| | 14,494 |
| | 13,357 |
| | 13,810 |
| | 14,399 |
|
| Commercial | 11,353 |
| | 11,578 |
| | 11,342 |
| | 11,478 |
| | 11,700 |
|
| Industrial | 29,801 |
| | 29,255 |
| | 29,754 |
| | 28,517 |
| | 27,713 |
|
| Governmental | 827 |
| | 823 |
| | 790 |
| | 794 |
| | 756 |
|
| Total retail | 56,027 |
| | 56,150 |
| | 55,243 |
| | 54,599 |
| | 54,568 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 4,813 |
| | 5,498 |
| | 4,793 |
| | 7,345 |
| | 7,500 |
|
| Non-associated companies | 1,924 |
| | 1,762 |
| | 1,711 |
| | 1,690 |
| | 770 |
|
| Total | 62,764 |
| | 63,410 |
| | 61,747 |
| | 63,634 |
| | 62,838 |
|
| | | | | | | | | | |
ENTERGY MISSISSIPPI, LLC
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19” Pandemic section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Mississippi’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $50 million to $60 million. Natural gas purchases for Entergy Mississippi for February 1st through 25th, 2021 are approximately $45 million compared to natural gas purchases for February 2020 of $14 million.
Results of Operations
20192020 Compared to 20182019
Net Income
Net income decreased $6.2increased $20.7 million primarily due to higher retail electric price, partially offset by higher depreciation and amortization expenses, higher other operation and maintenance expenses, and lower volume/weather, and a higher effective income tax rate, partially offset by higher retail electric price.weather.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 20192020 to 2018.
|
| | | | |
| Amount |
| (In Millions) |
20182019 operating revenues |
| $1,335.1 |
|
| Fuel, rider, and other revenues that do not significantly affect net income | (51.6(153.2) | ) |
| Volume/weather | (15.9(17.6) | ) |
Return of unprotected excess accumulated deferred income taxes to customers | 25.8 |
|
| Retail electric price | 29.695.7 |
|
20192020 operating revenues |
| $1,323.0 |
|
Entergy Mississippi’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The volume/weather variance is primarily due to decreased commercial and industrial usage as a decreaseresult of 455 GWh, or 3%, in billed electricity usage, includingthe COVID-19 pandemic and the effect of less favorable weather on residential sales, andpartially offset by increased residential usage as a decrease in industrial usage. The decrease in industrial usage is primarily due to decreased small industrial sales.
The return of unprotected excess accumulated deferred income taxes to customers is due to the return of unprotected excess accumulated deferred income taxes through customer bill credits over a three-month period from July 2018 through September 2018 per an agreement approved by the MPSC in June 2018 resulting from the stipulation related to the effectsresult of the Tax CutsCOVID-19 pandemic. See “The COVID-19 Pandemic” section of Entergy Corporation and Jobs Act. There was no effect on net income as the reduction in operating revenues was offset by a reduction in income tax expense. See Note 2 to the financial statementsSubsidiaries Management’s Financial Discussion and Analysis for further discussion of regulatory activity regarding the Tax CutsCOVID-19 pandemic.
Entergy Mississippi, LLC
Management’s Financial Discussion and Jobs Act.Analysis
The retail electric price variance is primarily due to an increaseto:
•increases in the formula rate plan rates effective with the first billing cyclecycles of July 2019 and April 2020 and an accrual in the fourth quarter 2019 for the interim capacity rate adjustment to the formula rate plan effective January 2020 to recover non-fuel related costs associated with the acquisition of acquiring and operating the Choctaw Generating Station, each as approved by Station; and
•the MPSC. Entergy Mississippi beganimplementation of a vegetation management rider effective with the April 2020 billing the interim capacity rate adjustment in January 2020. cycle.
See Note 2 to the financial statements for further discussion of the formula rate plan filingfilings and the interim capacity rate adjustment.vegetation management rider.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
Other Income Statement Variances
Other operation and maintenance expenses increased primarily due to:
| |
• | an increase of $4.7 million in spending on initiatives to explore new customer products and services; and
|
an increase of $4.6$13.5 million in information technology costsnon-nuclear generation expenses primarily due to an increase in costs after the purchase of the Choctaw Generating Station in October 2019, partially offset by a decrease of $11.1 million primarily due to a lower scope of work performed during plant outages in 2020 as compared to the same period in 2019, including a delay in plant outages as a result of the COVID-19 pandemic;
•an increase of $8.1 million in storm damage provisions. See Note 2 to the financial statements for a discussion of storm cost recovery;
•an increase of $4.7 million in distribution operations costs due to a higher scope of work, including contract costs relatedin 2020 as compared to applicationsthe same period in 2019;
•an increase of $2.5 million in energy efficiency costs due to the timing of recovery from customers; and infrastructure support, enhanced cyber security, and upgrades and maintenance.
•several individually insignificant items.
The increase was partially offset by a $5.8decrease of $3.7 million lossprimarily due to contract costs in 2018 on the sale of fuel oil inventory per an agreement approved by the MPSC in June 2018 resulting from the stipulation2019 related to the effects of the Tax Act. There is no effect on net income as the loss on the sale of fuel oil inventory is offset by a reduction in income tax expense.initiatives to explore new customer products and services.
Depreciation and amortization expenses increased primarily as a result of higher depreciation rates effective July 2019, as approved by the MPSC, and additions to plant in service.service, including the Choctaw Generating Station, which was purchased in October 2019.
Other regulatory charges include a regulatory charge recorded in second quarter 2018 to reflect the return of unprotected excess accumulated deferred income taxes per an agreement approved by the MPSC in June 2018 that resulted in a reduction in net utility plant of $127.2 million. There was no effect on net income as the regulatory charge was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity related to the Tax Cuts and Jobs Act.
Interest expense increased primarily due to issuances of $300 million in June 2019 and $135 million in November 2019, of 3.85% Series mortgage bonds and the issuance of $55 million of 4.52% Series mortgage bonds in December 2018, partially offset by the repayment, at maturity, of $150 million of 6.64% Series mortgage bonds in July 2019. See Note 5 to the financial statements for details on long-term debt.
The effective income tax rates were 16.2% for 2020 and 20.5% for 2019 and (41,237%) for 2018. The difference in the effective income tax rate of (41,237%) versus the federal statutory rate of 21% for 2018 was primarily due to the flow through of excess accumulated deferred income taxes.2019. See Note 3 to the financial statements for a reconciliation of the federal statutory raterates of 21% to the effective income tax rates.
20182019 Compared to 20172018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Mississippi’s Annual Report on Form 10-K for the year ended December 31, 20182019, filed with the SEC on February 21, 2020, for discussion of results of operations for 20182019 compared to 2017.2018.
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, 2018, and 2019 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 the regulatory proceedings that have considered the effects of the Act.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, 2018, and 20172018 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $51,601 | | | $36,954 | | | $6,096 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 300,314 | | | 339,952 | | | 418,382 | |
| Investing activities | (530,762) | | | (733,684) | | | (419,453) | |
| Financing activities | 178,865 | | | 408,379 | | | 31,929 | |
| Net increase (decrease) in cash and cash equivalents | (51,583) | | | 14,647 | | | 30,858 | |
| | | | | |
| Cash and cash equivalents at end of period | $18 | | | $51,601 | | | $36,954 | |
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $36,954 |
| |
| $6,096 |
| |
| $76,834 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 339,952 |
| | 418,382 |
| | 226,585 |
|
| Investing activities | (733,684 | ) | | (419,453 | ) | | (417,226 | ) |
| Financing activities | 408,379 |
| | 31,929 |
| | 119,903 |
|
| Net increase (decrease) in cash and cash equivalents | 14,647 |
| | 30,858 |
| | (70,738 | ) |
| | | | | | |
| Cash and cash equivalents at end of period |
| $51,601 |
| |
| $36,954 |
| |
| $6,096 |
|
20192020 Compared to 20182019
Operating Activities
Net cash flow provided by operating activities decreased $78.4$39.6 million in 20192020 primarily due to:
•the timing of collectionrecovery of fuel and purchased power;
•lower collections of receivables from customers;
the receipt of $36.2 million from Entergy Arkansas as a result of a compliance filing madecustomers, in responsepart due to the FERC’s October 2018 order in the Entergy Arkansas opportunity sales proceeding. See Note 2 to the financial statements for further discussionCOVID-19 pandemic; and
•an increase of the opportunity sales proceeding; and
$26.2$10.3 million in proceeds from the sale of fuel oil inventorystorm spending in 2018.2020.
The decrease was partially offset by the timing of recoverypayments to vendors and a decrease of fuel$8.2 million in pension contributions in 2020. See “Critical Accounting Estimates” below and purchased power costs and the return of unprotected excess accumulated deferred income taxes to customers in 2018. See Note 211 to the financial statements for furthera discussion of regulatory activity regarding the Tax Cutsqualified pension and Jobs Act.other postretirement benefits funding.
Investing Activities
Net cash flow used in investing activities increased $314.2decreased $202.9 million in 20192020 primarily due to:
•the purchase of the Choctaw Generating Station in October 2019 for approximately $305 million. See Note 14 to the financial statements for further discussion of the Choctaw Generating Station purchase; and
•money pool activity.
The decrease was partially offset by:
•an increase of $34.9$47.3 million in storm spending in 2020;
•an increase of $40.9 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Mississippi’s distribution system, including increased spending on advanced metering infrastructure; and
•an increase of $15.6$25.8 million in storm spendingnon-nuclear construction expenditures primarily due to increased expenditures after the purchase of the Choctaw Generating Station in 2019.October 2019 and higher long-term service agreement expenses;
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
•an increase was partially offset by money pool activity.of $22.4 million in transmission construction expenditures primarily due to a higher scope of work performed in 2020 as compared to 2019.
IncreasesDecreases in Entergy Mississippi’s receivable from the money pool are a usesource of cash flow, and Entergy Mississippi’s receivable from the money pool increaseddecreased by $44.7 million in 2020 compared to increasing by $3.3 million in 2019 compared to increasing by $39.7 million in 2018.2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
Financing Activities
Net cash flow provided by financing activities increased $376.5decreased $229.5 million in 20192020 primarily due to:
•the issuance of $170 million of 3.5% Series mortgage bonds in 2020 compared to the issuance of $435 million of 3.85% Series mortgage bonds in 2019 compared to the issuance of $55 million of 4.52% Series mortgage bonds 2018;2019; and
•a capital contribution of $130 million in October 2019 in anticipation of the purchase of the Choctaw Generating Station in October 2019; andStation.
the redemption of $20 million of preferred stock in 2018 in connection with the internal restructuring. See Note 2 to the financial statements for further discussion of the internal restructuring and Note 6 to the financial statements for details of preferred stock activity.
The increasedecrease was partially offset by the repayment, at maturity, of $150 million of 6.64% Series mortgage bonds in July 2019.2019 and money pool activity.
Increases in Entergy Mississippi’s payable to the money pool are a source of cash flow, and Entergy Mississippi’s payable to the money pool increased $16.5 million in 2020.
See Note 5 to the financial statements for details on long-term debt.
20182019 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Mississippi’s Annual Report on Form 10-K for the year ended December 31, 20182019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 20182019 compared to 2017.2018.
Capital Structure
Entergy Mississippi’s debt to capital ratio is shown in the following table.
| | | | | | | | | | | |
| | December 31,
2020 | | December 31,
2019 |
| Debt to capital | 51.7 | % | | 51.2 | % |
| Effect of subtracting cash | — | % | | (0.8 | %) |
| Net debt to net capital | 51.7 | % | | 50.4 | % |
|
| | | | | |
| | December 31,
2019 | | December 31,
2018 |
| Debt to capital | 51.2 | % | | 50.6 | % |
| Effect of subtracting cash | (0.8 | %) | | (0.7 | %) |
| Net debt to net capital | 50.4 | % | | 49.9 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and 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.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
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 distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Mississippi may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Mississippi may receive equity contributions to maintain its capital structure.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
Uses of Capital
Entergy Mississippi 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
•distributions and interest payments.
Following are the amounts of Entergy Mississippi’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2022 | | 2023 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $180 | | | $140 | | | $180 | |
| Transmission | 120 | | | 75 | | | 55 | |
| Distribution | 210 | | | 200 | | | 225 | |
| Utility Support | 80 | | | 85 | | | 30 | |
| Total | $590 | | | $500 | | | $490 | |
|
| | | | | | | | | | | |
| | 2020 | | 2021 | | 2022 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $110 |
| |
| $285 |
| |
| $85 |
|
| Transmission | 130 |
| | 125 |
| | 90 |
|
| Distribution | 150 |
| | 115 |
| | 95 |
|
| Utility Support | 145 |
| | 130 |
| | 135 |
|
| Total |
| $535 |
| |
| $655 |
| |
| $405 |
|
Following are the amounts of Entergy Mississippi’s existing debt obligations and lease obligations (includes estimated interest payments) and other purchase obligations.
|
| | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $59 |
| |
| $118 |
| |
| $455 |
| |
| $2,301 |
| |
| $2,933 |
|
| Operating leases (b) |
| $6 |
| |
| $9 |
| |
| $2 |
| |
| $2 |
| |
| $19 |
|
| Finance leases (b) |
| $2 |
| |
| $3 |
| |
| $2 |
| |
| $1 |
| |
| $8 |
|
| Purchase obligations (c) |
| $266 |
| |
| $502 |
| |
| $477 |
| |
| $4,444 |
| |
| $5,689 |
|
| |
(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) | 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. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| | (In Millions) |
| Long-term debt (a) | $65 | | | $376 | | | $209 | | | $2,575 | | | $3,225 | |
| Operating leases (b) | $6 | | | $8 | | | $2 | | | $2 | | | $18 | |
| Finance leases (b) | $2 | | | $3 | | | $2 | | | $1 | | | $8 | |
| Purchase obligations (c) | $223 | | | $434 | | | $412 | | | $3,779 | | | $4,848 | |
(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)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 $7.8$13.7 million to its qualified pension plans and approximately $130 thousand to other postretirement health care and life insurance plans in 2020,2021, although the 20202021 required pension contributions will be known with more certainty when the January 1, 20202021 valuations are completed, which is expected by April 1, 2020.2021. See
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
“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 $59.3$84 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 the Sunflower Solar Facility;
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; software and security; 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.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Mississippi pays distributions from its earnings at a percentage determined monthly.
Sunflower Solar Facility
In November 2018, Entergy Mississippi announced that it signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. The estimated base purchase price is approximately $138.4 million. The estimated total investment, including the base purchase price and other related costs, for Entergy Mississippi to acquire the Sunflower Solar Facility is approximately $153.2 million. The purchase is contingent upon, among other things, obtaining necessary approvals, including full cost recovery, from applicable federal and state regulatory and permitting agencies. The project will beis being built by Sunflower County Solar Project, LLC, a sub-subsidiaryan indirect subsidiary of Recurrent Energy, LLC. Entergy Mississippi will purchase the facility upon mechanical completion and after the other purchase contingencies have been met. In December 2018, Entergy Mississippi filed a joint petition with Sunflower Solar Project atwith the MPSC for Sunflower Solar Project to construct and for Entergy Mississippi to acquire and thereafter own, operate, improve, and maintain the solar facility. Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism, the interim capacity rate adjustment mechanism, in the formula rate plan to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi, including the annual ownership costs of the Sunflower Solar Facility. In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for an interim capacity rate adjustment mechanism. The MPSC must approve recoveryRecovery through the interim capacity rate adjustment requires MPSC approval for each new resource. In August 2019 consultants retained by the Mississippi Public Utilities Staff filed a report expressing concerns regarding the project economics and recommended that, should the MPSC wish to approve the project,economics. In March 2020, Entergy Mississippi should be required to guaranteefiled supplemental testimony addressing questions and observations raised by the energy output ofconsultants retained by the unit. Entergy Mississippi Public Utilities Staff and proposing an alternative structure for the Staff are engaged in settlement discussions to address these concerns.transaction that would reduce its cost. A hearing before the MPSC was held in March 2020. In April 2020 the MPSC issued an order approving certification of the Sunflower Solar Facility and its recovery through the interim capacity rate adjustment mechanism, subject to certain conditions including: (i) that Entergy Mississippi pursue a partnership structure through which the partnership would acquire and own the facility under the build-own-transfer agreement and (ii) that if Entergy Mississippi does not consummate the partnership structure under the terms of the order, there will be a cap of $136 million on the level of recoverable costs. Closing is targeted to occur by the second quarter of 2020. Closing is expected to occur by the end of 2021.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
Sources of Capital
Entergy Mississippi’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•storm reserve escrow accounts;
•debt or preferred membership interest issuances;issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Mississippi may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
All debt and preferred membership interest issuances by Entergy Mississippi require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indenture and other agreements. Entergy Mississippi has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Mississippi, LLC
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.
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | | 2017 |
| (In Thousands) |
| ($16,516) | | $44,693 | | $41,380 | | $1,633 |
|
| | | | | | |
| 2019 | | 2018 | | 2017 | | 2016 |
| (In Thousands) |
| $44,693 | | $41,380 | | $1,633 | | $10,595 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Mississippi has three separate credit facilities in the aggregate amount of $82.5 million scheduled to expire in May 2020.April 2021. No borrowings were outstanding under the credit facilities as of December 31, 2019.2020. In addition, Entergy Mississippi is a party to an uncommitted letter of credit facility primarily as a means to post collateral to support its obligations to MISO. As of December 31, 2019, $1.82020, $1 million of MISO letters of credit and $1 million of non-MISO letters of credit were outstanding under Entergy Mississippi’s uncommitted letter of creditthis facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy Mississippi obtained authorization from the FERC through November 2020July 2022 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 $33 million in its storm reserve escrow account at December 31, 2020.
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.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
Formula Rate Plan Filings
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 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.
In March 2018, Entergy Mississippi submitted its formula rate plan 2018 test year filing and 2017 look-back filing showing Entergy Mississippi’s earned return for the historical 2017 calendar year and projected earned return for the 2018 calendar year, in large part as a result of the lower federal corporate income tax rate effective in 2018, to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2018, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy Mississippi’s earned returns for both the 2017 look-back filing and 2018 test year were within the respective formula rate plan bandwidths. In June 2018 the MPSC approved the stipulation, which resulted in no change in rates.
In October 2018, Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism in the formula rate plan, the interim capacity rate adjustment mechanism, to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi, including the non-fuel annual ownership costs of the Choctaw Generating Station, as well as to allow similar cost recovery treatment for other future capacity acquisitions, such as the Sunflower Solar Facility, that are approved by the MPSC. In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for an interim capacity rate adjustment mechanism to recover the $59 million first-year annual revenue requirement associated with the non-fuel ownership costs of the Choctaw Generating Station, which Entergy Mississippi began billing in January 2020. The MPSC must approve recovery through the interim
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
capacity rate adjustment for each new resource. In addition, the MPSC approved revisions to the formula rate plan which allows Entergy Mississippi to begin billing rate adjustments effective April 1 of the filing year on a temporary basis subject to refund or credit to customers, subject to final MPSC order. The MPSC also authorized Entergy Mississippi to remove vegetation management costs from the formula rate plan and recover these costs through the establishment of a vegetation management rider. Effective with the April 2020 billing cycle, Entergy Mississippi implemented a rider to recover $22 million in vegetation management costs.
In March 2019, Entergy Mississippi submitted its formula rate plan 2019 test year filing and 2018 look-back filing showing Entergy Mississippi’s earned return for the historical 2018 calendar year to be above the formula rate plan bandwidth and projected earned return for the 2019 calendar year to be below the formula rate plan bandwidth. The 2019 test year filing shows a $36.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.94% return on rate base, within the formula rate plan bandwidth. The 2018 look-back filing compares actual 2018 results to the approved benchmark return on rate base and shows a $10.1 million interim decrease in formula rate plan revenues is necessary. In the fourth quarter 2018, Entergy Mississippi recorded a provision of $9.3 million that reflected the estimate of the difference between the 2018 expected earned rate of return on rate base and an established performance-adjusted benchmark rate of return under the formula rate plan performance-adjusted bandwidth mechanism. In the first quarter 2019, Entergy Mississippi recorded a $0.8 million increase in the provision to reflect the amount shown in the look-back filing. In June 2019, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed that the 2019 test year filing showed that a $32.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.93% return on rate base, within the formula rate plan bandwidth. Additionally, pursuant to the joint stipulation, Entergy Mississippi’s 2018 look-back filing reflected an earned return on rate base of 7.81% in calendar year 2018 which is above the look-back benchmark return on rate base of 7.13%, resulting in an $11 million decrease in formula rate plan revenues on an interim basis through May 2020. In the second quarter 2019, Entergy Mississippi recorded an additional $0.9 million increase in the provision to reflect the $11 million shown in the look-back filing. In June 2019 the MPSC approved the joint stipulation with rates effective for the first billing cycle of July 2019.
In March 2020, Entergy Mississippi submitted its formula rate plan 2020 test year filing and 2019 look-back filing showing Entergy Mississippi’s earned return for the historical 2019 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2020 calendar year to be below the formula rate plan bandwidth. The 2020 test year filing shows a $24.6 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.51% return on rate base, within the formula rate plan bandwidth. The 2019 look-back filing compares actual 2019 results to the approved benchmark return on rate base and reflects the need for a $7.3 million interim increase in formula rate plan revenues. In accordance with the MPSC-approved revisions to the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2019 retail revenues, effective with the April 2020 billing cycle, subject to refund. In June 2020, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed that the 2020 test year filing showed that a $23.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
adjustment of 6.51% return on rate base, within the formula rate plan bandwidth. Pursuant to the joint stipulation, Entergy Mississippi’s 2019 look-back filing reflected an earned return on rate base of 6.75% in calendar year 2019, which is within the look-back bandwidth. As a result, there is no change in formula rate plan revenues in the 2019 look-back filing. In June 2020 the MPSC approved the joint stipulation with rates effective for the first billing cycle of July 2020. In the June 2020 order the MPSC directed Entergy Mississippi to submit revisions to its formula rate plan to realign recovery of costs from its energy efficiency cost recovery rider to its formula rate plan. In November 2020 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan providing for the realignment of energy efficiency costs to its formula rate plan, the deferral of energy efficiency expenditures into a regulatory asset, and the elimination of its energy efficiency cost recovery rider effective with the January 2022 billing cycle.
COVID-19 Order
In March 2020 the MPSC issued an order suspending disconnections for a period of sixty days. The MPSC extended the order on disconnections through May 26, 2020. In April 2020 the MPSC issued an order authorizing utilities to defer incremental costs and expenses associated with COVID-19 compliance and to seek future recovery through rates of the prudently incurred incremental costs and expenses. In December 2020, Entergy Mississippi resumed disconnections for commercial, industrial, and governmental customers with past-due balances that have not made payment arrangements. In January 2021, Entergy Mississippi resumed disconnecting service for residential customers with past-due balances that have not made arrangements. As of December 31, 2020, Entergy Mississippi recorded a regulatory asset of $19.2 million for costs associated with the COVID-19 pandemic.
Internal Restructuring
In March 2018, Entergy Mississippi filed an application with the MPSC seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy Mississippi to a new entity, which would ultimately be held by an existing Entergy subsidiary holding company. In September 2018, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed a joint stipulation regarding the restructuring filing. In September 2018 the MPSC issued an order accepting the stipulation in its entirety and approving the restructuring and credits of $27 million to retail customers over six years, consisting of annual payments of $4.5 million for the years 2019-2024. Entergy Mississippi also received the required FERC approval.
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light 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 Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
In December 2018, Entergy Mississippi filed its notice of intent to implement the restructuring credit rider to allow Entergy Mississippi to return credits of $27 million to retail customers over six years. In January 2019 the MPSC approved the proposed restructuring credit adjustment factor, which is effective for bills rendered beginning February 2019.
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 and identified a number of quantified and unquantified benefits. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which began in 2019. Deployment of the communications network began 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. In June 2018, as part of the order approving the joint stipulation between the Mississippi Public Utilities Staff and Entergy Mississippi addressing Entergy Mississippi’s 2018 formula rate plan evaluation report and the ratemaking effects of the Tax Act, the MPSC approved the acceleration of the recovery of substantially all of Entergy Mississippi’s existing customer meters in anticipation of AMI deployment.
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.
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 November 2017 the Mississippi Public Utilities Staff separately engaged a consultant to review the September 2016 outage at the Grand Gulf Nuclear Station and to review ongoing operations at Grand Gulf. This engagement continues, and subsequently, was expanded to include all outages at Grand Gulf that occurred through 2019.
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. In January 2018 the MPSC approved the proposed energy cost factors effective for February 2018 bills.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
In November 2018, 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 $57 million as of September 30, 2018. In January 2019 the MPSC approved the proposed energy cost factor effective for February 2019 bills.
In November 2019, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation included $39.6 million of prior over-recovery flowing back to customers beginning September 2020. Entergy Mississippi’s balance in its deferred fuel account did not decrease as expected after implementation of the new factor. In an effort to assist customers during the COVID-19 pandemic, in May 2020, Entergy Mississippi requested an interim adjustment to the energy cost recovery rider to credit approximately $50 million from the over-recovered balance in the deferred fuel account to customers over four consecutive billing months. The MPSC approved this interim adjustment in May 2020 effective for June through September 2020 bills.
In November 2020, 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 approximately $39.6$24.4 million as of September 30, 2019.2020. In January 20202021 the MPSC approved the proposed energy cost factor effective for February 20202021 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. In June 2010 the MPSC authorized the deferral of certain legal expenses associated with this litigation until it is resolved. As of December 31, 2019, Entergy Mississippi has a regulatory asset of $29.5 million for these deferred legal expenses. In April 2019 the District Court remanded the Attorney General’s lawsuit to the Hinds County Chancery Court. A hearing on procedural and dispositive motions was held in August 2019. In December 2019 the Hinds County Chancery Court issued its ruling granting the motion for summary judgment filed by the Entergy defendants. The Chancery Court found it lacked subject matter jurisdiction and that the claims fall under the purview of the FERC. In February 2020 the Chancery Court entered a final order dismissing all claims. The order was approved by counsel for the Attorney General, and dismisses with prejudice all claims and matters in dispute and states that the plaintiff will not seek an appeal or further relief and that all matters in dispute have been resolved.
Storm Cost Recovery Filings with Retail Regulators
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 July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision wasbalance has been less than $10 million thereforesince May 2019, and Entergy Mississippi resumedhas been billing the monthly storm damage provision effective with September 2017 bills. Assince July 2019.
Entergy Mississippi, resumed billing the monthly storm damage provision effective with July 2019 bills.LLC
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
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
Entergy Mississippi, LLC
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, 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.
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, LLC
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.
Entergy Mississippi, LLC
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 2021 Qualified Pension Cost | | Impact on 2020 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $654 | | $12,777 |
| Rate of return on plan assets | | (0.25%) | | $828 | | $— |
| Rate of increase in compensation | | 0.25% | | $533 | | $2,720 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Qualified Pension Cost | | Impact on 2019 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $719 | | $11,678 |
| Rate of return on plan assets | | (0.25%) | | $823 | | $— |
| Rate of increase in compensation | | 0.25% | | $483 | | $2,529 |
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 2021 Postretirement Benefit Cost | | Impact on 2020 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $59 | | $1,970 |
| Health care cost trend | | 0.25% | | $73 | | $1,402 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Postretirement Benefit Cost | | Impact on 2019 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $29 | | $1,939 |
| Health care cost trend | | 0.25% | | $81 | | $1,456 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Mississippi in 20192020 was $11.3 million.$20.2 million, including $3.4 million in settlement costs. Entergy Mississippi anticipates 20202021 qualified pension cost to be $17.4$19.6 million. Entergy Mississippi contributed $20.8$12.6 million to its qualified pension plans in 20192020 and estimates 20202021 pension contributions will be approximately $7.8$13.7 million, although the 20202021 required pension contributions will be known with more certainty when the January 1, 20202021 valuations are completed, which is expected by April 1, 2020.2021.
Total postretirement health care and life insurance benefit income for Entergy Mississippi in 20192020 was $2.1$3.6 million. Entergy Mississippi expects 20202021 postretirement health care and life insurance benefit income of approximately $3.1 thousand.$4.7 million. Entergy Mississippi contributed $228$343 thousand to its other postretirement plans in 20192020 and estimates that 20202021 contributions will be approximately $130 thousand.
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 Mississippi, LLC
Management’s Financial Discussion and Analysis
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 member and Board of Directors of
Entergy Mississippi, LLC
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Entergy Mississippi, LLC (the “Company”) as of December 31, 20192020 and 2018,2019, the related statements of income, cash flows and changes in member’s equity (pages 363379 through 368384 and applicable items in pages 4951 through 236)238), for each of the three years in the period ended December 31, 2019,2020, 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, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2020, 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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Mississippi, LLC — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Mississippi Public Service Commission (the “MPSC”), which has jurisdiction with respect to the rates of electric companies in Mississippi, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment;
regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the MPSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses 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. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the MPSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the MPSC and the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the MPSC and the FERC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the MPSC and the FERC for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the MPSC’s and FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected the Company’s filings with the MPSC and the FERC, including the annual formula rate plan filing, and considered the filings with the MPSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202026, 2021
We have served as the Company’s auditor since 2001.
|
| | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $1,323,043 |
| |
| $1,335,112 |
| |
| $1,198,229 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 277,425 |
| | 260,198 |
| | 185,816 |
|
| Purchased power | | 284,492 |
| | 364,575 |
| | 328,463 |
|
| Other operation and maintenance | | 266,175 |
| | 261,613 |
| | 240,738 |
|
| Taxes other than income taxes | | 105,318 |
| | 101,999 |
| | 95,051 |
|
| Depreciation and amortization | | 170,886 |
| | 152,577 |
| | 143,479 |
|
| Other regulatory charges (credits) - net | | 14,993 |
| | 147,704 |
| | (19,134 | ) |
| TOTAL | | 1,119,289 |
| | 1,288,666 |
| | 974,413 |
|
| | | | | | | |
| OPERATING INCOME | | 203,754 |
| | 46,446 |
| | 223,816 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 8,356 |
| | 8,710 |
| | 9,667 |
|
| Interest and investment income | | 1,412 |
| | 135 |
| | 85 |
|
| Miscellaneous - net | | (4,478 | ) | | (2,732 | ) | | (2,232 | ) |
| TOTAL | | 5,290 |
| | 6,113 |
| | 7,520 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 61,785 |
| | 55,905 |
| | 51,260 |
|
| Allowance for borrowed funds used during construction | | (3,532 | ) | | (3,651 | ) | | (3,875 | ) |
| TOTAL | | 58,253 |
| | 52,254 |
| | 47,385 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 150,791 |
| | 305 |
| | 183,951 |
|
| | | | | | | |
| Income taxes | | 30,866 |
| | (125,773 | ) | | 73,919 |
|
| | | | | | | |
| NET INCOME | | 119,925 |
| | 126,078 |
| | 110,032 |
|
| | | | |
|
| | |
| Preferred dividend requirements and other | | — |
| | 834 |
| | 953 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | |
| $119,925 |
| |
| $125,244 |
| |
| $109,079 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $1,247,854 | | | $1,323,043 | | | $1,335,112 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 187,087 | | | 277,425 | | | 260,198 | |
| Purchased power | | 240,471 | | | 284,492 | | | 364,575 | |
| Other operation and maintenance | | 288,543 | | | 266,175 | | | 261,613 | |
| | | | | | |
| Taxes other than income taxes | | 101,525 | | | 105,318 | | | 101,999 | |
| Depreciation and amortization | | 209,252 | | | 170,886 | | | 152,577 | |
| Other regulatory charges (credits) - net | | (15,219) | | | 14,993 | | | 147,704 | |
| TOTAL | | 1,011,659 | | | 1,119,289 | | | 1,288,666 | |
| | | | | | |
| OPERATING INCOME | | 236,195 | | | 203,754 | | | 46,446 | |
| | | | | | |
| OTHER INCOME (DEDUCTIONS) | | | | | | |
| Allowance for equity funds used during construction | | 6,726 | | | 8,356 | | | 8,710 | |
| Interest and investment income | | 272 | | | 1,412 | | | 135 | |
| Miscellaneous - net | | (9,253) | | | (4,478) | | | (2,732) | |
| TOTAL | | (2,255) | | | 5,290 | | | 6,113 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 68,945 | | | 61,785 | | | 55,905 | |
| Allowance for borrowed funds used during construction | | (2,778) | | | (3,532) | | | (3,651) | |
| TOTAL | | 66,167 | | | 58,253 | | | 52,254 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 167,773 | | | 150,791 | | | 305 | |
| | | | | | |
| Income taxes | | 27,190 | | | 30,866 | | | (125,773) | |
| | | | | | |
| NET INCOME | | 140,583 | | | 119,925 | | | 126,078 | |
| | | | | | |
| Preferred dividend requirements and other | | 0 | | | 0 | | | 834 | |
| | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | | $140,583 | | | $119,925 | | | $125,244 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
(Page left blank intentionally)
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $140,583 | | | $119,925 | | | $126,078 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 209,252 | | | 170,886 | | | 152,577 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 36,827 | | | 32,547 | | | 56,502 | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (1,889) | | | (17,245) | | | 37,762 | |
| Fuel inventory | | (1,978) | | | (3,208) | | | 33,675 | |
| Accounts payable | | 22,794 | | | (226) | | | (7,472) | |
| Taxes accrued | | 17,423 | | | 13,109 | | | (5,291) | |
| Interest accrued | | 1,989 | | | (1,331) | | | (2,670) | |
| Deferred fuel costs | | (55,711) | | | 78,418 | | | 24,428 | |
| Other working capital accounts | | 630 | | | (5,557) | | | (9,902) | |
| Provisions for estimated losses | | (3,517) | | | (1,121) | | | 6,378 | |
| Other regulatory assets | | (89,369) | | | (34,923) | | | 54,860 | |
| Other regulatory liabilities | | (18,672) | | | (21,524) | | | (131,856) | |
| | | | | | |
| Pension and other postretirement liabilities | | 11,319 | | | 6,534 | | | (8,405) | |
| Other assets and liabilities | | 30,633 | | | 3,668 | | | 91,718 | |
| Net cash flow provided by operating activities | | 300,314 | | | 339,952 | | | 418,382 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (555,287) | | | (432,600) | | | (387,293) | |
| Allowance for equity funds used during construction | | 6,726 | | | 8,356 | | | 8,710 | |
| | | | | | |
| | | | | | |
| | | | | | |
| Changes in money pool receivable - net | | 44,692 | | | (3,313) | | | (39,747) | |
| | | | | | |
| | | | | | |
| Payment for purchase of plant or assets | | (28,612) | | | (305,472) | | | 0 | |
| Other | | 1,719 | | | (655) | | | (1,123) | |
| Net cash flow used in investing activities | | (530,762) | | | (733,684) | | | (419,453) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 165,385 | | | 437,153 | | | 54,449 | |
| Retirement of long-term debt | | 0 | | | (150,000) | | | 0 | |
| Changes in money pool payable - net | | 16,516 | | | 0 | | | 0 | |
| Redemption of preferred stock | | 0 | | | 0 | | | (21,208) | |
| Capital contributions from parent | | 0 | | | 130,000 | | | 0 | |
| Distributions/dividends paid: | | | | | | |
| Common equity | | (10,000) | | | 0 | | | (10,000) | |
| Preferred stock | | 0 | | | 0 | | | (993) | |
| Other | | 6,964 | | | (8,774) | | | 9,681 | |
| Net cash flow provided by financing activities | | 178,865 | | | 408,379 | | | 31,929 | |
| Net increase (decrease) in cash and cash equivalents | | (51,583) | | | 14,647 | | | 30,858 | |
| Cash and cash equivalents at beginning of period | | 51,601 | | | 36,954 | | | 6,096 | |
| Cash and cash equivalents at end of period | | $18 | | | $51,601 | | | $36,954 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $64,536 | | | $60,533 | | | $56,037 | |
| Income taxes | | ($8,084) | | | ($12,204) | | | ($19,118) | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $119,925 |
| |
| $126,078 |
| |
| $110,032 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 170,886 |
| | 152,577 |
| | 143,479 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 32,547 |
| | 56,502 |
| | 84,816 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | (17,245 | ) | | 37,762 |
| | (29,528 | ) |
| Fuel inventory | | (3,208 | ) | | 33,675 |
| | 5,266 |
|
| Accounts payable | | (226 | ) | | (7,472 | ) | | 3,595 |
|
| Taxes accrued | | 13,109 |
| | (5,291 | ) | | 18,803 |
|
| Interest accrued | | (1,331 | ) | | (2,670 | ) | | 1,248 |
|
| Deferred fuel costs | | 78,418 |
| | 24,428 |
| | (25,487 | ) |
| Other working capital accounts | | (5,557 | ) | | (9,902 | ) | | 5,115 |
|
| Provisions for estimated losses | | (1,121 | ) | | 6,378 |
| | (9,676 | ) |
| Other regulatory assets | | (34,923 | ) | | 54,860 |
| | (17,412 | ) |
| Other regulatory liabilities | | (21,524 | ) | | (131,856 | ) | | 405,395 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | — |
| | — |
| | (452,429 | ) |
| Pension and other postretirement liabilities | | 6,534 |
| | (8,405 | ) | | (8,055 | ) |
| Other assets and liabilities | | 3,668 |
| | 91,718 |
| | (8,577 | ) |
| Net cash flow provided by operating activities | | 339,952 |
| | 418,382 |
| | 226,585 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (432,600 | ) | | (387,293 | ) | | (427,616 | ) |
| Allowance for equity funds used during construction | | 8,356 |
| | 8,710 |
| | 9,667 |
|
| Changes in money pool receivable - net | | (3,313 | ) | | (39,747 | ) | | 8,962 |
|
| Payment for purchase of plant or assets | | (305,472 | ) | | — |
| | (6,958 | ) |
| Other | | (655 | ) | | (1,123 | ) | | (1,281 | ) |
| Net cash flow used in investing activities | | (733,684 | ) | | (419,453 | ) | | (417,226 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 437,153 |
| | 54,449 |
| | 148,185 |
|
| Retirement of long-term debt | | (150,000 | ) | | — |
| | — |
|
| Redemption of preferred stock | | — |
| | (21,208 | ) | | — |
|
| Capital contributions from parent | | 130,000 |
| | — |
| | — |
|
| Distributions/dividends paid: | | |
| | |
| | |
|
| Common equity | | — |
| | (10,000 | ) | | (26,000 | ) |
| Preferred stock | | — |
| | (993 | ) | | (953 | ) |
| Other | | (8,774 | ) | | 9,681 |
| | (1,329 | ) |
| Net cash flow provided by financing activities | | 408,379 |
| | 31,929 |
| | 119,903 |
|
| Net increase (decrease) in cash and cash equivalents | | 14,647 |
| | 30,858 |
| | (70,738 | ) |
| Cash and cash equivalents at beginning of period | | 36,954 |
| | 6,096 |
| | 76,834 |
|
| Cash and cash equivalents at end of period | |
| $51,601 |
| |
| $36,954 |
| |
| $6,096 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $60,533 |
| |
| $56,037 |
| |
| $47,631 |
|
| Income taxes | |
| ($12,204 | ) | |
| ($19,118 | ) | |
| ($25,043 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2020 | | 2019 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $11 | | | $11 | |
| Temporary cash investments | | 7 | | | 51,590 | |
| Total cash and cash equivalents | | 18 | | | 51,601 | |
| Accounts receivable: | | | | |
| Customer | | 105,732 | | | 92,050 | |
| Allowance for doubtful accounts | | (19,527) | | | (636) | |
| Associated companies | | 2,740 | | | 49,257 | |
| Other | | 11,821 | | | 14,986 | |
| Accrued unbilled revenues | | 59,514 | | | 47,426 | |
| Total accounts receivable | | 160,280 | | | 203,083 | |
| | | | |
| | | | |
| Fuel inventory - at average cost | | 17,117 | | | 15,139 | |
| Materials and supplies - at average cost | | 59,542 | | | 57,972 | |
| | | | |
| Prepayments and other | | 4,876 | | | 7,149 | |
| TOTAL | | 241,833 | | | 334,944 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Non-utility property - at cost (less accumulated depreciation) | | 4,543 | | | 4,560 | |
| Escrow accounts | | 64,635 | | | 80,201 | |
| | | | |
| TOTAL | | 69,178 | | | 84,761 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 6,084,730 | | | 5,672,589 | |
| | | | |
| Construction work in progress | | 134,854 | | | 88,373 | |
| TOTAL UTILITY PLANT | | 6,219,584 | | | 5,760,962 | |
| Less - accumulated depreciation and amortization | | 2,005,087 | | | 1,894,000 | |
| UTILITY PLANT - NET | | 4,214,497 | | | 3,866,962 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets | | 467,341 | | | 377,972 | |
| Other | | 14,413 | | | 10,105 | |
| TOTAL | | 481,754 | | | 388,077 | |
| | | | |
| TOTAL ASSETS | | $5,007,262 | | | $4,674,744 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $11 |
| |
| $11 |
|
| Temporary cash investments | | 51,590 |
| | 36,943 |
|
| Total cash and cash equivalents | | 51,601 |
| | 36,954 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 92,050 |
| | 73,205 |
|
| Allowance for doubtful accounts | | (636 | ) | | (563 | ) |
| Associated companies | | 49,257 |
| | 51,065 |
|
| Other | | 14,986 |
| | 8,647 |
|
| Accrued unbilled revenues | | 47,426 |
| | 50,171 |
|
| Total accounts receivable | | 203,083 |
| | 182,525 |
|
| Deferred fuel costs | | — |
| | 8,016 |
|
| Fuel inventory - at average cost | | 15,139 |
| | 11,931 |
|
| Materials and supplies - at average cost | | 57,972 |
| | 47,255 |
|
| Prepayments and other | | 7,149 |
| | 9,365 |
|
| TOTAL | | 334,944 |
| | 296,046 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Non-utility property - at cost (less accumulated depreciation) | | 4,560 |
| | 4,576 |
|
| Escrow accounts | | 80,201 |
| | 32,447 |
|
| TOTAL | | 84,761 |
| | 37,023 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 5,672,589 |
| | 4,780,720 |
|
| Construction work in progress | | 88,373 |
| | 128,149 |
|
| TOTAL UTILITY PLANT | | 5,760,962 |
| | 4,908,869 |
|
| Less - accumulated depreciation and amortization | | 1,894,000 |
| | 1,641,821 |
|
| UTILITY PLANT - NET | | 3,866,962 |
| | 3,267,048 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Other regulatory assets | | 377,972 |
| | 343,049 |
|
| Other | | 10,105 |
| | 3,638 |
|
| TOTAL | | 388,077 |
| | 346,687 |
|
| | | | | |
| TOTAL ASSETS | |
| $4,674,744 |
| |
| $3,946,804 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2020 | | 2019 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| | | | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | $61,727 | | | $48,090 | |
| Other | | 117,629 | | | 94,729 | |
| Customer deposits | | 86,200 | | | 85,938 | |
| Taxes accrued | | 108,084 | | | 90,661 | |
| | | | |
| Interest accrued | | 20,889 | | | 18,900 | |
| Deferred fuel costs | | 14,691 | | | 70,402 | |
| | | | |
| Other | | 34,270 | | | 32,667 | |
| TOTAL | | 443,490 | | | 441,387 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 646,674 | | | 594,832 | |
| Accumulated deferred investment tax credits | | 9,062 | | | 9,602 | |
| Regulatory liability for income taxes - net | | 224,000 | | | 236,988 | |
| | | | |
| Other regulatory liabilities | | 15,828 | | | 21,512 | |
| Asset retirement cost liabilities | | 9,762 | | | 9,727 | |
| Accumulated provisions | | 46,504 | | | 50,021 | |
| Pension and other postretirement liabilities | | 110,901 | | | 99,406 | |
| Long-term debt | | 1,780,577 | | | 1,614,129 | |
| Other | | 47,730 | | | 54,989 | |
| TOTAL | | 2,891,038 | | | 2,691,206 | |
| | | | |
| Commitments and Contingencies | | 0 | | 0 |
| | | | |
| | | | |
| | | | |
| EQUITY | | | | |
| Member's equity | | 1,672,734 | | | 1,542,151 | |
| TOTAL | | 1,672,734 | | | 1,542,151 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $5,007,262 | | | $4,674,744 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $— |
| |
| $150,000 |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 48,090 |
| | 42,928 |
|
| Other | | 94,729 |
| | 79,117 |
|
| Customer deposits | | 85,938 |
| | 85,085 |
|
| Taxes accrued | | 90,661 |
| | 77,552 |
|
| Interest accrued | | 18,900 |
| | 20,231 |
|
| Deferred fuel costs | | 70,402 |
| | — |
|
| Other | | 32,667 |
| | 7,526 |
|
| TOTAL | | 441,387 |
| | 462,439 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 594,832 |
| | 551,869 |
|
| Accumulated deferred investment tax credits | | 9,602 |
| | 10,186 |
|
| Regulatory liability for income taxes - net | | 236,988 |
| | 246,402 |
|
| Other regulatory liabilities | | 21,512 |
| | 33,622 |
|
| Asset retirement cost liabilities | | 9,727 |
| | 9,206 |
|
| Accumulated provisions | | 50,021 |
| | 51,142 |
|
| Pension and other postretirement liabilities | | 99,406 |
| | 93,100 |
|
| Long-term debt | | 1,614,129 |
| | 1,175,750 |
|
| Other | | 54,989 |
| | 20,862 |
|
| TOTAL | | 2,691,206 |
| | 2,192,139 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| EQUITY | | |
| | |
|
| Member's equity | | 1,542,151 |
| | 1,292,226 |
|
| TOTAL | | 1,542,151 |
| | 1,292,226 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $4,674,744 |
| |
| $3,946,804 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | |
| ENTERGY MISSISSIPPI, LLC |
| STATEMENTS OF CHANGES IN MEMBER'S EQUITY |
For the Years Ended December 31, 2020, 2019, 2018, and 20172018 |
| |
| |
| Member's Equity |
| (In Thousands) |
| |
Balance at December 31, 2016 |
| $1,094,791 |
|
Net income | 110,032 |
|
Common equity distributions | (26,000 | ) |
Preferred stock dividends | (953 | ) |
| Balance at December 31, 2017 |
| $1,177,870 |
|
| Net income | 126,078 |
|
| Common equity distributions | (10,000(10,000) | ) |
| Preferred stock dividends | (834(834) | ) |
| Other | (888(888) | ) |
| Balance at December 31, 2018 |
| $1,292,226 |
|
| Net income | 119,925 |
|
| Capital contribution from parent | 130,000 |
|
| |
| |
| Balance at December 31, 2019 |
| $1,542,151 |
|
| Net income | 140,583 | |
| |
| Common equity distributions | (10,000) | |
| |
| |
| Balance at December 31, 2020 | $1,672,734 | |
| |
| See Notes to Financial Statements. | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $1,323,043 |
| |
| $1,335,112 |
| |
| $1,198,229 |
| |
| $1,094,649 |
| |
| $1,396,985 |
|
| Net income |
| $119,925 |
| |
| $126,078 |
| |
| $110,032 |
| |
| $109,184 |
| |
| $92,708 |
|
| Total assets |
| $4,674,744 |
| |
| $3,946,804 |
| |
| $3,879,375 |
| |
| $3,602,140 |
| |
| $3,477,407 |
|
| Long-term obligations (a) |
| $1,614,129 |
| |
| $1,175,750 |
| |
| $1,290,503 |
| |
| $1,141,924 |
| |
| $972,058 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and preferred stock without sinking fund. |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $562 |
| |
| $579 |
| |
| $502 |
| |
| $459 |
| |
| $565 |
|
| Commercial | 444 |
| | 462 |
| | 423 |
| | 374 |
| | 465 |
|
| Industrial | 165 |
| | 175 |
| | 159 |
| | 134 |
| | 164 |
|
| Governmental | 44 |
| | 44 |
| | 41 |
| | 38 |
| | 47 |
|
| Total billed retail | 1,215 |
| | 1,260 |
| | 1,125 |
| | 1,005 |
| | 1,241 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | — |
| | 1 |
| | — |
| | 1 |
| | 75 |
|
| Non-associated companies | 39 |
| | 25 |
| | 18 |
| | 30 |
| | 10 |
|
| Other | 69 |
| | 49 |
| | 55 |
| | 59 |
| | 71 |
|
| Total |
| $1,323 |
| |
| $1,335 |
| |
| $1,198 |
| |
| $1,095 |
| |
| $1,397 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
|
| Residential | 5,659 |
| | 5,829 |
| | 5,308 |
| | 5,617 |
| | 5,661 |
|
| Commercial | 4,698 |
| | 4,865 |
| | 4,783 |
| | 4,894 |
| | 4,913 |
|
| Industrial | 2,443 |
| | 2,559 |
| | 2,536 |
| | 2,493 |
| | 2,283 |
|
| Governmental | 436 |
| | 438 |
| | 421 |
| | 439 |
| | 433 |
|
| Total retail | 13,236 |
| | 13,691 |
| | 13,048 |
| | 13,443 |
| | 13,290 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | — |
| | — |
| | — |
| | — |
| | 1,419 |
|
| Non-associated companies | 1,776 |
| | 1,060 |
| | 857 |
| | 1,021 |
| | 261 |
|
| Total | 15,012 |
| | 14,751 |
| | 13,905 |
| | 14,464 |
| | 14,970 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | |
| | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | (In Thousands) |
| | | | | | | | | |
| Operating revenues | $1,247,854 | | | $1,323,043 | | | $1,335,112 | | | $1,198,229 | | | $1,094,649 | |
| Net income | $140,583 | | | $119,925 | | | $126,078 | | | $110,032 | | | $109,184 | |
| Total assets | $5,007,262 | | | $4,674,744 | | | $3,946,804 | | | $3,879,375 | | | $3,602,140 | |
| Long-term obligations (a) | $1,780,577 | | | $1,614,129 | | | $1,175,750 | | | $1,290,503 | | | $1,141,924 | |
| | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and preferred stock without sinking fund. |
| | | | | | | | | |
| | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | (Dollars In Millions) |
| | | | | | | | | |
| Electric Operating Revenues: | | | | | | | | | |
| Residential | $523 | | | $562 | | | $579 | | | $502 | | | $459 | |
| Commercial | 396 | | | 444 | | | 462 | | | 423 | | | 374 | |
| Industrial | 145 | | | 165 | | | 175 | | | 159 | | | 134 | |
| Governmental | 42 | | | 44 | | | 44 | | | 41 | | | 38 | |
| Total billed retail | 1,106 | | | 1,215 | | | 1,260 | | | 1,125 | | | 1,005 | |
| Sales for resale: | | | | | | | | | |
| Associated companies | — | | | — | | | 1 | | | — | | | 1 | |
| Non-associated companies | 78 | | | 39 | | | 25 | | | 18 | | | 30 | |
| Other | 64 | | | 69 | | | 49 | | | 55 | | | 59 | |
| Total | $1,248 | | | $1,323 | | | $1,335 | | | $1,198 | | | $1,095 | |
| | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | |
| Residential | 5,378 | | | 5,659 | | | 5,829 | | | 5,308 | | | 5,617 | |
| Commercial | 4,283 | | | 4,698 | | | 4,865 | | | 4,783 | | | 4,894 | |
| Industrial | 2,343 | | | 2,443 | | | 2,559 | | | 2,536 | | | 2,493 | |
| Governmental | 398 | | | 436 | | | 438 | | | 421 | | | 439 | |
| Total retail | 12,402 | | | 13,236 | | | 13,691 | | | 13,048 | | | 13,443 | |
| Sales for resale: | | | | | | | | | |
| | | | | | | | | |
| Non-associated companies | 4,316 | | | 1,776 | | | 1,060 | | | 857 | | | 1,021 | |
| Total | 16,718 | | | 15,012 | | | 14,751 | | | 13,905 | | | 14,464 | |
ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
Hurricane Zeta
In October 2020, Hurricane Zeta caused significant damage to Entergy New Orleans’s service area. The storm resulted in widespread power outages, significant damage to distribution and transmission 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 Zeta are currently estimated to be approximately $40 million, including approximately $30 million in capital costs and approximately $10 million in non-capital costs. Entergy New Orleans is considering all available avenues to recover storm-related costs from Hurricane Zeta, including accessing funded storm reserve escrows and securitization. Storm cost recovery or financing will be subject to review by applicable regulatory authorities.
Entergy New Orleans recorded accounts payable and corresponding construction work in progress and regulatory assets for the estimated costs incurred that were necessary to return customers to service. Entergy New Orleans recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles. Because Entergy New Orleans has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy New Orleans is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy New Orleans’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $1 million. Natural gas purchases for Entergy New Orleans for February 1st through 25th, 2021 are approximately $15 million compared to natural gas purchases for February 2020 of $7 million.
Results of Operations
20192020 Compared to 20182019
Net Income
Net income decreased $0.5$3.3 million primarily due to lower volume/weather, lower retail electric price, and higher interest expense, partially offset by a higherlower effective income tax rate, substantially offset by higher other incomerate.
Entergy New Orleans, LLC and lower other operationSubsidiaries
Management’s Financial Discussion and maintenance expenses.Analysis
Operating Revenues
Following is an analysis of the change in operating revenues comparing 20192020 to 2018.
|
| | | | |
| Amount |
| (In Millions) |
| |
20182019 operating revenues |
| $717.4 |
|
| Fuel, rider, and other revenues that do not significantly affect net income | (37.4(32.5) | ) |
| Volume/weather | (12.5) | |
| Retail electric price | (5.5(7.4) | ) |
Volume/weather | 1.8 |
|
Return of unprotected excess accumulated deferred income taxes to customers | 9.9 |
|
20192020 operating revenues |
| $686.2 |
|
Entergy New Orleans’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The volume/weather variance is primarily due to a decrease of 374 GWh, or 6.4%, in billed electricity usage, including the effect of decreased commercial and governmental usage as a result of the COVID-19 pandemic and the effect of less favorable weather on residential and commercial sales, partially offset by an increase in residential usage as a result of the COVID-19 pandemic. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the COVID-19 pandemic.
The retail electric price variance is primarily due to the effects of a provisionrate reduction implemented with April 2020 bills that was effective August 2019 in accordance with the City Council resolution and related agreement in principle reached in the 2018 base rate case. See Note 2 to the financial statements for further discussion of the rate refund recorded in fourth quartercase.
Other Income Statement Variances
Other operation and maintenance expenses increased primarily due to:
•an increase of $4.9 million primarily due to the 2019 deferral of costs related to the 2018 rate case and a system conversion for Algiers customers as a result of the 2018 combined rate case resolution approved by the City Council. See Note 2 to the financial statements for further discussion of the rate case resolution.resolution; and
•an increase of $3.8 million in energy efficiency costs.
The volume/weather variance isincrease was partially offset by:
•a decrease of $2.4 million in gas operations costs primarily due to an increase in usage during the unbilled sales period.
The return of unprotected excess accumulated deferred income taxes to customers variance is due to a decrease in the return of unprotected excess accumulated deferred income taxes through the fuel adjustment clause. In 2019, $2.1 million was returned to customers as compared to $12 million in 2018. There is no effect on net income as the reduction in operating revenues in each period is offset by a reduction in income tax expense. See Note 2 to the financial statements for discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
Other Income Statement Variances
Other operation and maintenance expenses decreased primarily due to:
a decrease of $9.2 million as a result of the deferral in 20192020 of 2018certain gas infrastructure replacement program costs related to the rate case and a system conversion for Algiers customers as a result of the 2018 combined rate case resolution approved by the City
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Council.resolution. See Note 2 to the financial statements for further discussion of the rate case resolution; and
•a decrease of $2.9$2.2 million in distribution expenses primarily due to lower contract labor costs.
The decrease was partially offset by:
an increase of $2.9 millioncosts in spending on2019 related to initiatives to explore new customer products and services;services.
an increase of $2.8 million in information technology costs
Depreciation and amortization expenses increased primarily due to higher software maintenance costsadditions to plant in service.
Entergy New Orleans, LLC and higher contract costs;Subsidiaries
an increaseManagement’s Financial Discussion and Analysis
Other regulatory charges - net include regulatory credits recorded in the first quarter 2020 to reflect compliance with terms of $2 millionthe 2018 combined rate case resolution approved by the City Council in customer service costsFebruary 2020. See Note 2 to the financial statements for further discussion of the rate case resolution.
Interest expense increased primarily due to higher labor costs, including contract labor;the issuance of:
•a $70 million term loan at 3.0% in December 2019;
•$78 million of 3.00% Series mortgage bonds in March 2020; and
an increase•$62 million of $1.8 million3.75% Series mortgage bonds in energy efficiency costs.March 2020.
Other income increased primarily due to:
an increase in allowance for equity funds used during construction resulting from higher construction work in progress in 2019, including the New Orleans Power Station project; and
| |
• | the accrual in fourth quarter 2018 of a $5 million settlement offer in the New Orleans Power Station show cause proceeding. See “Liquidity and Capital Resources - Uses of Capital - New Orleans Power Station” below for discussion of the New Orleans Power Station proceedings.
|
The effective income tax rates were (9.3%) for 2020 and 0.4% for 2019 and (4.8%) for 2018.2019. The differencesdifference in the effective income tax ratesrate versus the federal statutory rate of 21% for 2019 and 2018 were2020 was primarily due to the amortization of excess accumulated deferred income taxes and the completion of the 2014-2015 IRS audit effectively settling the tax positions for those years. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes. See Notes 2 and 3 to the financial statements for a discussion of the effects and regulatory activity regarding the Tax Cuts and Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
20182019 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy New Orleans’s Annual Report on Form 10-K for the year ended December 31, 20182019, filed with the SEC on February 21, 2020, for discussion of results of operations for 20182019 compared to 2017.2018.
Income Tax Legislation
See
Cash Flow
Cash flows for the “years ended December 31, 2020, 2019, and 2018 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $6,017 | | | $19,677 | | | $32,741 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 64,024 | | | 115,604 | | | 171,778 | |
| Investing activities | (220,845) | | | (204,310) | | | (207,616) | |
| Financing activities | 150,830 | | | 75,046 | | | 22,774 | |
| Net decrease in cash and cash equivalents | (5,991) | | | (13,660) | | | (13,064) | |
| | | | | |
| Cash and cash equivalents at end of period | $26 | | | $6,017 | | | $19,677 | |
2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities decreased $51.6 million in 2020 primarily due to:
•Income Tax Legislation” sectionlower collections 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 enactedreceivables from customers, in December 2017. Note 3part due to the financial statements contains additional discussionCOVID-19 pandemic;
•the timing of the effectrecovery of the Act on 2017, 2018,fuel and 2019 results of operationspurchased power costs; 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 the regulatory proceedings that have considered the effects of 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, 2019, 2018, and 2017 were as follows:
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $19,677 |
| |
| $32,741 |
| |
| $103,068 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 115,604 |
| | 171,778 |
| | 127,797 |
|
| Investing activities | (204,310 | ) | | (207,616 | ) | | (109,500 | ) |
| Financing activities | 75,046 |
| | 22,774 |
| | (88,624 | ) |
| Net decrease in cash and cash equivalents | (13,660 | ) |
| (13,064 | ) |
| (70,327 | ) |
| | | | | | |
| Cash and cash equivalents at end of period |
| $6,017 |
|
|
| $19,677 |
|
|
| $32,741 |
|
2019 Compared•income tax payments of $3.4 million made in 2020 compared to 2018
Operating Activities
Net cash flow provided by operating activities decreased $56.2 million in 2019 primarily due to a decrease of $34.5 million in 2019 of income tax refunds and the timing of collection of receivables from customers. Entergy New Orleans had income tax refunds$5.3 million received in 2019, and 2018each in accordance with an intercompany income tax allocation agreement. The income tax refunds resulted from the utilization of Entergy New Orleans’s net operating loss.
The decrease was partially offset by the timing of payments to vendors.
Investing Activities
Net cash flow used in investing activities decreased $3.3increased $16.5 million in 20192020 primarily due to money pool activity. The decrease was substantially offset by:to:
•an increase of $15.6 million in transmission construction expenditures primarily due to a higher scope of work performed in 2019 as compared to 2018, including investment in Entergy New Orleans’s system reliability and infrastructure; and
an increase of $10.7$12.4 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy New Orleans’s distribution system, including increased spending on advanced metering infrastructure.infrastructure;
•money pool activity;
•an increase of $10.8 million in storm spending in 2020, primarily due to Hurricane Zeta restoration efforts. See “Hurricane Zeta” above for discussion of hurricane restoration efforts; and
•an increase of $5.1 million in facilities construction expenditures primarily due to a higher scope of work performed in 2020.
The increase was partially offset by:
•a decrease of $16.2 million in non-nuclear generation construction expenditures primarily due to lower spending in 2020 on the New Orleans Power Station project, partially offset by higher spending in 2020 on the New Orleans Solar Station project; and
•a decrease of $7.5 million in transmission construction expenditures primarily due to lower spending in 2020 on the New Orleans Power Station project.
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 by$5.2 million in 2020 compared to decreasing $16.8 million in 2019 compared to increasing by $9.3 million in 2018.2019. 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 $52.3$75.8 million primarily due to:
proceedsto a capital contribution received from a $70 million 3.0% unsecured term loan due May 2022 in December 2019;
$23.8Entergy Corporation of $60 million in common equity distributionsNovember 2020 in 2018. There were no common equity distributions made in 2019 in anticipation of planned capital investments; and
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
net borrowings of $20 million in 2019 onorder to maintain Entergy New Orleans’s credit facility.capital structure and money pool activity.
The increase was partially offset by the issuance of $60 million of 4.51% Series mortgage bondsIncreases in September 2018.
See Note 5Entergy New Orleans’s payable to the financial statements for details on long-term debt.money pool are a source of cash flow, and Entergy New Orleans’s payable to the money pool increased $10.2 million in 2020.
20182019 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy New Orleans’s Annual Report on Form 10-K for the year ended December 31, 20182019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 20182019 compared to 2017.2018.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Capital Structure
Entergy New Orleans’s debt to capital ratio is shown in the following table. The increasedecrease in the debt to capital ratio is primarily due to an increase in equity resulting from a $60 million capital contribution received from Entergy Corporation in 2020 and net income, partially offset by the net issuance of long-term debt in 2019.2020.
| | | | | | | | | | | |
| December 31,
2020 | | December 31,
2019 |
| Debt to capital | 51.5 | % | | 53.1 | % |
| Effect of excluding securitization bonds | (1.6 | %) | | (2.4 | %) |
| Debt to capital, excluding securitization bonds (a) | 49.9 | % | | 50.7 | % |
| Effect of subtracting cash | — | % | | (0.3 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 49.9 | % | | 50.4 | % |
|
| | | | | |
| | December 31,
2019 | | December 31,
2018 |
| Debt to capital | 53.1 | % | | 52.1 | % |
| Effect of excluding securitization bonds | (2.4 | %) | | (3.5 | %) |
| Debt to capital, excluding securitization bonds (a) | 50.7 | % | | 48.6 | % |
| Effect of subtracting cash | (0.3 | %) | | (1.2 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 50.4 | % | | 47.4 | % |
(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, finance lease obligations, long-term debt, including the currently maturing portion, and the long-term payable due to an associated company. Capital consists of debt and 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 distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy New Orleans may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy New Orleans may receive equity contributions to maintain its 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
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.
Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2022 | | 2023 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $10 | | | $15 | | | $5 | |
| Transmission | 20 | | | 25 | | | 20 | |
| Distribution | 90 | | | 125 | | | 120 | |
| Utility Support | 20 | | | 15 | | | 10 | |
| Total | $140 | | | $180 | | | $155 | |
|
| | | | | | | | | | | |
| | 2020 | | 2021 | | 2022 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $70 |
| |
| $15 |
| |
| $15 |
|
| Transmission | 10 |
| | 20 |
| | 25 |
|
| Distribution | 90 |
| | 80 |
| | 40 |
|
| Utility Support | 65 |
| | 40 |
| | 70 |
|
| Total |
| $235 |
| |
| $155 |
| |
| $150 |
|
In addition to the planned spending in the table above, Entergy New Orleans also expects to pay for $25 million of capital investments in 2021 related to Hurricane Zeta restoration work that have been accrued as of December 31, 2020.
Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| | (In Millions) |
| Long-term debt (a) | $37 | | | $240 | | | $119 | | | $686 | | | $1,082 | |
| Operating leases (b) | $2 | | | $2 | | | $1 | | | $1 | | | $6 | |
| Finance leases (b) | $1 | | | $1 | | | $1 | | | $1 | | | $4 | |
| Purchase obligations (c) | $217 | | | $438 | | | $419 | | | $3,287 | | | $4,361 | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $62 |
| |
| $159 |
| |
| $153 |
| |
| $612 |
| |
| $986 |
|
| Operating leases (b) |
| $1 |
| |
| $2 |
| |
| $1 |
| |
| $— |
| |
| $4 |
|
| Finance leases (b) |
| $1 |
| |
| $1 |
| |
| $1 |
| |
| $1 |
| |
| $4 |
|
| Purchase obligations (c) |
| $224 |
| |
| $459 |
| |
| $448 |
| |
| $3,602 |
| |
| $4,733 |
|
(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)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.
| |
(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) | 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 $3.2$5.4 million to its qualified pension plan and approximately $162$175 thousand to other postretirement health care and life insurance plans in 2020,2021, although the 20202021 required pension contributions will be known with more certainty when the January 1, 20202021 valuations are completed, which is expected by April 1, 2020.2021. 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 $271.3$187.6 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 and New Orleans Solar
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Station; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; software and security; 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,
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
New Orleans Power Station
In March 2018 the City Council adopted a resolution approving construction of the New Orleans Power Station, a 128 MW unit composed of natural gas-fired reciprocating engines, and a related cost recovery plan. The cost estimate for the plant, which will be located at the site of the Michoud generating facility that was retired in May 2016, is $210 million. Entergy New Orleans had previously filed an application with the City Council seeking a public interest determination and authorization to construct a 226 MW advanced combustion turbine power station. 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 power station, or alternatively, the 128 MW power station. In addition, the application renewed the commitment to pursue up to 100 MW of renewable resources to serve New Orleans.
In April 2018 intervenors opposing the construction of the New Orleans Power Station filed with the City Council a request for rehearing, which was subsequently denied, and a petition for judicial review of the City Council’s decision, and also filed a lawsuit challenging the City Council’s approval based on Louisiana’s open meeting law. In May 2018 the City Council announced that it would initiate an investigation into allegations that Entergy New Orleans, Entergy, or some other entity paid or participated in paying certain attendees and speakers in support of the New Orleans Power Station to attend or speak at certain meetings organized by the City Council. In October 2018 investigators for the City Council released their report, concluding that individuals were paid to attend or speak in support of the New Orleans Power Station and that Entergy New Orleans “knew or should have known that such conduct occurred or reasonably might occur.” The City Council issued a resolution requiring Entergy New Orleans to show cause why it should not be fined $5 million as a result of the findings in the report. In November 2018, Entergy New Orleans submitted its response to the show cause resolution, disagreeing with certain characterizations and omissions of fact in the report and asserting that the City Council could not legally impose the proposed fine. Simultaneous with the filing of its response to the show cause resolution, Entergy New Orleans sent a letter to the City Council re-asserting that the City Council’s imposition of the proposed fine would be unlawful, but acknowledging that the actions of a subcontractor, which was retained by an Entergy New Orleans contractor without the knowledge or contractually-required consent of Entergy New Orleans, were contrary to Entergy’s values. In that letter, Entergy New Orleans offered to donate $5 million to the City Council to resolve the show cause proceeding. In January 2019, Entergy New Orleans submitted a new settlement proposal to the City Council. The proposal retains the components of the first offer but adds to it a commitment to make reasonable efforts to limit the costs of the project to the $210 million cost estimate with advanced notification of anticipated cost overruns, additional reporting requirements for cost and environmental items, and a commitment regarding reliability investment and to work with the New Orleans Sewerage and Water Board to provide a reliable source of power. In February 2019 the City Council approved a resolution approving the settlement proposal and allowing the construction of the New Orleans Power Station to commence.
Also in February 2019 certain intervenors in the City Council proceeding on the New Orleans Power Station filed suit in Louisiana state court challenging the Louisiana Department of Environmental Quality’s issuance of the New Orleans Power Station’s air permit. Entergy New Orleans intervened in that lawsuit and, along with the Louisiana
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Department of Environmental Quality, filed exceptions seeking dismissal of the lawsuit. In June 2019 the state court judge sustained the exceptions and dismissed the plaintiffs’ petition with prejudice.
Also in June 2019, a state court judge in New Orleans affirmed the City Council’s approval of the New Orleans Power Station and dismissed the petition for judicial review that had been filed in April 2018. The petitioners have filed an appeal of that ruling. Also in June 2019, with regard to the lawsuit challenging the City Council’s decision on the basis of a violation of the open meetings law, the same state court judge in New Orleans ruled that there was a violation of the open meetings law at the February 2018 meeting of the City Council’s Utility Committee at which that Committee considered the New Orleans Power Station approval, and further ruled that, although there was no violation of the open meetings law at the March 2018 full City Council meeting at which the New Orleans Power Station was approved, both the approval of the Utility Committee and the approval of the full City Council were void. The City Council and Entergy New Orleans each filed a suspensive appeal of the open meetings law ruling. A suspensive appeal suspends the effect of the judgment in the open meetings law proceeding while the appeal is being taken. The petitioners sought in the state appellate court, and then at the Louisiana Supreme Court, to terminate the suspension of the effect of the judgment, but both courts declined to do so. Appellate briefing on the merits both in the open meetings law appeal and in the judicial review appeal occurred in November and December 2019 and oral argument in both cases was heard in January 2020. In February 2020 the state appellate court reversed the lower court’s ruling that the City Council’s approval of the New Orleans Power Station was void due to a violation of the open meetings law at the City Council’s Utility Committee meeting in February 2018. The state appellate court ruled that there was no violation of the open meetings law at the full City Council meeting in March 2018 and that the lower court erred in voiding the City Council resolution approving the New Orleans Power Station. The appellate court’s decision on the appeal of the judicial review decision that affirmed the City Council’s approval of the New Orleans Power Station as in the public interest is still pending. Construction of the plant is on schedule, with commercial operation expected in mid-2020.
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 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. The City Council authorized Entergy New Orleans to proceed with its replacement plans and established a schedule for proceedings in advance of the rate case intended to provide an opportunity for evaluation of the gas infrastructure plan that would best serve the public interest and the effect on customers of the approval of any such plan. In the course of that proceeding, the City Council’s advisors submitted pre-filed testimony recommending that Entergy New Orleans be allowed to continue with its condition-based approach to gas pipeline replacement to replace approximately 238 miles of low pressure pipe at a rate of approximately 25 miles per year. The City Council’s advisors also recommended that Entergy New Orleans be required to adhere to certain reporting requirements and recognized the need to address the sustained level of investment in gas infrastructure on customer bills. In September 2017, Entergy New Orleans filed rebuttal testimony suggesting that its recovery of future investment and customer effects would be addressed in the rate case that Entergy New Orleans was required to file in July 2018. The procedural schedule was suspended in order to allow for resolution in the rate case proceeding. As a result of the rate case, the City Council approved the planned gas rebuild expenditures through 2019, but rejected Entergy New Orleans’s proposed gas infrastructure rider. In April 2020, Entergy New Orleans is required to submit asubmitted its gas infrastructure rebuild plan to the City Council, in March 2020which maintained the previously proposed timeline and cost estimates, but included measures to convene a working groupspread out the cost impact to explore appropriate cost mitigation measures.customers of the program.
Renewables
In July 2018, Entergy New Orleans filed an application with the City Council requesting approval of three utility-scale solar projects totaling 90 MW. If approved, the resource additions will allow Entergy New Orleans to make significant progress towards meeting its voluntary commitment to the City Council to add up to 100 MW of renewable energy resources. The three projects include constructing a self-build solar plant in Orleans Parish with an
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
output of 20 MW, acquiring a 50 MW solar facility in Washington Parish through a build-own-transfer acquisition, and procuring 20 MW of solar power from a project to be built in St. James Parish through a power purchase agreement. In December 2018 the City Council advisors requested that Entergy New Orleans pursue alternative deal structures for the Washington Parish project and attempt to reduce costs for the 20 MW New Orleans Solar Station. As a result of settlement discussions, in March 2019, Entergy New Orleans revised its application to convert the build-own transfer acquisition of the 50 MW facility in Washington Parish to a power purchase agreement. In June 2019 the parties to the proceeding executed a stipulated settlement term sheet, which recommends that the City Council approve Entergy New Orleans’s revised application as to all three projects. In July 2019 the City Council approved the stipulated settlement. Commercial operation of the 20 MW New Orleans Solar Station commenced in December 2020. Entergy New Orleans expects to begin receiving power under the 50 MW Iris Solar and the 20 MW St. James Solar power purchase agreements by third quarter 2021.
Sources of Capital
Entergy New Orleans’s sources to meet its capital requirements include:
•internally generated funds;
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•cash on hand;
•storm reserve escrow accounts;
•debt and preferred membership interest issuances;issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; 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.
All debt and common and preferred membership interest issuances by Entergy New Orleans require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy New Orleans has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy New Orleans’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | | 2017 |
| (In Thousands) |
| ($10,190) | | $5,191 | | $22,016 | | $12,723 |
|
| | | | | | |
| 2019 | | 2018 | | 2017 | | 2016 |
| (In Thousands) |
| $5,191 | | $22,016 | | $12,723 | | $14,215 |
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 2021. The credit facility includes fronting commitments for the issuance of letters of credit against $10 million of the borrowing capacity of the facility. As of December 31, 2019,2020, there were $20 million ofno cash borrowings and aan $0.8 million letter of credit 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, 2019,2020, a $5.6$1 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 2021July 2022 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 October 2021.July 2022.
Entergy New Orleans, LLC and Subsidiaries
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
As a provision of the settlement agreement approved by the City Council in May 2015 providing for the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers, 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 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.Energy Efficiency
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 and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. 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. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. In December 2019, Entergy New Orleans filed an application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022. Entergy New Orleans proposed to recover the costs of the program through mechanisms previously approved by the City Council
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
or through the energy efficiency cost recovery rider, which was approved in the 2018 combined rate case resolution. In January 2020 the City Council’s advisors recommended that, beginning with Program Year 10, the City Council allow Entergy New Orleans to earn a utility performance incentive of 7% of Energy Smart costs for each year in which Entergy New Orleans achieves 100% of the City Council’s savings targets for Energy Smart. TheIn February 2020 the City Council is expected to decide on the matter in February 2020.
approved Entergy New Orleans, LLC and SubsidiariesOrleans’s application.
Management’s Financial Discussion and Analysis
2018 Base Rate Case
In September 2018, Entergy New Orleans filed an electric and gas base rate case with the City Council. The filing requested a 10.5% return on equity for electric operations with opportunity to earn a 10.75% return on equity through a performance adder provision of the electric formula rate plan in subsequent years under a formula rate plan and requested a 10.75% return on equity for gas operations. The proposed electric rates in the revised filing reflect a net reduction of $20.3 million. The reduction in electric rates includes a base rate increase of $135.2 million, of which $131.5 million is associated with moving costs currently collected through fuel and other riders into base rates, plus a request for an advanced metering surcharge to recover $7.1 million associated with advanced metering infrastructure, offset by a net decrease of $31.1 million related to fuel and other riders. The filing also included a proposed gas rate decrease of $142 thousand. Entergy New Orleans’s rates reflected the inclusion of federal income tax reductions due to the Tax Act and the provisions of a previously-approved agreement in principle determining how the benefits of the Tax Act would flow. Entergy New Orleans included cost of service studies for electric and gas operations for the twelve months ended December 31, 2017 and the projected twelve months ending December 31, 2018. In addition, Entergy New Orleans included capital additions expected to be placed into service for the period through December 31, 2019. Entergy New Orleans based its request for a change in rates on the projected twelve months ending December 31, 2018.
The filing’s major provisions included: (1) a new electric rate structure, which realigns the revenue requirement associated with capacity and long-term service agreement expense from certain existing riders to base revenue, provides for the recovery of the cost of advanced metering infrastructure, and partially blends rates for Entergy New Orleans’s customers residing in Algiers with customers residing in the remainder of Orleans Parish through a three-year phase-in; (2) contemporaneous cost recovery riders for investments in energy efficiency/demand response, incremental changes in capacity/long-term service agreement costs, grid modernization investment, and gas infrastructure replacement investment; and (3) formula rate plans for both electric and gas operations. In February 2019 the City Council’s advisors and several intervenors filed testimony in response to Entergy New Orleans’s application. The City Council’s advisors recommended, among other things, overall rate reductions of approximately $33 million in electric rates and $3.8 million in gas rates. Certain intervenors recommended overall rate reductions of up to approximately $49 million in electric rates and $5 million in gas rates. An evidentiary hearing was held in June 2019, and the record and post-hearing briefs were submitted in July 2019.
In October 2019 the City Council’s Utility Committee approved a resolution for a change in electric and gas rates for consideration by the full City Council that included a 9.35% return on common equity, an equity ratio of the lesser of 50% or Entergy New Orleans’s actual equity ratio, and a total reduction in revenues that Entergy New Orleans initially estimated to be approximately $39 million ($36 million electric; $3 million gas). At its November 7, 2019 meeting, the full City Council approved the resolution that had previously been approved by the City Council’s Utility Committee. Based on the approved resolution, in the fourth quarter 2019 Entergy New Orleans recorded an accrual of $10 million that reflects the estimate of the revenue billed in 2019 to be refunded to customers in 2020 based on an August 2019 effective date for the rate decrease. Entergy New Orleans also recorded a total of $12 million in regulatory assets for rate case costs and information technology costs associated with integrating Algiers customers with Entergy New Orleans’s legacy system and records. Entergy New Orleans will also transferredbe allowed to recover $10 million of retired general plant costs to a regulatory asset to be recovered over a 20-year period.
The resolution directed Entergy New Orleans to submit a compliance filing within 30 days of the date of the resolution to facilitate the eventual implementation of rates, including all necessary calculations and conforming rate schedules and riders. The electric formula rate plan rider includes, among other things, 1) a provision for
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
forward-looking adjustments to include known and measurable changes realized up to 12 months after the evaluation period; 2) a decoupling mechanism; and 3) recognition that Entergy New Orleans is authorized to make an in-service adjustment to the formula rate plan to include the non-fuel cost of the New Orleans Power Station in rates, unless the two pending appeals in the New Orleans Power Station proceeding have not concluded. Under this circumstance, Entergy New Orleans shall be permitted to defer the New Orleans Power Station non-fuel costs, including the cost of capital, until Entergy New Orleans commences non-fuel cost recovery. After taking into account the requirements for submission of the compliance filing, the total annual revenue requirement reduction required by the resolution was refined to approximately $45 million ($42 million electric, including $29 million in rider reductions; $3 million gas). In January
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2020 the City Council’s advisors found that the rates calculated by Entergy New Orleans and reflected in the December 2019 compliance filing should be implemented, except with respect to the City Council-approved energy efficiency cost recovery rider, which rider calculation should take into account events to be determined by the City Council in the future. Also in response to the resolution, Entergy New Orleans filed timely a petition for appeal and judicial review and for stay of or injunctive relief alleging that the resolution is unlawful in failing to produce just and reasonable rates. Based on the general acceptance of Entergy New Orleans’s compliance filing, however, during the pendency of its appeal Entergy New Orleans expects to implement the compliance filing rates in April 2020. A hearing on the requested injunction was scheduled in Civil District Court for February 2020, but by joint motion of the City Council and Entergy New Orleans, the Civil District Court issued an order for a limited remand to the City Council to consider a potential agreement in principle/stipulation at its February 20, 2020 meeting. On February 17, 2020, Entergy New Orleans filed with the City Council an agreement in principle between Entergy New Orleans and the City Council’s advisors. On February 20, 2020, the full City Council voted to approve the proposed agreement in principle and issued a resolution modifying the required treatment of certain accumulated deferred income taxes. As a result of the agreement in principle, the total annual revenue requirement reduction will be approximately $45 million ($42 million electric, including $29 million in rider reductions; and $3 million gas). As a result, Entergy New Orleans will fully implementimplemented the new rates byin April 2020. The merits of the appeal will be subject to a separate procedural schedule issued by the Civil District Court.
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 and identified a number of quantified and unquantified benefits. Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters. Deployment of the information technology infrastructure began in 2017 and deployment of the communications network began 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 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. In April 2018 the City Council adopted a resolution directing Entergy New Orleans to explore the options for accelerating the deployment of AMI. In June 2018 the City Council approved a one-year acceleration of AMI in its service area for an incremental $4.4 million. Entergy New Orleans began deployment of AMI during the first quarter of 2019 and expects to complete deployment by the end of 2020. Entergy New Orleans will recover the undepreciated balance of its existing meters through a regulatory asset to be amortized on a straight-line basis over 12 years, as approved by the City Council.
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. In May 2017 the City Council adopted a resolution approving the proposed internal restructuring2021, pursuant to an agreement in principle with the City Council advisors and certain intervenors. Pursuant to the agreement in principle approved by the City Council in October 2020, Entergy New Orleans would credit retail customers $10 million in 2017, $1.4 millionfiled with Civil District Court a motion seeking to dismiss its petition for judicial review of the City Council’s resolution in the first quarter2018 combined rate case.
Commercial operation of the year afterNew Orleans Power Station commenced in May 2020. In accordance with the transaction closes, and $117,500 each monthCity Council resolution issued in the second year after the transaction closes until such time as new base rates go into effect as a result of the then-anticipated 2018 base rate case.case proceeding, Entergy New Orleans had been deferring the New Orleans Power Station non-fuel costs pending the conclusion of the appellate proceedings. In October 2020 the Louisiana Supreme Court denied all writ applications relating to the New Orleans Power Station. With those denials, Entergy New Orleans began crediting retailrecovering New Orleans Power Station costs in rates in November 2020. As of December 31, 2020 the regulatory asset for the deferral of New Orleans Power Station non-fuel costs was $5 million. Entergy New Orleans is recovering the costs over a five-year period that began in November 2020. In December 2020 the Alliance for Affordable Energy and Sierra Club filed a joint motion with the City Council to institute a prudence review to investigate the costs of the New Orleans Power Station. On January 28, 2021, the City Council passed a resolution giving parties 30 days to respond to the motion. Entergy New Orleans plans to respond to the motion.
2020 Formula Rate Plan Filing
Entergy New Orleans’s first annual filing under the three-year formula rate plan approved by the City Council in November 2019 was originally due to be filed in April 2020. The authorized return on equity under the approved three-year formula rate plan is 9.35% for both electric and gas operations. The City Council approved several extensions of the deadline to allow additional time to assess the effects of the COVID-19 pandemic on the New Orleans community, Entergy New Orleans customers,
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
in June 2017.
COVID-19 Orders
In June 2017 the FERC approved the transaction and, pursuant to the agreement in principle,March 2020, Entergy New Orleans will provide additional creditsvoluntarily suspended customer disconnections for non-payment of utility bills through May 2020. Subsequently, the City Council ordered that the moratorium be extended to retail customers of $5 million in each ofAugust 1, 2020. In May 2020 the years 2018, 2019, and 2020.
In November 2017,City Council issued an accounting order authorizing Entergy New Orleans undertookto establish a multi-step restructuring, including the following:
regulatory asset for incremental COVID-19-related expenses. In January 2021, Entergy New Orleans Inc. redeemed its outstanding preferred stock atresumed disconnecting service to commercial and small business customers with past-due balances that have not made payment arrangements. In February 2021 the City Council adopted a priceresolution suspending residential customer disconnections for non-payment of approximately $21 million, which included a call premiumutility bills and suspending the assessment and accumulation of approximately $819,000, plus any accumulated and unpaid dividends.
late fees on residential customers with past-due balances through May 15, 2021. As of December 31, 2020, Entergy New Orleans Inc. converted fromrecorded a Louisiana corporation to a Texas corporation.regulatory asset of $14.3 million for costs associated with the COVID-19 pandemic.
Under
In June 2020 the Texas Business Organizations Code (TXBOC),City Council established the City Council Cares Program and directed Entergy New Orleans Inc. allocated substantially allto use the approximately $7 million refund received from the Entergy Arkansas opportunity sales FERC proceeding, currently being held in escrow, and approximately $15 million of its assetsnon-securitized storm reserves to fund this program, which is intended to provide temporary bill relief to customers who become unemployed during the COVID-19 pandemic. The program became effective July 1, 2020, and offers qualifying residential customers bill credits of $100 per month for up to four months, for a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially allmaximum of the liabilities$400 in residential customer bill credits. As of Entergy New Orleans, Inc. in a transaction regarded as a mergerDecember 31, 2020, credits of $3.4 million have been applied to customer bills under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.City Council Cares Program.
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.
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.
Show Cause Order
In July 2016 the City Council approved the issuance of a show cause order, which directed Entergy New Orleans to make a filing on or before September 29, 2016 to demonstrate the reasonableness of its actions or positions with regard to certain issues in four existing dockets that relate to Entergy New Orleans’s: (i) storm hardening proposal; (ii) 2015 integrated resource plan; (iii) gas infrastructure rebuild proposal; and (iv) proposed sizing of the New Orleans Power Station and its community outreach prior to the filing. In September 2016, Entergy New Orleans filed its response to the City Council’s show cause order. The City Council has not established any further procedural schedule with regard to this proceeding.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Reliability Investigation
In August 2017 the City Council established a docket to investigate the reliability of the Entergy New Orleans distribution system and to consider implementing certain reliability standards and possible financial penalties for not meeting any such standards. In April 2018 the City Council adopted a resolution directing Entergy New Orleans to demonstrate that it has been prudent in the management and maintenance of the reliability of its distribution system. The resolution also called for Entergy New Orleans to file a revised reliability plan addressing
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
the current state of its distribution system and proposing remedial measures for increasing reliability. In June 2018, Entergy New Orleans filed its response to the City Council’s resolution regarding the prudence of its management and maintenance of the reliability of its distribution system. In July 2018, Entergy New Orleans filed its revised reliability plan discussing the various reliability programs that it uses to improve distribution system reliability and discussing generally the positive effect that advanced meter deployment and grid modernization can have on future reliability. Entergy New Orleans has retained a national consulting firm with expertise in distribution system reliability to conduct a review of Entergy New Orleans’s distribution system reliability-related practices and procedures and to provide recommendations for improving distribution system reliability. The report was filed with the City Council in October 2018. The City Council also approved a resolution that opens a prudence investigation into whether Entergy New Orleans was imprudent for not acting sooner to address outages in New Orleans and whether fines should be imposed. In January 2019, Entergy New Orleans filed testimony in response to the prudence investigation and asserting that it had been prudent in managing system reliability. In April 2019 the City Council advisors filed comments and testimony asserting that Entergy New Orleans did not act prudently in maintaining and improving its distribution system reliability in recent years and recommending that a financial penalty in the range of $1.5 million to $2 million should be assessed. Entergy New Orleans disagrees with the recommendation and submitted rebuttal testimony and rebuttal comments in June 2019. In November 2019 the City Council passed a resolution that penalized Entergy New Orleans $1 million for alleged imprudence in the maintenance of its distribution system. In December 2019, Entergy New Orleans filed suit in Louisiana state court seeking judicial review of the City Council’s resolution. Although the City Council evidentiary record has been lodged with the Civil District count, the court has not yet established a briefing schedule.
Renewable Portfolio Standard Rulemaking
In March 2019 the City Council initiated a rulemaking proceeding to consider whether to establish a renewable portfolio standard. The rulemaking will consider, among other issues, whether to adopt a renewable portfolio standard, whether such standard should be voluntary or mandatory, what kinds of technologies should qualify for inclusion in the rules, what level, if any, of renewable generation should be required, and whether penalties are an appropriate component of the proposed rules. Parties to the proceeding submitted initial comments in June 2019 and reply comments in July 2019. Entergy New Orleans recommends that the City Council adopt a voluntary clean energy standard of 70% of generation being clean energy by 2030, as so defined, which, in addition to renewable generation, would include nuclear, beneficial electrification, and demand-side management as compliant technologies. Several other industry leaders, academic researchers, and environmental advocates filed comments also supporting a clean energy standard. Other parties, including many representatives of the solar and wind industry, are recommending mandatory, renewables-only requirements of up to 100% renewable resources by 2040. In September 2019 the City Council advisors issued a report and recommendations, which also put forth three alternative rules for comment from the parties. Comments were submitted in October 2019 and replies were filed in November 2019. FurtherIn March 2020 the City Council’s Utility Committee recommended a resolution for approval by the City Council action, includingthat directed the establishmentCity Council advisors to work toward development of additional procedural stepsa rule for enacting a Renewable and Clean Portfolio Standard. The four components of the rulemaking,Renewable and Clean Portfolio Standard that the City Council expressed a desire to implement are: (1) a mandatory requirement that Entergy New Orleans achieve 100% net zero carbon emissions by 2040; (2) reliance on renewable energy credits purchased without the associated energy for compliance with the standard being phased out over the ten-year period from 2040 to 2050; (3) no carbon-emitting resources in the portfolio of resources Entergy New Orleans uses to serve New Orleans by 2050; and (4) a mechanism to limit costs in any one plan year to no more than one percent of plan year total utility retail sales revenues. The City Council adopted the Utility Committee resolution in April 2020. The first technical meeting of the parties occurred in June 2020; a second technical meeting occurred in July 2020. In August 2020 the City Council advisors issued a final draft of the rules for review and comment from the parties before final rules are proposed for consideration by the City Council. Entergy New Orleans filed comments in September and October 2020. A City Council decision is expected in the first quarter 2021.
Management’s Financial Discussion and Analysis
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 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, 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 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.
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 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 Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 New Orleans, 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 2021 Qualified Pension Cost | | Impact on 2020 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $303 | | $5,858 |
| Rate of return on plan assets | | (0.25%) | | $388 | | $— |
| Rate of increase in compensation | | 0.25% | | $225 | | $1,060 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Qualified Pension Cost | | Impact on 2019 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $334 | | $5,567 |
| Rate of return on plan assets | | (0.25%) | | $376 | | $— |
| Rate of increase in compensation | | 0.25% | | $209 | | $1,118 |
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 2021 Postretirement Benefit Cost | | Impact on 2020 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $76 | | $893 |
| Health care cost trend | | 0.25% | | $82 | | $571 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Postretirement Benefit Cost | | Impact on 2019 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $61 | | $950 |
| Health care cost trend | | 0.25% | | $97 | | $665 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy New Orleans in 20192020 was $5.1$6 million. Entergy New Orleans anticipates 20202021 qualified pension cost to be $6$5.9 million. Entergy New Orleans contributed $4.6 million to its qualified pension plans in 20192020 and estimates 20202021 pension contributions will be approximately $3.2$5.4 million, although the 20202021 required pension contributions will be known with more certainty when the January 1, 20202021 valuations are completed, which is expected by April 1, 2020.2021.
Total postretirement health care and life insurance benefit income for Entergy New Orleans in 20192020 was $3.5$4.9 million. Entergy New Orleans expects 20202021 postretirement health care and life insurance benefit income of approximately $4.3$6.4 million. Entergy New Orleans contributed $1.7 million$641 thousand to its other postretirement plans in 20192020 and estimates 20202021 contributions will be approximately $162$175 thousand.
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 member and Board of Directors of
Entergy New Orleans, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy New Orleans, LLC and Subsidiaries (the “Company”) as of December 31, 20192020 and 2018,2019, the related consolidated statements of income, cash flows, and changes in member’s equity (pages 386402 through 390406 and applicable items in pages 4951 through 236)238), for each of the three years in the period ended December 31, 2019,2020, 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, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2020, 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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters— Entergy New Orleans, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Council of the City of New Orleans, Louisiana (the “City Council”), which has jurisdiction with respect to the rates of electric companies in the City of New Orleans, Louisiana, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based
rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the City Council and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses 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. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the City Council and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the City Council and the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the City Council and the FERC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the City Council and the FERC for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the City Council’s and the FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected the Company’s filings with the City Council and the FERC, including the base rate case filing, and considered the filings with the City Council and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202026, 2021
We have served as the Company’s auditor since 2001.
|
| | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $594,417 |
| |
| $624,733 |
| |
| $631,744 |
|
| Natural gas | | 91,806 |
| | 92,657 |
| | 84,326 |
|
| TOTAL | | 686,223 |
| | 717,390 |
| | 716,070 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 105,217 |
| | 114,787 |
| | 111,082 |
|
| Purchased power | | 258,306 |
| | 270,634 |
| | 282,178 |
|
| Other operation and maintenance | | 121,057 |
| | 124,293 |
| | 107,977 |
|
| Taxes other than income taxes | | 55,270 |
| | 56,141 |
| | 54,590 |
|
| Depreciation and amortization | | 56,072 |
| | 55,930 |
| | 52,945 |
|
| Other regulatory charges - net | | 21,616 |
| | 21,413 |
| | 10,889 |
|
| TOTAL | | 617,538 |
| | 643,198 |
| | 619,661 |
|
| | | | | | | |
| OPERATING INCOME | | 68,685 |
| | 74,192 |
| | 96,409 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 9,941 |
| | 5,941 |
| | 2,418 |
|
| Interest and investment income | | 428 |
| | 604 |
| | 707 |
|
| Miscellaneous - net | | (6,038 | ) | | (10,444 | ) | | (1,269 | ) |
| TOTAL | | 4,331 |
| | (3,899 | ) | | 1,856 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 24,463 |
| | 21,772 |
| | 21,281 |
|
| Allowance for borrowed funds used during construction | | (4,262 | ) | | (2,195 | ) | | (847 | ) |
| TOTAL | | 20,201 |
| | 19,577 |
| | 20,434 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 52,815 |
| | 50,716 |
| | 77,831 |
|
| | | | | | | |
| Income taxes | | 186 |
| | (2,436 | ) | | 33,278 |
|
| | | | | | | |
| NET INCOME | | 52,629 |
| | 53,152 |
| | 44,553 |
|
| | | | | | | |
| Preferred dividend requirements and other | | — |
| | — |
| | 841 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | |
| $52,629 |
| |
| $53,152 |
| |
| $43,712 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $560,632 | | | $594,417 | | | $624,733 | |
| Natural gas | | 73,209 | | | 91,806 | | | 92,657 | |
| TOTAL | | 633,841 | | | 686,223 | | | 717,390 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 76,781 | | | 105,217 | | | 114,787 | |
| Purchased power | | 243,572 | | | 258,306 | | | 270,634 | |
| Other operation and maintenance | | 125,756 | | | 121,057 | | | 124,293 | |
| Taxes other than income taxes | | 57,454 | | | 55,270 | | | 56,141 | |
| Depreciation and amortization | | 64,012 | | | 56,072 | | | 55,930 | |
| Other regulatory charges - net | | 1,854 | | | 21,616 | | | 21,413 | |
| TOTAL | | 569,429 | | | 617,538 | | | 643,198 | |
| | | | | | |
| OPERATING INCOME | | 64,412 | | | 68,685 | | | 74,192 | |
| | | | | | |
| OTHER INCOME (DEDUCTIONS) | | | | | | |
| Allowance for equity funds used during construction | | 6,339 | | | 9,941 | | | 5,941 | |
| Interest and investment income | | 120 | | | 428 | | | 604 | |
| Miscellaneous - net | | 316 | | | (6,038) | | | (10,444) | |
| TOTAL | | 6,775 | | | 4,331 | | | (3,899) | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 29,105 | | | 24,463 | | | 21,772 | |
| Allowance for borrowed funds used during construction | | (3,049) | | | (4,262) | | | (2,195) | |
| TOTAL | | 26,056 | | | 20,201 | | | 19,577 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 45,131 | | | 52,815 | | | 50,716 | |
| | | | | | |
| Income taxes | | (4,207) | | | 186 | | | (2,436) | |
| | | | | | |
| NET INCOME | | $49,338 | | | $52,629 | | | $53,152 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $52,629 |
| |
| $53,152 |
| |
| $44,553 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 56,072 |
| | 55,930 |
| | 52,945 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 21,350 |
| | 24,548 |
| | 64,036 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | (9,372 | ) | | 15,724 |
| | (18,058 | ) |
| Fuel inventory | | (387 | ) | | 357 |
| | (49 | ) |
| Accounts payable | | (5,571 | ) | | (385 | ) | | 1,874 |
|
| Prepaid taxes and taxes accrued | | 234 |
| | 30,547 |
| | (22,100 | ) |
| Interest accrued | | 550 |
| | 879 |
| | 44 |
|
| Deferred fuel costs | | 3,630 |
| | (6,486 | ) | | 12,592 |
|
| Other working capital accounts | | 5,021 |
| | 4,146 |
| | (2,711 | ) |
| Provisions for estimated losses | | 1,948 |
| | 1,511 |
| | (3,430 | ) |
| Other regulatory assets | | (29,567 | ) | | 21,637 |
| | 16,673 |
|
| Other regulatory liabilities | | (22,105 | ) | | (28,459 | ) | | 110,147 |
|
Deferred tax rate change recognized as regulatory liability/asset
| | — |
| | — |
| | (111,170 | ) |
| Pension and other postretirement liabilities | | (14,624 | ) | | (15,134 | ) | | (15,994 | ) |
| Other assets and liabilities | | 55,796 |
| | 13,811 |
| | (1,555 | ) |
| Net cash flow provided by operating activities | | 115,604 |
| | 171,778 |
| | 127,797 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (229,560 | ) | | (202,186 | ) | | (115,584 | ) |
| Allowance for equity funds used during construction | | 9,941 |
| | 5,941 |
| | 2,418 |
|
| Changes in money pool receivable - net | | 16,825 |
| | (9,293 | ) | | 1,492 |
|
| Payments to storm reserve escrow account | | (1,752 | ) | | (1,311 | ) | | (597 | ) |
| Receipts from storm reserve escrow account | | — |
| | 3 |
| | 2,488 |
|
| Changes in securitization account | | 236 |
| | (770 | ) | | 283 |
|
| Net cash flow used in investing activities | | (204,310 | ) | | (207,616 | ) | | (109,500 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 113,876 |
| | 59,234 |
| | — |
|
| Retirement of long-term debt | | (35,376 | ) | | (11,042 | ) | | (10,600 | ) |
| Repayment of long-term payable due to associated company | | (1,979 | ) | | (2,077 | ) | | (2,104 | ) |
Redemption of preferred stock
| | — |
| | — |
| | (20,599 | ) |
| Capital contributions from parent | | — |
| | — |
| | 20,000 |
|
| Distributions/dividends paid: | | |
| | |
| | |
|
| Common equity | | — |
| | (23,750 | ) | | (74,250 | ) |
| Preferred stock | | — |
| | — |
| | (1,083 | ) |
| Other | | (1,475 | ) | | 409 |
| | 12 |
|
| Net cash flow provided by (used in) financing activities | | 75,046 |
| | 22,774 |
| | (88,624 | ) |
| Net decrease in cash and cash equivalents | | (13,660 | ) | | (13,064 | ) | | (70,327 | ) |
| Cash and cash equivalents at beginning of period | | 19,677 |
| | 32,741 |
| | 103,068 |
|
| Cash and cash equivalents at end of period | |
| $6,017 |
| |
| $19,677 |
| |
| $32,741 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $22,873 |
| |
| $19,840 |
| |
| $20,180 |
|
| Income taxes | |
| ($5,310 | ) | |
| ($39,781 | ) | |
| ($8,660 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $49,338 | | | $52,629 | | | $53,152 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 64,012 | | | 56,072 | | | 55,930 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 3,938 | | | 21,350 | | | 24,548 | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (12,003) | | | (9,372) | | | 15,724 | |
| Fuel inventory | | (58) | | | (387) | | | 357 | |
| Accounts payable | | 5,582 | | | (5,571) | | | (385) | |
| Taxes accrued | | 398 | | | 234 | | | 30,547 | |
| Interest accrued | | 1,179 | | | 550 | | | 879 | |
| Deferred fuel costs | | (7,048) | | | 3,630 | | | (6,486) | |
| Other working capital accounts | | (13,156) | | | 5,021 | | | 4,146 | |
| Provisions for estimated losses | | 1,356 | | | 1,948 | | | 1,511 | |
| Other regulatory assets | | (7,427) | | | (29,567) | | | 21,637 | |
| Other regulatory liabilities | | (4,728) | | | (22,105) | | | (28,459) | |
| Pension and other postretirement liabilities | | (14,063) | | | (14,624) | | | (15,134) | |
| Other assets and liabilities | | (3,296) | | | 55,796 | | | 13,811 | |
| Net cash flow provided by operating activities | | 64,024 | | | 115,604 | | | 171,778 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (228,983) | | | (229,560) | | | (202,186) | |
| Allowance for equity funds used during construction | | 6,339 | | | 9,941 | | | 5,941 | |
| Payment for purchase of assets | | (1,584) | | | 0 | | | 0 | |
| | | | | | |
| | | | | | |
| Changes in money pool receivable - net | | 5,191 | | | 16,825 | | | (9,293) | |
| Payments to storm reserve escrow account | | (433) | | | (1,752) | | | (1,311) | |
| Receipts from storm reserve escrow account | | 0 | | | 0 | | | 3 | |
| Changes in securitization account | | (1,375) | | | 236 | | | (770) | |
| Net cash flow used in investing activities | | (220,845) | | | (204,310) | | | (207,616) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 138,925 | | | 113,876 | | | 59,234 | |
| Retirement of long-term debt | | (56,593) | | | (35,376) | | | (11,042) | |
| Repayment of long-term payable due to associated company | | (1,838) | | | (1,979) | | | (2,077) | |
| | | | | | |
| Capital contributions from parent | | 60,000 | | | 0 | | | 0 | |
| | | | | | |
| Changes in money pool payable - net | | 10,190 | | | 0 | | | 0 | |
| | | | | | |
| Common equity distributions paid | | 0 | | | 0 | | | (23,750) | |
| | | | | | |
| Other | | 146 | | | (1,475) | | | 409 | |
| Net cash flow provided by financing activities | | 150,830 | | | 75,046 | | | 22,774 | |
| Net decrease in cash and cash equivalents | | (5,991) | | | (13,660) | | | (13,064) | |
| Cash and cash equivalents at beginning of period | | 6,017 | | | 19,677 | | | 32,741 | |
| Cash and cash equivalents at end of period | | $26 | | | $6,017 | | | $19,677 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $26,673 | | | $22,873 | | | $19,840 | |
| Income taxes | | $3,392 | | | ($5,310) | | | ($39,781) | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents | | | | |
| Cash | |
| $26 |
| |
| $26 |
|
| Temporary cash investments | | 5,991 |
| | 19,651 |
|
| Total cash and cash equivalents | | 6,017 |
| | 19,677 |
|
| Securitization recovery trust account | | 1,989 |
| | 2,224 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 48,265 |
| | 43,890 |
|
| Allowance for doubtful accounts | | (3,226 | ) | | (3,222 | ) |
| Associated companies | | 6,280 |
| | 27,938 |
|
| Other | | 7,378 |
| | 4,090 |
|
| Accrued unbilled revenues | | 25,453 |
| | 18,907 |
|
| Total accounts receivable | | 84,150 |
| | 91,603 |
|
| Fuel inventory - at average cost | | 1,920 |
| | 1,533 |
|
| Materials and supplies - at average cost | | 13,522 |
| | 12,133 |
|
| Prepayments and other | | 4,846 |
| | 6,905 |
|
| TOTAL | | 112,444 |
|
| 134,075 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Non-utility property at cost (less accumulated depreciation) | | 1,016 |
| | 1,016 |
|
| Storm reserve escrow account | | 82,605 |
| | 80,853 |
|
| TOTAL | | 83,621 |
| | 81,869 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 1,467,215 |
| | 1,364,091 |
|
| Natural gas | | 311,432 |
| | 284,728 |
|
| Construction work in progress | | 201,829 |
| | 146,668 |
|
| TOTAL UTILITY PLANT | | 1,980,476 |
| | 1,795,487 |
|
| Less - accumulated depreciation and amortization | | 715,406 |
| | 670,135 |
|
| UTILITY PLANT - NET | | 1,265,070 |
| | 1,125,352 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Deferred fuel costs | | 4,080 |
| | 4,080 |
|
| Other regulatory assets (includes securitization property of $49,542 as of December 31, 2019 and $60,453 as of December 31, 2018) | | 259,363 |
| | 229,796 |
|
| Other | | 10,720 |
| | 1,416 |
|
| TOTAL | | 274,163 |
| | 235,292 |
|
| | | | | |
| TOTAL ASSETS | |
| $1,735,298 |
| |
| $1,576,588 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2020 | | 2019 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents | | | | |
| Cash | | $26 | | | $26 | |
| Temporary cash investments | | 0 | | | 5,991 | |
| Total cash and cash equivalents | | 26 | | | 6,017 | |
| Securitization recovery trust account | | 3,364 | | | 1,989 | |
| Accounts receivable: | | | | |
| Customer | | 70,694 | | | 48,265 | |
| Allowance for doubtful accounts | | (17,430) | | | (3,226) | |
| Associated companies | | 2,381 | | | 6,280 | |
| Other | | 4,248 | | | 7,378 | |
| Accrued unbilled revenues | | 31,069 | | | 25,453 | |
| Total accounts receivable | | 90,962 | | | 84,150 | |
| | | | |
| Deferred fuel costs | | 2,130 | | | 0 | |
| Fuel inventory - at average cost | | 1,978 | | | 1,920 | |
| Materials and supplies - at average cost | | 16,550 | | | 13,522 | |
| | | | |
| Prepayments and other | | 3,715 | | | 4,846 | |
| TOTAL | | 118,725 | | | 112,444 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Non-utility property at cost (less accumulated depreciation) | | 1,016 | | | 1,016 | |
| Storm reserve escrow account | | 83,038 | | | 82,605 | |
| | | | |
| TOTAL | | 84,054 | | | 83,621 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 1,821,638 | | | 1,467,215 | |
| Natural gas | | 348,024 | | | 311,432 | |
| Construction work in progress | | 12,460 | | | 201,829 | |
| TOTAL UTILITY PLANT | | 2,182,122 | | | 1,980,476 | |
| Less - accumulated depreciation and amortization | | 740,796 | | | 715,406 | |
| UTILITY PLANT - NET | | 1,441,326 | | | 1,265,070 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Deferred fuel costs | | 4,080 | | | 4,080 | |
| Other regulatory assets (includes securitization property of $35,559 as of December 31, 2020 and $49,542 as of December 31, 2019) | | 266,790 | | | 259,363 | |
| Other | | 23,931 | | | 10,720 | |
| TOTAL | | 294,801 | | | 274,163 | |
| | | | |
| TOTAL ASSETS | | $1,938,906 | | | $1,735,298 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES | ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES | ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | LIABILITIES AND EQUITY |
| | | December 31, | | | December 31, |
| | | 2019 | | 2018 | | | 2020 | | 2019 |
| | | (In Thousands) | | | (In Thousands) |
| | | | | | |
| CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $25,000 |
| |
| $— |
| Currently maturing long-term debt | | $0 | | | $25,000 | |
| Payable due to associated company | | 1,838 |
| | 1,979 |
| Payable due to associated company | | 1,618 | | | 1,838 | |
| Accounts payable: | | |
| | |
| Accounts payable: | | | | |
| Associated companies | | 43,222 |
| | 43,416 |
| Associated companies | | 54,234 | | | 43,222 | |
| Other | | 43,963 |
| | 36,686 |
| Other | | 60,766 | | | 43,963 | |
| Customer deposits | | 28,493 |
| | 28,667 |
| Customer deposits | | 27,912 | | | 28,493 | |
| Taxes accrued | | 4,302 |
| | 4,068 |
| Taxes accrued | | 4,700 | | | 4,302 | |
| Interest accrued | | 6,916 |
| | 6,366 |
| Interest accrued | | 8,095 | | | 6,916 | |
| Deferred fuel costs | | 4,918 |
| | 1,288 |
| Deferred fuel costs | | 0 | | | 4,918 | |
| Current portion of unprotected excess accumulated deferred income taxes | | 9,470 |
| | 25,301 |
| Current portion of unprotected excess accumulated deferred income taxes | | 3,296 | | | 9,470 | |
| | Other | | 15,827 |
| | 9,521 |
| Other | | 5,462 | | | 15,827 | |
| TOTAL CURRENT LIABILITIES | | 183,949 |
| | 157,292 |
| TOTAL CURRENT LIABILITIES | | 166,083 | | | 183,949 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 354,536 |
| | 323,595 |
| Accumulated deferred income taxes and taxes accrued | | 338,714 | | | 354,536 | |
| Accumulated deferred investment tax credits | | 2,131 |
| | 2,219 |
| Accumulated deferred investment tax credits | | 16,095 | | | 2,131 | |
| Regulatory liability for income taxes - net | | 49,090 |
| | 60,249 |
| Regulatory liability for income taxes - net | | 55,675 | | | 49,090 | |
| Asset retirement cost liabilities | | 3,522 |
| | 3,291 |
| Asset retirement cost liabilities | | 3,768 | | | 3,522 | |
| Accumulated provisions | | 88,542 |
| | 86,594 |
| Accumulated provisions | | 89,898 | | | 88,542 | |
| Long-term debt (includes securitization bonds of $52,641 as of December 31, 2019 and $63,620 as of December 31, 2018) | | 521,539 |
| | 467,358 |
| |
| | Long-term debt (includes securitization bonds of $41,291 as of December 31, 2020 and $52,641 as of December 31, 2019) | | Long-term debt (includes securitization bonds of $41,291 as of December 31, 2020 and $52,641 as of December 31, 2019) | | 629,704 | | | 521,539 | |
| Long-term payable due to associated company | | 12,529 |
| | 14,367 |
| Long-term payable due to associated company | | 10,911 | | | 12,529 | |
| Other | | 21,881 |
| | 16,673 |
| Other | | 21,141 | | | 21,881 | |
| TOTAL NON-CURRENT LIABILITIES | | 1,053,770 |
| | 974,346 |
| TOTAL NON-CURRENT LIABILITIES | | 1,165,906 | | | 1,053,770 | |
| | | | | | | | | |
| Commitments and Contingencies | |
|
| |
|
| Commitments and Contingencies | | 0 | | 0 |
| | | | | | |
| EQUITY | | |
| | |
| EQUITY | | | | |
| Member's equity | | 497,579 |
| | 444,950 |
| Member's equity | | 606,917 | | | 497,579 | |
| TOTAL | | 497,579 |
| | 444,950 |
| TOTAL | | 606,917 | | | 497,579 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $1,735,298 |
| |
| $1,576,588 |
| TOTAL LIABILITIES AND EQUITY | | $1,938,906 | | | $1,735,298 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| 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, 2020, 2019, 2018, and 20172018 |
| | |
| |
| Member’s Equity |
| | (In Thousands) |
| | |
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 |
|
| Net income | 53,152 |
| |
| | |
| Common equity distributions | (23,750 | )(23,750) | |
| | |
| | |
| Balance at December 31, 2018 |
| $444,950 |
|
| Net income | 52,629 |
| |
| | |
| | |
| | |
| | |
| Balance at December 31, 2019 |
| $497,579 |
|
| Net income | | 49,338 | |
| Capital contributions from parent | | 60,000 | |
| | |
| | |
| | |
| Balance at December 31, 2020 | | $606,917 | |
| | |
| See Notes to Financial Statements. | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $686,223 |
| |
| $717,390 |
| |
| $716,070 |
| |
| $665,463 |
| |
| $671,446 |
|
| Net income |
| $52,629 |
| |
| $53,152 |
| |
| $44,553 |
| |
| $48,849 |
| |
| $44,925 |
|
| Total assets |
| $1,735,298 |
| |
| $1,576,588 |
| |
| $1,497,836 |
| |
| $1,494,569 |
| |
| $1,215,144 |
|
| Long-term obligations (a) |
| $534,068 |
| |
| $481,725 |
| |
| $434,793 |
| |
| $466,670 |
| |
| $357,687 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (including the long-term payable to associated company and excluding currently maturing debt) and preferred stock without sinking fund. |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $245 |
| |
| $262 |
| |
| $250 |
| |
| $231 |
| |
| $220 |
|
| Commercial | 202 |
| | 217 |
| | 228 |
| | 206 |
| | 186 |
|
| Industrial | 32 |
| | 33 |
| | 36 |
| | 33 |
| | 30 |
|
| Governmental | 71 |
| | 72 |
| | 77 |
| | 69 |
| | 64 |
|
| Total billed retail | 550 |
| | 584 |
| | 591 |
| | 539 |
| | 500 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | — |
| | — |
| | — |
| | 30 |
| | 66 |
|
| Non-associated companies | 38 |
| | 30 |
| | 29 |
| | 3 |
| | — |
|
| Other | 6 |
| | 11 |
| | 12 |
| | 15 |
| | 18 |
|
| Total |
| $594 |
| |
| $625 |
| |
| $632 |
| |
| $587 |
| |
| $584 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
|
| Residential | 2,353 |
| | 2,401 |
| | 2,155 |
| | 2,231 |
| | 2,301 |
|
| Commercial | 2,215 |
| | 2,270 |
| | 2,248 |
| | 2,268 |
| | 2,257 |
|
| Industrial | 438 |
| | 448 |
| | 429 |
| | 441 |
| | 463 |
|
| Governmental | 815 |
| | 795 |
| | 790 |
| | 794 |
| | 825 |
|
| Total retail | 5,821 |
| | 5,914 |
| | 5,622 |
| | 5,734 |
| | 5,846 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | — |
| | — |
| | — |
| | 1,071 |
| | 1,644 |
|
| Non-associated companies | 1,961 |
| | 1,484 |
| | 1,703 |
| | 141 |
| | 11 |
|
| Total | 7,782 |
| | 7,398 |
| | 7,325 |
| | 6,946 |
| | 7,501 |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | |
| | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | (In Thousands) |
| | | | | | | | | |
| Operating revenues | $633,841 | | | $686,223 | | | $717,390 | | | $716,070 | | | $665,463 | |
| Net income | $49,338 | | | $52,629 | | | $53,152 | | | $44,553 | | | $48,849 | |
| Total assets | $1,938,906 | | | $1,735,298 | | | $1,576,588 | | | $1,497,836 | | | $1,494,569 | |
| Long-term obligations (a) | $640,615 | | | $534,068 | | | $481,725 | | | $434,793 | | | $466,670 | |
| | | | | | | | | |
| (a) Includes long-term debt (including the long-term payable to associated company and excluding currently maturing debt) and preferred stock without sinking fund. |
| | | | | | | | | |
| | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | (Dollars In Millions) |
| | | | | | | | | |
| Electric Operating Revenues: | | | | | | | | | |
| Residential | $244 | | | $245 | | | $262 | | | $250 | | | $231 | |
| Commercial | 179 | | | 202 | | | 217 | | | 228 | | | 206 | |
| Industrial | 24 | | | 32 | | | 33 | | | 36 | | | 33 | |
| Governmental | 60 | | | 71 | | | 72 | | | 77 | | | 69 | |
| Total billed retail | 507 | | | 550 | | | 584 | | | 591 | | | 539 | |
| Sales for resale: | | | | | | | | | |
| Associated companies | — | | | — | | | — | | | — | | | 30 | |
| Non-associated companies | 33 | | | 38 | | | 30 | | | 29 | | | 3 | |
| Other | 21 | | | 6 | | | 11 | | | 12 | | | 15 | |
| Total | $561 | | | $594 | | | $625 | | | $632 | | | $587 | |
| | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | |
| Residential | 2,294 | | | 2,353 | | | 2,401 | | | 2,155 | | | 2,231 | |
| Commercial | 1,975 | | | 2,215 | | | 2,270 | | | 2,248 | | | 2,268 | |
| Industrial | 423 | | | 438 | | | 448 | | | 429 | | | 441 | |
| Governmental | 755 | | | 815 | | | 795 | | | 790 | | | 794 | |
| Total retail | 5,447 | | | 5,821 | | | 5,914 | | | 5,622 | | | 5,734 | |
| Sales for resale: | | | | | | | | | |
| Associated companies | — | | | — | | | — | | | — | | | 1,071 | |
| Non-associated companies | 1,969 | | | 1,961 | | | 1,484 | | | 1,703 | | | 141 | |
| Total | 7,416 | | | 7,782 | | | 7,398 | | | 7,325 | | | 6,946 | |
| | | | | | | | | |
| | | | | | | | | |
ENTERGY TEXAS, INC. AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
Hurricane Laura and Hurricane Delta
In August 2020 and October 2020, Hurricane Laura and Hurricane Delta caused extensive damage to Entergy Texas’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution and transmission infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair and/or replacement of Entergy Texas’s electric facilities damaged by Hurricane Laura and Hurricane Delta are currently estimated to be approximately $300 million, including $245 million in capital costs and approximately $55 million in non-capital costs. Entergy Texas is considering all available avenues to recover storm-related costs from Hurricanes Laura and Hurricane Delta, including securitization. Storm cost recovery or financing will be subject to review by applicable regulatory authorities.
Entergy Texas recorded accounts payable and corresponding construction work in progress and regulatory assets for the estimated costs incurred that were necessary to return customers to service. Entergy Texas recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles. Because Entergy Texas has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy Texas is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Texas’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $12 million. Natural gas purchases for Entergy Texas for February 1st through 25th, 2021 are approximately $155 million compared to natural gas purchases for February 2020 of $10 million.
Results of Operations
20192020 Compared to 20182019
Net Income
Net income decreased $2.8increased $55.7 million primarily due to higher retail electric price, higher other income, lower other operation and maintenance expenses, a higherlower effective income tax rate, after excluding the effect of the return of unprotected excess accumulated deferred income taxes to customers which is offset in operating revenues,income taxes, and higher volume/weather. The increase was partially offset by higher depreciation and amortization expensesexpenses.
Entergy Texas, Inc. and higher other operationSubsidiaries
Management’s Financial Discussion and maintenance expenses, partially offset by higher retail electric price and higher other income.Analysis
Operating Revenues
Following is an analysis of the change in operating revenue comparing 20192020 to 2018.
|
| | | | |
| Amount |
| (In Millions) |
| |
|
20182019 operating revenues |
| $1,605.9 |
|
| Fuel, rider, and other revenues that do not significantly affect net income | (88.44.4 | ) |
| Return of unprotected excess accumulated deferred income taxes to customers | (72.858.6 | ) |
| Retail electric price | 41.028.1 |
|
| Volume/weather | 3.37.0 |
|
20192020 operating revenues |
| $1,489.0 |
|
Entergy Texas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a rider effective October 2018. In 2019, $87.42020, $28.8 million was returned to customers as compared to $14.6$87.4 million in 2018.2019. There is no effect on net income as the reduction in operating revenues is offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
The retail electric price variance is primarily due to a base ratean increase in the transmission cost recovery factor rider effective January 2020 and an increase in the distribution cost recovery factor rider effective October 2018 as approved
by the PUCT.2020. See Note 2 to the financial statements for further discussion of the rate case.transmission and distribution cost recovery factor rider filings.
The volume/weather variance is primarily due to an increase in usage during the unbilled sales period.period and an increase in billed residential usage as a result of the COVID-19 pandemic, partially offset by the effect of less favorable weather on residential sales and decreased commercial and industrial usage as a result of the COVID-19 pandemic. The decrease in industrial usage is partially offset by an increase in demand from expansion projects, primarily in the chemicals and transportation industries. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the COVID-19 pandemic.
Other Income Statement Variances
Other operation and maintenance expenses increaseddecreased primarily due to:
an increase•a decrease of $5.1$7.7 million in information technology costsnon-nuclear generation expenses primarily due to highera lower scope of work performed during plant outages in 2020 as compared to the same period in 2019, including a delay in plant outages as a result of the COVID-19 pandemic; and
•a decrease of $3.7 million primarily due to contract costs in 2019 related to applicationsinitiatives to explore new customer products and services.
The decrease was partially offset by $2.3 million of transaction costs incurred in connection with the purchase of the Hardin County Peaking Facility and the partial sale of Montgomery County Power Station.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
and infrastructure support, enhanced cyber security, and upgrades and maintenance;
an increase of $4.7 million in spending on initiatives to explore new customer products and services;
an increase of $3.9 million in fossil-fueled generation expenses primarily due to a higher scope of work performed during plant outages in 2019 as compared to 2018; and
an increase of $3.4 million in distribution operations and asset management costs primarily due to higher contract costs for meter reading services and higher advanced metering customer education costs.
Depreciation and amortization expenses increased primarily as a result of new depreciation rates established in the settlement of the 2018 base rate case anddue to additions to plant in service.
Other regulatory charges (credits) include regulatory charges of $25.4 million recorded in 2018 to reflect the effects of a provision in the settlement reached in the 2018 rate case proceeding to return the benefits of the lower federal income tax rate in 2018 to customers. See Note 2 to the financial statements for discussion of the rate case proceeding.
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 2019,2020, including the Montgomery County Power Station project.
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 2019, including the Montgomery County Power Station project.
The effective income tax rates were 1.4% for 2020 and (51.1%) for 2019 and (19.3%) for 2018.2019. The difference in the effective income tax rate of (51.1%)rates versus the federal statutory rate of 21% for 2020 and 2019 was primarily due to the amortization of excess accumulated deferred income taxestaxes. See Notes 2 and book and tax differences related3 to the allowancefinancial statements for equity funds used during construction. The difference in the effective income tax rate of (19.3%) versus the federal statutory rate of 21% for 2018 was primarily due to the flow through and amortization of excess accumulated deferred income taxes, along with the effect on income tax expensea discussion of the resolution of Entergy Texas’s 2018 base rate proceeding.effects and regulatory activity regarding the Tax Cuts and Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
20182019 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Texas’s Annual Report on Form 10-K for the year ended December 31, 20182019, filed with the SEC on February 21, 2020, for discussion of results of operations for 20182019 compared to 2017.2018.
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, 2018, and 2019 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 the regulatory proceedings that have considered the effects of the Act.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, 2018, and 20172018 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $12,929 | | | $56 | | | $115,513 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 375,325 | | | 286,739 | | | 331,753 | |
| Investing activities | (848,648) | | | (878,280) | | | (395,973) | |
| Financing activities | 708,990 | | | 604,414 | | | (51,237) | |
| Net increase (decrease) in cash and cash equivalents | 235,667 | | | 12,873 | | | (115,457) | |
| | | | | |
| Cash and cash equivalents at end of period | $248,596 | | | $12,929 | | | $56 | |
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $56 |
| |
| $115,513 |
| |
| $6,181 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 286,739 |
| | 331,753 |
| | 301,396 |
|
| Investing activities | (878,280 | ) | | (395,973 | ) | | (383,176 | ) |
| Financing activities | 604,414 |
| | (51,237 | ) | | 191,112 |
|
| Net increase (decrease) in cash and cash equivalents | 12,873 |
| | (115,457 | ) | | 109,332 |
|
| | | | | | |
| Cash and cash equivalents at end of period |
| $12,929 |
| |
| $56 |
| |
| $115,513 |
|
20192020 Compared to 20182019
Operating Activities
Net cash flow provided by operating activities decreased $45increased $88.6 million in 2020 compared to 2019 primarily due to the return of unprotected excess accumulated deferred income taxes to customers and the receipt of $33.2 million in 2018 from Entergy Arkansas as a result of a compliance filing made in response to the FERC’s October 2018 order in the Entergy Arkansas opportunity sales proceeding. The decrease was partially offset by the timing of recovery of fuel and purchased power costs and a decrease in the timingreturn of collectionunprotected excess accumulated deferred income taxes to customers. The increase was partially offset by lower collections of receivables from customers.customers, in part due to the COVID-19 pandemic, and increased storm spending. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding and regulatory activity regarding the Tax Cuts and Jobs Act. See “Hurricane Laura and Hurricane Delta” above for discussion of hurricane restoration efforts.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Investing Activities
Net cash flow used in investing activities increased $482.3decreased $29.6 million in 20192020 primarily due to:
an increase•a decrease of $243.3$158.8 million in fossil-fuelednon-nuclear generation construction expenditures primarily due to increased spending on the Montgomery County Power Station;Station in 2020 as compared to 2019;
an increase•a decrease of $153.4$9.9 million in transmission constructioninformation technology capital expenditures primarily due to a higher scope of work performed in 2019 as compared to 2018;decreased spending on various technology projects; and
•money pool activity.
The decrease was partially offset by:
•an increase of $47.1$93.8 million in storm spending in 2020, primarily due to Hurricane Laura and Hurricane Delta restoration efforts. See “Hurricane Laura and Hurricane Delta” above for discussion of hurricane restoration efforts;
•an increase of $43.9 million in distribution construction expenditures, primarily due to investment in the reliability and infrastructure of Entergy Texas’s distribution system, including increased spending on advanced metering infrastructure,infrastructure; and increased storm spending; and
money pool activity.•an increase of $29.8 million in transmission construction expenditures primarily due to a higher scope of work performed in 2020 as compared to 2019.
IncreasesDecreases in Entergy Texas’s receivable from the money pool are a usesource of cash flow, and Entergy Texas’s receivable from the money pool increaseddecreased by $6.6 million in 2020 compared to increasing $11.2 million in 2019 compared to decreasing $44.9 million in 2018.2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Entergy Texas’sNet cash flow provided by financing activities provided $604.4increased $104.6 million of cash in 2019from 2020 compared to using $51.2 million of cash in 20182019 primarily due to:
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
the issuance of $600 million of 1.75% Series mortgage bonds in October 2020;
•the repayment, at maturity, of $500 million of 7.125% Series mortgage bonds in February 2019;
•the issuance of $175 million of 3.55% Series mortgage bonds in March 2020; and
•money pool activity.
The increase was partially offset by:
•the issuances of $300 million of 4.0% Series mortgage bonds and $400 million of 4.5% Series mortgage bonds, each in January 2019;
•the issuance of $300 million of 3.55% Series mortgage bonds in September 2019;
capital contributions•the repayment of $185$135 million of 5.625% Series mortgage bonds in 2019 received from Entergy Corporation in anticipation of upcoming construction expenditures, including Montgomery County Power Station; andNovember 2020;
•the issuance of $35 million aggregate liquidation value 5.375% Series A preferred stock in September 2019.2019; and
The increase was partially offset by •the repayment, at maturity,payment of $500$30 million of 7.125% Series mortgage bondscommon stock dividends in 2020. No common stock dividends were paid in 2019 as a result of upcoming capital expenditures, including Montgomery County Power Station.
February 2019 and money pool activity. See Note 5 to the financial statements for more details on long-term debt. See Note 6 to the financial statements for more details on the issuance of preferred stock.
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 $22.4 million in 2019 compared to increasing by $22.4 million in 2018.2019.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
2019 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Texas’s Annual Report on Form 10-K for the year ended December 31, 20182019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 20182019 compared to 2017.2018.
Capital Structure
Entergy Texas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio
for Entergy Texas is primarily due to the net issuance of $500$640 million of mortgage bonds in 2019,2020, partially offset by the $175 million capital contribution received from Entergy Corporation in 2020 and net income in 2020.
an increase in equity. | | | | | | | | | | | |
| | December 31,
2020 | | December 31,
2019 |
| Debt to capital | 53.7 | % | | 51.7 | % |
| Effect of excluding the securitization bonds | (1.3 | %) | | (2.8 | %) |
| Debt to capital, excluding securitization bonds (a) | 52.4 | % | | 48.9 | % |
| Effect of subtracting cash | (2.7 | %) | | (0.2 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 49.7 | % | | 48.7 | % |
|
| | | | | |
| | December 31,
2019 | | December 31,
2018 |
| Debt to capital | 51.7 | % | | 51.6 | % |
| Effect of excluding the securitization bonds | (2.8 | %) | | (5.2 | %) |
| Debt to capital, excluding securitization bonds (a) | 48.9 | % | | 46.4 | % |
| Effect of subtracting cash | (0.2 | %) | | — | % |
| Net debt to net capital, excluding securitization bonds (a) | 48.7 | % | | 46.4 | % |
|
| | | | |
| (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 finance lease obligations and long-term debt, including the currently maturing portion. Capital consists of debt and 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 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 capital structure. In addition, Entergy Texas may receive equity
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
contributions to maintain its capital structure for certain circumstances such as financing of 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.
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.
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2022 | | 2023 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $95 | | | $40 | | | $490 | |
| Transmission | 115 | | | 125 | | | 180 | |
| Distribution | 245 | | | 285 | | | 295 | |
| Utility Support | 55 | | | 75 | | | 50 | |
| Total | $510 | | | $525 | | | $1,015 | |
|
| | | | | | | | | | | |
| | 2020 | | 2021 | | 2022 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $235 |
| |
| $165 |
| |
| $195 |
|
| Transmission | 265 |
| | 180 |
| | 220 |
|
| Distribution | 150 |
| | 125 |
| | 170 |
|
| Utility Support | 115 |
| | 135 |
| | 130 |
|
| Total |
| $765 |
| |
| $605 |
| |
| $715 |
|
In addition to the planned spending in the table above, Entergy Texas also expects to pay for $180 million of capital investments in 2021 related to Hurricane Laura and Hurricane Delta restoration work that have been accrued as of December 31, 2020.
Following are the amounts of Entergy Texas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| | (In Millions) |
| Long-term debt (a) | $353 | | | $207 | | | $151 | | | $2,163 | | | $2,874 | |
| Operating leases (b) | $5 | | | $7 | | | $3 | | | $1 | | | $16 | |
| Finance leases (b) | $1 | | | $2 | | | $2 | | | $1 | | | $6 | |
| Purchase obligations (c) | $255 | | | $384 | | | $361 | | | $294 | | | $1,294 | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $164 |
| |
| $466 |
| |
| $133 |
| |
| $2,683 |
| |
| $3,446 |
|
| Operating leases (b) |
| $4 |
| |
| $7 |
| |
| $4 |
| |
| $1 |
| |
| $16 |
|
| Finance leases (b) |
| $1 |
| |
| $2 |
| |
| $2 |
| |
| $1 |
| |
| $6 |
|
| Purchase obligations (c) |
| $280 |
| |
| $434 |
| |
| $514 |
| |
| $1,039 |
| |
| $2,267 |
|
(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)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.
| |
(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) | 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 $3.5$7 million to its qualified pension plans and approximately $61$66 thousand to other postretirement health care and life insurance plans in 2020,2021, although the 20202021 required pension contributions will be known with more certainty when the January 1, 20202021 valuations are completed, which is expected by April 1, 2020.2021. 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 $17.5$14.2 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.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Texas includes specific investments such as the MontgomeryLiberty County Power Station;Station and the Hardin County Peaking Facility; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; software and security; 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,
Entergy Texas, Inc. 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 in Note 5 to the financial statements.
As a subsidiary, Entergy Texas dividends its earnings to Entergy Corporation at a percentage determined monthly.
Montgomery County Power Station
Liberty County Solar Facility
In October 2016,September 2020, Entergy Texas filed an application with theseeking PUCT seeking certification that the publicapproval to amend Entergy Texas’s certificate of convenience and necessity to acquire the 100 MW Liberty County Solar Facility and a determination that Entergy Texas’s acquisition of the facility through a tax equity partnership is in the public interest. In its preliminary order, the PUCT determined that, in considering Entergy Texas’s application, it would be served bynot specifically address whether Entergy Texas’s use of a tax equity partnership is in the constructionpublic interest. A procedural schedule was established with a hearing on the merits scheduled in April 2021. Closing is expected to occur in 2023.
Hardin County Peaking Facility
In April 2020, Entergy Texas and East Texas Electric Cooperative, Inc. filed a joint report and application seeking PUCT approvals related to two transactions: (1) Entergy Texas’s acquisition of the Hardin County Peaking Facility from East Texas Electric Cooperative, Inc.; and (2) Entergy Texas’s sale of a 7.55% partial interest in the Montgomery County Power Station a nominal 993 MW combined-cycle generating unitto East Texas Electric Cooperative, Inc. The two transactions, currently scheduled to close in Willis,April 2021 (pending PUCT approval), are interdependent. In October 2020, Entergy 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 thatagreement supporting approval of the transactions. Key provisions of the settlement include: Entergy Texas will propose to depreciate its investment in Hardin County Peaking Facility through the end of 2041; Entergy Texas’s levelrecovery of cost-recovery for generation constructionits investment in Hardin County Peaking Facility will be capped at approximately $36 million; and Entergy Texas will not seek recovery of an acquisition adjustment, if any, or transaction costs for Montgomery County Power Stationeither transaction. The settlement 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 tocurrently pending before 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.PUCT.
Sources of Capital
Entergy Texas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•debt or preferred stock issuances;issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; 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.
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.
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | | 2017 |
| (In Thousands) |
| $4,601 | | $11,181 | | ($22,389) | | $44,903 |
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
|
| | | | | | |
| 2019 | | 2018 | | 2017 | | 2016 |
| (In Thousands) |
| $11,181 | | ($22,389) | | $44,903 | | $681 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Texas has a credit facility in the amount of $150 million scheduled to expire in September 2024. The credit facility includes fronting commitments for the issuance of letters of credit against $30 million of the borrowing capacity of the facility. As of December 31, 2019,2020, there were no cash borrowings and $1.3 million of letters of credit outstanding under the credit facility. In addition, Entergy Texas 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, 2019, a $12.12020, $6.2 million letterin letters of credit waswere 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 November 2020July 2022 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.
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
2018 Rate Case
In May 2018, Entergy Texas filed a base rate case with the PUCT seeking an increase in base rates and rider rates of approximately $166 million, of which $48 million is associated with moving costs currently being collected through riders into base rates such that the total incremental revenue requirement increase is approximately $118 million. The base rate case was based on a 12-month test year ending December 31, 2017. In addition, Entergy Texas included capital additions placed into service for the period of April 1, 2013 through December 31, 2017, as well as a post-test year adjustment to include capital additions placed in service by June 30, 2018.
In October 2018 the parties filed an unopposed settlement resolving all issues in the proceeding and a motion for interim rates effective for usage on and after October 17, 2018. The unopposed settlement reflects the following terms: a base rate increase of $53.2 million (net of costs realigned from riders and including updated depreciation rates), a $25 million refund to reflect the lower federal income tax rate applicable to Entergy Texas from January 25, 2018 through the date new rates are implemented, $6 million of capitalized skylining tree hazard costs will not be recovered from customers, $242.5 million of protected excess accumulated deferred income taxes, which includes a tax gross-up, will be returned to customers through base rates under the average rate assumption method over the lives of the associated assets, and $185.2 million of unprotected excess accumulated deferred income taxes, which includes a tax gross-up, will be returned to customers through a rider. The unprotected excess accumulated deferred income taxes rider will include carrying charges and will be in effect over a period of 12 months for large customers and over a period of four years for other customers. The settlement also provides for the deferral of $24.5 million of costs associated with the remaining book value of the Neches and Sabine 2 plants, previously taken out of service, to be recovered over a ten-year period and the deferral of $20.5 million of costs associated with Hurricane Harvey to be recovered over a 12-year period, each beginning in October 2018. The settlement provides final resolution of all issues in the matter, including those related to the Tax Act. In October 2018 the ALJ granted the unopposed motion for interim rates to be effective for service rendered on or after October 17, 2018. In December 2018 the PUCT issued an order approving the unopposed settlement.
In January 2019, Entergy Texas filed for recovery of rate case expenses totaling $7.2 million. The amounts requested primarily include internal and external expenses related to litigating the 2018 base rate case. Parties filed testimony in April 2019 recommending a disallowance ranging from $3.2 million to $4.2 million of the $7.2 million requested. In May 2019, Entergy Texas filed rebuttal testimony responding to the parties’ positions. In September 2019 an order was issued abating the procedural schedule and scheduled hearing to allow the finalization of a settlement
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
in principle reached among the parties. The settlement provides for a black box disallowance of $1.4 million. In the third quarter 2019, Entergy Texas recorded a provision for the 2018 base rate case expenses based on the settlement in principle. In October 2019 the settlement was filed for review by the PUCT. In February 2020 the PUCT approved the settlement.
Distribution Cost Recovery Factor (DCRF) Rider
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 staff, 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. 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. DCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the 2018 base rate case discussion.
In March 2019, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The proposed new DCRF rider is designed to collect approximately $3.2 million annually from Entergy Texas’s retail customers based on its capital invested in distribution between January 1, 2018 and December 31, 2018. In September 2019 the PUCT issued an order approving rates, which had been effective on an interim basis since June 2019, at the level proposed in Entergy Texas’s application.
Transmission Cost Recovery Factor (TCRF) Rider
In September 2016,March 2020, Entergy Texas filed with the PUCT a request to amend its TCRFDCRF rider. The proposed amended TCRF rider wasis designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers.customers approximately $23.6 million annually, or $20.4 million in incremental annual DCRF revenue beyond Entergy Texas’s then-effective DCRF rider, based on its capital invested in distribution between January 1, 2019 and December 31, 2019. In December 2016, concurrent with the 2016 fuel reconciliation stipulationMay and settlement agreement discussed below,June 2020 intervenors filed testimony recommending reductions in Entergy Texas and the PUCT staff reached a settlement agreeing to the amended TCRFTexas’s annual revenue requirement of $29.5approximately $0.3 million and $4.1 million. As discussed below,The parties briefed the terms ofcontested issues in this matter and a proposal for decision was issued in September 2020 recommending a $4.1 million revenue reduction related to non-Advanced Metering System meters included in the two settlements are interdependent.DCRF calculation. The PUCT approvedparties filed exceptions to the settlementproposal for decision and replies to those exceptions in September 2020. In October 2020 the PUCT issued a final order approving a $16.3 million incremental annual DCRF revenue increase.
In October 2020, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $26.3 million annually, or $6.8 million in incremental annual revenues beyond Entergy Texas’s currently effective DCRF rider based on its capital invested in distribution between January 1, 2020 and August 31, 2020. In February 2021 the administrative law judge with the State Office of Administrative Hearings approved Entergy Texas's agreed motion for interim rates, which will go into effect in March 2017. Entergy Texas implemented2021. The administrative law judge also adopted a procedural schedule setting a hearing on the amended TCRF rider beginning with bills covering usage on and after March 20, 2017. TCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as discussed abovemerits, if necessary, in the 2018 base rate case discussion.April 2021.
Transmission Cost Recovery Factor (TCRF) Rider
In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The proposed new TCRF rider is designed to collect approximately $2.7 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and September 30, 2018. In April 2019 parties filed testimony proposing a load growth adjustment, which would fully offset Entergy Texas’s proposed TCRF revenue requirement. In July 2019 the PUCT granted Entergy Texas’s application as filed to begin recovery of the requested $2.7 million annual revenue requirement, rejecting opposing parties’ proposed adjustment; however, the PUCT found that the question of prudence of the actual investment costs should be determined in Entergy Texas’s next rate case similar to the procedure used for the costs recovered through the DCRF rider. In October 2019 the PUCT issued an order on a motion for rehearing, clarifying and affirming its prior order granting Entergy Texas’s application as filed. Also, in October 2019 a second motion for rehearing was filed, and Entergy Texas filed a response in opposition to the motion. The second motion for rehearing was overruled by operation of law. In December 2019, Texas Industrial Energy Consumers filed an appeal to the PUCT order in district court alleging that the PUCT erred in declining to apply a load growth adjustment.
In August 2019, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed newamended TCRF rider is designed to collect approximately $19.4 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and June 30, 2019, which is $16.7 million in incremental annual revenue above the $2.7 million approved in the prior pending TCRF proceeding. In November 2019, Entergy Texas filedJanuary 2020 the PUCT issued an order approving an unopposed stipulation and settlement agreement providing for recovery of the requested revenue requirement. InEntergy Texas implemented the amended rider beginning with bills covering usage on and after January 2020 the PUCT issued an order approving the unopposed settlement.23, 2020.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Advanced Metering Infrastructure (AMI)
In April 2017 the Texas legislature enacted legislation that extends statutory support for AMI deployment toOctober 2020, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $51 million annually, or $31.6 million in incremental annual revenues beyond Entergy Texas’s currently effective TCRF rider based on its capital invested in transmission between July 1, 2019 and directs that ifAugust 31, 2020. A procedural schedule was established with a hearing scheduled in March 2021. In February 2021, Entergy Texas electsfiled an agreed motion to deploy AMI, it shall do so as rapidly as practicable. abate the procedural schedule, noting that the parties had reached a settlement in principle, and the administrative law judge granted the motion to abate.
Generation Cost Recovery Rider
In July 2017,October 2020, Entergy Texas filed an application seekingto establish a generation cost recovery rider with an orderinitial annual revenue requirement of approximately $91 million to begin recovering a return of and on its capital investment in the Montgomery County Power Station through August 31, 2020. In December 2020, Entergy Texas filed an unopposed settlement supporting a generation cost recovery rider with an annual revenue requirement of approximately $86 million. The settlement revenue requirement is based on a depreciation rate intended to fully depreciate Montgomery County Power Station over 38 years and the removal of certain costs from Entergy Texas’s request. Under the settlement, Entergy Texas retains the right to propose a different depreciation rate and seek recovery of a majority of the costs removed from its request in its next base rate proceeding. On January 14, 2021, the PUCT approved the generation cost recovery rider settlement rates on an interim basis and abated the proceeding. Within 60 days of Montgomery County Power Station being placed in service on January 1, 2021, Entergy Texas will file to update its generation cost recovery rider to include investment in Montgomery County Power Station after August 31, 2020. The current estimated cost of Montgomery County Power Station, including transmission interconnection and network upgrades, is approximately $921 million. Of this investment, approximately $756 million is eligible to begin being recovered through the generation cost recovery rider. Entergy Texas will address recovery of the remainder of its Montgomery County Power Station investment through other rate mechanisms.
In December 2020, Entergy Texas filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which is expected to close in April 2021.The initial generation cost recovery rider rates proposed in the application represent no change from the PUCT approvinggeneration cost recovery rider rates to be established in Entergy Texas’s deployment of AMI.previous generation cost recovery rider proceeding.Once Entergy Texas proposedhas acquired the Hardin County Peaking Facility, its investment in the facility will be reflected in the updated filing 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 estimateapplication, which will be made within 60 days of implementation coststhe acquisition’s closing.
COVID-19 Orders
In March 2020 the PUCT authorized electric utilities to record as a regulatory asset expenses resulting from the effects of COVID-19.In future proceedings the PUCT will consider whether each utility's request for AMIrecovery of $132 million and identified a number of quantified and unquantified benefits. Entergy Texas proposed a seven-year depreciable life for the new advanced meters. Entergy Texas also proposed a surcharge tariff to recover thethese regulatory assets is reasonable and necessary, the appropriate period of recovery, and any amount of carrying costs it has and will incur underthereon.In March 2020 the deployment planPUCT ordered a moratorium on disconnections for nonpayment for all customer classes, but, in April 2020, revised the full deployment of advanced meters. Further,disconnect moratorium to apply only to residential customers.The PUCT allowed the moratorium to expire on June 13, 2020, but on July 17, 2020, the PUCT re-established the disconnect moratorium for residential customers until August 31, 2020.In January 2021, Entergy Texas sought approval of feesresumed disconnections for customers with past-due balances 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 approved the stipulation and settlement agreement in December 2017. Entergy Texas implemented the AMI surcharge tariff beginning with January 2018 bills.have not made payment arrangements. As of December 31, 2019,2020, Entergy Texas has a regulatory liability related to the collection of the surcharge from customers. Consistent with the approval, deployment of the communications network began in 2018 and the three-year deployment of the advanced meters began in 2019. Entergy Texas will recover the undepreciated balance of its existing meters throughrecorded a regulatory asset to be amortized at current depreciation rates, as approved byof $12.9 million for costs associated with the PUCT.COVID-19 pandemic.
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
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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 July 2015 certain parties filed briefs in the open proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production costs. In October 2015 an ALJ issued a proposal for decision recommending that the additional $10.9 million in bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’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 2016, Entergy Texas filed with the PUCT 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, discussed above, 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 $68 million refund. The ALJ approved the refund on an interim basis and it was 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 December 2016, and the Federal 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 Fifth Circuit in February 2018. In April 2018 the Fifth Circuit reversed the decision of the Federal District Court, reinstating the original PUCT decision. In October 2018, Entergy Texas filed a notice of nonsuit in its appeal to the Travis County District Court regarding the PUCT’s January 2016 decision.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period April 1, 2013 through March 31, 2016. 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 over-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also requested a prudence finding for each of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT in a prior proceeding. In December 2016, Entergy Texas entered into a stipulation and settlement agreement resulting in a $6 million disallowance not associated with any particular issue raised and a refund of the over-recovery balance of $21 million as of November 30, 2016, to most customers beginning April 2017 through June 2017. This settlement was developed concurrently with the stipulation and settlement agreement in the 2016 transmission cost recovery factor rider amendment discussed above, and the terms and conditions in both settlements are interdependent. The A fuel reconciliation settlement was approved by the PUCT in March 2017is required to be filed at least once every three years and the refunds were made.outside of a base rate case filing.
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 January 2018 through March 2018. The fuel refund was approved by the PUCT in March 2018.
In September 2019, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period from April 2016 through March 2019. During the reconciliation period, Entergy Texas incurred approximately $1.6 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 under-recovery balance of approximately $25.8 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2019. In March 2020 an intervenor filed testimony proposing that the PUCT disallow: (1) $2 million in replacement power costs associated with generation outages during the reconciliation period; and (2) $24.4 million associated with the operation of the Spindletop natural gas storage facility during the reconciliation period. In April 2020, Entergy Texas filed rebuttal testimony refuting all points raised by the intervenor. In June 2020 the parties filed a stipulation and settlement agreement, which included a $1.2 million disallowance not associated with any particular issue raised by any party.The PUCT approved the settlement in August 2020.
In July 2020, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $25.5 million, including interest.Entergy Texas proposed that the interim fuel refund be implemented beginning with the first August 2020 billing cycle over a three-month period for smaller customers and in a lump sum amount in the billing month of August 2020 for transmission-level customers.The interim fuel refund was approved in July 2020, and Entergy Texas began refunds in August 2020.
In February 2021, Entergy Texas filed an application to implement a fuel refund for a cumulative over-recovery of approximately $75 million that is primarily attributable to settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas planned to issue the refund over the period of March through August 2021. On February 22, 2021, Entergy Texas filed a motion to abate its fuel refund proceeding is currently pending.to assess how the February 2021 winter storm impacted Entergy Texas’s fuel over-recovery position.
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
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
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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, 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 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 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.
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 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).
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
| | | Actuarial Assumption | | Change in Assumption | | Impact on 2020 Qualified Pension Cost | | Impact on 2019 Qualified Projected Benefit Obligation | Actuarial Assumption | | Change in Assumption | | Impact on 2021 Qualified Pension Cost | | Impact on 2020 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $535 | | $9,465 | Discount rate | | (0.25%) | | $472 | | $9,960 |
| Rate of return on plan assets | | (0.25%) | | $783 | | $— | Rate of return on plan assets | | (0.25%) | | $772 | | $— |
| Rate of increase in compensation | | 0.25% | | $347 | | $1,676 | Rate of increase in compensation | | 0.25% | | $388 | | $1,916 |
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 2021 Postretirement Benefit Cost | | Impact on 2020 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $49 | | $2,206 |
| Health care cost trend | | 0.25% | | $76 | | $1,593 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Postretirement Benefit Cost | | Impact on 2019 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $— | | $2,673 |
| Health care cost trend | | 0.25% | | $97 | | $2,050 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Texas in 20192020 was $5.7 million.$12.4 million, including $4.3 million in settlement costs. Entergy Texas anticipates 20202021 qualified pension cost to be $8.4$8.9 million. Entergy Texas contributed $3.7$5 million to its qualified pension plans in 20192020 and estimates 20202021 pension contributions will be approximately $3.5$7 million, although the 20202021 required pension contributions will be known with more certainty when the January 1, 20202021 valuations are completed, which is expected by April 1, 2020.2021.
Total postretirement health care and life insurance benefit income for Entergy Texas in 20192020 was $6.5$8.9 million. Entergy Texas expects 2020 postretirement health care and life insurance benefit income to approximate $6.7$10.9 million. In 2019,2020, Entergy Texas’ postretirement contributions (that is, contributions to the external trusts plus claims payments) were offset by trust claims reimbursements, resulting in a net reimbursement of $596$690 thousand. Entergy Texas estimates 20202021 contributions will be approximately $61$66 thousand.
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 Texas, Inc. and Subsidiaries
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, 20192020 and 2018,2019, the related consolidated statements of income, cash flows, and changes in common equity (pages 405423 through 410428 and applicable items in pages 4951 through 236)238), for each of the three years in the period ended December 31, 2019,2020, 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, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2020, 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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Texas, Inc. and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Public Utility Commission of Texas (the “PUCT”), which has jurisdiction with respect to the rates of electric companies in Texas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate
regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the PUCT and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses 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. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the PUCT and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the PUCT and the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the PUCT and the FERC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the PUCT and the FERC for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the PUCT’s and the FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected the Company’s filings with the PUCT and the FERC, including the base rate case filing, and considered the filings with the PUCT and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202026, 2021
We have served as the Company’s auditor since 2001.
|
| | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $1,488,955 |
| |
| $1,605,902 |
| |
| $1,544,893 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 162,544 |
| | 204,830 |
| | 225,517 |
|
| Purchased power | | 602,563 |
| | 614,012 |
| | 610,279 |
|
| Other operation and maintenance | | 258,924 |
| | 238,400 |
| | 230,437 |
|
| Taxes other than income taxes | | 76,366 |
| | 82,033 |
| | 79,254 |
|
| Depreciation and amortization | | 153,286 |
| | 128,534 |
| | 117,520 |
|
| Other regulatory charges - net | | 88,770 |
| | 131,667 |
| | 82,328 |
|
| TOTAL | | 1,342,453 |
| | 1,399,476 |
| | 1,345,335 |
|
| | | | | | | |
| OPERATING INCOME | | 146,502 |
| | 206,426 |
| | 199,558 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 28,445 |
| | 9,723 |
| | 6,722 |
|
| Interest and investment income | | 3,072 |
| | 2,188 |
| | 981 |
|
| Miscellaneous - net | | 546 |
| | (655 | ) | | 14 |
|
| TOTAL | | 32,063 |
| | 11,256 |
| | 7,717 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 86,333 |
| | 87,203 |
| | 86,719 |
|
| Allowance for borrowed funds used during construction | | (13,269 | ) | | (5,513 | ) | | (4,098 | ) |
| TOTAL | | 73,064 |
| | 81,690 |
| | 82,621 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 105,501 |
| | 135,992 |
| | 124,654 |
|
| | | | | | | |
| Income taxes | | (53,896 | ) | | (26,243 | ) | | 48,481 |
|
| | | | | | | |
| NET INCOME | | 159,397 |
| | 162,235 |
| | 76,173 |
|
| | | | | | | |
| Preferred dividend requirements | | 580 |
| | — |
| | — |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | |
| $158,817 |
| |
| $162,235 |
| |
| $76,173 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $1,587,125 | | | $1,488,955 | | | $1,605,902 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 238,428 | | | 162,544 | | | 204,830 | |
| Purchased power | | 510,633 | | | 602,563 | | | 614,012 | |
| Other operation and maintenance | | 250,170 | | | 258,924 | | | 238,400 | |
| | | | | | |
| Taxes other than income taxes | | 72,909 | | | 76,366 | | | 82,033 | |
| Depreciation and amortization | | 177,738 | | | 153,286 | | | 128,534 | |
| Other regulatory charges - net | | 90,398 | | | 88,770 | | | 131,667 | |
| TOTAL | | 1,340,276 | | | 1,342,453 | | | 1,399,476 | |
| | | | | | |
| OPERATING INCOME | | 246,849 | | | 146,502 | | | 206,426 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 44,073 | | | 28,445 | | | 9,723 | |
| Interest and investment income | | 1,201 | | | 3,072 | | | 2,188 | |
| Miscellaneous - net | | (28) | | | 546 | | | (655) | |
| TOTAL | | 45,246 | | | 32,063 | | | 11,256 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 92,920 | | | 86,333 | | | 87,203 | |
| Allowance for borrowed funds used during construction | | (18,940) | | | (13,269) | | | (5,513) | |
| TOTAL | | 73,980 | | | 73,064 | | | 81,690 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 218,115 | | | 105,501 | | | 135,992 | |
| | | | | | |
| Income taxes | | 3,042 | | | (53,896) | | | (26,243) | |
| | | | | | |
| NET INCOME | | 215,073 | | | 159,397 | | | 162,235 | |
| | | | | | |
| Preferred dividend requirements | | 1,882 | | | 580 | | | 0 | |
| | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | | $213,191 | | | $158,817 | | | $162,235 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
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|
| | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $159,397 |
| |
| $162,235 |
| |
| $76,173 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 153,286 |
| | 128,534 |
| | 117,520 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 20,143 |
| | (39,545 | ) | | 42,119 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | 58,445 |
| | (17,099 | ) | | (15,934 | ) |
| Fuel inventory | | (4,926 | ) | | 64 |
| | (25,054 | ) |
| Accounts payable | | (33,646 | ) | | 43,319 |
| | 32,842 |
|
| Prepaid taxes and taxes accrued | | (3,805 | ) | | 7,854 |
| | 30,308 |
|
| Interest accrued | | (5,363 | ) | | (1,201 | ) | | (421 | ) |
| Deferred fuel costs | | (6,696 | ) | | (47,604 | ) | | 12,758 |
|
| Other working capital accounts | | (13,822 | ) | | 1,328 |
| | (7,852 | ) |
| Provisions for estimated losses | | (5,748 | ) | | 3,741 |
| | 2,531 |
|
| Other regulatory assets | | 85,400 |
| | 63,350 |
| | 184,574 |
|
| Other regulatory liabilities | | (105,517 | ) | | (19,336 | ) | | 410,968 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | — |
| | — |
| | (520,547 | ) |
| Pension and other postretirement liabilities | | (7,152 | ) | | (13,135 | ) | | (49,445 | ) |
| Other assets and liabilities | | (3,257 | ) | | 59,248 |
| | 10,856 |
|
| Net cash flow provided by operating activities | | 286,739 |
| | 331,753 |
| | 301,396 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (898,090 | ) | | (451,988 | ) | | (348,027 | ) |
| Allowance for equity funds used during construction | | 28,526 |
| | 9,861 |
| | 6,874 |
|
| Proceeds from sale of assets | | — |
| | 3,753 |
| | — |
|
| Insurance proceeds | | — |
| | — |
| | 2,431 |
|
| Changes in money pool receivable - net | | (11,181 | ) | | 44,903 |
| | (44,222 | ) |
| Changes in securitization account | | 2,465 |
| | (2,502 | ) | | (232 | ) |
| Net cash flow used in investing activities | | (878,280 | ) | | (395,973 | ) | | (383,176 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 986,019 |
| | — |
| | 148,277 |
|
| Retirement of long-term debt | | (578,593 | ) |
| (74,950 | ) |
| (71,683 | ) |
| Capital contributions from parent | | 185,000 |
| | — |
| | 115,000 |
|
| Proceeds from the issuance of preferred stock | | 33,188 |
| | — |
| | — |
|
| Change in money pool payable - net | | (22,389 | ) | | 22,389 |
| | — |
|
| Other | | 1,189 |
| | 1,324 |
| | (482 | ) |
| Net cash flow provided by (used in) financing activities | | 604,414 |
| | (51,237 | ) | | 191,112 |
|
| Net increase (decrease) in cash and cash equivalents | | 12,873 |
| | (115,457 | ) | | 109,332 |
|
| Cash and cash equivalents at beginning of period | | 56 |
| | 115,513 |
| | 6,181 |
|
| Cash and cash equivalents at end of period | |
| $12,929 |
| |
| $56 |
| |
| $115,513 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $89,402 |
| |
| $85,719 |
| |
| $84,556 |
|
| Income taxes | |
| $17,010 |
| |
| $20,787 |
| |
| ($21,107 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $215,073 | | | $159,397 | | | $162,235 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 177,738 | | | 153,286 | | | 128,534 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 36,033 | | | 20,143 | | | (39,545) | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (30,082) | | | 58,445 | | | (17,099) | |
| Fuel inventory | | (5,938) | | | (4,926) | | | 64 | |
| Accounts payable | | (23,692) | | | (33,646) | | | 43,319 | |
| Prepaid taxes and taxes accrued | | 2,730 | | | (3,805) | | | 7,854 | |
| Interest accrued | | 1,864 | | | (5,363) | | | (1,201) | |
| Deferred fuel costs | | 72,355 | | | (6,696) | | | (47,604) | |
| Other working capital accounts | | (11,837) | | | (13,822) | | | 1,328 | |
| Provisions for estimated losses | | 274 | | | (5,748) | | | 3,741 | |
| Other regulatory assets | | (12,065) | | | 85,400 | | | 63,350 | |
| Other regulatory liabilities | | (57,477) | | | (105,517) | | | (19,336) | |
| | | | | | |
| Pension and other postretirement liabilities | | (28,825) | | | (7,152) | | | (13,135) | |
| Other assets and liabilities | | 39,174 | | | (3,257) | | | 59,248 | |
| Net cash flow provided by operating activities | | 375,325 | | | 286,739 | | | 331,753 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (895,857) | | | (898,090) | | | (451,988) | |
| Allowance for equity funds used during construction | | 44,073 | | | 28,526 | | | 9,861 | |
| Proceeds from sale of assets | | 0 | | | 0 | | | 3,753 | |
| | | | | | |
| Payment for purchase of assets | | (4,931) | | | 0 | | | 0 | |
| Changes in money pool receivable - net | | 6,580 | | | (11,181) | | | 44,903 | |
| | | | | | |
| Changes in securitization account | | 1,487 | | | 2,465 | | | (2,502) | |
| | | | | | |
| Net cash flow used in investing activities | | (848,648) | | | (878,280) | | | (395,973) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 937,725 | | | 986,019 | | | 0 | |
| Retirement of long-term debt | | (367,565) | | | (578,593) | | | (74,950) | |
| Capital contributions from parent | | 175,000 | | | 185,000 | | | 0 | |
| Proceeds from the issuance of preferred stock | | 0 | | | 33,188 | | | 0 | |
| Change in money pool payable - net | | 0 | | | (22,389) | | | 22,389 | |
| Dividends paid: | | | | | | |
| Common stock | | (30,000) | | | 0 | | | 0 | |
| Preferred stock | | (2,064) | | | 0 | | | 0 | |
| Other | | (4,106) | | | 1,189 | | | 1,324 | |
| Net cash flow provided by (used in) financing activities | | 708,990 | | | 604,414 | | | (51,237) | |
| Net increase (decrease) in cash and cash equivalents | | 235,667 | | | 12,873 | | | (115,457) | |
| Cash and cash equivalents at beginning of period | | 12,929 | | | 56 | | | 115,513 | |
| Cash and cash equivalents at end of period | | $248,596 | | | $12,929 | | | $56 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid during the period for: | | | | | | |
| Interest - net of amount capitalized | | $89,077 | | | $89,402 | | | $85,719 | |
| Income taxes | | $2,792 | | | $17,010 | | | $20,787 | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $25 |
| |
| $26 |
|
| Temporary cash investments | | 12,904 |
| | 30 |
|
| Total cash and cash equivalents | | 12,929 |
| | 56 |
|
| Securitization recovery trust account | | 37,720 |
| | 40,185 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 59,365 |
| | 69,714 |
|
| Allowance for doubtful accounts | | (471 | ) | | (461 | ) |
| Associated companies | | 24,001 |
| | 64,441 |
|
| Other | | 17,050 |
| | 12,275 |
|
| Accrued unbilled revenues | | 50,048 |
| | 51,288 |
|
| Total accounts receivable | | 149,993 |
| | 197,257 |
|
| Fuel inventory - at average cost | | 47,593 |
| | 42,667 |
|
| Materials and supplies - at average cost | | 46,056 |
| | 41,883 |
|
| Prepayments and other | | 21,012 |
| | 15,903 |
|
| TOTAL | | 315,303 |
| | 337,951 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Investments in affiliates - at equity | | 396 |
| | 448 |
|
| Non-utility property - at cost (less accumulated depreciation) | | 376 |
| | 376 |
|
| Other | | 20,077 |
| | 19,218 |
|
| TOTAL | | 20,849 |
| | 20,042 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 5,199,027 |
| | 4,773,984 |
|
| Construction work in progress | | 760,354 |
| | 325,193 |
|
| TOTAL UTILITY PLANT | | 5,959,381 |
| | 5,099,177 |
|
| Less - accumulated depreciation and amortization | | 1,770,852 |
| | 1,684,569 |
|
| UTILITY PLANT - NET | | 4,188,529 |
| | 3,414,608 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Other regulatory assets (includes securitization property of $160,375 as of December 31, 2019 and $236,336 as of December 31, 2018) | | 512,648 |
| | 598,048 |
|
| Other | | 33,393 |
| | 29,371 |
|
| TOTAL | | 546,041 |
| | 627,419 |
|
| | | | | |
| TOTAL ASSETS | |
| $5,070,722 |
| |
| $4,400,020 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2020 | | 2019 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $26 | | | $25 | |
| Temporary cash investments | | 248,570 | | | 12,904 | |
| Total cash and cash equivalents | | 248,596 | | | 12,929 | |
| Securitization recovery trust account | | 36,233 | | | 37,720 | |
| Accounts receivable: | | | | |
| Customer | | 103,221 | | | 59,365 | |
| Allowance for doubtful accounts | | (16,810) | | | (471) | |
| Associated companies | | 18,892 | | | 24,001 | |
| Other | | 11,780 | | | 17,050 | |
| Accrued unbilled revenues | | 56,411 | | | 50,048 | |
| Total accounts receivable | | 173,494 | | | 149,993 | |
| | | | |
| | | | |
| Fuel inventory - at average cost | | 53,531 | | | 47,593 | |
| Materials and supplies - at average cost | | 56,227 | | | 46,056 | |
| | | | |
| Prepayments and other | | 20,165 | | | 21,012 | |
| TOTAL | | 588,246 | | | 315,303 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Investments in affiliates - at equity | | 349 | | | 396 | |
| Non-utility property - at cost (less accumulated depreciation) | | 376 | | | 376 | |
| Other | | 19,889 | | | 20,077 | |
| TOTAL | | 20,614 | | | 20,849 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 6,007,687 | | | 5,199,027 | |
| Construction work in progress | | 879,908 | | | 760,354 | |
| TOTAL UTILITY PLANT | | 6,887,595 | | | 5,959,381 | |
| Less - accumulated depreciation and amortization | | 1,864,494 | | | 1,770,852 | |
| UTILITY PLANT - NET | | 5,023,101 | | | 4,188,529 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets (includes securitization property of $78,590 as of December 31, 2020 and $160,375 as of December 31, 2019) | | 524,713 | | | 512,648 | |
| | | | |
| Other | | 70,397 | | | 33,393 | |
| TOTAL | | 595,110 | | | 546,041 | |
| | | | |
| TOTAL ASSETS | | $6,227,071 | | | $5,070,722 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | ENTERGY TEXAS, INC. AND SUBSIDIARIES | ENTERGY TEXAS, INC. AND SUBSIDIARIES | ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | LIABILITIES AND EQUITY |
| | | | | |
| | | December 31, | | | December 31, |
| | | 2019 | | 2018 | | | 2020 | | 2019 |
| | | (In Thousands) | | | (In Thousands) |
| CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $— |
| |
| $500,000 |
| Currently maturing long-term debt | | $200,000 | | | $0 | |
| Accounts payable: | | | | | Accounts payable: | | | | |
| Associated companies | | 58,055 |
| | 119,371 |
| Associated companies | | 55,944 | | | 58,055 | |
| Other | | 188,460 |
| | 150,679 |
| Other | | 350,947 | | | 188,460 | |
| Customer deposits | | 40,232 |
| | 43,387 |
| Customer deposits | | 36,282 | | | 40,232 | |
| Taxes accrued | | 49,708 |
| | 53,513 |
| Taxes accrued | | 52,438 | | | 49,708 | |
| Interest accrued | | 18,992 |
| | 24,355 |
| Interest accrued | | 20,856 | | | 18,992 | |
| Current portion of unprotected excess accumulated deferred income taxes | | 26,552 |
| | 87,627 |
| Current portion of unprotected excess accumulated deferred income taxes | | 29,249 | | | 26,552 | |
| Deferred fuel costs | | 13,001 |
| | 19,697 |
| Deferred fuel costs | | 85,356 | | | 13,001 | |
| | Other | | 10,521 |
| | 6,353 |
| Other | | 12,370 | | | 10,521 | |
| TOTAL | | 405,521 |
| | 1,004,982 |
| TOTAL | | 843,442 | | | 405,521 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 585,413 |
| | 552,535 |
| Accumulated deferred income taxes and taxes accrued | | 639,422 | | | 585,413 | |
| Accumulated deferred investment tax credits | | 10,559 |
| | 11,176 |
| Accumulated deferred investment tax credits | | 9,942 | | | 10,559 | |
| Regulatory liability for income taxes - net | | 225,980 |
| | 264,623 |
| Regulatory liability for income taxes - net | | 175,594 | | | 225,980 | |
| Other regulatory liabilities | | 42,085 |
| | 47,884 |
| Other regulatory liabilities | | 32,297 | | | 42,085 | |
| Asset retirement cost liabilities | | 7,631 |
| | 7,222 |
| Asset retirement cost liabilities | | 8,063 | | | 7,631 | |
| Accumulated provisions | | 8,108 |
| | 13,856 |
| Accumulated provisions | | 8,382 | | | 8,108 | |
| Long-term debt (includes securitization bonds of $205,349 as of December 31, 2019 and $283,659 as of December 31, 2018) | | 1,922,956 |
| | 1,013,735 |
| |
| | Long-term debt (includes securitization bonds of $123,066 as of December 31, 2020 and $205,349 as of December 31, 2019) | | Long-term debt (includes securitization bonds of $123,066 as of December 31, 2020 and $205,349 as of December 31, 2019) | | 2,293,708 | | | 1,922,956 | |
| Other | | 63,062 |
| | 61,605 |
| Other | | 58,643 | | | 63,062 | |
| TOTAL | | 2,865,794 |
| | 1,972,636 |
| TOTAL | | 3,226,051 | | | 2,865,794 | |
| | | | | | | | | |
| Commitments and Contingencies | |
|
| |
|
| Commitments and Contingencies | | 0 | | 0 |
| | | | | | |
| EQUITY | | |
| | |
| EQUITY | | | | |
| Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2019 and 2018 | | 49,452 |
| | 49,452 |
| |
| Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2020 and 2019 | | Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2020 and 2019 | | 49,452 | | | 49,452 | |
| Paid-in capital | | 780,182 |
| | 596,994 |
| Paid-in capital | | 955,162 | | | 780,182 | |
| Retained earnings | | 934,773 |
| | 775,956 |
| Retained earnings | | 1,117,964 | | | 934,773 | |
| Total common shareholder's equity | | 1,764,407 |
| | 1,422,402 |
| Total common shareholder's equity | | 2,122,578 | | | 1,764,407 | |
| Preferred stock without sinking fund | | 35,000 |
| | — |
| Preferred stock without sinking fund | | 35,000 | | | 35,000 | |
| TOTAL | | 1,799,407 |
| | 1,422,402 |
| TOTAL | | 2,157,578 | | | 1,799,407 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $5,070,722 |
| |
| $4,400,020 |
| TOTAL LIABILITIES AND EQUITY | | $6,227,071 | | | $5,070,722 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2019, 2018, and 2017 |
| | | | | | |
| | | | Common Equity | | |
| | Preferred Stock | | Common Stock | | Paid-in Capital | | Retained Earnings | | Total |
| | | | (In Thousands) |
| | | | | | | | | | |
| Balance at December 31, 2016 |
| $— |
| |
| $49,452 |
| |
| $481,994 |
| |
| $537,548 |
| |
| $1,068,994 |
|
| Net income | — |
| | — |
| | — |
| | 76,173 |
| | 76,173 |
|
| Capital contributions from parent | — |
| | — |
| | 115,000 |
| | — |
| | 115,000 |
|
| Balance at December 31, 2017 |
| $— |
| |
| $49,452 |
| |
| $596,994 |
| |
| $613,721 |
| |
| $1,260,167 |
|
| Net income | — |
| | — |
| | — |
| | 162,235 |
| | 162,235 |
|
| Balance at December 31, 2018 |
| $— |
| |
| $49,452 |
| |
| $596,994 |
| |
| $775,956 |
| |
| $1,422,402 |
|
| Net income | — |
| | — |
| | — |
| | 159,397 |
| | 159,397 |
|
| Capital contributions from parent | — |
| | — |
| | 185,000 |
| | — |
| | 185,000 |
|
| Preferred stock issuance | 35,000 |
| | — |
| | (1,812 | ) | | — |
| | 33,188 |
|
| Preferred stock dividends | — |
| | — |
| | — |
| | (580 | ) | | (580 | ) |
| Balance at December 31, 2019 |
| $35,000 |
| |
| $49,452 |
| |
| $780,182 |
| |
| $934,773 |
| |
| $1,799,407 |
|
| | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2020, 2019, and 2018 |
| | | | | |
| | | | Common Equity | | |
| | Preferred Stock | | Common Stock | | Paid-in Capital | | Retained Earnings | | Total |
| | | | (In Thousands) |
| | | | | | | | | |
| Balance at December 31, 2017 | $0 | | | $49,452 | | | $596,994 | | | $613,721 | | | $1,260,167 | |
| Net income | 0 | | | 0 | | | 0 | | | 162,235 | | | 162,235 | |
| Balance at December 31, 2018 | $0 | | | $49,452 | | | $596,994 | | | $775,956 | | | $1,422,402 | |
| Net income | 0 | | | 0 | | | 0 | | | 159,397 | | | 159,397 | |
| Capital contributions from parent | 0 | | 0 | | | 185,000 | | | 0 | | | 185,000 | |
| Preferred stock issuance | 35,000 | | | 0 | | | (1,812) | | | 0 | | | 33,188 | |
| Preferred stock dividends | 0 | | | 0 | | | 0 | | | (580) | | | (580) | |
| Balance at December 31, 2019 | $35,000 | | | $49,452 | | | $780,182 | | | $934,773 | | | $1,799,407 | |
| Net income | 0 | | | 0 | | | 0 | | | 215,073 | | | 215,073 | |
| Capital contributions from parent | 0 | | | 0 | | | 175,000 | | | 0 | | | 175,000 | |
| Common stock dividends | 0 | | | 0 | | | 0 | | | (30,000) | | | (30,000) | |
| Preferred stock dividends | 0 | | | 0 | | | 0 | | | (1,882) | | | (1,882) | |
| Other | 0 | | | 0 | | | (20) | | | 0 | | | (20) | |
| Balance at December 31, 2020 | $35,000 | | | $49,452 | | | $955,162 | | | $1,117,964 | | | $2,157,578 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $1,488,955 |
| |
| $1,605,902 |
| |
| $1,544,893 |
| |
| $1,615,619 |
| |
| $1,707,203 |
|
| Net income |
| $159,397 |
| |
| $162,235 |
| |
| $76,173 |
| |
| $107,538 |
| |
| $69,625 |
|
| Total assets |
| $5,070,722 |
| |
| $4,400,020 |
| |
| $4,279,738 |
| |
| $4,033,081 |
| |
| $3,898,582 |
|
| Long-term obligations (a) |
| $1,922,956 |
| |
| $1,013,735 |
| |
| $1,587,150 |
| |
| $1,508,407 |
| |
| $1,451,967 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt). |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $658 |
| |
| $674 |
| |
| $636 |
| |
| $613 |
| |
| $633 |
|
| Commercial | 343 |
| | 381 |
| | 378 |
| | 356 |
| | 369 |
|
| Industrial | 373 |
| | 394 |
| | 384 |
| | 365 |
| | 372 |
|
| Governmental | 22 |
| | 25 |
| | 25 |
| | 24 |
| | 25 |
|
| Total billed retail | 1,396 |
| | 1,474 |
| | 1,423 |
| | 1,358 |
| | 1,399 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 52 |
| | 59 |
| | 58 |
| | 178 |
| | 259 |
|
| Non-associated companies | 7 |
| | 39 |
| | 22 |
| | 40 |
| | 14 |
|
| Other | 34 |
| | 34 |
| | 42 |
| | 40 |
| | 35 |
|
| Total |
| $1,489 |
| |
| $1,606 |
| |
| $1,545 |
| |
| $1,616 |
| |
| $1,707 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
|
| Residential | 6,039 |
| | 6,135 |
| | 5,716 |
| | 5,836 |
| | 5,889 |
|
| Commercial | 4,667 |
| | 4,747 |
| | 4,548 |
| | 4,570 |
| | 4,548 |
|
| Industrial | 8,043 |
| | 8,052 |
| | 7,521 |
| | 7,493 |
| | 7,036 |
|
| Governmental | 259 |
| | 286 |
| | 273 |
| | 283 |
| | 276 |
|
| Total retail | 19,008 |
| | 19,220 |
| | 18,058 |
| | 18,182 |
| | 17,749 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 1,472 |
| | 1,516 |
| | 1,534 |
| | 4,625 |
| | 5,853 |
|
| Non-associated companies | 343 |
| | 962 |
| | 729 |
| | 1,086 |
| | 254 |
|
| Total | 20,823 |
| | 21,698 |
| | 20,321 |
| | 23,893 |
| | 23,856 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | |
| | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | (In Thousands) |
| | | | | | | | | |
| Operating revenues | $1,587,125 | | | $1,488,955 | | | $1,605,902 | | | $1,544,893 | | | $1,615,619 | |
| Net income | $215,073 | | | $159,397 | | | $162,235 | | | $76,173 | | | $107,538 | |
| Total assets | $6,227,071 | | | $5,070,722 | | | $4,400,020 | | | $4,279,738 | | | $4,033,081 | |
| Long-term obligations (a) | $2,293,708 | | | $1,922,956 | | | $1,013,735 | | | $1,587,150 | | | $1,508,407 | |
| | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt). |
| | | | | | | | | |
| | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | (Dollars In Millions) |
| | | | | | | | | |
| Electric Operating Revenues: | | | | | | | | | |
| Residential | $672 | | | $658 | | | $674 | | | $636 | | | $613 | |
| Commercial | 365 | | | 343 | | | 381 | | | 378 | | | 356 | |
| Industrial | 386 | | | 373 | | | 394 | | | 384 | | | 365 | |
| Governmental | 23 | | | 22 | | | 25 | | | 25 | | | 24 | |
| Total billed retail | 1,446 | | | 1,396 | | | 1,474 | | | 1,423 | | | 1,358 | |
| Sales for resale: | | | | | | | | | |
| Associated companies | 40 | | | 52 | | | 59 | | | 58 | | | 178 | |
| Non-associated companies | 60 | | | 7 | | | 39 | | | 22 | | | 40 | |
| Other | 41 | | | 34 | | | 34 | | | 42 | | | 40 | |
| Total | $1,587 | | | $1,489 | | | $1,606 | | | $1,545 | | | $1,616 | |
| | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | |
| Residential | 6,146 | | | 6,039 | | | 6,135 | | | 5,716 | | | 5,836 | |
| Commercial | 4,386 | | | 4,667 | | | 4,747 | | | 4,548 | | | 4,570 | |
| Industrial | 7,885 | | | 8,043 | | | 8,052 | | | 7,521 | | | 7,493 | |
| Governmental | 260 | | | 259 | | | 286 | | | 273 | | | 283 | |
| Total retail | 18,677 | | | 19,008 | | | 19,220 | | | 18,058 | | | 18,182 | |
| Sales for resale: | | | | | | | | | |
| Associated companies | 1,203 | | | 1,472 | | | 1,516 | | | 1,534 | | | 4,625 | |
| Non-associated companies | 810 | | | 343 | | | 962 | | | 729 | | | 1,086 | |
| Total | 20,690 | | | 20,823 | | | 21,698 | | | 20,321 | | | 23,893 | |
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. As discussed in “Complaints Against System Energy” below, System Energy is currently involved in proceedings at the FERC commenced by the retail regulators of its customers regarding its return on equity, its capital structure, its renewal of the sale-leaseback of 11.5% of Grand Gulf, the treatment of uncertain tax positions in rate base, and the rates it charges under the Unit Power Sales Agreement.
Results of Operations
20192020 Compared to 20182019
Net Income
Net income increased $5 million primarily due to theremained relatively unchanged. An increase in operating revenues resulting from changes in rate base was substantially offset by higher provisions against revenue, as compared to prior year, andyear. A provision for rate refund was recorded in 2020 to reflect a lower effective income tax rate, after excludingone-time credit of $25.2 million provided for in the effect ofFederal Power Act section 205 filing made by System Energy in December 2020. Provisions against revenue were recorded in 2019 in connection with the return on equity complaint against System Energy. See “Complaints Against System Energy” below for further discussion of unprotected excess accumulated deferred income taxes to customers whichthese items and other proceedings involving System Energy at the FERC. The one-time credit is offsetdiscussed in income taxes.the Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue part of that section. The return on equity complaint is discussed in the Return on Equity and Capital Structure Complaints part of that section.
Income Taxes
The effective income tax rates werewere 17.2% for 2020 and 13.4% for 2019 and (102.7%) for 2018. The difference in the effective income tax rate of 13.4% versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes and certain book and tax differences related to utility plant items, partially offset by state income taxes. The difference in the effective income tax rate of (102.7%) versus the federal statutory rate of 21% for 2018 was primarily due to the amortization of excess accumulated deferred income taxes.2019. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
20182019 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of System Energy’s Annual Report on Form 10-K for the year ended December 31, 20182019, filed with the SEC on February 21, 2020, for discussion of results of operations for 20182019 compared to 2017.2018.
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 Tax Act on 2017, 2018, and 2019 results of operations and financial position, the provisions of the Tax Act, and the uncertainties associated with accounting for the Tax Act, and Note 2 to the financial statements discusses the regulatory proceedings that have considered the effects of the Tax 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, 2020, 2019, 2018, and 20172018 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $68,534 | | | $95,685 | | | $287,187 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | (145,462) | | | 300,141 | | | 101,328 | |
| Investing activities | (206,443) | | | (119,553) | | | (286,161) | |
| Financing activities | 525,840 | | | (207,739) | | | (6,669) | |
| Net increase (decrease) in cash and cash equivalents | 173,935 | | | (27,151) | | | (191,502) | |
| | | | | |
| Cash and cash equivalents at end of period | $242,469 | | | $68,534 | | | $95,685 | |
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $95,685 |
| |
| $287,187 |
| |
| $245,863 |
|
| | | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 300,141 |
| | 101,328 |
| | 371,278 |
|
| Investing activities | (119,553 | ) | | (286,161 | ) | | (174,250 | ) |
| Financing activities | (207,739 | ) | | (6,669 | ) | | (155,704 | ) |
| Net increase (decrease) in cash and cash equivalents | (27,151 | ) | | (191,502 | ) | | 41,324 |
|
| | | | | | |
| Cash and cash equivalents at end of period |
| $68,534 |
| |
| $95,685 |
| |
| $287,187 |
|
20192020 Compared to 20182019
Operating Activities
Net cash flow provided bySystem Energy’s operating activities increased $198.8used $145.5 million of cash in 2020 compared to providing $300.1 million of cash in 2019 primarily due to:
the decrease in the return•an increase of the unprotected excess accumulated deferred income taxes in 2018;
a decrease in spending of $48.5 million on nuclear refueling outages in 2019 as compared to prior year; and
a decrease of $51.7$382 million in income taxes paid in 2019.2020. System Energy made income tax payments of $54$384.3 million in 20182020 in accordance with an intercompany income tax allocation agreement. The 2020 income tax payments are primarily related to the resolution of the 2014-2015 IRS audit regarding the treatment of nuclear decommissioning costs included in cost of goods sold, which is discussed in Note 3 to the financial statements in Tax Accounting Methods;
•an increase in spending of $34.9 million on nuclear refueling outages in 2020 as compared to prior year; and
•timing of payments to vendors.
The increase in cash used was offset by proceeds of $35 million received in December 2020 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.
Investing Activities
Net cash flow used in investing activities decreasedincreased by $166.6$86.9 million in 20192020 primarily due to:
a decrease•an increase of $102.7$77.2 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; and
money pool activity; and
a decrease•an increase of $28.4$28 million in nuclear construction expenditures as a result of spending in 20182020 on Grand Gulf outage projects.
The increase was partially offset by money pool activity and proceeds of $5.5 million received in December 2020 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.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
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 $47.8$55.3 million in 20192020 compared to decreasing by $4.5$47.8 million in 2018.2019. 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 used inSystem Energy’s financing activities increased $201.1provided $525.8 million of cash in 2020 compared to using $207.7 million of cash in 2019 primarily due to:to the following activity:
•a $350 million capital contribution from Entergy Corporation in order to maintain System Energy’s capital structure in conjunction with the tax payments discussed in “Operating Activities”;
•the issuance in March 2018December 2020 of $100$200 million of 3.42%2.14% Series Jmortgage bonds;
•the issuance in October 2020 of $90 million of 2.05% Series K notes by the System Energy nuclear fuel company variable interest entity;
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
an increase of $56.5 milliona decrease in common stock dividends and distributions in 2019. Common stock dividends and distributions were lower in 2018 in anticipation of the excess accumulated deferred income taxes being returned to customers as a result of the Tax Cuts and Jobs Act; and
net repayments of $82.3$50.7 million of long-term borrowings in 2019 compared to net borrowings of $63.9 million of long-term borrowings in 20182020 on the nuclear fuel company variable interest entity’s credit facility.facility; and
The increase was partially offset by:
the payment in October 2018, at maturity,•a decrease of $85 million of the System Energy nuclear fuel company variable interest entity’s 3.78% Series I notes; and
net repayments of short-term borrowings of $17.8$43.6 million in 2018 on the nuclear fuel company variable interest entity’s credit facility.common stock dividends and distributions in 2020 in order to maintain System Energy’s capital structure.
In March 2019, System Energy issued $134 million of 2.50% Series 2019 revenue refunding bonds due April 2022. The proceeds were used to redeem, prior to maturity, $134 million of 5.875% Series 1998 pollution control revenue refunding bonds due April 2022.
See Note 5 to the financial statements for additional details of long-term debt.
20182019 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of System Energy’s Annual Report on Form 10-K for the year ended December 31, 20182019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 20182019 compared to 2017.2018.
Capital Structure
System Energy’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio is primarily due to a decrease in long-term debt outstanding,the capital contribution from Entergy Corporation, partially offset by a decreasethe issuance of long-term debt in retained earnings.2020.
| | | | | | | | | | | |
| | December 31,
2020 | | December 31,
2019 |
| Debt to capital | 42.7 | % | | 43.5 | % |
| Effect of subtracting cash | (8.5 | %) | | (3.3 | %) |
| Net debt to net capital | 34.2 | % | | 40.2 | % |
|
| | | | | |
| | December 31,
2019 | | December 31,
2018 |
| Debt to capital | 43.5 | % | | 46.1 | % |
| Effect of subtracting cash | (3.3 | %) | | (4.0 | %) |
| Net debt to net capital | 40.2 | % | | 42.1 | % |
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. 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 Resources, Inc.
Management’s Financial Discussion and Analysis
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,a capital distribution, or a combination of the three, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments and other uses of cash, System Energy may issue incremental debt or reduce dividends, or both, to maintain its capital structure.
In addition, System Energy Resources, Inc.may receive equity contributions to maintain its capital structure for certain circumstances that would materially alter the capital structure if financed entirely with debt and reduced dividends.
Management’s Financial Discussion and Analysis
Uses of Capital
System Energy requires capital resources for:
•construction and other capital investments;
•debt maturities or retirements;
•working capital purposes, including the financing of fuel costs;costs and tax payments; and
•dividend, distribution, and interest payments.
Following are the amounts of System Energy’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2022 | | 2023 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $90 | | | $145 | | | $140 | |
| Utility Support | 15 | | | 10 | | | 15 | |
| Total | $105 | | | $155 | | | $155 | |
|
| | | | | | | | | | | |
| | 2020 | | 2021 | | 2022 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $165 |
| |
| $80 |
| |
| $145 |
|
| Utility Support | 5 |
| | 15 |
| | 15 |
|
| Total |
| $170 |
| |
| $95 |
| |
| $160 |
|
Following are the amounts of System Energy’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| | (In Millions) |
| Long-term debt (a) | $138 | | | $444 | | | $246 | | | $299 | | | $1,127 | |
| Purchase obligations (b) | $6 | | | $53 | | | $47 | | | $40 | | | $146 | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $35 |
| |
| $326 |
| |
| $287 |
| |
| $206 |
| |
| $854 |
|
| Purchase obligations (b) |
| $32 |
| |
| $54 |
| |
| $47 |
| |
| $— |
| |
| $133 |
|
(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.
| |
(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 $10.5$18.7 million to its qualified pension plans and approximately $21$22 thousand to other postretirement health care and life insurance plans in 2020,2021, although the 20202021 required pension contributions will be known with more certainty when the January 1, 20202021 valuations are completed, which is expected by April 1, 2020.2021. 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 $464.9$14.2 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.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
In addition to routine spending to maintain operations, the planned capital investment estimate includes specific Grand Gulf investments and initiatives.
As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Sources of Capital
System Energy’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•debt issuances;issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•equity contributions; and
•bank financing under new or existing facilities.
System Energy may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
All debt issuances by System Energy require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indenture 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.
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | | 2017 |
| (In Thousands) |
| $4,004 | | $59,298 | | $107,122 | | $111,667 |
|
| | | | | | |
| 2019 | | 2018 | | 2017 | | 2016 |
| (In Thousands) |
| $59,298 | | $107,122 | | $111,667 | | $33,809 |
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 $120 million scheduled to expire in September 2021.2022. As of December 31, 2019, $31.6 million in2020, no loans were outstanding under 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 facility.
System Energy obtained authorizations from the FERC through November 2020July 14, 2022 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
•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.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Complaints Against System Energy
Return on Equity and Capital Structure Complaints
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,
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Entergy Mississippi, and Entergy New Orleans under separate agreements. The current return on equity under the Unit Power Sales Agreement is 10.94%, which was established in a rate proceeding that became final in July 2001.
The APSC and MPSC complaint alleges that the return on equity is unjust and unreasonable because 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 and directed the parties to engage in settlement proceedings before an ALJ. The parties have been unable to settle the return on equity issue and a FERC hearing judge was assigned in July 2018. The 15-month refund period in connection with the APSC/MPSC complaint expired on April 23, 2018.
In April 2018 the LPSC filed a complaint with the FERC against System Energy seeking an additional 15-month refund period. The LPSC complaint requests similar relief from the FERC with respect to System Energy’s return on equity and also requests the FERC to investigate System Energy’s capital structure. The APSC, MPSC, and City Council intervened in the proceeding, filed an answer expressing support for the complaint, and asked the FERC to consolidate this proceeding with the proceeding initiated by the complaint of the APSC and MPSC in January 2017. System Energy answered the LPSC complaint in May 2018 and also filed a motion to dismiss the complaint. The 15-month refund period in connection with the LPSC return on equity complaint expired on July 26, 2019.
In August 2018 the FERC issued an order dismissing the LPSC’s request to investigate System Energy’s capital structure and setting for hearing the return on equity complaint, with a refund effective date of April 27, 2018. The 15-month refund period in connection with the LPSC return on equity complaint expired on July 26, 2019.
The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and MPSC complaint for hearing. The parties are required to addressaddressed an order (issued in a separate proceeding involving New England transmission owners) that proposed modifying the FERC’s standard methodology for determining return on equity. In September 2018, System Energy filed a request for rehearing and the LPSC filed a request for rehearing or reconsideration of the FERC’s August 2018 order. The LPSC’s request referenced an amended complaint that it filed on the same day raising the same capital structure claim the FERC had earlier dismissed. The FERC initiated a new proceeding for the amended capital structure complaint, and System Energy submitted a response in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings. Settlement proceedings in the capital structure proceeding commenced in February 2019. As noted below, in June 2019 settlement discussions were terminated and the amended capital structure complaint was consolidated with the ongoing return on equity proceeding. The 15-month refund period in connection with the capital structure complaint iswas from September 24, 2018 to December 23, 2019.
In January 2019 the LPSC and the APSC and MPSC filed direct testimony in the return on equity proceeding. For the refund period January 23, 2017 through April 23, 2018, the LPSC argues for an authorized return on equity for System Energy of 7.81% and the APSC and MPSC argue for an authorized return on equity for System Energy of 8.24%. For the refund period April 27, 2018 through July 27, 2019, and for application on a
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
prospective basis, the LPSC argues for an authorized return on equity for System Energy of 7.97% and the APSC and MPSC argue for an authorized return on equity for System Energy of 8.41%. In March 2019, System Energy submitted answering testimony in the return on equity proceeding.testimony. For the first refund period, System Energy’s testimony argues for a return on equity of 10.10% (median) or 10.70% (midpoint). For the second refund period, System Energy’s testimony shows that the calculated returns on equity for the first period fall within the range of presumptively just and reasonable returns on equity, and thus the second complaint should be dismissed (and the first period return on equity used going forward). If the FERC nonetheless were to set a new return on equity for the second period (and going forward), System Energy argues the return on equity should be either 10.32% (median) or 10.69% (midpoint).
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
In May 2019 the FERC trial staff filed its direct and answering testimony in the return on equity proceeding. For the first refund period, the FERC trial staff calculates an authorized return on equity for System Energy of 9.89% based on the application of FERC’s proposed methodology. The FERC trial staff’s direct and answering testimony noted that an authorized return on equity of 9.89% for the first refund period was within the range of presumptively just and reasonable returns on equity for the second refund period, as calculated using a study period ending January 31, 2019 for the second refund period.
In June 2019, System Entergy filed testimony responding to the testimony filed by the FERC trial staff. Among other things, System Energy’s testimony rebutted arguments raised by the FERC trial staff and provided updated calculations for the second refund period based on the study period ending May 31, 2019. For that refund period, System Energy’s testimony shows that strict application of the return on equity methodology proposed by the FERC staff indicates that the second complaint would not be dismissed, and the new return on equity would be set at 9.65% (median) or 9.74% (midpoint). System Energy’s testimony argues that these results are insufficient in light of benchmarks such as state returns on equity and treasury bond yields, and instead proposes that the calculated returns on equity for the second period should be either 9.91% (median) or 10.3% (midpoint). System Energy’s testimony also argues that, under application of its proposed modified methodology, the 10.10% return on equity calculated for the first refund period would fall within the range of presumptively just and reasonable returns on equity for the second refund period. System Energy is recording a provision against revenue for the potential outcome of this proceeding.
Also in June 2019, the FERC’s Chief ALJ issued an order terminating settlement discussions in the amended complaint addressing System Energy’s capital structure. The ALJ consolidated the amended capital structure complaint with the ongoing return on equity proceeding and set new procedural deadlines for the consolidated hearing.
In August 2019 the LPSC and the APSC and MPSC filed rebuttal testimony in the return on equity proceeding and direct and answering testimony relating to System Energy’s capital structure. The LPSC rearguesre-argues for an authorized return on equity for System Energy of 7.81% for the first refund period and 7.97% for the second refund period. The APSC and MPSC argue for an authorized return on equity for System Energy of 8.26% for the first refund period and 8.32% for the second refund period. With respect to capital structure, the LPSC proposes that the FERC establish a hypothetical capital structure for System Energy for ratemaking purposes. Specifically, the LPSC proposes that System Energy’s common equity ratio be set to Entergy Corporation’s equity ratio of 37% equity and 63% debt. In the alternative, the LPSC argues that the equity ratio should be no higher than 49%, the composite equity ratio of System Energy and the other Entergy operating companies who purchase under the Unit Power Sales Agreement. The APSC and MPSC recommend that 35.98% be set as the common equity ratio for System Energy. As an alternative, the APSC and MPSC propose that System Energy’s common equity be set at 46.75% based on the median equity ratio of the proxy group for setting the return on equity.
In September 2019 the FERC trial staff filed its rebuttal testimony in the return on equity proceeding. For the first refund period, the FERC trial staff calculates an authorized return on equity for System Energy of 9.40% based on the application of the FERC’s proposed methodology and an updated proxy group. For the second refund period, based on the study period ending May 31, 2019, the FERC trial staff rebuttal testimony argues for a return on equity of 9.63%. In September 2019 the FERC trial staff also filed direct and answering testimony relating to System Energy’s capital structure. The FERC trial staff argues that the average capital structure of the proxy group used to develop System Energy’s return on equity should be used to establish the capital structure. Using this
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
approach, the FERC trial staff calculates the average capital structure for its proposed proxy group of 46.74% common equity, and 53.26% debt.
In October 2019, System Energy filed answering testimony disputing the FERC trial staff’s, the LPSC’s, and the APSC’s and MPSC’s arguments for the use of a hypothetical capital structure and arguing that the use of System Energy’s actual capital structure is just and reasonable.
In November 2019, in a proceeding that did not involve Entergy,System Energy, the FERC issued an order addressing the methodology for determining the return on equity applicable to transmission owners in MISO. Thereafter, the participantsprocedural schedule in the System Energy proceeding agreed to amend the procedural schedulewas amended to allow the participants to file supplemental testimony addressing the order in the MISO transmission owner proceeding. proceeding (Opinion No. 569).
In February 2020 the LPSC, the MPSC and APSC, and the FERC trial staff filed supplemental testimony addressing Opinion No. 569 and how it would affect the return on equity evaluation for the two complaint periods concerning System Energy.For the first refund period, based on their respective interpretations and applications of the Opinion No. 569 methodology, the LPSC argues for an authorized return on equity for System Energy of 8.44%; the MPSC and APSC argue for an authorized return on equity of 8.41%; and the FERC trial staff argues for an authorized return on equity of 9.22%.For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569 methodology, the LPSC argues for an authorized return on equity for System Energy of 7.89%; the MPSC and APSC argue that an authorized return on equity of 8.01% may be appropriate; and the FERC trial staff argues for an authorized return on equity of 8.66%.
In April 2020, System Energy filed supplemental answering testimony addressing Opinion No. 569.System Energy argues that the Opinion No. 569 methodology is conceptually and analytically defective for purposes of establishing just and reasonable authorized return on equity determinations and proposes an alternative approach.As its primary recommendation, System Energy continues to support the return on equity determinations in its March 2019 testimony for the first refund period and its June 2019 testimony for the second refund period.Under the newOpinion No. 569 methodology, System Energy calculates a “presumptively just and reasonable range” for the authorized return on equity for the first refund period of 8.57% to 9.52%, and for the second refund period of 8.28% to 9.11%.System Energy argues that these ranges are not just and reasonable results.Under its proposed alternative methodology, System Energy calculates an authorized return on equity of 10.26% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively.
In May 2020 the FERC issued an order on rehearing of Opinion No. 569 (Opinion No. 569-A).In June 2020 the procedural schedule the hearing in the System Energy proceeding will commencewas further revised in order to allow parties to address the Opinion No. 569-A methodology.Pursuant to the revised schedule, in June 2020, the LPSC, MPSC and APSC, and the initial decision willFERC trial staff filed supplemental testimony addressing Opinion No. 569-A and how it would affect the return on equity evaluation for the two complaint periods concerning System Energy.For the first refund period, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argues for an authorized return on equity for System Energy of 7.97%; the MPSC and APSC argue for an authorized return on equity of 9.24%; and the FERC trial staff argues for an authorized return on equity of 9.49%.For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argues for an authorized return on equity for System Energy of 7.78%; the MPSC and APSC argue that an authorized return on equity of 9.15% may be dueappropriate if the second complaint is not dismissed; and the FERC trial staff argues for an authorized return on equity of 9.09% if the second complaint is not dismissed.
Pursuant to the revised procedural schedule, in October 2020.
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Management’s Financial Discussion and Analysis
The parties and FERC trial staff filed final rounds of testimony in August 2020. The hearing before a FERC ALJ occurred in late-September through early-October 2020, post-hearing briefing took place in November and December 2020, and the initial decision is due in March 2021. System Energy recorded a provision against revenue for the potential outcome of this proceeding.
Grand Gulf Sale-leaseback Renewal Complaint
In May 2018 the LPSC filed a complaint against System Energy and Entergy Services related to System Energy’s renewal of a sale-leaseback transaction originally entered into in December 1988 for an 11.5% undivided interest in Grand Gulf Unit 1. The complaint alleges that System Energy violated the filed rate and the FERC’s ratemaking and accounting requirements when it included in Unit Power Sales Agreement billings the cost of capital additions associated with the sale-leaseback interest, and that System Energy is double-recovering costs by including both the lease payments and the capital additions in Unit Power Sales Agreement billings. The complaint also claims that System Energy was imprudent in entering into the sale-leaseback renewal because the Utility operating companies that purchase Grand Gulf’s output from System Energy could have obtained cheaper capacity and energy in the MISO markets. The complaint further alleges that System Energy violated various other reporting and accounting requirements and should have sought prior FERC approval of the lease renewal. The complaint seeks various forms of relief from the FERC. The complaint seeks refunds for capital addition costs for all years in which they were recorded in allegedly non-formula accounts or, alternatively, the disallowance of the return on equity for the capital additions in those years plus interest. The complaint also asks that the FERC disallow and refund the lease costs of the sale-leaseback renewal on grounds of imprudence, investigate System Energy’s treatment of a DOE litigation payment, and impose certain forward-looking procedural protections, including audit rights for retail regulators of the Unit Power Sales Agreement formula rates. The APSC, MPSC, and City Council intervened in the proceeding.
In June 2018, System Energy and Entergy Services filed a motion to dismiss and an answer to the LPSC complaint denying that System Energy’s treatment of the sale-leaseback renewal and capital additions violated the terms of the filed rate or any other FERC ratemaking, accounting, or legal requirements or otherwise constituted double recovery. The response also argued that the complaint is inconsistent with a FERC-approved settlement to which the LPSC is a party and that explicitly authorizes System Energy to recover its lease payments. Finally, the response argued that both the capital additions and the sale-leaseback renewal were prudent investments and the LPSC complaint fails to justify any disallowance or refunds. The response also offered to submit formula rate protocols for the Unit Power Sales Agreement similar to the procedures used for reviewing transmission rates under the MISO tariff. In September 2018 the FERC issued an order setting the complaint for hearing and settlement proceedings. The FERC established a refund effective date of May 18, 2018.
In February 2019 the presiding ALJ ruled that the hearing ordered by the FERC includes the issue of whether specific subcategories of accumulated deferred income tax should be included in, or excluded from, System Energy’s formula rate. In March 2019 the LPSC, MPSC, APSC and City Council filed direct testimony. The LPSC testimony seekssought refunds that include the renewal lease payments (approximately $17.2 million per year since July 2015), rate base reductions for accumulated deferred income tax associated with uncertain tax positions, (claimed to be approximately $334.5 million as of December 2018), and the cost of capital additions associated with the sale-leaseback interest, (claimed to be approximately $274.8 million), as well as interest on those amounts. The direct testimony
System Energy disputes that any refunds are owed for billings under the Unit Power Sales Agreement.Resources, Inc.
Management’s Financial Discussion and Analysis
In June 2019 System Energy filed answering testimony in the sale-leaseback complaint proceeding arguing that the FERC should reject all claims for refunds. Among other things, System Energy argued that claims for refunds of the costs of lease renewal payments and capital additions should be rejected because those costs were recovered consistent with the Unit Power Sales Agreement formula rate, System Energy was not over or double recovering any costs, and ratepayers will save approximately $850 millioncosts over the initial and renewal terms of the leases. System Energy argued that claims for refunds associated with liabilities arising from uncertain tax positions should be rejected because the liabilities do not provide cost-free capital, the repayment timing of the liabilities is uncertain, and the outcome of the underlying tax positions is uncertain. System Energy’s testimony also challenged the refund calculations supplied by the other parties.
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Management’s Financial Discussion and Analysis
In August 2019 the FERC trial staff filed direct and answering testimony seeking refunds for rate base reductions for liabilities associated with uncertain tax positions (claimed to be up to approximately $602 million plus interest).positions. The FERC trial staff also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. In September 2019, System Energy filed cross-answering testimony disputing the FERC trial staff’s arguments for refunds, stating that the FERC trial staff’s position regarding depreciation rates for capital additions is not unreasonable, andbut explaining that any change in depreciation expense is only one element of a Unit Power Sales Agreement rebillingre-billing calculation. Adjustments to depreciation expense in any rebillingre-billing under the Unit Power Sales Agreement formula rate will also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed. In October 2019 the LPSC filed rebuttal testimony increasing the amount of refunds sought for liabilities associated with uncertain tax positions. The LPSC now seeks approximately $512 million plus interest. At the same time, theinterest, which is approximately $191 million through December 31, 2020. The FERC trial staff also filed rebuttal testimony conceding thatin which it was no longer seeking up to $602 million related toseeks refunds of a similar amount as the LPSC for the liabilities associated with uncertain tax positions; instead, it is seeking approximately $511 million plus interest.positions. The LPSC testimony also argued that adjustments to depreciation rates should affect rate base on a prospective basis only.
A hearing was held before a FERC ALJ in November 20192019.In April 2020 the ALJ issued an initial decision.Among other things, the ALJ determined that refunds were due on three main issues.First, with regard to the lease renewal payments, the ALJ determined that System Energy is recovering an unjust acquisition premium through the lease renewal payments, and that System Energy’s recovery from customers through rates should be limited to the cost of service based on the remaining net book value of the leased assets, which is approximately $70 million.The ALJ found that the remedy for this issue should be the refund of lease payments (approximately $17.2 million per year since July 2015) with interest determined at the FERC quarterly interest rate, which would be offset by the addition of the net book value of the leased assets in the cost of service.The ALJ did not calculate a value for the refund expected as a result of this remedy.In addition, System Energy would no longer recover the lease payments in rates prospectively.Second, with regard to the liabilities associated with uncertain tax positions, the ALJ determined that the liabilities are accumulated deferred income taxes and System Energy’s rate base should have been reduced for those liabilities.If the ALJ’s initial decision is upheld, the estimated refund for this issue through December 31, 2020, is approximately $422 million, plus interest, which is approximately $110 million through December 31, 2020.The ALJ also found that System Energy should include liabilities associated with uncertain tax positions as a rate base reduction going forward.Third, with regard to the depreciation expense adjustments, the ALJ found that System Energy should correct for the error in re-billings retroactively and prospectively, but that System Energy should not be permitted to recover interest on any retroactive return on enhanced rate base resulting from such corrections.If the initial decision is affirmed on this issue, System Energy estimates refunds of approximately $19 million, which includes interest through December 31, 2020.
The ALJ initial decision is an interim step in the FERC litigation process, and an ALJ’s determinations made in an initial decision are not controlling on the FERC.The ALJ in the initial decision acknowledges that these are issues of first impression before the FERC.In June 2020, System Energy, the LPSC, and the FERC trial staff filed briefs on exceptions, challenging several of the initial decision’s findings.System Energy’s brief on exceptions challenged the initial decision’s limitations on recovery of the lease renewal payments, its proposed rate base refund for the liabilities associated with uncertain tax positions, and its proposal to asymmetrically treat interest on bill corrections for depreciation expense adjustments.The LPSC’s and the FERC trial staff’s briefs on
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Management’s Financial Discussion and Analysis
exceptions each challenged the initial decision’s allowance for recovery of the cost of service associated with the lease renewal based on the remaining net book value of the leased assets, its calculation of the remaining net book value of the leased assets, and the amount of the initial decision’s proposed rate base refund for the liabilities associated with uncertain tax positions.The LPSC’s brief on exceptions also challenged the initial decision’s proposal that depreciation expense adjustments include retroactive adjustments to rate base and its finding that section 203 of the Federal Power Act did not apply to the lease renewal.The FERC trial staff’s brief on exceptions also challenged the initial decision’s finding that the FERC need not institute a formal investigation into System Energy’s tariff.In October 2020, System Energy, the LPSC, the MPSC, the APSC, and the City Council filed briefs opposing exceptions. System Energy opposed the exceptions filed by the LPSC and the FERC trial staff. The LPSC, MPSC, APSC, City Council, and the FERC trial staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff. The case is pending before the FERC, which will review the case and issue an order on the proceeding, and the FERC may accept, reject, or modify the ALJ’s initial decision in whole or in part.Refunds, if any, that might be required will only become due after the FERC issues its order reviewing the initial decision.
In addition, in AprilSeptember 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it.The NOPA memorializes the IRS’s decision to adjust the 2015 consolidated federal income tax return of Entergy Corporation and certain of its subsidiaries, including System Energy, with regard to the uncertain decommissioning tax position.Pursuant to the audit resolution documented in the NOPA, the IRS allowed System Energy’s inclusion of $102 million of future nuclear decommissioning costs in System Energy’s cost of goods sold for the 2015 tax year, roughly 10% of the requested deduction, but disallowed the balance of the position. In September 2020, System Energy filed a motion to lodge the NOPA into the record in the FERC proceeding. In October 2020 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed oppositions to System Energy’s motion. As a result of the NOPA issued by the IRS in September 2020, System Energy filed, in October 2020, a new Federal Power Act section 205 filing at FERC to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position. On a prospective basis beginning with the October 2020 bill, System Energy proposes to include the accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position as a credit to rate base under the Unit Power Sales Agreement. In November 2020 the LPSC, APSC, MPSC, and City Council filed a protest to the filing, and System Energy responded.
In November 2020 the IRS issued a Revenue Agent’s Report (RAR) for the 2014/2015 tax year and in December 2020 Entergy executed it. The RAR contained the same adjustment to the uncertain nuclear decommissioning tax position as that which the IRS had announced in the NOPA. In December 2020, System Energy filed a motion to lodge the RAR into the record in the FERC proceeding addressing the uncertain tax position rate base issue. In January 2021 the LPSC, APSC, MPSC, and City Council filed a protest to the motion.
As a result of the RAR, in December 2020, System Energy filed amendments to its new Federal Power Act section 205 filings to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position and to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. The amendments both propose the inclusion of the RAR as support for the filings. In December 2020 the LPSC, APSC, and City Council filed a protest in response to the amendments, reiterating their prior objections to the filings. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filings subject to refund, setting them for hearing, and holding the hearing in abeyance.
In December 2020, System Energy filed a new Federal Power Act section 205 filing to provide a one-time, historical credit of $25.2 million for the accumulated deferred income taxes that would have been created by the decommissioning uncertain tax position if the IRS’s decision had been known in 2016. In January 2021 the LPSC, APSC, MPSC, and City Council filed a protest to the filing.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
LPSC Authorization of Additional Complaints
In May 2020 the LPSC authorized its staff to file additional complaints at the FERC related to the rates charged by System Energy for Grand Gulf energy and capacity supplied to Entergy Louisiana under the Unit Power Sales Agreement. The LPSC directive notes that the initial decision issued by the presiding ALJ in the Grand Gulf sale-leaseback complaint proceeding did not address, for procedural reasons, certain rate issues raised by the LPSC and declined to order further investigation of rates charged by System Energy. The LPSC directive authorizes its staff to file complaints at the FERC “necessary to address these rate issues, to request a full investigation into the rates charged by System Energy for Grand Gulf power, and to seek rate refund, rate reduction, and such other remedies as may be necessary and appropriate to protect Louisiana ratepayers.” The LPSC directive further stated that the LPSC has seen “information suggesting that the Grand Gulf plant has been significantly underperforming compared to other nuclear plants in the United States, has had several extended and unexplained outages, and has been plagued with serious safety concerns.” The LPSC expressed concern that the costs paid by Entergy Louisiana's retail customers may have been detrimentally impacted, and authorized “the filing of a FERC complaint to address these performance issues and to seek appropriate refund, rate reduction, and other remedies as may be appropriate.”
The first of the additional complaints was filed at the FERC by the LPSC, the APSC, the MPSC, and the City Council in September 2020. The new complaint raises two sets of rate allegations: violations of the filed rate and a corresponding request for refunds for prior periods; and elements of the Unit Power Sales Agreement are unjust and unreasonable and a corresponding request for refunds for the 15-month refund period and changes to the Unit Power Sales Agreement prospectively. Several of the filed rate allegations overlap with the previous complaints. The filed rate allegations not previously raised are that System Energy: failed to provide a rate base credit to customers for the “time value” of sale-leaseback lease payments collected from customers in advance of the time those payments were due to the owner-lessors; improperly included certain lease refinancing costs in rate base as prepayments; improperly included nuclear decommissioning outage costs in rate base; failed to include categories of accumulated deferred income taxes as a reduction to rate base; charged customers based on a higher equity ratio than would be appropriate due to excessive retained earnings; and did not correctly reflect money pool investments and imprudently invested cash into the money pool. The elements of the Unit Power Sales Agreement that the complaint alleges are unjust and unreasonable include: incentive and executive compensation, lack of an equity re-opener, lobbying, and private airplane travel. The new complaint also requests a rate investigation into the Unit Power Sales Agreement and System Energy’s billing practices pursuant to section 206 of the Federal Power Act, including any issue relevant to the Unit Power Sales Agreement and its inputs. System Energy filed its answer opposing the new complaint in November 2020. In its answer, System Energy argued that all of the claims raised in the complaint should be dismissed and agreed that bill adjustment with respect to two discrete issues were justified.System Energy argued that dismissal is warranted because all claims fall into one or more of the following categories: the claims have been raised and are being litigated in another proceeding; the claims do not present a prima facie case and do not satisfy the threshold burden to establish a complaint proceeding; the claims are premised on a theory or request relief that is incompatible with federal law or FERC policy; the claims request relief that is inconsistent with the filed rate; the claims are barred or waived by the legal doctrine of laches; and/or the claims have been fully addressed and do not warrant further litigation. In December 2020, System Energy filed a bill adjustment report indicating that $3.4 million had been credited to customers in connection with the two discrete issues concerning the inclusion of certain accumulated deferred income taxes balances in rates.In January 2021 the complainants filed a response to System Energy’s November 2020 answer, and in February 2020, System Energy filed a response to the complainant’s response.
The operational prudence-related complaint has not been filed as of this date, and the LPSC directive did not set a date for the filing.
Unit Power Sales Agreement
In August 2017, System Energy submitted to the FERC proposed amendments to the Unit Power Sales
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
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 amendments result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The changes were 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.
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 Sectionsection 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. In June 2018, System Energy filed with the FERC an uncontested settlement relating to the updated depreciation rates and nuclear decommissioning cost annual revenue requirements. In August 2018 the FERC issued an order accepting the settlement. In the third quarter 2018, System Energy recorded a reduction in depreciation expense of approximately $26 million, representing the cumulative difference in depreciation expense resulting from the depreciation rates used from October 11, 2017 through September 30, 2018 and the depreciation rates included in the settlement filing accepted by the FERC.
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 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 fleetGrand Gulf to meet its operational goals,goals; the performance and capacity factors of Grand Gulf, including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems and the Fukushima event;systems; 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
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Management’s Financial Discussion and Analysis
of nuclear decommissioning trust fund assets and earnings to complete decommissioning of eachthe 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 Grand Gulf, System Energy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Grand Gulf’s operating license expires in 2044.
In November 2020 the NRC placed Grand Gulf in the “regulatory response column”, or Column 2, of the NRC’s Reactor Oversight Process Action Matrix based on the incidence of three unplanned plant scrams during the second and third quarters of 2020.Two of the scram events related to new turbine control system components that failed, and a third related to a feedwater valve positioner that failed, all of which had been replaced in a refueling outage that ended in May 2020.The NRC plans to conduct a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 2.As a consequence of two additional Grand Gulf scrams during the fourth quarter 2020, System Energy expects Grand Gulf to be placed into the “degraded cornerstone column”, or Column 3, of the NRC’s Reactor Oversight Process Action Matrix based on plant performance indicators for the four quarters ended December 31, 2020. This will involve an additional supplemental NRC inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 3.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
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, 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 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.
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.
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.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
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
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
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.
System Energy Resources, Inc.
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 2021 Qualified Pension Cost | | Impact on 2020 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $727 | | $12,152 |
| Rate of return on plan assets | | (0.25%) | | $709 | | $— |
| Rate of increase in compensation | | 0.25% | | $464 | | $2,133 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Qualified Pension Cost | | Impact on 2019 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $737 | | $10,902 |
| Rate of return on plan assets | | (0.25%) | | $666 | | $— |
| Rate of increase in compensation | | 0.25% | | $422 | | $2,072 |
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 2021 Postretirement Benefit Cost | | Impact on 2020 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $58 | | $1,635 |
| Health care cost trend | | 0.25% | | $69 | | $1,202 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Postretirement Benefit Cost | | Impact on 2019 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $31 | | $1,507 |
| Health care cost trend | | 0.25% | | $64 | | $1,164 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for System Energy in 20192020 was $12.3 million.$17.3 million, including $105 thousand in settlement costs. System Energy anticipates 20202021 qualified pension cost to be $17.6$20 million. System Energy contributed $20.2$16.1 million to its qualified pension plans in 20192020 and estimates 20202021 pension contributions will approximate $10.5$18.7 million, although the 20202021 required pension contributions will be known with more certainty when the January 1, 20202021 valuations are completed, which is expected by April 1, 2020.2021.
Total postretirement health care and life insurance benefit income for System Energy in 20192020 was $1$1.5 million. System Energy expects 20202021 postretirement health care and life insurance benefit income to approximate $1.3 million. System Energy contributed $829 thousand$1.3 million to its other postretirement plans in 20192020 and expects 20202021 contributions to approximate $21$22 thousand.
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.
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Management’s Financial Discussion and Analysis
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 shareholder and Board of Directors of
System Energy Resources, Inc.
Opinion on the Financial Statements
We have audited the accompanying balance sheets of System Energy Resources, Inc. (the “Company”) as of December 31, 20192020 and 2018,2019, the related statements of income, cash flows, and changes in common equity (pages 425447 through 430452 and applicable items in pages 4951 through 236)238), for each of the three years in the period ended December 31, 2019,2020, 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, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2020, 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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that is material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.
Rate and Regulatory Matters —System Energy Resources, Inc. — Refer to Notes 2 to the financial statements
Critical Audit Matter Description
The Company is subject to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; income taxes; and depreciation and amortization expense.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the FERC sets the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses 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. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the (1) likelihood of recovery in future rates of incurred costs, (2) likelihood of refunds to customers, and (3) ongoing complaints filed with the FERC against the Company. Auditing management’s judgments regarding the outcome of future decisions by the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the FERC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the FERC for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected the Company’s filings and ongoing complaints filed with the FERC, including the Return on Equity, Capital Structure, and Grand Gulf Sale-Leaseback Renewal complaints, and considered the filings with the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, including the complaints filed with the FERC against the Company, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202026, 2021
We have served as the Company’s auditor since 2001.
|
| | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $573,410 |
| |
| $456,707 |
| |
| $633,458 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 82,438 |
| | 64,778 |
| | 71,700 |
|
| Nuclear refueling outage expenses | | 33,376 |
| | 20,715 |
| | 17,968 |
|
| Other operation and maintenance | | 206,444 |
| | 196,505 |
| | 207,344 |
|
| Decommissioning | | 35,729 |
| | 34,336 |
| | 43,347 |
|
| Taxes other than income taxes | | 29,018 |
| | 28,090 |
| | 26,180 |
|
| Depreciation and amortization | | 106,630 |
| | 97,527 |
| | 137,767 |
|
| Other regulatory credits - net | | (35,210 | ) | | (28,924 | ) | | (37,831 | ) |
| TOTAL | | 458,425 |
| | 413,027 |
| | 466,475 |
|
| | | | | | | |
| OPERATING INCOME | | 114,985 |
| | 43,680 |
| | 166,983 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 8,709 |
| | 8,750 |
| | 6,345 |
|
| Interest and investment income | | 29,488 |
| | 35,985 |
| | 17,538 |
|
| Miscellaneous - net | | (5,516 | ) | | (5,775 | ) | | (6,711 | ) |
| TOTAL | | 32,681 |
| | 38,960 |
| | 17,172 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 35,328 |
| | 38,424 |
| | 37,141 |
|
| Allowance for borrowed funds used during construction | | (2,131 | ) | | (2,218 | ) | | (1,551 | ) |
| TOTAL | | 33,197 |
| | 36,206 |
| | 35,590 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 114,469 |
| | 46,434 |
| | 148,565 |
|
| | | | | | | |
| Income taxes | | 15,349 |
| | (47,675 | ) | | 69,969 |
|
| | | | | | | |
| NET INCOME | |
| $99,120 |
| |
| $94,109 |
| |
| $78,596 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $495,458 | | | $573,410 | | | $456,707 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 23,026 | | | 82,438 | | | 64,778 | |
| Nuclear refueling outage expenses | | 27,737 | | | 33,376 | | | 20,715 | |
| Other operation and maintenance | | 178,249 | | | 206,444 | | | 196,505 | |
| Decommissioning | | 37,181 | | | 35,729 | | | 34,336 | |
| Taxes other than income taxes | | 28,657 | | | 29,018 | | | 28,090 | |
| Depreciation and amortization | | 110,395 | | | 106,630 | | | 97,527 | |
| Other regulatory credits - net | | (26,531) | | | (35,210) | | | (28,924) | |
| TOTAL | | 378,714 | | | 458,425 | | | 413,027 | |
| | | | | | |
| OPERATING INCOME | | 116,744 | | | 114,985 | | | 43,680 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 9,122 | | | 8,709 | | | 8,750 | |
| Interest and investment income | | 36,478 | | | 29,488 | | | 35,985 | |
| Miscellaneous - net | | (10,012) | | | (5,516) | | | (5,775) | |
| TOTAL | | 35,588 | | | 32,681 | | | 38,960 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 34,467 | | | 35,328 | | | 38,424 | |
| Allowance for borrowed funds used during construction | | (1,809) | | | (2,131) | | | (2,218) | |
| TOTAL | | 32,658 | | | 33,197 | | | 36,206 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 119,674 | | | 114,469 | | | 46,434 | |
| | | | | | |
| Income taxes | | 20,543 | | | 15,349 | | | (47,675) | |
| | | | | | |
| NET INCOME | | $99,131 | | | $99,120 | | | $94,109 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
(Page left blank intentionally)
| | | | | | | | | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $99,131 | | | $99,120 | | | $94,109 | |
| Adjustments to reconcile net income to net cash flow provided by (used in) operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 184,429 | | | 212,170 | | | 186,719 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | (455,732) | | | 95 | | | 24,040 | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | 13,932 | | | (23,382) | | | 18,169 | |
| Accounts payable | | (11,587) | | | 18,204 | | | (7,067) | |
| Prepaid taxes and taxes accrued | | 69,145 | | | 19,247 | | | (51,999) | |
| Interest accrued | | 729 | | | (1,302) | | | (94) | |
| Other working capital accounts | | (34,158) | | | 15,879 | | | (45,415) | |
| Other regulatory assets | | (48,880) | | | (43,712) | | | (2,044) | |
| Other regulatory liabilities | | 140,965 | | | 130,949 | | | (156,802) | |
| | | | | | |
| Pension and other postretirement liabilities | | 15,596 | | | 11,177 | | | (23,235) | |
| Other assets and liabilities | | (119,032) | | | (138,304) | | | 64,947 | |
| Net cash flow provided by (used in) operating activities | | (145,462) | | | 300,141 | | | 101,328 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (193,857) | | | (166,695) | | | (194,696) | |
| Allowance for equity funds used during construction | | 9,122 | | | 8,709 | | | 8,750 | |
| Nuclear fuel purchases | | (94,991) | | | (18,170) | | | (125,272) | |
| Proceeds from the sale of nuclear fuel | | 25,836 | | | 26,223 | | | 30,634 | |
| Proceeds from nuclear decommissioning trust fund sales | | 418,943 | | | 500,384 | | | 573,561 | |
| Investment in nuclear decommissioning trust funds | | (432,249) | | | (517,828) | | | (583,683) | |
| Changes in money pool receivable - net | | 55,294 | | | 47,824 | | | 4,545 | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | 5,459 | | | 0 | | | 0 | |
| Net cash flow used in investing activities | | (206,443) | | | (119,553) | | | (286,161) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 1,147,903 | | | 1,103,917 | | | 741,785 | |
| Retirement of long-term debt | | (891,410) | | | (1,187,406) | | | (662,904) | |
| Capital contribution from parent | | 350,000 | | | 0 | | | 0 | |
| Changes in short-term credit borrowings - net | | 0 | | | 0 | | | (17,830) | |
| | | | | | |
| Common stock dividends and distributions | | (80,653) | | | (124,250) | | | (67,720) | |
| | | | | | |
| Net cash flow provided by (used in) financing activities | | 525,840 | | | (207,739) | | | (6,669) | |
| Net increase (decrease) in cash and cash equivalents | | 173,935 | | | (27,151) | | | (191,502) | |
| Cash and cash equivalents at beginning of period | | 68,534 | | | 95,685 | | | 287,187 | |
| Cash and cash equivalents at end of period | | $242,469 | | | $68,534 | | | $95,685 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid during the period for: | | | | | | |
| Interest - net of amount capitalized | | $35,061 | | | $21,052 | | | $17,183 | |
| Income taxes | | $384,329 | | | $2,284 | | | $53,956 | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $99,120 |
| |
| $94,109 |
| |
| $78,596 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 212,170 |
| | 186,719 |
| | 240,962 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 95 |
| | 24,040 |
| | 7,827 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | (23,382 | ) | | 18,169 |
| | 9,210 |
|
| Accounts payable | | 18,204 |
| | (7,067 | ) | | 15,969 |
|
| Prepaid taxes and taxes accrued | | 19,247 |
| | (51,999 | ) | | 62,466 |
|
| Interest accrued | | (1,302 | ) | | (94 | ) | | (660 | ) |
| Other working capital accounts | | 15,879 |
| | (45,415 | ) | | 12,083 |
|
| Other regulatory assets | | (43,712 | ) | | (2,044 | ) | | 60,012 |
|
| Other regulatory liabilities | | 130,949 |
| | (156,802 | ) | | 331,251 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | — |
| | — |
| | (325,707 | ) |
| Pension and other postretirement liabilities | | 11,177 |
| | (23,235 | ) | | 4,024 |
|
| Other assets and liabilities | �� | (138,304 | ) | | 64,947 |
| | (124,755 | ) |
| Net cash flow provided by operating activities | | 300,141 |
| | 101,328 |
| | 371,278 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (166,695 | ) | | (194,696 | ) | | (91,705 | ) |
| Allowance for equity funds used during construction | | 8,709 |
| | 8,750 |
| | 6,345 |
|
| Nuclear fuel purchases | | (18,170 | ) | | (125,272 | ) | | (49,728 | ) |
| Proceeds from the sale of nuclear fuel | | 26,223 |
| | 30,634 |
| | 69,516 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 500,384 |
| | 573,561 |
| | 565,416 |
|
| Investment in nuclear decommissioning trust funds | | (517,828 | ) | | (583,683 | ) | | (596,236 | ) |
| Changes in money pool receivable - net | | 47,824 |
| | 4,545 |
| | (77,858 | ) |
| Net cash flow used in investing activities | | (119,553 | ) | | (286,161 | ) | | (174,250 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 1,103,917 |
| | 741,785 |
| | 150,100 |
|
| Retirement of long-term debt | | (1,187,406 | ) | | (662,904 | ) | | (150,103 | ) |
| Changes in short-term credit borrowings - net | | — |
| | (17,830 | ) | | (49,063 | ) |
| Common stock dividends and distributions | | (124,250 | ) | | (67,720 | ) | | (106,610 | ) |
| Other | | — |
| | — |
| | (28 | ) |
| Net cash flow used in financing activities | | (207,739 | ) | | (6,669 | ) | | (155,704 | ) |
| Net increase (decrease) in cash and cash equivalents | | (27,151 | ) | | (191,502 | ) | | 41,324 |
|
| Cash and cash equivalents at beginning of period | | 95,685 |
| | 287,187 |
| | 245,863 |
|
| Cash and cash equivalents at end of period | |
| $68,534 |
| |
| $95,685 |
| |
| $287,187 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $21,052 |
| |
| $17,183 |
| |
| $26,251 |
|
| Income taxes | |
| $2,284 |
| |
| $53,956 |
| |
| ($2,227 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2020 | | 2019 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $26,086 | | | $93 | |
| Temporary cash investments | | 216,383 | | | 68,441 | |
| Total cash and cash equivalents | | 242,469 | | | 68,534 | |
| Accounts receivable: | | | | |
| Associated companies | | 57,743 | | | 121,972 | |
| Other | | 2,550 | | | 7,547 | |
| Total accounts receivable | | 60,293 | | | 129,519 | |
| | | | |
| Materials and supplies - at average cost | | 123,006 | | | 108,766 | |
| Deferred nuclear refueling outage costs | | 34,459 | | | 14,493 | |
| | | | |
| Prepayments and other | | 6,864 | | | 6,045 | |
| TOTAL | | 467,091 | | | 327,357 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Decommissioning trust funds | | 1,215,868 | | | 1,054,098 | |
| TOTAL | | 1,215,868 | | | 1,054,098 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 5,309,458 | | | 5,070,859 | |
| | | | |
| Construction work in progress | | 59,831 | | | 164,996 | |
| Nuclear fuel | | 175,005 | | | 149,574 | |
| TOTAL UTILITY PLANT | | 5,544,294 | | | 5,385,429 | |
| Less - accumulated depreciation and amortization | | 3,355,367 | | | 3,285,487 | |
| UTILITY PLANT - NET | | 2,188,927 | | | 2,099,942 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets | | 538,963 | | | 490,083 | |
| Accumulated deferred income tax | | 0 | | | 8,023 | |
| Other | | 3,119 | | | 3,192 | |
| TOTAL | | 542,082 | | | 501,298 | |
| | | | |
| TOTAL ASSETS | | $4,413,968 | | | $3,982,695 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $93 |
| |
| $68 |
|
| Temporary cash investments | | 68,441 |
| | 95,617 |
|
| Total cash and cash equivalents | | 68,534 |
| | 95,685 |
|
| Accounts receivable: | | |
| | |
|
| Associated companies | | 121,972 |
| | 148,571 |
|
| Other | | 7,547 |
| | 5,390 |
|
| Total accounts receivable | | 129,519 |
| | 153,961 |
|
| Materials and supplies - at average cost | | 108,766 |
| | 97,225 |
|
| Deferred nuclear refueling outage costs | | 14,493 |
| | 44,424 |
|
| Prepaid taxes | | — |
| | 5,415 |
|
| Prepayments and other | | 6,045 |
| | 2,985 |
|
| TOTAL | | 327,357 |
| | 399,695 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Decommissioning trust funds | | 1,054,098 |
| | 869,543 |
|
| TOTAL | | 1,054,098 |
| | 869,543 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 5,070,859 |
| | 5,036,116 |
|
| Construction work in progress | | 164,996 |
| | 70,156 |
|
| Nuclear fuel | | 149,574 |
| | 234,889 |
|
| TOTAL UTILITY PLANT | | 5,385,429 |
| | 5,341,161 |
|
| Less - accumulated depreciation and amortization | | 3,285,487 |
| | 3,212,080 |
|
| UTILITY PLANT - NET | | 2,099,942 |
| | 2,129,081 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Other regulatory assets | | 490,083 |
| | 446,371 |
|
| Accumulated deferred income tax | | 8,023 |
| | — |
|
| Other | | 3,192 |
| | 4,124 |
|
| TOTAL | | 501,298 |
| | 450,495 |
|
| | | | | |
| TOTAL ASSETS | |
| $3,982,695 |
| |
| $3,848,814 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2020 | | 2019 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $100,015 | | | $10 | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | 15,309 | | | 14,619 | |
| Other | | 41,313 | | | 64,144 | |
| Taxes accrued | | 82,977 | | | 13,832 | |
| | | | |
| Interest accrued | | 12,722 | | | 11,993 | |
| | | | |
| Other | | 4,248 | | | 3,381 | |
| TOTAL | | 256,584 | | | 107,979 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 359,835 | | | 821,963 | |
| Accumulated deferred investment tax credits | | 38,902 | | | 40,181 | |
| Regulatory liability for income taxes - net | | 151,829 | | | 142,845 | |
| Other regulatory liabilities | | 665,396 | | | 533,415 | |
| Decommissioning | | 968,910 | | | 931,729 | |
| Pension and other postretirement liabilities | | 125,412 | | | 109,816 | |
| Long-term debt | | 705,259 | | | 548,097 | |
| Other | | 61,295 | | | 34,602 | |
| TOTAL | | 3,076,838 | | | 3,162,648 | |
| | | | |
| Commitments and Contingencies | | 0 | | 0 |
| | | | |
| COMMON EQUITY | | | | |
| Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2020 and 2019 | | 951,850 | | | 601,850 | |
| | | | |
| Retained earnings | | 128,696 | | | 110,218 | |
| TOTAL | | 1,080,546 | | | 712,068 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $4,413,968 | | | $3,982,695 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $10 |
| |
| $6 |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 14,619 |
| | 11,031 |
|
| Other | | 64,144 |
| | 47,565 |
|
| Taxes accrued | | 13,832 |
| | — |
|
| Interest accrued | | 11,993 |
| | 13,295 |
|
| Current portion of unprotected excess accumulated deferred income taxes | | — |
| | 4,426 |
|
| Other | | 3,381 |
| | 2,832 |
|
| TOTAL | | 107,979 |
| | 79,155 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 821,963 |
| | 805,296 |
|
| Accumulated deferred investment tax credits | | 40,181 |
| | 38,673 |
|
| Regulatory liability for income taxes - net | | 142,845 |
| | 158,998 |
|
| Other regulatory liabilities | | 533,415 |
| | 381,887 |
|
| Decommissioning | | 931,729 |
| | 896,000 |
|
| Pension and other postretirement liabilities | | 109,816 |
| | 98,639 |
|
| Long-term debt | | 548,097 |
| | 630,744 |
|
| Other | | 34,602 |
| | 22,224 |
|
| TOTAL | | 3,162,648 |
| | 3,032,461 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| COMMON EQUITY | | |
| | |
|
| Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2019 and 2018 | | 601,850 |
| | 601,850 |
|
| Retained earnings | | 110,218 |
| | 135,348 |
|
| TOTAL | | 712,068 |
| | 737,198 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $3,982,695 |
| |
| $3,848,814 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| STATEMENTS OF CHANGES IN COMMON EQUITY |
| For the Years Ended December 31, 2020, 2019, and 2018 |
| | | |
| | Common Equity | | |
| | Common Stock | | | | Retained Earnings | | Total |
| | (In Thousands) |
| | | | | | | |
| Balance at December 31, 2017 | $658,350 | | | | | $52,459 | | | $710,809 | |
| Net income | 0 | | | | | 94,109 | | | 94,109 | |
| Common stock dividends and distributions | (56,500) | | | | | (11,220) | | | (67,720) | |
| Balance at December 31, 2018 | $601,850 | | | | | $135,348 | | | $737,198 | |
| Net income | 0 | | | | | 99,120 | | | 99,120 | |
| Common stock dividends and distributions | 0 | | | | | (124,250) | | | (124,250) | |
| Balance at December 31, 2019 | $601,850 | | | | | $110,218 | | | $712,068 | |
| Net income | 0 | | | | | 99,131 | | | 99,131 | |
| Capital contribution from parent | 350,000 | | | | | 0 | | | 350,000 | |
| Common stock dividends and distributions | 0 | | | | | (80,653) | | | (80,653) | |
| Balance at December 31, 2020 | $951,850 | | | | | $128,696 | | | $1,080,546 | |
| | | | | | | |
| See Notes to Financial Statements. | | | | | | | |
|
| | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| STATEMENTS OF CHANGES IN COMMON EQUITY |
| For the Years Ended December 31, 2019, 2018, and 2017 |
| | | | |
| | Common Equity | | |
| | Common Stock | | Retained Earnings | | Total |
| | (In Thousands) |
| | | | | | |
| Balance at December 31, 2016 |
| $679,350 |
| |
| $59,473 |
| |
| $738,823 |
|
| Net income | — |
| | 78,596 |
| | 78,596 |
|
| Common stock dividends and distributions | (21,000 | ) | | (85,610 | ) | | (106,610 | ) |
| Balance at December 31, 2017 |
| $658,350 |
| |
| $52,459 |
| |
| $710,809 |
|
| Net income | — |
| | 94,109 |
| | 94,109 |
|
| Common stock dividends and distributions | (56,500 | ) | | (11,220 | ) | | (67,720 | ) |
| Balance at December 31, 2018 |
| $601,850 |
| |
| $135,348 |
| |
| $737,198 |
|
| Net income | — |
| | 99,120 |
| | 99,120 |
|
| Common stock dividends and distributions | — |
| | (124,250 | ) | | (124,250 | ) |
| Balance at December 31, 2019 |
| $601,850 |
| |
| $110,218 |
| |
| $712,068 |
|
| | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | |
| | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | (Dollars In Thousands) |
| | | | | | | | | |
| Operating revenues | $495,458 | | | $573,410 | | | $456,707 | | | $633,458 | | | $548,291 | |
| Net income | $99,131 | | | $99,120 | | | $94,109 | | | $78,596 | | | $96,744 | |
| Total assets | $4,413,968 | | | $3,982,695 | | | $3,848,814 | | | $3,938,887 | | | $3,927,712 | |
| Long-term obligations (a) | $705,259 | | | $548,097 | | | $630,744 | | | $466,484 | | | $501,129 | |
| Electric energy sales (GWh) | 5,849 | | | 9,940 | | | 6,264 | | | 6,675 | | | 5,384 | |
| | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt). |
|
| | | | | | | | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (Dollars In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $573,410 |
| |
| $456,707 |
| |
| $633,458 |
| |
| $548,291 |
| |
| $632,405 |
|
| Net income |
| $99,120 |
| |
| $94,109 |
| |
| $78,596 |
| |
| $96,744 |
| |
| $111,318 |
|
| Total assets |
| $3,982,695 |
| |
| $3,848,814 |
| |
| $3,938,887 |
| |
| $3,927,712 |
| |
| $3,728,875 |
|
| Long-term obligations (a) |
| $548,097 |
| |
| $630,744 |
| |
| $466,484 |
| |
| $501,129 |
| |
| $572,665 |
|
| Electric energy sales (GWh) | 9,940 |
| | 6,264 |
| | 6,675 |
| | 5,384 |
| | 10,547 |
|
| | | | | | | | | | |
| (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 20192020 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-lived Assets” in Note 14 to the financial statements.
Item 4. Mine Safety Disclosures
Not applicable.
INFORMATION ABOUT EXECUTIVE OFFICERS OF ENTERGY CORPORATION
Executive Officers
|
| | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Leo P. Denault (a) | | 6061 | | Chairman of the Board and Chief Executive Officer of Entergy Corporation | | 2013-Present |
| | | | | | |
| A. Christopher Bakken, III (a) | | 5859 | | Executive Vice President and Chief Nuclear Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy | | 2016-Present |
| | | | Project Director, Hinkley Point C of EDF Energy | | 2009-2016 |
| | | | | | |
| Marcus V. Brown (a) | | 5859 | | Executive Vice President and General Counsel of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2013-Present |
| | | | | | |
| Andrew S. Marsh (a) | | 4849 | | Executive Vice President and Chief Financial Officer of Entergy Corporation | | 2013-Present |
| | | | | Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2013-Present |
| | | | Chief Financial Officer of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2014-Present |
|
| | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Roderick K. West (a) | | 5152 | | Group President Utility Operations of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | | 2017-Present |
| | | | President, Chief Executive Officer, and Director of System Energy | | 2017-Present |
| | | | Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2017-Present |
| | | | President and Chief Executive Officer of Entergy New Orleans | | 2018 |
| | | | Executive Vice President of Entergy Corporation | | 2010-2017 |
| | | | Chief Administrative Officer of Entergy Corporation | | 2010-2016 |
| | | | | | |
| Paul D. Hinnenkamp (a) | | 5859 | | Executive Vice President and Chief Operating Officer of Entergy Corporation | | 2017-Present |
| | | | | Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | | 2015-Present |
| | | | Senior Vice President and Chief Operating Officer of Entergy Corporation | | 2015-2017 |
| | | | Senior Vice President, Capital Project Management and Technology of Entergy Services, Inc. | | 2015 |
| | | | | | |
| Kathryn A. Collins | | 57 | | Senior Vice President and Chief Human Resources Officer, Entergy Corporation | | 2020-Present |
| | | | Chief Human Resources Officer, Arcosa, Inc. | | 2018-2020 |
| | | | Vice President, Human Resources, Trinity, Inc. | | 2014-2018 |
| | | | | | |
| Julie E. Harbert (a) | | 47 | | Senior Vice President, Corporate Business Services of Entergy Corporation | | 2019-Present |
| | | | Vice President, Capital Project Management and TechnologyShared Services of Entergy Services, Inc. | | 2013-20152017-2019 |
| | | | Senior Vice President, Global Business Services of Philips Health Tech | | 2015-2017 |
| | | | | | |
| Kimberly A. Fontan (a) | | 4647 | | Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2019-Present |
| | | | Vice President, System Planning of Entergy Services, Inc. | | 2017-2019 |
| | | | Vice President, Regulatory Services of Entergy Services, Inc. | | 2015-2017 |
| | | | Vice President, Regulatory Affairs of Entergy Louisiana | | 2014-2015 |
| | | | | | |
| Peter S. Norgeot, Jr. (a) | | 5455 | | Senior Vice President, Transformation of Entergy Corporation | | 2018-Present |
| | | | Senior Vice President, Power Generation of Entergy Services | | 2017-2018 |
| | | | Vice President, Fossil Generation of Entergy Services | | 2015-2017 |
| | | | Vice President, Power Plant Operations, Steam of Entergy Services | | 2014-2015 |
| | | | | | |
Julie E. Harbert (a) | | 46 | | Senior Vice President, Corporate Business Services of Entergy Corporation | | 2019-Present |
| | | | Vice President, Shared Services of Entergy Services, Inc. | | 2017-2019 |
| | | | Senior Vice President, Global Business Services of Philips Health Tech | | 2015-2017 |
| | | | Vice President and Group Head of Operations, Global Shared Services of IBM | | 2014 |
| |
(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. |
(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 are provided as of December 31, 2019.2020.
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. As of January 31, 2020,2021, there were 23,69622,817 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) |
| | | | | | | | | |
10/01/20192020 - 10/31/20192020 | | — |
| |
| $— |
| — | — |
| $350,052,918 |
| $350,052,918 |
|
11/01/20192020 - 11/30/20192020 | | — |
| |
| $— |
| — | — |
| $350,052,918 |
| $350,052,918 |
|
12/01/20192020 - 12/31/20192020 | | — |
| |
| $— |
| — | — |
| $350,052,918 |
| $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 2019,2020, Entergy withheld 76,735151,159 shares of its common stock at $86.03$126.31 per share, 82,55079,153 shares of its common stock at $129.55 per share, 41,167 shares of its common stock at $131.52 per share, 2,269 shares of its common stock at $124.28 per share, 1,331 shares of its common stock at $123.74 per share, 1,088 shares of its common stock at $102.93 per share, 441 shares of its common stock at $132.19 per share, 71 shares of its common stock at $86.51 per share, 38,32631 shares of its common stock at $87.10$115.90 per share, 932and 19 shares of its common stock at $89.19 per share, and 2,280 shares of its common stock at $93.25$86.74 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. |
(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 Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
There is no market for the common equity of the Registrant Subsidiaries. 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, LLC AND SUBSIDIARIES, ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, LLC, ENTERGY NEW ORLEANS, 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, LLC AND SUBSIDIARIES, ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, LLC, ENTERGY NEW ORLEANS, 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 and Subsidiaries, Entergy Arkansas, LLC and Subsidiaries, Entergy Louisiana, LLC and Subsidiaries, Entergy Mississippi, LLC, Entergy New Orleans, LLC and Subsidiaries, Entergy Texas, Inc. and Subsidiaries, 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 Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, or System Energy.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
As of December 31, 2019,2020, evaluations were performed under the supervision and with the participation of Entergy Corporation, Entergy Arkansas, 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 Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The managements of Entergy Corporation, Entergy Arkansas, 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, 2019.2020. 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, 2019.2020.
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. The report of Deloitte & Touche LLP is not applicable to Entergy Arkansas, 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, 20192020 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 of
Entergy Corporation and Subsidiaries
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, 2019,2020, based on criteria established in Internal Control -Integrated—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019,2020, 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, 20192020 of the Corporation and our report dated February 21, 202026, 2021 expressed an unqualified opinion on 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 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 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202026, 2021
PART III
Item 10. Directors, Executive Officers, and Corporate Governance of the Registrants (Entergy Corporation, Entergy Arkansas, 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 “Proposal 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, 2020,7, 2021, 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, LLC |
| | | | | | |
NameDirectors | | Age | | Position | | Period |
Entergy Arkansas, LLC |
| | | | | | |
Directors | | | | | | |
| Laura R. Landreaux | | 4647 | | President and Chief Executive Officer of Entergy Arkansas | | 2018-Present |
| | | | Director of Entergy Arkansas | | 2018-Present |
| | | | Operational Finance Director of Entergy Arkansas | | 2017-2018 |
| | | | Vice President, Regulatory Affairs of Entergy Arkansas | | 2014-2017 |
| | | | | | |
| Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Andrew S. Marsh | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| | | | | | |
| Officers | | | | | | |
| A. Christopher Bakken, III | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Marcus V. Brown | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Leo P. Denault |
| | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Laura R. Landreaux | | | | See information under the Entergy Arkansas Directors Section above. | | |
| Andrew S. Marsh |
| | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Kimberly A. Fontan |
| | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Roderick K. West |
| | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC |
| Directors | | | | | | |
| Phillip R. May, Jr. | | 58 | | President and Chief Executive Officer of Entergy Louisiana | | 2013-Present |
| | | | Director of Entergy Louisiana | | 2013-Present |
| | | | | | |
ENTERGY LOUISIANA, LLC |
Directors | | | | | | |
Phillip R. May, Jr. | | 57 | | President and Chief Executive Officer of Entergy Louisiana | | 2013-Present |
| | | | Director of Entergy Louisiana | | 2013-Present |
| | | | | | |
| Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Andrew S. Marsh | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| | | | | | |
| Officers | | | | | | |
| A. Christopher Bakken, III | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Marcus V. Brown | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Leo P. Denault | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Andrew S. Marsh | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Phillip R. May, Jr. | | | | See information under the Entergy Louisiana Directors Section above. | | |
| Kimberly A. Fontan | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| Directors | | | | | | |
| Haley R. Fisackerly | | 55 | | President and Chief Executive Officer of Entergy Mississippi | | 2008-Present |
| | | | Director of Entergy Mississippi | | 2008-Present |
| | | | | | |
ENTERGY MISSISSIPPI, LLC |
Directors | | | | | | |
Haley R. Fisackerly | | 54 | | President and Chief Executive Officer of Entergy Mississippi | | 2008-Present |
| | | | Director of Entergy Mississippi | | 2008-Present |
| | | | | | |
| Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Andrew S. Marsh | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
|
| | | | | | | | | | | | | | | | | | | |
| Officers | | | | | | |
| Marcus V. Brown | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Leo P. Denault | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Haley R. Fisackerly | | | | See information under the Entergy Mississippi Directors Section above. | | |
| Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Andrew S. Marsh | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Kimberly A. Fontan | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC |
| Directors | | | | | | |
| David D. Ellis | | 5152 | | President and Chief Executive Officer of Entergy New Orleans | | 2018-Present |
| | | | Director of Entergy New Orleans | | 2018-Present |
| | | | President and Chief Executive Officer, Global Power Technologies | | 2018 |
| | | | Managing Director and Chairman of Comverge International, Inc. | | 2010-2017 |
| | | | | | |
| Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Andrew S. Marsh | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
|
| | | | | | | | | | | | | | | | | | | |
| Officers | | | | | | |
| Marcus V. Brown | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Leo P. Denault | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| David D. Ellis | | | | See information under the Entergy New Orleans Directors Section above. | | |
| Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Andrew S. Marsh | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Kimberly A. Fontan | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. |
| Directors | | | | | | |
| Sallie T. Rainer | | 58 | | President and Chief Executive Officer of Entergy Texas | | 2012-Present |
| | | | Director of Entergy Texas | | 2012-Present |
| | | | | | |
ENTERGY TEXAS, INC. |
Directors | | | | | | |
Sallie T. Rainer | | 57 | | President and Chief Executive Officer of Entergy Texas | | 2012-Present |
| | | | Director of Entergy Texas | | 2012-Present |
| | | | | | |
| Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Andrew S. Marsh | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
|
| | | | | | | | | | | | | | | | | | | |
| Officers | | | | | | |
| Marcus V. Brown | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Leo P. Denault | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Andrew S. Marsh | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Kimberly A. Fontan | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Sallie T. Rainer | | | | See information under the Entergy Texas Directors Section above. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
The directors and officers of Entergy Texas are elected annually to serve by the unanimous consent of its sole common stockholder. The directors and officers of Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC and Entergy New Orleans, LLC are elected annually to serve by the unanimous consent of the sole common membership owner, Entergy 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, which immediately follows the annual meeting of shareholders. The age of each officer and director for whom information is presented above is as of December 31, 2019.2020.
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 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:
Patrick J. Condon (Chairman)
Philip L. Frederickson
M. Elise Hyland
Karen A. Puckett
All Audit Committee members are independent. In addition to the general independence requirements of the NYSE, 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 required by the NYSE rules and the Board has determined that Messrs. Condon and Frederickson satisfy the financial expertise requirements of the NYSE and have the requisite experience to be designated an audit committee financial expert as that term is defined by the rules of the SEC.
Code of Ethics
Effective October 2018, the Entergy Corporation Board of Directors adopted a Code of Business Conduct and Ethics that applies to members of the Entergy Corporation Board of Directors and all Entergy officers and employees. The Code of Business Conduct and Ethics includes Special Provisions Relating to Principal Executive Officer and Senior Financial Officers. It 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 expected 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, 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.
Nominations to the Entergy Corporation Board of Directors; Nominating Procedure
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 discussed in the Proxy Statement under “Board of Directors - Identifying Director Candidates”; and
•the candidate’s signed consent to be named in the Proxy Statement and a representation of such candidates’ intent to serve as a director for the entire term if 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.
Item 11. Executive Compensation
ENTERGY CORPORATION
Information concerning compensation earned by the directors and officers of Entergy Corporation is set forth in its Proxy Statement, to be filed in connection with the Annual Meeting of Shareholders to be held May 8, 2020,7, 2021, under the headings “Compensation Discussion and Analysis,” “Annual Compensation Programs Risk Assessment,” “Executive Compensation Tables,” “Pay Ratio Disclosure,” “Our 20202021 Director Nominees,” and “2019“2020 Non-Employee Director Compensation,” all of which information is incorporated herein by reference. References in this section to the “Company” refer to Entergy Corporation.
ENTERGY ARKANSAS, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND ENTERGY TEXAS
COMPENSATION DISCUSSION AND ANALYSIS
In this section,This Compensation Discussion and Analysis describes Entergy Corporation’s executive compensation policies, programs, philosophy and decisions regarding the Named Executive Officers (“NEOs”) for 2020. It also explains how and why the Personnel Committee of Entergy Corporation’s Board of Directors arrived at the specific compensation earneddecisions involving the NEOs in 2019 by the following executive officers (referred to herein as “Named Executive Officers”) is discussed.2020 who were:
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| | | | |
Name(1) | Title |
| A. Christopher Bakken, III | Executive Vice President, Nuclear Operations/Chief Nuclear Officer |
| Marcus V. Brown | Executive Vice President and General Counsel |
| Leo P. Denault | Chairman of the Board and Chief Executive Officer |
| David D. Ellis | President and Chief Executive Officer, Entergy New Orleans |
| Haley R. Fisackerly | President and Chief Executive Officer, Entergy Mississippi |
| Laura R. Landreaux | President and Chief Executive Officer, Entergy Arkansas |
| Andrew S. Marsh | Executive Vice President and Chief Financial Officer, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas |
| Phillip R. May, Jr. | President and Chief Executive Officer, Entergy Louisiana |
| Sallie T. Rainer | President and Chief Executive Officer, Entergy Texas |
| Roderick K. West | Group President, Utility Operations |
| |
(1) | Messrs. Bakken, Brown, Denault, Marsh, and West hold the positions referenced above as executive officers of Entergy Corporation and are members of Entergy Corporation’s Office of the Chief Executive. No additional compensation was paid in 2019 to any of these officers for their service as Named Executive Officers of the Utility operating companies. |
Entergy Corporation’s Compensation Principles and Philosophy
Entergy Corporation’s executive compensation programs are based on a philosophy of pay for performance that supports its strategy and business objectives. It believes the executive pay programs:
•Motivate its management team to drive strong financial and operational results by linking pay to performance.
•Attract and retain a highly experienced, diverse and successful management team.
•Incentivize and reward the achievement of results that are deemed by the Personnel Committee to be consistent with the overall goals and strategic direction that the Entergy Corporation Board has approved.
•Create sustainable value for the benefit of all of Entergy Corporation’s stakeholders, including its customers, employees, communities and owners.
•Align the interests of the executives and Entergy Corporation’s investors in its long-term business strategy by directly tying the value of equity-based awards to Entergy Corporation’s stock price performance and relative total shareholder return.
Executive Compensation Programs andBest Practices:
Entergy Corporation regularly reviews its executive compensation programs to align them with commonly viewed best practices in the market and to reflect feedback from discussions with Entergy Corporation’s investors on executive compensation.compensation.
Entergy Corporation’s Compensation Principles and 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. It believes the executive pay programs:
| |
• | Motivate its management team to drive strong financial and operational results.
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| |
• | Attract and retain a highly experienced and successful management team.
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• | Incentivize and reward the achievement of financial and operational 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.
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• | Align the interests of the executives and Entergy Corporation shareholders by directly tying the value of equity-based awards to Entergy Corporation’s stock price performance, relative total shareholder return and earnings growth.
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• | Create sustainable value for the benefit of all of Entergy Corporation’s stakeholders, including its owners, customers, employees and communities.
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Executive Compensation Best Practices:
|
| | |
| What Entergy Corporation Does |
| ✓ | * | Executive compensation programs are highly correlated to performance and focused on long-term value creation |
*✓ | Double trigger for cash severance payments and equity acceleration in the event of a change in control |
*✓ | Clawback policy |
*✓ | Maximum payout capped at 200% of target under the Annual Incentive Planfor annual incentive awards and Long-Term Performance Unit Program for members of the Office of the Chief ExecutiveOCE |
*✓ | Rigorous goal setting aligned with externally disclosed annual and multi-year financial targets |
*✓ | Minimum vesting periods for equity-based awards |
*✓ | Long-term compensation mix weighted more toward performance units than service-based equity awards |
*✓ | All long-term incentive compensation is settled in Entergy Corporation common stock |
*✓ | Rigorous stock ownership and share retention requirements |
*✓ | Annual Say on Pay vote |
| ✓ | Annual Compensation Risk Assessment |
| 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 for members of the Office of the Chief Executive,OCE, other than relocation benefits |
*× | No option repricing or cash buy-outs for underwater options without shareholder approval |
*× | 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 |
*× | No hedging or pledging of Entergy Corporation common stock |
*× | No fixed term employment agreements |
*× | No new officer 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 |
2019
How Entergy Corporation Makes Compensation Decisions
The Personnel Committee oversees the executive compensation programs and policies with the advice of its independent compensation consultant and support from Entergy Corporation’s management team.
| | | | | | | | | | | |
| Personnel Committee | • | The Personnel Committee is responsible for the review and approval of all aspects of the executive compensation programs and policies. |
| • | Among its duties, the Personnel Committee is responsible for approving the compensation for all members of the OCE, including: |
| • | Annual review of the compensation elements and mix of elements for the following year; |
| • | Annual review and approval of incentive program design, goals and objectives for alignment with Entergy Corporation’s compensation and business strategies; |
| • | Evaluation of Company and individual performance results in light of these goals and objectives; |
| • | Evaluation of the competitiveness of each executive officer’s total compensation package; |
| • | Approval of any changes to its executive officers’ compensation, including but not limited to, base salary, annual and long-term incentive award opportunities and retention programs; |
| • | Evaluation of the performance of Entergy Corporation’s Chairman and Chief Executive Officer; and |
| • | Reporting, at least annually, to the Entergy Corporation Board of Directors on succession planning. |
| • | The Personnel Committee also receives reports and engages on other significant matters affecting the general employee population, including workforce diversity, inclusion and belonging, organizational health and safety. |
| • | The Personnel Committee has the sole authority to hire its compensation consultant, approve its compensation, determine the nature and scope of its services, evaluate its performance and terminate its engagement. |
| Management | • | Entergy Corporation’s Chief Executive Officer and Chief Human Resources Officer (CHRO) work closely with the Personnel Committee in managing the executive compensation programs and attend meetings of the Personnel Committee. Mr. Denault and the CHRO, Kathryn Collins since she joined Entergy Corporation, attended all of the Personnel Committee meetings held in 2020. |
| • | The Chief Executive Officer reviews with the committee the performance of the members of the OCE other than himself and makes recommendations to the committee regarding compensation for these executive officers. |
| Independent Compensation Consultant | • | During 2020, Pay Governance, LLC (“Pay Governance”) assisted the Personnel Committee with its responsibilities related to Entergy Corporation’s executive compensation programs. |
| • | Pay Governance: |
| • | Regularly attended meetings of the committee; |
| • | Conducted studies of competitive compensation practices; |
| • | Identified Entergy Corporation’s market surveys and proxy peer group; |
| • | Provided updates on executive compensation trends and regulatory developments; |
| • | Reviewed base salary, annual incentives and long-term incentive compensation opportunities relative to competitive practices; and |
| • | Developed conclusions and recommendations related to the executive compensation programs for consideration by the committee. |
2021 Executive Compensation Program ChangesEnhancements
During 2019, the following changes were made toAnnual Incentive Awards. Feedback from Entergy Corporation’s executive officer compensation programs:
Annual Incentive Plan
investors has indicated that environmental, social and governance (or ESG) issues are being viewed as increasingly vital to long-term performance. In recognition ofaddition, investors are expecting more transparency regarding corporate ESG commitments. This echoes Entergy Corporation’s successful execution onown commitment to ESG and all of its strategycritical stakeholders. Thus, Entergy Corporation conducted a comprehensive review of its incentive program in 2020 to exitidentify and prioritize the optimal incentive metrics – including ESG goals – to use in the 2021 program. Historically, Entergy Corporation has used two financial measures to determine the Entergy Wholesale Commodities merchant power business,Achievement Multiplier (“EAM”), which is the performance metric used to determine the maximum funding available for annual incentive awards. ESG and other performance metrics were considered in determining the allocation of incentive funds to certain workgroups and individual recipients. However, to demonstrate Entergy Corporation decidedCorporation’s strong commitment to establishits ESG goals, and to more explicitly link compensation to the interests of its stakeholders, the EAM will be determined based on financial and non-financial measures beginning in 2021. Specifically, a new, singlefinancial measure will be weighted 60%, while quantitative and qualitative non-financial measures, including ESG metrics, will account for the remaining 40%.
Financial Measure: Keeping with the committee’s goal of aligning performance measures with financial results that link to externally communicated investor guidance, ETR Tax Adjusted earnings per share or ETR Tax Adjusted EPS will continue to be used as the financial measure not calculated in accordance with generally accepted accounting principles into determine 60% of the United States (“GAAP”) for guidance
and investor reporting purposes that would better reflect its ongoing business and respond to feedback received from investorsEAM. ETR Tax Adjusted EPS is based on the earnings measures on which Entergy Corporation had previously reported and guided. This new measure, EntergyEntergy’s Adjusted Earnings Per Share (“ETR Adjusted EPS”), which is the earnings measure that is used for external guidance. ETR Adjusted EPS adjusts the Company’sEntergy Corporation’s as reported (GAAP) earnings per share results to eliminate the impact of its Entergy Wholesale Commodities merchant power business, significant tax items and other non-routine items. WithTo arrive at ETR Tax Adjusted EPS, ETR Adjusted EPS is adjusted to add back the effect of significant tax items, and to eliminate the effect of: (i) major storms, including the impact on total debt of pending securitizations, (ii) the resolution of certain unresolved regulatory litigation matters, (iii) unrealized gains or losses on equity securities, (iv) potential effects of federal income tax law changes, and (v) elective contributions to pension plans or trusts related to non-qualified postretirement benefits that deviate from original plan assumptions.
Non-Financial Measures: The following non-financial metrics will be used to determine 40% of the EAM for 2021:
| | | | | | | | |
| Measure | Description | Rationale |
| Safety | Quantitative measure of serious injury and fatalities per 100 employees or contractors as defined by EEI. | •Ensures a safe and incident-free workplace is maintained for all of Entergy Corporation’s employees and contractors. |
| Diversity, Inclusion & Belonging (DIB) | Overall qualitative assessment of DIB key performance indicators assessed in the workforce, workplace and marketplace, informed by quantitative measures; progress on DIB initiatives; and responsiveness to emergent issues. | •Reinforces the commitment to be a fair and equitable work environment that is welcoming to all and allows Entergy Corporation to attract and retain superb talent, allowing it to execute its strategy to be the Premier Utility. |
•Drives an engaged workforce; customer-centric service and solutions; enhancement of owner value; and community partnerships. |
| Environmental Stewardship | Assessment of progress toward environmental commitments through performance on key initiatives and Utility CO2 emission rate outcomes. | •Reinforces Entergy Corporation’s commitment to long-term sustainability and a reduced impact on the environment. Ensures accountability for achieving its significant external commitments to reduce carbon emissions. |
| Customer Net Promoter Score | Utilize quantitative Residential Net Promoter Score benchmark survey process. | •Incentivizes actions that drive positive customer outcomes (as measured through customer feedback) including impacts on reliability improvements, responsiveness, continuous improvement and innovation. |
•Signals overall health and loyalty of Entergy Corporation’s customer relationship. |
Targets for each of the non-financial measures will be clearly defined and will be designed to drive employee behaviors that support all four of Entergy Corporation’s stakeholders – customers, employees, communities and our owners.
Long-Term Performance Incentive Program (“LTIP”). In recent performance periods, Entergy Corporation has used two financial measures to determine awards under the LTIP – a cumulative earnings per share (EPS) measure (most recently cumulative ETR Adjusted EPS) and relative total shareholder return (“TSR”). To emphasize the importance of strong cash generation for the long-term health of its business, Entergy Corporation is replacing the EPS measure with a credit measure – adjusted FFO/Debt ratio for the 2021 – 2023 performance period. The adjusted FFO/Debt ratio is the ratio of: (i) adjusted funds from operations calculated as operating cash flow adjusted for allowance for funds used during construction, working capital and the effects of securitization revenue, and the pre-defined exclusions discussed above for the annual incentives; to (ii) total debt, excluding outstanding or pending securitization debt. The Personnel Committee decided to use this changeratio because it emphasizes financial stability, noting that a financially healthy utility creates the capacity to make investments on behalf of customers, addresses the needs of communities, provides low-cost access to capital markets and promotes employee confidence. Relative TSR will continue to be used as the other performance measure for the 2021 – 2023 LTIP performance period, with relative TSR weighted 80% and the credit measure weighted 20%. Relative TSR measures Entergy Corporation’s total TSR relative to the TSR of the companies in the external guidancePhiladelphia Utility Index as of December 31, 2020. Targets for the LTIP performance measures will include the same exclusions that will be used to determine the annual incentive financial measure targets.
2020 Incentive Payouts
Performance measures and giventargets for the 2020 annual incentive awards were determined by the Personnel Committee’s desire to maintain an appropriate degree of alignment between the Company’s externally communicated earnings targetsCommittee in January 2020 and the targets underand measures for the 2018 – 2020 LTIP performance cycle were
established in January 2018. In January 2021, the Personnel Committee certified the results for the EAM for the 2020 annual incentive plan,awards and the committee adopted new2018 – 2020 LTIP performance measurescycle. The Personnel Committee did not make any adjustments to determine the maximum funding leveltargets for either program for the impact of COVID-19 on Entergy Corporation and its subsidiaries.
Entergy Corporation believes the annual2020 incentive plan with eachpay outcomes for the NEOs demonstrate the application of its pay for performance measure weighted equally:philosophy.
Annual Incentive Awards
The Personnel Committee determined that the 2020 EAM would be based on two equally weighted performance metrics:
•ETR Tax Adjusted Earnings Per Share (“ETR Tax Adjusted EPS”): Entergy Corporation uses a single non-GAAP earnings measure for guidance and investor reporting purposes that reflects its ongoing business. This measure, Entergy Adjusted Earnings Per Share (“ETR Adjusted EPS”) adjusts Entergy Corporation’s as reported (GAAP) earnings per share results to eliminate the impact of its Entergy Wholesale Commodities business, significant tax items and other non-routine items. ETR Tax Adjusted EPS is based on the externally reported ETR Adjusted EPS, which is then adjusted to add back the effect of significant tax items, and to eliminate the effect of major storms, the resolution of certain unresolved regulatory litigation matters, changes in federal income tax law and unrealized gains or losses on equity securities (the “Pre-Determined Exclusions”)., as well as other items the Personnel Committee may consider appropriate adjustments based on management accountability and business rationale.
The cash flow measure, ETR•Entergy Adjusted Operating Cash Flow (“ETR Adjusted OCF”): ETR Adjusted OCF is calculated based on Entergy Corporation’s as-reported (GAAP) operating cash flow, adjusted to eliminate the effect of any Pre-Determined Exclusions.
Long-Term IncentivesThe 2020 annual incentive award targets and results determined by the Personnel Committee were:
| | | | | | | | |
| Annual Incentive Program Performance Goals | 2020 Targets | 2020 Results |
| ETR Tax Adjusted EPS | $5.60 | $6.90 |
| ETR Adjusted OCF ($ billions) | $3.450 | $3.127 |
| EAM as a percentage of target | 100% | 120% |
| Average NEO Payout (as a percentage of target) | | 124% |
In keeping withJanuary 2021, the changePersonnel Committee determined that ETR Adjusted EPS exceeded the maximum by $1.30, but fell short of achieving its ETR Adjusted OCF target of $3.45 billion by approximately $323 million, leading to a preliminary EAM of 118%. In recognition of management’s success in achieving positive outcomes in 2020 on certain strategic efforts deemed critical to Entergy Corporation’s external guidance measure,long-term success, the committee also adopted a new earnings measure for use in measuring performance underexercised its discretion to increase the Long-Term Performance Unit Program. In particular,EAM by 2% to 120%. Based on each NEO’s individual accountabilities and accomplishments, the committee decided that,then determined individual annual incentive awards of 115% to 150% of the target opportunity for each of the 2019-2021 the NEOs.
Long-Term Performance Unit Program period,
In January 2018, the Personnel Committee chose relative TSR and Cumulative Adjusted Utility, Plant & Other Earnings Per Share (“Cumulative Adjusted UP&O EPS”), each weighted equally, as the performance measures will be (1)for the 2018 – 2020 LTIP performance period. Cumulative Adjusted UP&O EPS adjusts Entergy Corporation’s cumulative ETR Adjusted EPS, adjustedoperational Utility, Parent & Other results to eliminate the effectimpact of any Pre-Determined Exclusions;tax items and (2) relative total shareholder return with relative total shareholder return weighted eighty percent and cumulative ETR Adjusted EPS accountingweather. Similar to the way targets are established for the remaining twenty percent.
Short-Termannual incentive awards, the relative TSR and Long-Term Incentive Targets Tailored to Role
Beginning in 2019, the short and long-term incentive targets for officers who are members of Entergy Corporation’s Office of the Chief Executive are being determined based on job-specific market data for the officer’s role. Previously, the targetsCumulative Adjusted UP&O EPS performance measures were the average of the market data for the officers within a specific management level, without regard to the officer’s specific job functions. The targets for the Named Executive Officers who are Presidents of the Utility operating companies continue to be determined based on the average of the market data for the officers within a specific management level, without regard to their specific job function. Entergy Corporation believes that this change for the members of the Office of the Chief Executive will help assure that each officer’s incentive targets are market competitive with respect to the officer’s particular role.
2019 Incentive Pay Outcomes
Entergy Corporation believes the 2019 incentive pay outcomes for the Named Executive Officers demonstrated the application of Entergy Corporation’s pay for performance philosophy.
Annual Incentive Plan
Awards under the Executive Annual Incentive Plan, or Annual Incentive Plan, are tied to Entergy Corporation’s financial and operational performance through the Entergy Achievement Multiplier (“EAM”), which is the performance metric used to determine the maximum funding available for awards under the plan. The 2019 EAM was determined based on the two equally weighted performance metrics discussed in the “2019 Executive Compensation Program Changes” section above.
2019 Annual Incentive Plan Payout
For 2019, the Personnel Committee, based on the recommendation of the Finance Committee, determined that management exceeded its ETR Tax Adjusted EPS goal of $5.30 per share by $1.23 per share and fell short of its ETR Adjusted Operating Cash Flow goal of $3.1 billion by approximately $134 million. Based on the targets and ranges previously established by the Personnel Committee these results resulted in a calculated EAMafter the Board’s review of 139%.
Long-Term Performance Unit Program
Under the Long-Term Performance Unit Program, units are granted with performance measured over a three-year period based on Entergy Corporation’s total shareholder return in relation tostrategic plan.
The targets and results for the total shareholder return of the companies included in the Philadelphia Utility Index. Payouts, if any, are based on Entergy Corporation’s performance on these measures against pre-established performance goals.
Long-Term Performance Unit Program Payout
For the three-year2018 – 2020 LTIP performance period ending in 2019, Entergy Corporation’s total shareholder return was in the top quartile of the companies in the Philadelphia Utility Index, yielding a payout of 200% of target for the Named Executive Officers. Payouts were made in shares of Entergy Corporation stock which are required to be heldas determined by the executive officers until they satisfy the executive stock ownership guidelines.Personnel Committee were:
| | | | | | | | |
| LTIP Results | 2018 - 2020 LTIP Target | 2018 - 2020 LTIP Result |
| Relative TSR | Median | 2nd Quartile |
| Cumulative Adjusted UP&O EPS | $15.20 | $15.25 |
| Payout (as a percentage of target) | 100% | 126% |
What Entergy Corporation Pays and Why
Principal Executive Compensation Elements
The principal components of Entergy Corporation’s 2020 executive compensation programs and the purpose of each component were:
| | | | | | | | | | | | | | | | | |
| Compensation Element | Form | Performance Metrics | Primary Purpose | Vesting Period | Subject to Clawback |
| Base Salary | Cash | N/A | Provides a base level of competitive cash compensation for executive talent. | N/A | N/A |
| Annual Incentive | Cash | ETR Tax Adjusted EPS (50%) | Motivates and rewards executives for performance on key financial measures during the year. | 1 year | ü |
ETR Adjusted OCF
(50%) |
| Long-Term Performance Units | Equity | Relative TSR (80%) | Focuses the executive officers on building long-term shareholder value, growing earnings and increases executives’ ownership of Entergy Corporation common stock. | 3 years | ü |
| Cumulative ETR Adjusted EPS (20%) |
| Stock Options | Equity | N/A | Align interests of executives with long-term shareholder value, provide competitive compensation, and increase executives’ ownership in Entergy Corporation common stock. | 3 years | ü |
| Restricted Stock | Equity | N/A | Aligns interests of executives with long-term shareholder value, provides competitive compensation, retains executive talent and increases the executives’ ownership in Entergy Corporation common stock. | 3 years | ü |
Competitive Positioning
Market Data for Compensation Comparison
Annually, the Personnel Committee reviews:
•Published and private compensation survey data compiled by Pay Governance, LLC (“Pay Governance”), the Personnel Committee’s independent compensation consultant;
•Both utility and general industry data to determine total cash compensation (base salary and annual incentive) for non-industry specific roles;
•Data from utility companies to determine total cash compensation for management roles that are utility-specific, such as Group President, Utility Operations; and
•Utility market data to determine long-term incentives for all positions.
How the Personnel Committee Uses the Market Data
The Personnel Committee uses this survey data to develop compensation opportunities that are designed to deliver total targetdirect compensation (“TDC”) within a targeted range of approximately the 50th percentile of the surveyed companies in the aggregate. In most cases, the committee considers its objectives to have been met if Entergy Corporation’s Chief Executive Officer and the eight other executive officers (including the applicable Named Executive Officers)NEOs) who constitute the Office of the Chief ExecutiveOCE each has a target compensation opportunity that falls within a targeted range of 85% - 115% of the 50th percentile of the survey data. In general, compensation levels for an executive officer who is new to a position tend to be at the lower end of the competitive range, while seasoned executive officers with strong performance whowhose experience and skill set are viewed as critical to retain would be positioned at the higher end of the competitive range. Generally, differences in the levels of total direct compensationTDC among the Named Executive OfficersNEOs are primarily driven by the scope of their responsibilities, differences in the competitive market pay range for similar positions, performance and considerations of internal pay equity.
Proxy Peer Group
Although the survey data described above are the primary data used in benchmarking compensation, the committee uses compensation information from the companies included in the Philadelphia Utility Index to evaluate the overall reasonableness of Entergy Corporation’s compensation programs and to determine relative total shareholder returnTSR for the 2017-2019 Long-Term Performance Unit Program awards. Companies2020 - 2022 LTIP performance period. The companies included in the Philadelphia Utility Index at the time the proxy data was compiled were as follows:Personnel Committee approved the 2020 compensation model and framework were:
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Ÿ | | AES Corporation | Ÿ | El Paso Electric Co.* |
Ÿ | | Ameren Corporation | Ÿ | Eversource Energy |
Ÿ | | American Electric Power Co. Inc. | Ÿ | Exelon Corporation |
Ÿ | | American Water Works Company, Inc. | Ÿ | FirstEnergy Corporation |
Ÿ | | CenterPoint Energy Inc. | Ÿ | NextEra Energy, Inc. |
Ÿ | | Consolidated Edison Inc. | Ÿ | PG&EPinnacle West Capital Corporation |
Ÿ | | Dominion Energy | Ÿ | Public Service Enterprise Group, Inc. |
Ÿ | | DTE Energy Company | Ÿ | Southern Company |
Ÿ | | Duke Energy Corporation | Ÿ | Xcel Energy, Inc. |
Ÿ | | Edison International | | |
Principal Executive Compensation Elements
The following table summarizes*El Paso Electric Co. is no longer included in the elements of total direct compensation (“TDC”) granted or paid to the executive officers under the 2019 executive compensation programs. The programs use a mix of fixed and variable compensation elements and are designed to provide alignment with both short- and long-term business goals through annual and long-term incentives. An executive officer’s TDC is based primarily on corporate performance, market-based compensation levels and individual performance with each of these elements reviewed annually for each Named Executive Officer.Philadelphia Utility Index.
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Compensation Component | Primary Purpose | Performance Measured | Performance Period |
Base Salary (Cash) | Provides a base level of competitive cash compensation for executive talent. | Experience, job scope, market data, individual performance and internal equity | Annual |
Annual Incentive (Cash) | Motivates and rewards executives for performance on key financial measures during the year. | ETR Tax Adjusted EPS
ETR Adjusted Operating Cash Flow
| 1 year |
Long-Term Performance Unit Program (Equity) | Focuses the executives on growing earnings and building long-term shareholder value and increases the executives’ ownership in Entergy Corporation common stock. | Relative total shareholder return
Cumulative ETR Adjusted EPS
| 3 years |
Stock Options (Equity) | Align interests of executives with long-term shareholder value, provide competitive compensation, and increase the executives’ ownership in Entergy Corporation’s common stock. | Stock price, job scope, market data, and individual performance | 3 years |
Restricted Stock (Equity) | Aligns interests of executives with long-term shareholder value, provides competitive compensation, retains executive talent and increases the executives’ ownership in Entergy Corporation’s common stock. | Stock price, job scope, market data, and individual performance
| 3 years |
2020 Compensation Decisions
Fixed Compensation
Base Salary
The Personnel Committee determinesWhen setting the base salaries for all of the Named Executive OfficersNEOs who are members of the OfficeOCE, the Personnel Committee generally targets the range of compensation paid to similarly situated executive officers of the Chief Executive based on competitive compensationcompanies included in the market data performance considerations,previously discussed in this Compensation Discussion and advice provided by the committee’s independent compensation consultant.Analysis under “Competitive Positioning.” For the other Named Executive Officers,NEOs, their salaries are established by their immediate supervisors using the same criteria. The base salaries of the Named Executive OfficersNEOs are considered annually as part of the performance review process, and upon a Named Executive Officer’sNEO’s promotion or other change in job responsibilities. In 2019, Based on this review in 2020 and after reviewing the market data above, all of the Named Executive Officers,NEOs, other than Mr. Denault, received merit increases in their base salaries ranging from approximately 2.5% to 4.5%6.15%. In 2019,2020, Mr. Denault did not receive a meritan increase in his base salary. Instead, the
Personnel Committee increased Mr.Mr. Denault’s TDC by increasing his annual and long-term incentive target opportunities; thus,thereby, increasing the shareportion of his compensation that is “at risk.” The increases in base salary were based on the market data previously discussed in this CD&A under “Whatrisk” and further aligning his interests with those of Entergy Corporation Pays and Why.”Corporation’s shareholders.
The following table sets forth the 20182019 and 20192020 base salaries for the Named Executive Officers. Changes in base salaries for 20192020 were effective in April.
| | | Named Executive Officer | | 2018 Base Salary | | 2019 Base Salary | Named Executive Officer | | 2019 Base Salary | | 2020 Base Salary |
| A. Christopher Bakken, III | | $638,125 | | $654,078 | A. Christopher Bakken, III | | $654,078 | | $673,700 |
| Marcus V. Brown | | $650,000 | | $666,250 | Marcus V. Brown | | $666,250 | | $690,000 |
| Leo P. Denault | | $1,260,000 | | $1,260,000 | Leo P. Denault | | $1,260,000 | | $1,260,000 |
| David D. Ellis | | $305,000 | | $313,388 | David D. Ellis | | $313,388 | | $321,849 |
| Haley R. Fisackerly | | $365,959 | | $376,023 | Haley R. Fisackerly | | $376,023 | | $388,244 |
| Laura R. Landreaux | | $308,000 | | $316,470 | Laura R. Landreaux | | $316,470 | | $326,755 |
| Andrew S. Marsh | | $622,000 | | $650,000 | Andrew S. Marsh | | $650,000 | | $690,000 |
| Phillip R. May, Jr. | | $381,550 | | $392,043 | Phillip R. May, Jr. | | $392,043 | | $404,784 |
| Sallie T. Rainer | | $338,123 | | $347,422 | Sallie T. Rainer | | $347,422 | | $358,713 |
| Roderick K. West | | $696,598 | | $714,013 | Roderick K. West | | $714,013 | | $731,863 |
Variable Compensation
Short-TermAnnual Incentive Compensation
Annual Incentive Plan
Awards under the Executive Annual Incentive Plan, or Annual Incentive Plan, areIn 2020, annual incentive awards were tied to Entergy Corporation’s financial and operational performance through the EAM, which is the performance metric used to determine the maximum funding available for awards under the plan.EAM. Entergy Corporation uses the following process to determine annual incentive awards:
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• | Establish Performance Measures to Determine EAM Pool.Annually, the Personnel Committee engages in a rigorous process to determine the performance measures used to determine the EAM. The Personnel Committee’s goal is to establish measures that are consistent with Entergy Corporation’s strategy and business objectives for the upcoming year, as reflected in its financial plan, and are designed to drive results that represent a high level of achievement. These measures are approved based on a comprehensive review by the full Board of Entergy Corporation’s financial plan, conducted in December of the preceding year and updated in January to reflect key drivers of anticipated changes in performance from the preceding year.
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• | Establish Target Achievement Levels.In January, after Entergy Corporation’s financial plan is updated to reflect any changes from that reviewed in December, the Personnel Committee establishes the specific targets that must be achieved for each performance measure. The Personnel Committee also seeks to assure that the targets:
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◦ | Take into account changes in the business environment and specific challenges facing Entergy Corporation; |
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◦ | Reflect an appropriate balancing of the various risks and opportunities recognized at the time the targets are set; and |
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◦ | Are aligned with external expectations communicated to Entergy Corporation’s shareholders. |
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• | Establish Named Officer Target Opportunities. In January of each year, the Personnel Committee establishes the target opportunities for the members of the Office of the Chief Executive based on its review of the competitive analysis of job-specific market data prepared by Pay Governance as well as the officer’s role, individual performance and internal equity considerations. For the Named Executive Officers who are members of the Office of the Chief Executive (Messrs. Bakken, Brown, Denault, Marsh and West), target award opportunities are established based on these factors. For the other Named Executive Officers, target award opportunities are determined based on their management level within the Entergy organization. Executive management levels at Entergy Corporation range from ML level 1 through ML level 4 (the “ML 1-4 Officers”). At December 31, 2019, Mr. May held a Level 3 position, and Mr. Ellis, Mr. Fisackerly, Ms. Landreaux and Ms. Rainer held Level 4 positions. Accordingly, their respective incentive award opportunities differ from one another based on either their management level or the external market data developed by the Committee’s independent compensation consultant. The 2019 target opportunities were increased for Mr. Denault, Mr. Marsh and Mr. Brown to align more closely with market data. The target levels for the other Named Executive Officers are comparable to the levels set for 2018.
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• | Determine the EAM.After the end of the fiscal year, the Finance and Personnel Committees jointly review Entergy Corporation’s financial results and the Personnel Committee determines the EAM, which represents the level of success in achieving the performance objectives established by the committee and determines the maximum funding level of the annual incentive plan, as a percentage of the total target opportunity.
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• | Determine Annual Incentive Awards. To determine individual executive officer awards under the annual incentive plan, the Personnel Committee considers not only each executive’s role in executing on Entergy Corporation’s strategies and delivering the financial performance achieved, but also the individual’s accountability for any challenges the Company experienced during•Establish Performance Measures to Determine EAM Pool.Annually, the Personnel Committee engages in a rigorous process to determine the performance measures used to determine the EAM. The Personnel Committee’s goal is to establish measures that are consistent with Entergy Corporation’s strategy and business objectives for the upcoming year, as reflected in its strategic plan, and are designed to drive results that represent a high level of achievement. These measures are approved based on a comprehensive review of Entergy Corporation’s strategic plan by its full Board of Directors conducted in December of the preceding year and updated in January to reflect key drivers of anticipated changes in performance from the preceding year.
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•Establish Target Achievement Levels.In January, after Entergy Corporation’s strategic plan is updated to reflect any changes from that reviewed in December, the Personnel Committee establishes the specific targets that must be achieved for each performance measure. The Personnel Committee also seeks to assure that the targets:
◦Take into account changes in the business environment and specific challenges facing Entergy Corporation;
◦Reflect an appropriate balancing of the various risks and opportunities recognized at the time the targets are set; and
◦Are aligned with external expectations communicated to Entergy Corporation’s shareholders.
•Establish NEO Target Opportunities. In January of each year, the Personnel Committee establishes the target opportunities for the members of the OCE based on its review of the competitive analysis of job-specific market data prepared by Pay Governance as well as the officer’s role, individual performance and internal equity considerations. For the NEOs who are members of the OCE (Messrs. Bakken, Brown, Denault, Marsh and West), target award opportunities are established based on these factors. For the other NEOs, target award opportunities are determined based on their management level within the Entergy organization. Executive management levels at Entergy Corporation range from ML level 1 through ML level 4 (the “ML 1-4 Officers”). At December 31, 2020, Mr. May held a Level 3 position, and Mr. Ellis,
Mr. Fisackerly, Ms. Landreaux and Ms. Rainer held Level 4 positions. Accordingly, their respective incentive award opportunities differ from one another based on either their management level or the external market data developed by the Committee’s independent compensation consultant. The 2020 target opportunities were increased for Mr. Bakken, Mr. Brown, Mr. Marsh and Mr. West to align more closely with market data and internal pay equity. Mr. Denault’s 2020 target opportunity was unchanged from the level set in 2019 due to the Personnel Committee’s decision to increase his TDC by increasing his long-term incentive target opportunities. The target levels for the other NEOs are comparable to the levels set for 2019.
•Determine the EAM.In January, after the end of the fiscal year, the Finance and Personnel Committees jointly review Entergy Corporation’s financial results and the Personnel Committee determines the EAM, which represents the level of success in achieving the performance objectives established by the committee and determines the maximum funding level of the annual incentive plan, as a percentage of the total target opportunity.
•Determine Annual Incentive Awards. To determine individual executive officer awards under the annual incentive plan, the Personnel Committee considers not only each executive’s role in executing on Entergy Corporation’s strategies and delivering the financial performance achieved, but also the individual’s accountability for any challenges Entergy Corporation experienced during the year.
Establishing 2020 Financial Measures and Targets
Using the process described above, in December 2018,2019, the Personnel Committee decided to use ETR Tax Adjusted EPS and ETR Adjusted Operating Cash Flow,OCF, with each measure weighted equally, as the performance measures for determining the 20192020 EAM pool. ETR Tax Adjusted EPS is based on ETR Adjusted EPS, which is the primary earnings measure used by the CompanyEntergy Corporation externally and the measure on which it provides annual earnings guidance, whichguidance. To arrive at ETR Tax Adjusted EPS, ETR Adjusted EPS is then adjusted to add back the effect of any significant tax items that were excluded to arrive at ETR Adjusted EPS and to eliminate the effects, if any, of the Pre-Determined Exclusions. ETR Adjusted Operating Cash FlowOCF is calculated based on Entergy Corporation’s as-reported (GAAP) operating cash flow, adjusted to eliminate the effect of any significant non-routine items not representative of the ongoing business, such as items associated with the decisions to sell or close the Entergy Wholesale Commodities nuclear plants, and any Pre-Determined Exclusions. The Personnel Committee determined that ETR Tax Adjusted EPS and ETR Adjusted Operating Cash FlowOCF were the appropriate metrics to use for this purposeannual incentives in 2020 because:
•They are based on objective financial measures that Entergy Corporation and its investors consider to be important in evaluating its financial performance;
•They are based on the same metrics we use for internal and external financial reporting; and
•They provide both discipline and transparency.
The Personnel Committee considered it appropriate to use ETR Tax Adjusted EPS, which adds back the effect of significant tax items that may have been excluded from ETR Adjusted EPS, as the earnings measure because of the significant financial benefits to Entergy Corporation resulting from such tax items and the management effort required to achieve them. The Personnel Committee also considered the appropriateness of excluding the effect of each of the specific Pre-Determined Exclusions it had identified from each of the financial measures. It viewed the exclusion of major storms 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 Personnel Committee considered the exclusion of any unanticipated effects of the tax reform legislation adopted at the end of 2017 to be appropriate because of the lingering uncertainty around those effects and the inability of management to impact those results. The Personnel Committee approved the other exclusions from reported results - for the impact of certain legacy unresolved regulatory litigation and unanticipated unrealized gains and losses on securities held by Entergy Corporation’s nuclear decommissioning trusts - primarily because of management’s inability to influence either of the related outcomes. The Personnel Committee further provided that in determining the 2020 EAM, the 2020 results would be subject to adjustment for other items the committee may consider appropriate in its review of 2020 performance, considering management accountability and business
rationale, and the EAM as so calculated would be subject to further adjustment at the committee’s discretion based on business considerations.
In determining the targets to set for 2019,2020, the Personnel Committee reviewed anticipated drivers and risks to Entergy Corporation’s expectations for consolidated operationalits adjusted earnings per share and consolidated operational operating cash flow for 20192020 as set forth in Entergy Corporation’sits financial plan, as well as factors driving the strong financial performance achieved in 2018.2019. The Personnel Committee confirmed that the proposed plan targets for ETR Tax Adjusted EPS and ETR Adjusted Operating Cash FlowOCF reflected substantialsignificant growth in the core weather-adjusted utility earnings and consolidated operating cash flow measures underlying the annual incentive plan targets. The Personnel Committee also noted that while the 2020 ETR Tax Adjusted EPS target was less than the 2019 results, the 2020 target represented significant growth in the underlying ETR Adjusted EPS both from 2019 results and from the 2019 target, with the primary driver of the higher results in 2019 being certain one-time tax benefits that would not be recurring in 2020. The Personnel Committee also considered the potential impact of a wide range of identified risks and opportunities and confirmed that there appeared to be more downside risk than upside opportunity embedded in the financial plan targets and, as a result, the Personnel Committee believed that the related annual incentive plan targets reflected a reasonable balancing of such risks and opportunities and an appropriate degree of challenge.
20192020 Performance Assessment
The following table shows the 2019 Incentive Plan2020 annual incentive plan performance metrics and targets established by the Personnel Committee to determine the 2020 EAM and 20192020 results:
Annual Incentive Plan Targets and Results
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| | Performance Goals(1) | |
| Weight | Minimum | Target | Maximum | 2020 Results |
| ETR Tax Adjusted EPS ($) | 50% | 5.04 | 5.60 | 6.16 | 6.90 |
| ETR Adjusted OCF ($ billions) | 50% | 3.070 | 3.450 | 3.830 | 3.127 |
| EAM as % of Target | | 25% | 100% | 200% | 120% |
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| | | Performance Goals(1) | |
| | Weight | Minimum | Target | Maximum | 2019 Results |
ETR Tax Adjusted EPS ($)(2) | 50% | $4.77 | $5.30 | $5.83 | $6.53 |
ETR Adjusted Operating Cash Flow ($ billions)(2) | 50% | $2.650 | $3.100 | $3.550 | $2.966 |
| EAM as % of Target | | 25% | 100% | 200% | 139% |
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(1) | Payouts for performance between minimum and target achievement levels and between target and maximum achievement levels are calculated using straight-line interpolation. There is no payout for performance below the minimum achievement level. |
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(2) | ETR Tax Adjusted Earnings Per Share is a different measure than the consolidated operational earnings per share, and ETR Adjusted Operating Cash Flow is a different measure than the consolidated operational operating cash flow used to determine the 2018 annual incentive awards. As a result, the goals and results are not comparable year over year. |
In January 2020,2021, the Finance and Personnel Committees jointly reviewed Entergy Corporation’s financial results against the performance objectives reflected in the table above. Management discussed with the committees Entergy Corporation’s ETR Tax Adjusted EPS and the ETR Adjusted Operating Cash FlowOCF results for 2019,2020, including primary factors explaining how those results compared to the 20192020 business plan and Annual Incentive Planannual incentive plan targets set in January 2019.2020. ETR Tax Adjusted EPS exceeded Entergy Corporation’sthe ETR Tax Adjusted EPS target of $5.30$5.60 per share by $1.23,$1.30, but management fell short of achieving its ETR Adjusted Operating Cash FlowOCF target of $3.1$3.45 billion by approximately $134$323 million, leading to a calculatedpreliminary EAM of 139%118%. NoneThese results reflected a positive adjustment of $0.10 to ETR Tax Adjusted EPS and a positive adjustment of $274 million to ETR Adjusted OCF for the effects on earnings and operational cash flow of major storms impacting Entergy Corporation’s service area during 2020, consistent with the Pre-Determined Exclusions resultedapproved when the targets were set at the beginning of the year. The results also reflected a positive adjustment of $100 million to ETR Adjusted OCF for the effect on operational cash flow of additional voluntary contributions made to Entergy Corporation’s pension plan in 2020 over and above the required level of contributions, which adjustment was made because the committee did not consider it appropriate for management to be penalized in the incentive compensation process for choosing to make such elective contributions, consistent with the Pre-Determined Exclusion for items the committee determined should be excluded based on management accountability and business rationale.
The Personnel Committee considered whether 2020 ETR Tax Adjusted EPS or ETR Adjusted OCF should be adjusted for any adjustmentother factors that had impacted 2020 results. The committee noted that 2020 revenues and cash flow had been adversely impacted by reduced sales resulting from unfavorable weather, the COVID-19 pandemic and, to a lesser extent, major storms, which collectively reduced ETR Adjusted EPS by approximately $0.71 per share, and ETR Adjusted OCF by approximately $663 million as compared to plan. In addition, the Personnel Committee noted that ETR Adjusted OCF had been further reduced by approximately $178 million due to increased customer arrearages as a result of regulatory moratoria on customer disconnects following the onset of the pandemic. As noted, both ETR Tax Adjusted EPS and ETR Adjusted Operating Cash Flow.OCF were adjusted to reflect the impact of
major storms as a Pre-Determined Exclusion. However, the committee decided not to adjust the results to reflect the impact of the COVID-19 pandemic, the disconnect moratoria or the unfavorable weather experienced in 2020.
In addition to the foregoing financial results, the Personnel Committee considered management’s degree of success in achieving various operational and regulatory goals set out at the beginning of the year and in overcoming certain challenges that arose in the business during the course of the year. The Personnel Committee also considered (i)committee took note of not only the many ways management had created value for all Entergy Corporation’s degreekey stakeholders during 2020, but also the major challenges that were overcome in the process, including the COVID-19 pandemic and the challenges of successresponding to three hurricanes in a record-breaking storm season for the Gulf Coast. The committee also noted that despite these challenges, management had remained focused on achieving strong financial results for the benefit of all of its published earnings guidance, which it exceeded by $0.10 per sharestakeholders while at the midpointsame time driving positive outcomes in certain areas that would contribute to Entergy Corporation’s long term sustainability, including particularly the achievement of the original guidance range for ETR Adjusted EPS provided at the beginningits 2020 CO2 emissions goal, development and announcement of the yearits goal to achieve net zero carbon emissions by 2050, and by $0.05 per share at the midpointsignificant enhancements to its sustainability disclosure and reporting, and substantial progress in other important ESG and sustainability efforts. In recognition of the adjusted guidance range published in July 2019, and (ii) total shareholder return for 2019 in relation to the Philadelphia Utility Index,these accomplishments, which placed Entergy Corporation in the top quartile of companies in the index with a total shareholder return of 44.3% for the year. Finally, the committee reviewedconsiders to be critical to Entergy Corporation’s long-term success, the impact on ETR Tax Adjusted EPS and ETR Adjusted Operating Cash Flow of significant tax items that were included in the results and additional pension contributions made during the year beyond those that were required or included in the initial 2019 financial plan. Following this review, the Personnel Committee decidedcommittee exercised its discretion to approveincrease the EAM as calculated in accordance with the plan design.by 2% to 120%.
To determine individual executive officerNEO annual incentive awards under the Annual Incentive Plan for the Named Executive OfficersNEOs who are membersmember of the Office of the Chief Executive,OCE, the Personnel Committee considered not only each executive’s roleindividual performance in executing on Entergy Corporation’s strategies and delivering the strong financial performance achieved in 2018, but also2020. In addition, the Personnel Committee considered the individual’s accountability forkey accountabilities and accomplishments in relation to certain operational and regulatory challenges itEntergy Corporation experienced during the year. With these considerations in mind, the committee exercised negative discretionPersonnel Committee approved payouts ranging from 115% to determine individual awards that ranged from 135% to 137%120% of target for each of the Named Executive OfficersNEOs who are members of the Office of the Chief Executive, with the extent of the negative discretion applied varying based on the executive’s specific accountabilities and accomplishments. OCE.
After the EAM was established to determine overall funding for the Annual Incentive Plan,annual incentive awards, Entergy Corporation’s Chief Executive Officer allocated incentive award funding to individual business units based on business unit results. Individual awards were determined for the remaining Named Executive OfficersNEOs who are not members of the Office of the Chief ExecutiveOCE by their immediate supervisor based on the individual officer’s key accountabilities, accomplishments, and performance. This resulted in payouts that ranged from 127%117% of target to 208%150% of target for the Named Executive OfficersNEOs who are not members of the Office of the Chief Executive.OCE.
Based on the foregoing evaluation of management performance, the Named Executive Officers received the following Annual Incentive Planannual incentive payouts for 2019:2020:
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| Named Executive Officer | Base Salary | Target as Percentage of Base Salary | Payout as Percentage of Target | 2020 Annual
Incentive Award |
| A. Christopher Bakken, III | $673,700 | 75% | 115% | $581,066 |
| Marcus V. Brown | $690,000 | 80% | 120% | $662,400 |
| Leo P. Denault | $1,260,000 | 140% | 120% | $2,116,800 |
| David D. Ellis | $321,849 | 40% | 128% | $164,955 |
| Haley R. Fisackerly | $388,244 | 40% | 150% | $232,737 |
| Laura R. Landreaux | $326,755 | 40% | 128% | $167,153 |
| Andrew S. Marsh | $690,000 | 85% | 120% | $703,800 |
| Phillip R. May, Jr. | $404,784 | 60% | 117% | $284,881 |
| Sallie T. Rainer | $358,713 | 40% | 122% | $175,713 |
| Roderick K. West | $731,863 | 80% | 115% | $673,314 |
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| Named Executive Officer | Base Salary | Target as Percentage of Base Salary | Payout as Percentage of Target | 2019 Annual Incentive Award |
| A. Christopher Bakken, III | $654,078 | 70% | 135% | $618,104 |
| Marcus V. Brown | $666,250 | 75% | 137% | $684,573 |
| Leo P. Denault | $1,260,000 | 140% | 137% | $2,416,680 |
| David D. Ellis | $313,388 | 40% | 127% | $159,804 |
| Haley R. Fisackerly | $376,023 | 40% | 183% | $274,570 |
| Laura R. Landreaux | $316,470 | 40% | 208% | $263,523 |
| Andrew S. Marsh | $650,000 | 80% | 137% | $712,400 |
| Phillip R. May, Jr. | $392,043 | 60% | 173% | $407,922 |
| Sallie T. Rainer | $347,422 | 40% | 158% | $219,069 |
| Roderick K. West | $714,013 | 70% | 135% | $674,742 |
Long-Term Incentive Compensation
Overview
Long-term incentive compensation, consisting solely of equity awards in 2019,2020, represents the largest portion of executive officer compensation, and as noted earlier, the Named Executive Officers’increase in Mr. Denault’s TDC opportunity was delivered in the form of long-term incentive compensation. Entergy Corporation’sCorporation believes the combination of long-term incentives we employit employs provides a compelling performance-based compensation opportunity, acts in retaining the senior management team, and aligns the interests of theEntergy Corporation’s executive officers
with the interests of Entergy Corporation’sits shareholders and customers by enhancing executives’executives focus on the Company’sEntergy Corporation’s long-term goals. 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, based on 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.
2019 Long-Term Incentive Award Mix
Beginning in 2019, a dollar value was established for the target long-term incentive awards forFor each Named Executive OfficerNEO who is a member of the Office of the Chief Executive.OCE, a dollar value is established to determine that NEO’s long-term incentive awards target. The targeted award value for these officers waseach NEO is determined based on market median compensation data for the officer’s role, adjusted to reflect individual performance and internal equity. Previously, the targets for these Named Executive Officers were the average of the market data for the officers within a specific management level, without regard to the officer’s specific job functions. In January 2019,2020, the Personnel Committee approved the 20192020 long-term incentive award target valuesamounts for the Named Executive Officers who are memberseach NEO with each NEO’s target amount increasing in recognition of the Office of the Chief Executive.contributions made to Entergy Corporation in 2019. This valuetarget amount was then converted into the number of performance units, stock options and shares of restricted stock granted usingto each NEO based on the allocation described above based on the target grant date value.above.
In consultation with Entergy Corporation’s Chief Executive Officer, the Personnel Committee reviews each of the other Named Executive Officer’sNEO’s performance, role and responsibilities, strengths, developmental opportunities and internal equity and allocates awards of restricted stock and stock options to each of these officers based on these factors. Grants of long-term performance units for these Named Executive Officers wasNEOs were determined based on the average of the market data for the officers within a specific management level, without regard to the officer’s specific job function.function, and allocated as described above.
2020 Long-Term Incentive Award Mix
Long-Term Performance Unit Program
The Named Executive OfficersNEOs are issued performance unit awards under the Long-Term Performance Unit Program.LTIP.
•Each performance unit represents one share of Entergy Corporation’s common stock at the end of the three-year performance period, plus dividends accrued during the performance period.
•The performance units and accrued dividends on any shares earned during the performance period are settled in shares of Entergy Corporation common stock.
•The Personnel Committee sets payout opportunities for the program at the outset of each performance period, with payouts only occurring if the performance goals are met.period.
Payouts•No payout under this program will not be made if relative TSR for the 2019-2021 performance period if total shareholder return falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and Cumulative EntergyETR Adjusted EPS is below the minimum performance goal.
•All shares paid out under the Long-Term Performance Unit ProgramLTIP are required to be retained by Entergy Corporation’s officers until applicable executive stock ownership requirements are met.
The Long-Term Performance Unit ProgramLTIP 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. For the 2019 - 20212020 – 2022 LTIP performance period, the Personnel Committee chose the performance measures and targets set forth below.
Given the economic and market conditions at the time the targets were set, the target payout level for the Cumulative ETR Adjusted EPS goal was designed to be challenging, but achievable while payout at the maximum levels was designed to require stretch performance.
2019-2021 Long-Term Performance2020-2022 LTIP Unit Performance PeriodProgram Period: Measures and Goals(1)
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Performance Measures(1) | Long-Term Performance LTIP
Measure Weight | Payout |
Relative Total Shareholder ReturnTSR | 80% | Minimum (25%) - Bottom of 3rd Quartile Target (100%) - Median Percentile Maximum (200%) - Top Quartile |
Cumulative ETR Adjusted EPS($)EPS | 20% | Minimum (25%) - Minus 10% of Target $16.07
Target (100%) - 100% of Target $17.85
Maximum (200%) - Plus 10% of Target $19.63 |
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(1) | Payouts for performance between achievement levels are calculated using straight-line interpolation, with no payouts for performance below the minimum achievement level for both performance measures. |
(1)Payouts for performance between achievement levels are calculated using straight-line interpolation, with no payouts for performance below the minimum achievement level for both performance measures.
Performance Measures
Total Shareholder ReturnRelative TSR
•The Personnel Committee chose relative total shareholder returnTSR as a performance measure because it reflects Entergy Corporation’s creation of shareholder value relative to other electric utilities included in the Philadelphia Utility Index over the performance period. By measuring performance in relation to an industry benchmark, this measure is intended to isolate and reward management for the creation of shareholder value that is not driven by 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 returnTSR in relation to the TSR of the companies in the Philadelphia Utility Index. The Personnel Committee identified the Philadelphia Utility Index as the appropriate industry peer group for determining relative total shareholder returnTSR because the companies included in this index, in the aggregate, are deemed to be comparable to the CompanyEntergy Corporation in terms of business and scale.
Cumulative ETR Adjusted EPS
•Cumulative ETR Adjusted EPS, which adjusts Entergy Corporation’s as reported (GAAP) results to eliminate the impact of earnings or loss from Entergy Wholesale Commodities and other non-routine items, was selected in 20192020 as a performance measure because the Personnel Committee wished to incentivize management to achieve steady, predictable earnings growth for the CompanyEntergy Corporation over the 3 year performance period, and because it aligns with the earnings measure used to communicate the Company’sEntergy Corporation’s earnings expectations externally to investors.
•In a manner similar to the way targets are established for the annual incentives, targets for the Cumulative ETR Adjusted EPS performance measure were established by the Personnel Committee after the Entergy Corporation Board’s review of Entergy’s financialstrategic plan for the three-year period beginning in 20192020 and are consistent with the earnings expectations for the CompanyEntergy Corporation that are communicated to investors. These targets also incorporate the Pre-Determined Exclusions discussed previously with respect to the annual incentive measures.
Stock Options and Restricted Stock
Entergy Corporation grants stock options and shares of restricted stock because they align the interests of the executive officers with long-term shareholder value, provide competitive compensation, and increase the executives’ ownership in Entergy Corporation common stock. Generally, stock options are granted with a maximum term of ten years, and vest one-third on each of the first three anniversaries of the date of grant. The exercise price for each option granted in 20192020 was $89.19,$131.72, which was the closing price of Entergy’sEntergy Corporation’s common stock on the date of grant. Shares of restricted stock vest one-third on each of the first three anniversaries
of the date of grant, are paid dividends which are
reinvested in shares of Entergy Corporation common stock and have the ability to vote.full voting rights. The dividend reinvestment shares are subject to forfeiture similar to the terms of the original grant.
20192020 Long-Term Incentive Awards
In January 2019,2020, the Personnel Committee granted the following long-term performance units, stock options and shares of restricted stock to each Named Executive Officer.NEO. The number of long-term performance units, stock options and shares of restricted stock were determined as discussed above under “Long-Term Incentive Compensation - 2019 Long-Term Incentive Award Mix.Overview.”
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| Named Executive Officer | 2020-2022
Target LTIP Units | Stock Options | Shares of
Restricted Stock |
| A. Christopher Bakken, III | 7,758 | 29,279 | 3,104 |
| Marcus V. Brown | 7,571 | 28,574 | 3,029 |
| Leo P. Denault | 31,263 | 117,990 | 12,505 |
| David D. Ellis | 950 | 3,200 | 500 |
| Haley R. Fisackerly | 950 | 4,300 | 750 |
| Laura R. Landreaux | 950 | 4,300 | 750 |
| Andrew S. Marsh | 9,560 | 36,079 | 3,824 |
| Phillip R. May, Jr. | 1,400 | 7,300 | 1,100 |
| Sallie T. Rainer | 950 | 4,300 | 750 |
| Roderick K. West | 8,401 | 31,705 | 3,361 |
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| Named Executive Officer | 2019-2021 Target Long-Term Performance Units | Stock Options | Shares of Restricted Stock |
| A. Christopher Bakken, III | 9,568 | 36,421 | 3,604 |
| Marcus V. Brown | 9,383 | 35,719 | 3,535 |
| Leo P. Denault | 40,508 | 154,206 | 15,259 |
| David D. Ellis | 1,450 | 4,700 | 500 |
| Haley R. Fisackerly | 1,450 | 6,200 | 600 |
| Laura R. Landreaux | 1,450 | 5,100 | 500 |
| Andrew S. Marsh | 11,869 | 45,182 | 4,471 |
| Phillip R. May, Jr. | 2,150 | 9,300 | 900 |
| Sallie T. Rainer | 1,450 | 6,200 | 600 |
| Roderick K. West | 10,073 | 38,346 | 3,795 |
All of the outstanding performance units, and all of the shares of restricted stock and stock options granted to the Named Executive OfficersNEOs in 20192020 were granted pursuant to the 2015 Equity Ownership2019 Omnibus Incentive Plan or 2015 Equity Plan.2019 OIP. The 2015 Equity Plan2019 OIP requires both a change in control and an involuntary job loss without cause or substantial diminution of dutiesa resignation by the NEO for good reason within 24 months following a change in control (a “double trigger”) for the acceleration of these awards upon a change in control.
2019 Long-Term Performance Unit Program2020 LTIP Payouts
Payout for the 2017-2019 Long-Term2018 – 2020 LTIP Performance Unit Program Period. For the 2017-2019 three-year performance period,In January 2018, the Personnel Committee chose relative total shareholder returnTSR and Cumulative Adjusted UP&O EPS as the performance measures, each weighted equally, for the 2018 – 2020 LTIP performance period. Cumulative Adjusted UP&O EPS, which adjusted Entergy Corporation’s operational Utility, Parent & Other results to eliminate the impact of tax items and weather (the “UP&O Adjustments”), was added as a performance measure because it aligned with Entergy Corporation’s externally communicated earnings measure on its core utility business and was the primary measure on which Entergy Corporation communicated its long term earnings outlooks in 2018. Similar to the way targets are established for the annual incentive program, targets for the Cumulative Adjusted UP&O EPS performance measure were established by the Personnel Committee after the Entergy Corporation Board’s review of Entergy Corporation’s strategic plan. These targets also exclude the Pre-Determined Exclusions discussed previously with respect to the annual incentive measures, as well as the UP&O Adjustments. The payout subject towas determined based on the achievement of the following:following performance goals established for both performance measures by the committee at the beginning of the performance period:
2018-2020 LTIP Performance Unit Program Period Measures and Goals(1)
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Performance Measure(1) | LTIP
Measure Weight | Minimum | Target | MaximumPayout |
Relative Total Shareholder ReturnTSR | 4th Quartile50% | Minimum (25%) - Bottom of 3rd3rd Quartile | Target (100%) - Median Percentile | Maximum (200%) - Top Quartile |
PayoutCumulative Adjusted UP&O EPS ($) | No Payout50% | Minimum Payout of 25% of (25%) - $13.68
Target | 100% of Target | 200% of Target (100%) - $15.20
Maximum (200%) - $16.72 |
(1)Payouts for performance between achievement levels are calculated using straight-line interpolation, with no payouts for performance below the minimum achievement level.
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(1) | Payouts for performance between achievement levels are calculated using straight-line interpolation, with no payouts for performance below the minimum achievement level. |
In January 2020,2021, the Personnel Committee reviewed Entergy Corporation’s TSR and the Company’s total shareholder returnCumulative Adjusted UP&O EPS for the 2017 - 20192018 – 2020 LTIP performance period in order to determine the payout to participants. The committee compared Entergy Corporation’s total shareholder return against the total shareholder return of the companies that comprise the Philadelphia Utility Index, withparticipants based upon the performance measures and range of potential payouts for the 2017 - 20192018 – 2020 LTIP performance period as provided above. The committee compared Entergy Corporation’s TSR against the TSR of the companies that were included in the Philadelphia Utility Index throughout the three year performance period, which were:
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| AES Corporation | | Edison International |
| Ameren Corporation | | Eversource Energy |
| American Electric Power Co. Inc. | | Exelon Corporation |
| American Water Works Company, Inc. | | FirstEnergy Corporation |
| CenterPoint Energy Inc. | | NextEra Energy, Inc. |
| Consolidated Edison Inc. | | PG&E Corporation |
| Dominion Energy | | Public Service Enterprise Group, Inc. |
| DTE Energy Company | | Southern Company |
| Duke Energy Corporation | | Xcel Energy, Inc. |
As recommended by the Finance Committee, the Personnel Committee
concluded that the Company’sEntergy Corporation’s relative total shareholder returnTSR for the 2017 - 20192018 – 2020 performance period was in the topsecond quartile, and that Cumulative Adjusted UP&O EPS was $15.25, yielding a payout of 200%126% of target for the Named Executive Officers.NEOs.
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| Named Executive Officer | 2018-2020 Target | Number of Shares Issued(1) | Value of Shares Actually Issued(2) | Grant Date Fair Value(3) |
| A. Christopher Bakken, III | 7,900 | 11,048 | $1,050,886 | $651,079 |
| Marcus V. Brown | 7,900 | 11,048 | $1,050,886 | $651,079 |
| Leo P. Denault | 42,700 | 59,718 | $5,680,376 | $3,519,121 |
David D. Ellis(4) | 1,100 | 1,488 | $141,539 | $90,657 |
| Haley R. Fisackerly | 1,650 | 2,307 | $219,442 | $135,985 |
Laura R. Landreaux(5) | 1,375 | 1,892 | $179,967 | $113,321 |
| Andrew S. Marsh | 7,900 | 11,048 | $1,050,886 | $651,079 |
| Phillip R. May, Jr. | 2,550 | 3,566 | $339,198 | $210,158 |
| Sallie T. Rainer | 1,650 | 2,307 | $219,442 | $135,985 |
| Roderick K. West | 7,900 | 11,048 | $1,050,886 | $651,079 |
(1)Includes accrued dividends.
(2)Value determined based on the closing price of Entergy Corporation common stock on January 19, 2021 ($95.12), the date the Personnel Committee certified the 2018-2020 performance period results.
(3)Represents the aggregate grant date fair value calculated in accordance with applicable accounting rules as reflected in the 2018 Summary Compensation Table.
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| Named Executive Officer | 2017-2019 Target | Number of Shares Issued(1) | Value of Shares Actually Issued(2) | Grant Date Fair Value(3) |
| A. Christopher Bakken, III | 8,300 | 18,088 | $2,284,695 | $592,620 |
| Marcus V. Brown | 8,300 | 18,088 | $2,284,695 | $592,620 |
| Leo P. Denault | 48,700 | 106,131 | $13,405,407 | $3,477,180 |
David D. Ellis(4) | 617 | 1,271 | $160,540 | $44,054 |
| Haley R. Fisackerly | 1,850 | 4,031 | $509,156 | $132,090 |
Laura R. Landreaux(5) | 925 | 1,934 | $244,284 | $66,045 |
| Andrew S. Marsh | 8,300 | 18,088 | $2,284,695 | $592,620 |
| Phillip R. May, Jr. | 3,150 | 6,864 | $866,992 | $224,910 |
| Sallie T. Rainer | 1,850 | 4,031 | $509,156 | $132,090 |
| Roderick K. West | 8,300 | 18,088 | $2,284,695 | $592,620 |
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(1) | Includes accrued dividends. |
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(2) | Value determined based on the closing price of Entergy Corporation common stock on January 17, 2020 ($126.31), the date the Personnel Committee certified the 2017-2019 performance period results. |
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(3) | Represents the aggregate grant date fair value calculated in accordance with applicable accounting rules as reflected in the 2017 Summary Compensation Table. |
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(4) | As a new hire in 2018, Mr. Ellis received a pro-rata target award opportunity for the 2017-2019 performance period. |
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(5) | As a new officer in 2018, Ms. Landreaux received a pro-rata target award opportunity for the 2017-2019 performance period. |
Benefits and Perquisites
Entergy Corporation’s Named Executive OfficersNEOs are eligible to participate in or receive the following benefits:
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| 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, 2014.2014 and before January 1, 2021. 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 “2019 Pension Benefits” for additional information regarding the operation of the plans described above.
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| Savings Plan | Entergy Corporation-sponsored 401(k) Savings Plan that covers a broad group of employees. |
| Health & Welfare Benefits | Medical, dental and vision coverage, health care and dependent care reimbursement plans, 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 OfficersNEOs as for the broad employee population.
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20192020 Perquisites | Corporate aircraft usage and annual mandatory physical exams, relocation assistance, and event tickets.exams. The Named Executive OfficesNEOs who are members of the Office of the Chief ExecutiveOCE do not receive tax gross ups on any benefits, except for relocation assistance.
Named Executive OfficersIn 2020, the NEOs who are not members of the Office of the Chief ExecutiveOCE also were provided in 20192020 with club dues and tax gross up payments on some perquisites.this perquisite.
For additional information regarding perquisites, see the “All Other Compensation” column in the 20192020 Summary Compensation Table. |
| Deferred Compensation | The Named Executive OfficersNEOs are eligible to defer up to 100% of their base salary and Annual Incentive Planannual incentive awards into the 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 provides these benefits to the Named Executive OfficersNEOs as part of its effort to provide a competitive executive compensation program and because it believes that these benefits are important retention and recruitment tools since many of the companies with which it competes for executive talent provide similar arrangements to their senior executive officers.
Severance and Other CompensationRetention Arrangements
The Personnel Committee believes that retention and transitional compensation arrangements are an important part of overall compensation as they help to secure the continued employment and dedication of the Named Executive Officers,NEOs, notwithstanding any concern that they might have at the time of a change in control regarding their own continued employment. In addition, the Personnel Committee believes that these arrangements are important as recruitment and retention devices, as many of the companies with which Entergy Corporation competes for executive talent have similar arrangements in place for their senior employees.
To achieve these objectives, Entergy Corporation has established a System Executive Continuity Plan under which ML 1-4 Officers are entitled to receive “change in control” payments and benefits if such officer’s employment is involuntarily terminated without cause or if the officer resigns for good reason, in each case, in connection with a change in control of Entergy Corporation and its subsidiaries. Entergy Corporation strives to ensure that the benefits and payment levels under the System Executive Continuity Plan are consistent with market practices. Entergy Corporation’s executive officers, including the Named Executive Officers,NEOs, are not entitled to any tax gross up payments on any severance benefits received under this plan. For more information regarding the System Executive Continuity Plan, see “2019“2020 Potential Payments Upon Termination or Change in Control.”
In certain cases, the Personnel 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.
Mr. Ellis
In connection with the commencement of his employment as President, Entergy New Orleans, Mr. Ellis was eligible for certain relocation benefits pursuant to Entergy Corporation’s Relocation Assistance Policy, including assistance with moving expenses, transportation of household goods and assistance with the sale of his home. Mr. Ellis also received a sign-on bonus of $200,000 when he assumed this role. Mr. Ellis’s sign-on bonus and certain of his relocation benefits are subject to forfeiture under certain circumstances if Mr. Ellis’s employment is terminated within 24 months of the commencement of his employment. Also, in accordance with the terms of the Long-Term Performance Unit Program in January 2019, Mr. Ellis received pro-rated target award opportunities for the 2017-2019 and 2018-2020 performance periods.
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 service 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.
In recognition of the value Entergy Corporation places on Mr. Bakken as a member of its senior management team and his extensive experience in the nuclear industry, and to keep his pay competitive, in May 2019, Mr. Bakken’s participation in the plan commenced inwas renewed for another three-year period beginning on May 2016, and in1, 2019. In accordance with the terms and conditions of the plan,Nuclear Retention Plan, in May 2017, 2018 and 2019,2020 Mr. Bakken received, and in May 2021 and 2022, Mr. Bakken will receive a cash bonus equal to $181,500 or 30% of $654,078, his base salary as of May 1, 20162019. The three-year period covered and percentage of base salary. Thissalary paid to Mr. Bakken under the plan does not provide for accelerated or prorated payout upon terminationare consistent with the terms of any kind.participation of other senior executive officers who participate in this plan.
Compensation PoliciesRisk Mitigation and Other Pay Practices
Entergy Corporation strives to ensure that its compensation philosophy and practices are in line with the best practices of companies in its 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 Exchange Act, including the membersall of the Office of the Chief Executive.NEOs. Under the policy, which goes beyond the requirements of Sarbanes-Oxley Act of 2002 (Sarbanes-Oxley), the Personnel Committee will require reimbursement of incentives paid to thesecovered executive officers are required to be reimbursed 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 Personnel Committee requiresrequired 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 Entergy Corporation’s financial statements,In addition, Entergy Corporation will seek to recover any compensation received by Entergy Corporation’sits Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under Sarbanes-Oxley.Sarbanes-Oxley following a material restatement of Entergy Corporation’s financial statements.
Stock Ownership Guidelines and Share Retention Requirements
For many years, Entergy Corporation has had stock ownership guidelines for executives, including the Named Executive Officers.NEOs. These guidelines are designed to align the executives’ long-term financial interests with the interests of Entergy Corporation’s shareholders. Annually, the Personnel Committee monitors the executive officers’ compliance with these guidelines.guidelines with all of the NEOs satisfying the applicable ownership guidelines at that time. The ownership guidelines are as follows:
The ownership guidelines are as follows:
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| Role | Value of Common Stock to be Owned |
| Chief Executive Officer (ML-1) | 6 timesx base salary |
| Executive Vice Presidents (ML-2) | 3 timesx base salary |
| Senior Vice Presidents (ML-3) | 2 timesx base salary |
| Vice Presidents (ML-4) | 1 timex base salary |
Further, to facilitate 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;LTIP;
•all net after-tax shares of the 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.
Trading Controls
Executive officers, including the Named Executive Officers,NEOs, are required to receive permission from Entergy Corporation’s General Counsel or his designee 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 beginning shortly after the release of earnings. Employees, who are subject to trading restrictions, including the Named Executive Officers,NEOs, 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 OfficerA NEO bears full responsibility if he or she violates Entergy Corporation’s policy by buying or selling shares of Entergy Corporation stock without pre-approval or when trading is restricted.
Entergy Corporation also prohibits directors and executive officers, including the Named Executive Officers,NEOs, from pledging any Entergy Corporation securities or entering into margin accounts involving Entergy Corporation securities. Entergy Corporation prohibits these transactions because of the potential that sales of Entergy Corporation securities could occur outside trading periods and without the required approval of the General Counsel.
Entergy Corporation also has adopted an anti-hedging policy that prohibits officers, directors, and employees from entering into hedging or monetization transactions involving Entergy Corporation’s 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 Entergy Corporation’s stock or transactions involving “short-sales” of its common stock. The Board adopted this policy to require officers, directors, and employees to continue to own Entergy Corporation stock with the full risks and rewards
How Entergy Corporation Makes Compensation Decisions
The Personnel Committee oversees Entergy Corporation’s executive compensation programs and policies with the advice of its independent compensation consultant and support from its management team.
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Personnel Committee | Ÿ | The Personnel Committee is responsible for the review and approval of all aspects of Entergy Corporation’s executive compensation programs. |
Ÿ | Among its duties, the Personnel Committee is responsible for approving the compensation for all members of the Office of Chief Executive, including: |
| Ÿ | Annual review of the compensation elements and mix of elements for the following year; |
| Ÿ | Annual review and approval of incentive program design, goals and objectives for alignment with Entergy Corporation’s compensation and business strategies; |
| Ÿ | Evaluation of Entergy Corporation and individual performance results in light of these goals and objectives; |
| Ÿ | Evaluation of the competitiveness of each executive officer’s total compensation package; |
| Ÿ | Approval of any changes to the officers’ compensation, including but not limited to, base salary, annual and long-term incentive award opportunities, and retention programs; |
| Ÿ | Evaluation of the performance of Entergy Corporation’s Chairman and Chief Executive Officer; and |
| Ÿ | Reporting, at least annually, to the Board on succession planning. |
Ÿ | The Personnel Committee has the sole authority to hire its compensation consultant, approve its compensation, determine the nature and scope of its services, evaluate its performance and terminate its engagement. |
Management | Ÿ | The CEO and Chief Human Resources Officer work closely with the Personnel Committee in managing the executive compensation programs and attend meetings of the Personnel Committee. During 2019, Mr. Denault attended 8 meetings of the Personnel Committee. |
Ÿ | The CEO makes recommendations to the Committee regarding compensation for executive officers other than himself. |
Independent Compensation Consultant | Ÿ | During 2019, Pay Governance assisted the Personnel Committee with its responsibilities related to Entergy Corporation’s executive compensation programs. |
Ÿ | Pay Governance: |
| Ÿ | Regularly attended meetings of the committee; |
| Ÿ | Conducted studies of competitive compensation practices; |
| Ÿ | Identified Entergy Corporation’s market surveys and proxy peer group; |
| Ÿ | Provided updates on executive compensation trends and regulatory developments; |
| Ÿ | Reviewed base salary, annual incentives and long-term incentive compensation opportunities relative to competitive practices; and |
| Ÿ | Developed conclusions and recommendations related to Entergy Corporation’s executive compensation programs for consideration by the committee. |
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 or 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. Pay Governance, which serves as the Personnel Committee’s compensation consultant, did not provide any services to management in 2019.
Annually, the Personnel Committee reviews the relationship with its compensation consultant including services provided, qualityto determine whether any conflicts of those services, and fees associatedinterest exist that would prevent Pay Governance from independently advising the Personnel Committee. Factors considered by the committee when assessing the independence of its compensation consultant included, among others:
•Pay Governance has policies in place to prevent conflicts of interest;
•No member of Pay Governance’s consulting team serving the committee has a business relationship with services in its evaluationany member of the compensation consultant’s independence. committee or any of Entergy Corporation’s executive officers;
•Neither Pay Governance nor any of its principals own any shares of Entergy Corporation’s common stock; and
•The committee also assessesamount of fees paid to Pay Governance is less than 1% of Pay Governance’s independence undertotal consulting income.
Based on these factors, the Personnel Committee concluded that Pay Governance is independent in accordance with SEC and NYSE rules and has concluded that no conflicts of interest exist that would prevent Pay Governance from independently advising the committee.
In addition, Pay Governance has agreed that it will not accept any engagement with management without prior approval from the Personnel Committee.Committee, and Entergy Corporation’s Board has adopted a policy that prohibits a compensation consultant from providing other services to it if the aggregate amount for those services would exceed $120,000 in any year. During 2020, Pay Governance did not provide any services to Entergy Corporation other than the services it performed on behalf of the Personnel and Corporate Governance Committees, and it worked with Entergy Corporation’s management only as directed by the committees.
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 Registrant Subsidiaries has a compensation committee or other board committee performing equivalent functions. The board of directors of each of the Registrant Subsidiaries is comprised of individuals who are officers or employees of Entergy Corporation or one of the Registrant Subsidiaries. These boards do not make determinations regarding the compensation paid to executive officers of the Registrant Subsidiaries.
EXECUTIVE COMPENSATION TABLES
20192020 Summary Compensation Tables
The following table summarizes the total compensation paid or earned by each of the Named Executive OfficersNEOs for the fiscal year ended December 31, 2019,2020, and to the extent required by SEC executive compensation disclosure rules, the fiscal years ended December 31, 20182019 and 2017.2018. For information on the principal positions held by each of the Named Executive Officers,NEOs, see Item 10, “Directors, Executive Officers, and Corporate Governance of the Registrants.”
The compensation set forth in the table represents the aggregate compensation paid by all Entergy System companies. 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.”
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| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | (k) |
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 Compen-sation (8) | Total | Total Without Change in Pension Value (9) |
| A. Christopher Bakken, III | 2020 | $693,819 | | $196,223 | | $1,666,710 | | $335,245 | | $581,066 | | $115,100 | | $85,846 | | $3,674,009 | | $3,558,909 | |
| Executive Vice President and | 2019 | $649,507 | | $181,500 | | $1,273,399 | | $303,023 | | $618,104 | | $98,500 | | $62,407 | | $3,186,440 | | $3,087,940 | |
| Chief Nuclear Officer of Entergy Corp. | 2018 | $632,967 | | $181,500 | | $1,041,479 | | $283,095 | | $544,959 | | $108,700 | | $452,012 | | $3,244,712 | | $3,136,012 | |
| | | | | | | | | | |
| Marcus V. Brown | 2020 | $709,688 | | $— | | $1,626,512 | | $327,172 | | $662,400 | | $1,746,000 | | $78,631 | | $5,150,403 | | $3,404,403 | |
| Executive Vice President and | 2019 | $661,563 | | $— | | $1,248,839 | | $297,182 | | $684,573 | | $1,455,300 | | $69,955 | | $4,417,412 | | $2,962,112 | |
| General Counsel of Entergy Corp. | 2018 | $644,231 | | $— | | $1,041,479 | | $283,095 | | $546,000 | | $371,800 | | $61,885 | | $2,948,490 | | $2,576,690 | |
| | | | | | | | | | |
| Leo P. Denault | 2020 | $1,308,462 | | $— | | $6,716,017 | | $1,350,986 | | $2,116,800 | | $4,416,700 | | $289,632 | | $16,198,597 | | $11,781,897 | |
| Chairman of the | 2019 | $1,260,000 | | $— | | $5,391,253 | | $1,282,994 | | $2,416,680 | | $3,704,500 | | $208,822 | | $14,264,249 | | $10,559,749 | |
| Board and CEO - | 2018 | $1,251,346 | | $— | | $4,744,977 | | $1,168,029 | | $2,041,200 | | $982,800 | | $138,104 | | $10,326,456 | | $9,343,656 | |
| Entergy Corp. | | | | | | | | | | |
| | | | | | | | | | |
| David D. Ellis | 2020 | $331,803 | | $— | | $219,889 | | $36,640 | | $164,955 | | $32,200 | | $19,323 | | $804,810 | | $772,610 | |
| CEO - Entergy | 2019 | $311,004 | | $— | | $188,861 | | $39,104 | | $159,804 | | $18,000 | | $15,267 | | $732,040 | | $714,040 | |
| New Orleans | 2018 | $7,258 | | $200,000 | | $— | | $— | | $— | | $600 | | $35,308 | | $243,166 | | $242,566 | |
| | | | | | | | | | |
| Haley R. Fisackerly | 2020 | $384,848 | | $— | | $252,819 | | $49,235 | | $232,737 | | $836,200 | | $48,101 | | $1,803,940 | | $967,740 | |
| CEO - Entergy | 2019 | $373,313 | | $— | | $197,780 | | $51,584 | | $274,570 | | $644,700 | | $37,897 | | $1,579,844 | | $935,144 | |
| Mississippi | 2018 | $363,089 | | $— | | $198,449 | | $46,134 | | $172,000 | | $— | | $35,982 | | $815,654 | | $815,654 | |
| | | | | | | | | | |
| Laura R. Landreaux | 2020 | $323,907 | | $— | | $252,819 | | $49,235 | | $167,153 | | $330,700 | | $26,698 | | $1,150,512 | | $819,812 | |
| CEO - Entergy | 2019 | $314,407 | | $— | | $188,861 | | $42,432 | | $263,523 | | $228,700 | | $26,536 | | $1,064,459 | | $835,759 | |
| Arkansas | 2018 | $246,136 | | $— | | $273,062 | | $— | | $124,000 | | $21,500 | | $10,741 | | $675,439 | | $653,939 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (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 |
| A. Christopher Bakken, III | | 2019 | |
| $649,507 |
| |
| $181,500 |
| |
| $1,273,399 |
| |
| $303,023 |
| |
| $618,104 |
| |
| $98,500 |
| |
| $62,407 |
| |
| $3,186,440 |
|
| Executive Vice President and | | 2018 | |
| $632,967 |
| |
| $181,500 |
| |
| $1,041,479 |
| |
| $283,095 |
| |
| $544,959 |
| |
| $108,700 |
| |
| $452,012 |
| |
| $3,244,712 |
|
| Chief Nuclear Officer of Entergy Corp. | | 2017 | |
| $615,791 |
| |
| $181,500 |
| |
| $959,376 |
| |
| $245,904 |
| |
| $559,973 |
| |
| $33,000 |
| |
| $114,494 |
| |
| $2,710,038 |
|
| | | | | | | | | | | | | | | | | | | |
| Marcus V. Brown | | 2019 | |
| $661,563 |
| |
| $— |
| |
| $1,248,839 |
| |
| $297,182 |
| |
| $684,573 |
| |
| $1,455,300 |
| |
| $69,955 |
| |
| $4,417,412 |
|
| Executive Vice President and | | 2018 | |
| $644,231 |
| |
| $— |
| |
| $1,041,479 |
| |
| $283,095 |
| |
| $546,000 |
| |
| $371,800 |
| |
| $61,885 |
| |
| $2,948,490 |
|
| General Counsel of Entergy Corp. | | 2017 | |
| $622,788 |
| |
| $— |
| |
| $1,022,853 |
| |
| $287,760 |
| |
| $568,890 |
| |
| $1,217,200 |
| |
| $43,269 |
| |
| $3,762,760 |
|
| | | | | | | | | | | | | | | | | | | |
| Leo P. Denault | | 2019 | |
| $1,260,000 |
| |
| $— |
| |
| $5,391,253 |
| |
| $1,282,994 |
| |
| $2,416,680 |
| |
| $3,704,500 |
| |
| $208,822 |
| |
| $14,264,249 |
|
| Chairman of the | | 2018 | |
| $1,251,346 |
| |
| $— |
| |
| $4,744,977 |
| |
| $1,168,029 |
| |
| $2,041,200 |
| |
| $982,800 |
| |
| $138,104 |
| |
| $10,326,456 |
|
| Board and CEO - | | 2017 | |
| $1,221,346 |
| |
| $— |
| |
| $4,676,190 |
| |
| $1,173,276 |
| |
| $2,142,045 |
| |
| $3,819,500 |
| |
| $125,863 |
| |
| $13,158,220 |
|
| Entergy Corp. | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| David D. Ellis | | 2019 | |
| $311,004 |
| |
| $— |
| |
| $188,861 |
| |
| $39,104 |
| |
| $159,804 |
| |
| $18,000 |
| |
| $15,267 |
| |
| $732,040 |
|
| CEO - Entergy | | 2018 | |
| $7,258 |
| |
| $200,000 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $600 |
| |
| $35,308 |
| |
| $243,166 |
|
| New Orleans | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Haley R. Fisackerly | | 2019 | |
| $373,313 |
| |
| $— |
| |
| $197,780 |
| |
| $51,584 |
| |
| $274,570 |
| |
| $644,700 |
| |
| $37,897 |
| |
| $1,579,844 |
|
| CEO - Entergy | | 2018 | |
| $363,089 |
| |
| $— |
| |
| $198,449 |
| |
| $46,134 |
| |
| $172,000 |
| |
| $— |
| |
| $35,982 |
| |
| $815,654 |
|
| Mississippi | | 2017 | |
| $354,451 |
| |
| $— |
| |
| $192,041 |
| |
| $49,704 |
| |
| $169,123 |
| |
| $406,300 |
| |
| $35,724 |
| |
| $1,207,343 |
|
| | | | | | | | | | | | | | | | | | |
|
|
| Laura R. Landreaux | | 2019 | |
| $314,407 |
| |
| $— |
| |
| $188,861 |
| |
| $42,432 |
| |
| $263,523 |
| |
| $228,700 |
| |
| $26,536 |
| |
| $1,064,459 |
|
| CEO - Entergy | | 2018 | |
| $246,136 |
| |
| $— |
| |
| $273,062 |
| |
| $— |
| |
| $124,000 |
| |
| $21,500 |
| |
| $10,741 |
| |
| $675,439 |
|
| Arkansas | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | (k) |
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 Compen-sation (8) | Total | Total Without Change in Pension Value (9) |
| Andrew S. Marsh | 2020 | $704,692 | | $— | | $2,053,717 | | $413,105 | | $703,800 | | $2,054,000 | | $77,741 | | $6,007,055 | | $3,953,055 | |
| Executive Vice | 2019 | $641,923 | | $— | | $1,579,663 | | $375,914 | | $712,400 | | $1,554,300 | | $69,863 | | $4,934,063 | | $3,379,763 | |
| President and CFO - | 2018 | $615,654 | | $— | | $1,057,095 | | $342,510 | | $531,188 | | $— | | $57,638 | | $2,604,085 | | $2,604,085 | |
| Entergy Corp., | | | | | | | | | | |
| Entergy Arkansas, | | | | | | | | | | |
| Entergy Louisiana, | | | | | | | | | | |
| Entergy Mississippi, | | | | | | | | | | |
| Entergy New | | | | | | | | | | |
| Orleans, | | | | | | | | | | |
| Entergy Texas | | | | | | | | | | |
| | | | | | | | | | |
| Phillip R. May, Jr. | 2020 | $416,677 | | $— | | $371,882 | | $83,585 | | $284,881 | | $1,072,100 | | $28,836 | | $2,257,961 | | $1,185,861 | |
| CEO - Entergy | 2019 | $389,016 | | $— | | $294,183 | | $77,376 | | $407,922 | | $877,100 | | $28,297 | | $2,073,894 | | $1,196,794 | |
| Louisiana | 2018 | $377,108 | | $— | | $288,238 | | $69,201 | | $270,000 | | $— | | $26,874 | | $1,031,421 | | $1,031,421 | |
| | | | | | | | | | |
| Sallie T. Rainer | 2020 | $369,133 | | $— | | $252,819 | | $49,235 | | $175,713 | | $663,100 | | $33,383 | | $1,543,383 | | $880,283 | |
| CEO - Entergy | 2019 | $344,722 | | $— | | $197,780 | | $51,584 | | $219,069 | | $617,200 | | $37,361 | | $1,467,716 | | $850,516 | |
| Texas | 2018 | $335,263 | | $— | | $198,449 | | $46,134 | | $159,000 | | $— | | $35,379 | | $774,225 | | $774,225 | |
| | | | | | | | | | |
| Roderick K. West | 2020 | $754,742 | | $— | | $1,804,816 | | $363,022 | | $673,314 | | $1,976,400 | | $59,730 | | $5,632,024 | | $3,655,624 | |
| Group President | 2019 | $709,023 | | $— | | $1,340,679 | | $319,039 | | $674,742 | | $1,604,100 | | $67,191 | | $4,714,774 | | $3,110,674 | |
| Utility Operations of | 2018 | $690,581 | | $— | | $1,057,095 | | $297,075 | | $560,762 | | $— | | $67,234 | | $2,672,747 | | $2,672,747 | |
| 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 |
| Andrew S. Marsh | | 2019 | |
| $641,923 |
| |
| $— |
| |
| $1,579,663 |
| |
| $375,914 |
| |
| $712,400 |
| |
| $1,554,300 |
| |
| $69,863 |
| |
| $4,934,063 |
|
| Executive Vice | | 2018 | |
| $615,654 |
| |
| $— |
| |
| $1,057,095 |
| |
| $342,510 |
| |
| $531,188 |
| |
| $— |
| |
| $57,638 |
| |
| $2,604,085 |
|
| President and CFO - | | 2017 | |
| $588,291 |
| |
| $— |
| |
| $1,022,853 |
| |
| $287,760 |
| |
| $541,800 |
| |
| $801,900 |
| |
| $51,647 |
| |
| $3,294,251 |
|
| Entergy Corp., | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas, | | | | | | | | | | | | | | | | | | |
| Entergy Louisiana, | | | | | | | | | | | | | | | | | | |
| Entergy Mississippi, | | | | | | | | | | | | | | | | | | |
| Entergy New | | | | | | | | | | | | | | | | | | |
| Orleans, | | | | | | | | | | | | | | | | | | |
| Entergy Texas | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Phillip R. May, Jr. | | 2019 | |
| $389,016 |
| |
| $— |
| |
| $294,183 |
| |
| $77,376 |
| |
| $407,922 |
| |
| $877,100 |
| |
| $28,297 |
| |
| $2,073,894 |
|
| CEO - Entergy | | 2018 | |
| $377,108 |
| |
| $— |
| |
| $288,238 |
| |
| $69,201 |
| |
| $270,000 |
| |
| $— |
| |
| $26,874 |
| |
| $1,031,421 |
|
| Louisiana | | 2017 | |
| $363,410 |
| |
| $— |
| |
| $302,493 |
| |
| $68,670 |
| |
| $300,000 |
| |
| $503,400 |
| |
| $26,981 |
| |
| $1,564,954 |
|
| | | | | | | | | | | | | | | | | | | |
| Sallie T. Rainer | | 2019 | |
| $344,722 |
| |
| $— |
| |
| $197,780 |
| |
| $51,584 |
| |
| $219,069 |
| |
| $617,200 |
| |
| $37,361 |
| |
| $1,467,716 |
|
| CEO - Entergy | | 2018 | |
| $335,263 |
| |
| $— |
| |
| $198,449 |
| |
| $46,134 |
| |
| $159,000 |
| |
| $— |
| |
| $35,379 |
| |
| $774,225 |
|
| Texas | | 2017 | |
| $325,737 |
| |
| $— |
| |
| $195,567 |
| |
| $51,012 |
| |
| $156,259 |
| |
| $435,900 |
| |
| $35,785 |
| |
| $1,200,260 |
|
| | | | | | | | | | | | | | | | | | | |
| Roderick K. West | | 2019 | |
| $709,023 |
| |
| $— |
| |
| $1,340,679 |
| |
| $319,039 |
| |
| $674,742 |
| |
| $1,604,100 |
| |
| $67,191 |
| |
| $4,714,774 |
|
| Group President | | 2018 | |
| $690,581 |
| |
| $— |
| |
| $1,057,095 |
| |
| $297,075 |
| |
| $560,762 |
| |
| $— |
| |
| $67,234 |
| |
| $2,672,747 |
|
| Utility Operations of | | 2017 | |
| $670,876 |
| |
| $— |
| |
| $818,316 |
| |
| $190,968 |
| |
| $610,065 |
| |
| $867,200 |
| |
| $52,220 |
| |
| $3,209,645 |
|
| Entergy Corp. | | | | | | | | | | | | | | | | | | |
| |
(1) | (1)Mr. Ellis was named Chief Executive Officer, Entergy New Orleans in December 2018, and Ms. Landreaux was named Chief Executive Officer, Entergy Arkansas in July 2018. |
| |
(2) | The amounts in column (c) represent the actual base salary paid to the Named Executive Officers in the applicable year. The 2019 changes in base salaries noted in the Compensation Discussion and Analysis were effective in April 2019. |
| |
(3) | The amount in column (d) in 2019, 2018 and 2017 for Mr. Bakken represents the cash bonus paid to him pursuant to the Nuclear Retention Plan. See “Nuclear Retention Plan” in Compensation Discussion and Analysis. The amount in column (d) in 2018 for Mr. Ellis represents a cash sign-on bonus paid in connection with his commencement of employment with Entergy New Orleans. |
| |
(4) | The amounts in column (e) represent the aggregate grant date fair value of restricted stock and performance units granted under the 2015 Equity Plan, each calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures. The grant date fair value of the restricted stock is based on the closing price of Entergy Corporation common stock on the date of grant. The grant date fair value of the portion of the performance units with vesting based on the total shareholder return was 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. The performance units in the table are also valued based on the probable outcome of the applicable performance condition at the time of grant. The maximum value of shares that will be received if the highest achievement level is attained with respect to both the total shareholder return and Cumulative ETR Adjusted EPS, for performance units granted in 2019 are as follows: Mr. Bakken, $1,953,212; Mr. Brown, $1,915,446; Mr. Denault, $8,269,303; Mr. Ellis, $296,003; Mr. |
Fisackerly, $296,003; Ms. Landreaux $296,003;was named Chief Executive Officer, Entergy Arkansas in July 2018.
(2)The amounts in column (c) represent the actual base salary paid to the NEOs in the applicable year. The 2020 base salary amounts include an amount attributable to an extra pay period that occurred in 2020 as the NEOs are paid on a bi-weekly basis. The 2020 changes in base salaries noted in the Compensation Discussion and Analysis were effective in April 2020.
(3)The amount in column (d) in 2020, 2019, and 2018 for Mr. Bakken represents the cash bonus paid to him pursuant to the Nuclear Retention Plan. See “Nuclear Retention Plan” in Compensation Discussion and Analysis. The amount in column (d) in 2018 for Mr. Ellis represents a cash sign-on bonus paid in connection with his commencement of employment with Entergy New Orleans.
(4)The amounts in column (e) represent the aggregate grant date fair value of restricted stock and performance units granted under the 2015 Equity Ownership Plan of Entergy Corporation and Subsidiaries (the “2015 EOP”) and the 2019 OIP (together with the 2015 EOP, the “Equity Plans”), each calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures. The grant date fair value of the restricted stock is based on the closing price of Entergy Corporation common stock on the date of grant. The grant date fair value of the portion of the performance units with vesting based on the total shareholder return was 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. The performance units in the table are also valued based on the probable outcome of the applicable performance condition at the time of grant. The maximum value of shares that would be received if the highest achievement level is attained with respect to both the total shareholder return and Cumulative ETR Adjusted EPS, for performance units granted in 2020 are as follows: Mr. Bakken,
$2,043,768; Mr. Brown, $1,994,504; Mr. Denault, $8,235,925; Mr. Ellis, $250,268; Mr. Fisackerly, $250,268; Ms. Landreaux $250,268; Mr. Marsh, $2,422,938;$2,518,486; Mr. May, $438,901;$368,816; Ms. Rainer, $296,003;$250,268; and Mr. West, $2,056,302.$2,213,159.
| |
(5) | The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the 2015 Equity Plan 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) | For all Named Executive Officers, the amounts in column (h) include the annual actuarial increase in the present value of these 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 “2019 Pension Benefits”). The increase in pension benefits for all of the Named Executive Officers in 2019 was driven by a decline in the discount rate that was a result of the decrease in prevailing interest rates. None of the increases for any of the Named Executive Officers is attributable to above-market or preferential earnings on non-qualified deferred compensation. For 2018, the aggregate change in the actuarial present value was a decrease of pension benefits of $52,000 for Mr. Fisackerly, $163,000 for Mr. Marsh, $700 for Mr. May, $110,700 for Ms. Rainer, and $149,300 for Mr. West. |
| |
(8) | The amounts in column (i) for 2019 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 and relocation expenses; and (e) perquisites and other compensation as described further below. The amounts are listed in the following table: |
(5)The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the Equity Plans 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 annual incentive award cash payments made under the 2019 OIP.
(7)For all NEOs, the amounts in column (h) include the annual actuarial increase in the present value of these NEOs’ 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 NEOs may not currently be entitled to receive because such amounts are not vested (see “2020 Pension Benefits”). The increase in pension benefits for all of the NEOs in 2020 was driven by a decline in the discount rate that was a result of the decrease in prevailing interest rates. None of the increases for any of the NEOs is attributable to above-market or preferential earnings on non-qualified deferred compensation. For 2018, the aggregate change in the actuarial present value was a decrease of pension benefits of $52,000 for Mr. Fisackerly, $163,000 for Mr. Marsh, $700 for Mr. May, $110,700 for Ms. Rainer, and $149,300 for Mr. West.
(8)The amounts in column (i) for 2020 include (a) matching contributions by Entergy Corporation under the Savings Plan to each of the NEOs; (b) dividends paid on restricted stock when vested; (c) life insurance premiums; (d) tax gross up payments on club dues; and (e) perquisites and other compensation as described further below. 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 |
| A. Christopher Bakken, III | $17,100 | | $52,032 | | $12,415 | | $— | | $4,299 | | $85,846 | |
| Marcus V. Brown | $11,970 | | $56,953 | | $7,482 | | $— | | $2,226 | | $78,631 | |
| Leo P. Denault | $11,970 | | $173,952 | | $11,484 | | $— | | $92,226 | | $289,632 | |
| David D. Ellis | $17,100 | | $658 | | $745 | | $— | | $820 | | $19,323 | |
| Haley R. Fisackerly | $11,970 | | $8,305 | | $5,705 | | $7,939 | | $14,182 | | $48,101 | |
| Laura R. Landreaux | $— | | $13,094 | | $493 | | $4,281 | | $8,829 | | $26,697 | |
| Andrew S. Marsh | $11,970 | | $59,177 | | $6,594 | | $— | | $— | | $77,741 | |
| Phillip R. May, Jr. | $11,970 | | $10,902 | | $5,964 | | $— | | $— | | $28,836 | |
| Sallie T. Rainer | $11,970 | | $8,564 | | $1,580 | | $2,836 | | $8,433 | | $33,383 | |
| Roderick K. West | $11,970 | | $41,931 | | $4,002 | | $— | | $1,827 | | $59,730 | |
(9)In order to show the effect that the year-over-year change in pension value had on total compensation, as determined under applicable SEC rules, we have included an additional column to show total compensation minus the change in pension value. The amounts reported in the Total Without Change in Pension Value column may differ substantially from the amounts reported in the Total column required under SEC rules and are not a substitute for total compensation. Total Without Change in Pension Value represents total compensation, as determined under applicable SEC rules, minus the change in pension value reported in the Change in Pension Value and Nonqualified Deferred Compensation Earnings column. The change in pension value is subject to many external variables, such as interest rates, assumptions about life expectancy and changes in the discount rate determined at each year end, which are functions of economic factors and actuarial calculations that are not related to Entergy Corporation’s performance and are outside of the control of the Personnel Committee.
|
| | | | | | | | | | | | | | | | | | |
| Named Executive Officer | 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 |
| $16,800 |
|
| $20,114 |
|
| $12,277 |
|
| $— |
|
| $13,216 |
|
| $62,407 |
|
| Marcus V. Brown |
| $11,760 |
|
| $48,749 |
|
| $7,482 |
|
| $— |
|
| $1,964 |
|
| $69,955 |
|
| Leo P. Denault |
| $11,760 |
|
| $129,470 |
|
| $11,484 |
|
| $— |
|
| $56,108 |
|
| $208,822 |
|
| David D. Ellis |
| $14,436 |
|
| $— |
|
| $722 |
|
| $— |
|
| $109 |
|
| $15,267 |
|
| Haley R. Fisackerly |
| $11,760 |
|
| $7,793 |
|
| $2,959 |
|
| $4,729 |
|
| $10,656 |
|
| $37,897 |
|
| Laura R. Landreaux |
| $— |
|
| $11,257 |
|
| $477 |
|
| $4,510 |
|
| $10,292 |
|
| $26,536 |
|
| Andrew S. Marsh |
| $11,760 |
|
| $49,010 |
|
| $6,275 |
|
| $— |
|
| $2,818 |
|
| $69,863 |
|
| Phillip R. May, Jr. |
| $11,760 |
|
| $9,958 |
|
| $5,779 |
|
| $— |
|
| $800 |
|
| $28,297 |
|
| Sallie T. Rainer |
| $11,760 |
|
| $7,879 |
|
| $6,872 |
|
| $2,728 |
|
| $8,122 |
|
| $37,361 |
|
| Roderick K. West |
| $11,760 |
|
| $39,754 |
|
| $4,002 |
|
| $— |
|
| $11,675 |
|
| $67,191 |
|
Perquisites and Other Compensation
The amounts set forth in column (i) also include perquisites and other personal benefits that Entergy Corporation provides to its Named Executive OfficersNEOs as part of providing a competitive executive compensation programsprogram and for employee retention. The following perquisites were provided to the Named Executive OfficersNEOs in 2019.2020.
|
| | | | | | | | | | |
| Named Executive Officer | Relocation | Personal Use of Corporate Aircraft | Club Dues | Executive Physical Exams | Event Tickets |
| A. Christopher Bakken, III | | X | | X | |
| Marcus V. Brown | X | | | X | |
| Leo P. Denault | X | X | | X | |
| David D. Ellis | X | | | | |
| Haley R. Fisackerly | | X | X | | |
| Laura R. Landreaux | | X | X | | X |
| Andrew S. Marsh | | X | | X | |
| Phillip R. May, Jr. | | | | | X |
| Sallie T. Rainer | | X | X | | |
| Roderick K. West | | X | | X | |
For security and business reasons, Entergy Corporation’s Chief Executive Officer is permitted to use its corporate aircraft for personal use at the expense of Entergy Corporation. The other Named Executive OfficersNEOs 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. The aggregate incremental aircraft usage cost associated with Mr. Denault’s personal use of the corporate aircraft was $56,108$86,618 for fiscal year 2019.2020. In addition, Entergy Corporation offers its executives comprehensive annual physical exams at Entergy Corporation’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. None of the other perquisites referenced above exceeded $25,000 for any of the other Named Executive Officers.NEOs.
20192020 Grants of Plan-Based Awards
The following table summarizes award grants during 20192020 to the Named Executive Officers.NEOs.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) | | Estimated Future Payouts under Equity Incentive Plan Awards (2) | | | | | | | | |
| (a) | | (b) | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) |
| Name | | Grant Date | | Thresh-old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under-lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards |
| | | | ($) | ($) | ($) | | (#) | (#) | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) |
| A. Christopher | | 1/30/20 | | $- | $505,275 | $1,010,550 | | | | | | | | | | | | |
| Bakken, III | | 1/30/20 | | | | | | 1,940 | | 7,758 | | 15,516 | | | | | | | | | $1,257,851 |
| | 1/30/20 | | | | | | | | | | 3,104 | | | | | | | $408,859 |
| | 1/30/20 | | | | | | | | | | | | 29,279 | | | $131.72 | | $335,245 |
| | | | | | | | | | | | | | | | | | |
| Marcus V. | | 1/30/20 | | $- | $552,000 | $1,104,000 | | | | | | | | | | | | |
| Brown | | 1/30/20 | | | | | | 1,893 | | 7,571 | | 15,142 | | | | | | | | | $1,227,532 |
| | 1/30/20 | | | | | | | | | | 3,029 | | | | | | | $398,980 |
| | 1/30/20 | | | | | | | | | | | | 28,574 | | | $131.72 | | $327,172 |
| | | | | | | | | | | | | | | | | | |
| Leo P. | | 1/30/20 | | $- | $1,764,000 | $3,528,000 | | | | | | | | | | | | |
| Denault | | 1/30/20 | | | | | | 7,816 | | 31,263 | | 62,526 | | | | | | | | | $5,068,858 |
| | 1/30/20 | | | | | | | | | | 12,505 | | | | | | | $1,647,159 |
| | 1/30/20 | | | | | | | | | | | | 117,990 | | | $131.72 | | $1,350,986 |
| | | | | | | | | | | | | | | | | | |
| David D. | | 1/30/20 | | $- | $128,740 | $257,480 | | | | | | | | | | | | |
| Ellis | | 1/30/20 | | | | | | 238 | | 950 | | 1,900 | | | | | | | | | $154,029 |
| | | | | | | | | | | | 500 | | | | | | $65,860 |
| | | | | | | | | | | | | | 3,200 | | | $131.72 | | $36,640 |
| | | | | | | | | | | | | | | | | | |
| Haley R. | | 1/30/20 | | $- | $155,297 | $310,594 | | | | | | | | | | | | |
| Fisackerly | | 1/30/20 | | | | | | 238 | | 950 | | 1,900 | | | | | | | | | $154,029 |
| | | 1/30/20 | | | | | | | | | | 750 | | | | | | | $98,790 |
| | | 1/30/20 | | | | | | | | | | | | 4,300 | | | $131.72 | | $49,235 |
| | | | | | | | | | | | | | | | | | |
| Laura R. | | 1/30/20 | | $- | $130,702 | $261,404 | | | | | | | | | | | | |
| Landreaux | | 1/30/20 | | | | | | 238 | | 950 | | 1,900 | | | | | | | | | $154,029 |
| | 1/30/20 | | | | | | | | | | 750 | | | | | | | $98,790 |
| | | | | | | | | | | | | | 4,300 | | | $131.72 | | $49,235 |
| | | | | | | | | | | | | | | | | | |
| Andrew S. | | 1/30/20 | | $- | $586,500 | $1,173,000 | | | | | | | | | | | | |
| Marsh | | 1/30/20 | | | | | | 2,390 | | 9,560 | | 19,120 | | | | | | | | | $1,550,020 |
| | 1/30/20 | | | | | | | | | | 3,824 | | | | | | | $503,697 |
| | 1/30/20 | | | | | | | | | | | | 36,079 | | | $131.72 | | $413,105 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) | | Estimated Future Payouts under Equity Incentive Plan Awards (2) | | | | | | | | |
| (a) | | (b) | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) |
| Name | | Grant Date | | Thresh-old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under-lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards |
| | | | | ($) | ($) | ($) | | (#) | (#) | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) |
| A. Christopher | | 1/31/19 | | $- | $457,855 | $915,710 | | | | | | | | | | | | |
| Bakken, III | | 1/31/19 | | | | | | 2,392 |
| 9,568 |
| 19,136 |
| | | | | | | | $951,959 |
| | | 1/31/19 | | | | | |
|
| |
|
| | 3,604 |
| | | | | | $321,441 |
| | | 1/31/19 | | | | | | | | | | | | 36,421 |
| | $89.19 | | $303,023 |
| | | | | | | | | | | | | | | | | | | |
| Marcus V. | | 1/31/19 | | $- | $499,688 | $999,376 | | | | | | | | | | | | |
| Brown | | 1/31/19 | | | | | | 2,346 |
| 9,383 |
| 18,766 |
| | | | | | | | $933,552 |
| | | 1/31/19 | | | | | | | | | | 3,535 |
| | | | | | $315,287 |
| | | 1/31/19 | | | | | | | | | | | | 35,719 |
| | $89.19 | | $297,182 |
| | | | | | | | | | | | | | | | | | | |
| Leo P. | | 1/31/19 | | $- | $1,764,000 | $3,528,000 | | | | | | | | | | | | |
| Denault | | 1/31/19 | | | | | | 10,127 |
| 40,508 |
| 81,016 |
| | | | | | | | $4,030,303 |
| | | 1/31/19 | | | | | | | | | | 15,259 |
| | | | | | $1,360,950 |
| | | 1/31/19 | | | | | | | | | | | | 154,206 |
| | $89.19 | | $1,282,994 |
| | | | | | | | | | | | | | | | | | | |
| David D. | | 1/31/19 | | $- | $125,355 | $250,710 | | | | | | | | | | | | |
| Ellis | | 1/31/19 | | | | | | 363 |
| 1,450 |
| 2,900 |
| | | | | | | | $144,266 |
| | | | | | | | | | | | | 500 |
| | | | | | $44,595 |
| | | | | | | | | | | | | | | 4,700 |
| | $89.19 | | $39,104 |
| | | | | | | | | | | | | | | | | | | |
| Haley R. | | 1/31/19 | | $- | $150,409 | $300,818 | | | | | | | | |
| | | | |
| Fisackerly | | 1/31/19 | | | | | | 363 |
| 1,450 |
| 2,900 |
| | | | | | | | $144,266 |
| | | 1/31/19 | | | | | | | | | | 600 |
| | | | | | $53,514 |
| | | 1/31/19 | | | | | | | | | | | | 6,200 |
| | $89.19 | | $51,584 |
| | | | | | | | | | | | | | | | | | | |
| Laura R. | | 1/31/19 | | $- | $126,588 | $253,176 | |
| | | | | | | | | | |
| Landreaux | | 1/31/19 | | | | | | 363 |
| 1,450 |
| 2,900 |
| | | | | | | | $144,266 |
| | | 1/31/19 | | | | | | | | | | 500 |
| | | |
| | $44,595 |
| | | | | | | | | | | | | | | 5,100 |
| | $89.19 | | $42,432 |
| | | | | | | | | | | | | | | | | | | |
| Andrew S. | | 1/31/19 | | $- | $520,000 | $1,040,000 | | | | | | | | | | | | |
| Marsh | | 1/31/19 | | | | | | 2,967 |
| 11,869 |
| 23,738 |
| | | | | | | | $1,180,894 |
| | | 1/31/19 | | | | | | | | | | 4,471 |
| | | | | | $398,768 |
| | | 1/31/19 | | | | | | | | | | | | 45,182 |
| | $89.19 | | $375,914 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) | | Estimated Future Payouts under Equity Incentive Plan Awards (2) | | | | | | | | |
| (a) | | (b) | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) |
| Name | | Grant Date | | Thresh-old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under-lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards |
| | | | ($) | ($) | ($) | | (#) | (#) | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) |
| Phillip R. | | 1/30/20 | | $- | $242,870 | $485,740 | | | | | | | | | | | | |
| May, Jr. | | 1/30/20 | | | | | | 350 | | 1,400 | | 2,800 | | | | | | | | | $226,990 |
| | 1/30/20 | | | | | | | | | | 1,100 | | | | | | | $144,892 |
| | 1/30/20 | | | | | | | | | | | | 7,300 | | | $131.72 | | $85,585 |
| | | | | | | | | | | | | | | | | | |
| Sallie T. | | 1/30/20 | | $- | $143,485 | $286,970 | | | | | | | | | | | | |
| Rainer | | 1/30/20 | | | | | | 238 | | 950 | | 1,900 | | | | | | | | | $154,029 |
| | | 1/30/20 | | | | | | | | | | 750 | | | | | | | $98,790 |
| | 1/30/20 | | | | | | | | | | | | 4,300 | | | $131.72 | | $49,235 |
| | | | | | | | | | | | | | | | | | |
| Roderick K. | | 1/30/20 | | $- | $585,490 | $1,170,980 | | | | | | | | | | | | |
| West | | 1/30/20 | | | | | | 2,100 | | 8,401 | | 16,802 | | | | | | | | | $1,362,105 |
| | | 1/30/20 | | | | | | | | | | 3,361 | | | | | | | $442,711 |
| | 1/30/20 | | | | | | | | | | | | 31,705 | | | $131.72 | | $363,022 |
(1)The amounts in columns (c), (d), and (e) represent minimum, target, and maximum payment levels under the annual incentive program. 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 LTIP. 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 and Cumulative Entergy Adjusted EPS with total shareholder return weighted eighty percent and Cumulative Entergy Adjusted EPS weighted twenty percent. There is no payout under the program if Entergy Corporation’s total shareholder return falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and Cumulative Entergy Adjusted EPS is below the minimum performance goal. 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, 2022). 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 2019 OIP. 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 2019 OIP.
(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 2020 Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Estimated Possible 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) |
| Phillip R. | | 1/31/19 | | $- | $235,226 | $470,452 | | | | | | | | | | | | |
| May, Jr. | | 1/31/19 | | | | | | 538 |
| 2,150 |
| 4,300 |
| | | | | | | | $213,912 |
| | | 1/31/19 | | | | | | | | | | 900 |
| | | | | | $80,271 |
| | | 1/31/19 | | | | | | | | | | | | 9,300 |
| | $89.19 | | $77,376 |
| | | | | | | | | | | | | | | | | | | |
| Sallie T. | | 1/31/19 | | $- | $138,969 | $277,938 | | | | | | |
| | |
| | | | |
| Rainer | | 1/31/19 | | | | | | 363 |
| 1,450 |
| 2,900 |
| | | | | | | | $144,266 |
| | | 1/31/19 | | | | | | | | | | 600 |
| | | | | | $53,514 |
| | | 1/31/19 | | | | | | | | | | | | 6,200 |
| | $89.19 | | $51,584 |
| | | | | | | | | | | | | | | | | | | |
| Roderick K. | | 1/31/19 | | $- | $499,809 | $999,618 | | | | | | | | | | | | |
| West | | 1/31/19 | | | | | | 2,518 |
| 10,073 |
| 20,146 |
| | | | | | | | $1,002,203 |
| | | 1/31/19 | | | | | | | | | | 3,795 |
| | | | | | $338,476 |
| | | 1/31/19 | | | | | | | | | | | | 38,346 |
| | $89.19 | | $319,039 |
| |
(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 and Cumulative Entergy Adjusted EPS with total shareholder return weighted eighty percent and Cumulative Entergy Adjusted EPS weighted twenty percent. There is no payout under the program if Entergy Corporation’s total shareholder return falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and Cumulative Entergy Adjusted EPS is below the minimum performance goal. 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, 2021.) 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 2015 Equity 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 2015 Equity 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 2019 Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value. |
20192020 Outstanding Equity Awards at Fiscal Year-End
The following table summarizes, for each Named Executive Officer,NEO, unexercised options, restricted stock that has not vested, and equity incentive plan awards outstanding as of December 31, 2019.2020.
|
| | | | | | | | | | | | | | | | | | | | |
| | | 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 | | — |
| | 36,421(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | — |
| | 27,000(2) |
| | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | — |
| | 12,534(3) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | | | | | | | | | | | | | | | 19,136(4) | | $2,292,493 |
| | | | | | | | | | | | | | | | | 15,800(5) | | $1,892,840 |
| | | | | | | | | | | | | 3,604(6) | | $431,759 | | | | |
| | | | | | | | | | | | | 3,334(7) | | $399,413 | | | | |
| | | | | | | | | | | | | 1,734(8) | | $207,733 | | | | |
| | | | | | | | | | | | | 20,000(10) | | $2,396,000 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Marcus V. Brown | | — |
| | 35,719(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | — |
| | 27,000(2) |
| | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | 1 |
| | 14,667(3) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 1 |
| | — |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | | | | | | | | | | | | | | | 18,766(4) | | $2,248,167 |
| | | | | | | | | | | | | | | | | 15,800(5) | | $1,892,840 |
| | | | | | | | | | | | | 3,535(6) | | $423,493 | | | | |
| | | | | | | | | | | | | 3,334(7) | | $399,413 | | | | |
| | | | | | | | | | | | | 2,034(8) | | $243,673 | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Leo P. Denault | | — |
| | 154,206(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | 55,700 |
| | 111,400(2) |
| | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | 119,600 |
| | 59,800(3) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 167,000 |
| | — |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 88,000 |
| | — |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 106,000 |
| | — |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 50,000 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | | | | | | | | | | | | | | | 81,016(4) | | $9,705,717 |
| | | | | | | | | | | | | | | | | 85,400(5) | | $10,230,920 |
| | | | | | | | | | | | | 15,259(6) | | $1,828,028 | | | | |
| | | | | | | | | | | | | 10,467(7) | | $1,253,947 | | | | |
| | | | | | | | | | | | | 5,667(8) | | $678,907 | | | | |
| | | | | | | | | | | | | | | | | | | |
| David D. Ellis | | — |
| | 4,700(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | | | | | | | | | | | | | | | 2,900(4) | | $347,420 |
| | | | | | | | | | | | | | | | | 2,200(5) | | $263,560 |
| | | | | | | | | | | | | 500(6) | | $59,900 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Haley R. Fisackerly | | — |
| | 6,200(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | — |
| | 4,400(2) |
| | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | — |
| | 2,534(3) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | | | | | | | | | | | | | | | 2,900(4) | | $347,420 |
| | | | | | | | | | | | | | | | | 3,300(5) | | $395,340 |
| | | | | | | | | | | | | 600(6) | | $71,880 | | | | |
| | | | | | | | | | | | | 534(7) | | $63,973 | | | | |
| | | | | | | | | | | | | 284(8) | | $34,023 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Laura R. Landreaux | | — |
| | 5,100(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | | | | | | | | | | | | | | | 2,900(4) | | $347,420 |
| | | | | | | | | | | | | | | | | 2,750(5) | | $329,450 |
| | | | | | | | | | | | | 500(6) | | $59,900 | | | | |
| | | | | | | | | | | | | 800(7) | | $95,840 | | | | |
| | | | | | | | | | | | | 500(8) | | $59,900 | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Andrew S. Marsh | | — |
| | 45,182(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | 16,333 |
| | 32,667(2) |
| | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | 29,333 |
| | 14,667(3) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 45,000 |
| | — |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 24,000 |
| | — |
| | | | $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 | | | | | | | | |
| | | | | | | | | | | | | | | | | 23,738(4) | | $2,843,812 |
| | | | | | | | | | | | | | | | | 15,800(5) | | $1,892,840 |
| | | | | | | | | | | | | 4,471(6) | | $535,626 | | | | |
| | | | | | | | | | | | | 3,467(7) | | $415,347 | | | | |
| | | | | | | | | | | | | 2,034(8) | | $243,673 | | | | |
| | | | | | | | | | | | | 21,100(9) | | $2,527,780 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Phillip R. May, Jr. | | — |
| | 9,300(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | — |
| | 6,600(2) |
| | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | — |
| | 3,500(3) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 2,000 |
| | — |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 2,000 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | | | | | | | | | | | | | | | 4,300(4) | | $515,140 |
| | | | | | | | | | | | | | | | | 5,100(5) | | $610,980 |
| | | | | | | | | | | | | 900(6) | | $107,820 | | | | |
| | | | | | | | | | | | | 667(7) | | $79,907 | | | | |
| | | | | | | | | | | | | 367(8) | | $43,967 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Sallie T. Rainer | | — |
| | 6,200(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | — |
| | 4,400(2) |
| | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | — |
| | 2,600(3) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | | | | | | | | | | | | | | | 2,900(4) | | $347,420 |
| | | | | | | | | | | | | | | | | 3,300(5) | | $395,340 |
| | | | | | | | | | | | | 600(6) | | $71,880 | | | | |
| | | | | | | | | | | | | 534(7) | | $63,973 | | | | |
| | | | | | | | | | | | | 300(8) | | $35,940 | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Roderick K. West | | — |
| | 38,346(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | 14,166 |
| | 28,334(2) |
| | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | 9,733 |
| | 9,734(3) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 13,667 |
| | — |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 23,000 |
| | — |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | | | |
| | | | | | | | | | | | 20,146(4) | | $2,413,491 |
| | | |
| | |
| | | | | | | | | | | | 15,800(5) | | $1,892,840 |
| | | |
| | |
| | | | | | | | 3,795(6) | | $454,641 | | | | |
| | | |
| | |
| | | | | | | | 3,467(7) | | $415,347 | | | | |
| | | |
| | |
| | | | | | | | 1,067(8) | | $127,827 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) | Consists | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of options granted under the 2015 Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan that vestedAwards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or will vest as follows: 1/3Units of the options granted vest on eachStock That Have Not Vested | | Market Value of January 31, 2020, January 31, 2021 and January 31, 2022.Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| A. Christopher Bakken, III | | — | | | 29,279(1) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
(2) | Consists of options granted under the 2015 Equity Plan that vested or will vest as follows: | — | | | 24,281(2) | | | | $89.19 | | 1/2 of the remaining unexercisable options vest on each of January 25, 2020 and January 25, 2021.31/2029 |
| | | | | | | |
(3) | Consists of options granted under the 2015 Equity Plan that vested on January 26, 2020. |
| — | | | 13,500(3) | | | | $78.08 | | 1/25/2028 | | | | | | | | |
(4) | Consists of performance units granted under the 2015 Equity Plan that will vest on December 31, 2021 based on two performance measures: 1) Entergy Corporation’s total shareholder return performance over the 2019-2021 performance period and 2) Cumulative Entergy Adjusted EPS with total shareholder return weighted eighty percent and Cumulative Entergy Adjusted EPS weighted twenty percent, as described under “What Entergy Corporation Pays and Why - Principal Executive Compensation Elements - Variable Compensation - Long-Term Incentive Compensation - Performance Unit Program” in the Compensation Discussion and Analysis. | | | | | | | | | | | | | | | 1,940(4) | | $193,640 |
| | | | | | | | | | | | | | | | 19,136(5) | | $1,910,538 |
| | | | | | | | | | | | 3,104(6) | | $309,903 | | | | |
(5) | Consists of performance units granted under the 2015 Equity Plan that will vest on December 31, 2020 based on two performance measures: 1) Entergy Corporation’s total shareholder return performance over the 2018-2020 performance period and 2) Cumulative Utility, Parent and Other Adjusted EPS with each performance measure weighted equally. |
| | | | | | | | | | 2,403(7) | | $239,916 | | | | |
(6) | Consists of shares of restricted stock granted under the 2015 Equity Plan that vested or will vest as follows: 1/3 of the shares of restricted stock granted vest on each of January 31, 2020, January 31, 2021, and January 31, 2022. |
| | | | | | | | | | 1,667(8) | | $166,433 | | | | |
(7) | Consists of shares of restricted stock granted under the 2015 Equity Plan that vested or will vest as follows: 1/2 of the shares of restricted stock granted vest on each of January 25, 2020 and January 25, 2021. |
| | | | | | | | | | 20,000(9) | | $1,996,800 | | | | |
(8) | Consists of shares of restricted stock granted under the 2015 Equity Plan that vested on January 26, 2020. |
| | | | | | | | | | | | | | | | |
(9)Marcus V. Brown | Consists of restricted stock units granted under the 2015 Equity Plan which will vest on August 3, 2020. |
| — | | | 28,574(1) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
(10) | Consists of restricted stock units granted under the 2015 Equity Plan which will vest | — | | | 23,813(2) | | | | $89.19 | | 1/2 on each of April 6, 2022 and April 6, 2025.31/2029 | | | | | | | | |
| | — | | | 13,500(3) | | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | | | | | | | | | | | | | | 1,893(4) | | $188,972 |
| | | | | | | | | | | | | | | | 18,766(5) | | $1,873,597 |
| | | | | | | | | | | | 3,029(6) | | $302,415 | | | | |
| | | | | | | | | | | | 2,357(7) | | $235,323 | | | | |
| | | | | | | | | | | | 1,667(8) | | $166,433 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Leo P. Denault | | — | | | 117,990(1) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
| | 51,402 | | | 102,804(2) | | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | 111,400 | | | 55,700(3) | | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | 179,400 | | | — | | | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 167,000 | | | — | | | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 88,000 | | | — | | | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 106,000 | | | — | | | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | 50,000 | | | — | | | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | | | | | | | | | | | | | | 7,816(4) | | $780,324 |
| | | | | | | | | | | | | | | | 81,016(5) | | $8,088,637 |
| | | | | | | | | | | | 12,505(6) | | $1,248,499 | | | | |
| | | | | | | | | | | | 10,173(7) | | $1,015,672 | | | | |
| | | | | | | | | | | | 5,234(8) | | $522,563 | | | | |
| | | | | | | | | | | | | | | | | | |
| David D. Ellis | | — | | | 3,200(1) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
| | 1,566 | | | 3,134(2) | | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | | | | | | | | | | | | | | 238(4) | | $23,712 |
| | | | | | | | | | | | | | | | 2,900(5) | | $289,536 |
| | | | | | | | | | | | 500(6) | | $49,920 | | | | |
| | | | | | | | | | | | 334(7) | | $33,347 | | | | |
| | | | | | | | | | | | | | | | | | |
| Haley R. Fisackerly | | — | | | 4,300(1) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
| | — | | | 4,134(2) | | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | — | | | 2,200(3) | | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | | | | | | | | | | | | | | 238(4) | | $23,712 |
| | | | | | | | | | | | | | | | 2,900(5) | | $289,536 |
| | | | | | | | | | | | 750(6) | | $74,880 | | | | |
| | | | | | | | | | | | 400(7) | | $39,936 | | | | |
| | | | | | | | | | | | 267(8) | | $26,657 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Laura R. Landreaux | | — | | | 4,300(1) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
| | 1,700 | | | 3,400(2) | | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | | | | | | | | | | | | | | 238(4) | | $23,712 |
| | | | | | | | | | | | | | | | 2,900(5) | | $289,536 |
| | | | | | | | | | | | 750(6) | | $74,880 | | | | |
| | | | | | | | | | | | | 334(7) | | $33,347 | | | | |
| | | | | | | | | | | | 400(8) | | $39,936 | | | | |
| | | | | | | | | | | | | | | | | | |
| Andrew S. Marsh | | — | | | 36,079(1) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
| | 15,060 | | | 30,122(2) | | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | 32,666 | | | 16,334(3) | | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | 44,000 | | | — | | | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 45,000 | | | — | | | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 24,000 | | | — | | | | | $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 | | | | | | | | |
| | | | | | | | | | | | | | | | 2,390(4) | | $238,618 |
| | | | | | | | | | | | | | | | | 23,738(5) | | $2,370,002 |
| | | | | | | | | | | | 3,824(6) | | $381,788 | | | | |
| | | | | | | | | | | | 2,981(7) | | $297,623 | | | | |
| | | | | | | | | | | | 1,734(8) | | $173,123 | | | | |
| | | | | | | | | | | | | | | | | | |
| Phillip R. May, Jr. | | — | | | 7,300(1) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
| | — | | | 6,200(2) | | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | — | | | 3,300(3) | | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | | | | | | | | | | | | | | | 350(4) | | $34,944 |
| | | | | | | | | | | | | | | | | 4,300(5) | | $429,312 |
| | | | | | | | | | | | | 1,100(6) | | $109,824 | | | | |
| | | | | | | | | | | | | 600(7) | | $59,904 | | | | |
| | | | | | | | | | | | 343(8) | | $33,347 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Sallie T. Rainer | | — | | | 4,300(1) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
| | 2,066 | | | 4,134(2) | | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | 2,200 | | | 2,200(3) | | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | 2,600 | | | — | | | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | | | | | | | | | | | | | | | 238(4) | | $23,712 |
| | | | | | | | | | | | | | | | | 2,900(5) | | $289,536 |
| | | | | | | | | | | | 750(6) | | $74,880 | | | | |
| | | | | | | | | | | | 400(7) | | $39,936 | | | | |
| | | | | | | | | | | | 267(8) | | $26,657 | | | | |
| | | | | | | | | | | | | | | | | | |
| Roderick K. West | | — | | | 31,705(1) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
| | — | | | 25,564(2) | | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | — | | | 14,167(3) | | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | | | | | | | | | | | | | | | 2,100(4) | | $209,689 |
| | | | | | | | | | | | | | | | | 20,146(5) | | $2,011,377 |
| | | | | | | | | | | | | 3,361(6) | | $335,562 | | | | |
| | | | | | | | | | | | | 2,530(7) | | $252,595 | | | | |
| | | | | | | | | | | | | 1,734(8) | | $173,123 | | | | |
(1)Consists of options granted under the 2019 OIP; 1/3 of the options vested on January 30, 2021 and 1/3 of the remaining options will vest on each of January 30, 2022 and January 30, 2023.
(2)Consists of options granted under the 2015 EOP; 1/2 of the options vested on January 31, 2021 and the remaining options will vest on January 30, 2022.
(3)Consists of options granted under the 2015 EOP that vested on January 25, 2021.
(4)Consists of performance units granted under the 2019 OIP that will vest on December 31, 2022 based on two performance measures: 1) Entergy Corporation’s total shareholder return performance over the 2020-2022 performance period and 2) Cumulative Entergy Adjusted EPS with total shareholder return weighted eighty percent and Cumulative Entergy Adjusted EPS weighted twenty percent, as described under “What Entergy Corporation Pays and Why - Long-Term Incentive Compensation - 2020 Long-Term Incentive Award Mix - Long-Term Performance Unit Program” in the Compensation Discussion and Analysis.
(5)Consists of performance units granted under the 2015 EOP that will vest on December 31, 2021 based on two performance measures: 1) Entergy Corporation’s total shareholder return performance over the 2019-2021 performance period and 2) Cumulative Entergy Adjusted EPS with total shareholder return weighted eighty percent and Cumulative Entergy Adjusted EPS weighted twenty percent.
(6)Consists of shares of restricted stock granted under the 2019 OIP; 1/3 of the shares of restricted stock vested on January 30, 2021 and 1/3 of the remaining shares will vest on each of January 30, 2022 and January 30, 2023.
(7)Consists of shares of restricted stock granted under the 2015 EOP; 1/2 of the shares of restricted stock vested on January 31, 2021 and the remaining shares of restricted stock will vest on January 31, 2022.
(8)Consists of shares of restricted stock granted under the 2015 EOP that vested on January 25, 2021.
(9)Consists of restricted stock units granted under the 2015 EOP which will vest 1/2 on each of April 6, 2022 and April 6, 2025.
2020 Option Exercises and Stock Vested
The following table provides information concerning each exercise of stock options and each vesting of stock during 20192020 for the Named Executive Officers.NEOs.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Options Awards | | Stock Awards |
| (a) | | (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 (1) |
| | (#) | | ($) | | (#) | | ($) |
| A. Christopher Bakken, III | | 38,174 | | | $1,954,334 | | | 16,051 | | | $1,701,473 | |
| | | | | | | | |
| Marcus V. Brown | | 40,075 | | | $2,081,630 | | | 16,366 | | | $1,742,234 | |
| | | | | | | | |
| Leo P. Denault | | — | | | $— | | | 77,044 | | | $7,935,333 | |
| | | | | | | | |
| David D. Ellis | | — | | | $— | | | 1,659 | | | $164,028 | |
| | | | | | | | |
| Haley R. Fisackerly | | 6,800 | | | $351,077 | | | 3,122 | | | $325,433 | |
| | | | | | | | |
| Laura R. Landreaux | | — | | | $— | | | 3,059 | | | $331,489 | |
| | | | | | | | |
| Andrew S. Marsh | | — | | | $— | | | 37,861 | | | $3,959,325 | |
| | | | | | | | |
| Phillip R. May, Jr. | | 13,900 | | | $774,394 | | | 4,650 | | | $480,241 | |
| | | | | | | | |
| Sallie T. Rainer | | — | | | $— | | | 3,140 | | | $327,765 | |
| | | | | | | | |
| Roderick K. West | | 97,249 | | | $4,940,267 | | | 15,436 | | | $1,621,930 | |
(1)Represents the value of performance units for the 2018 - 2020 performance period (payable solely in shares based on the closing stock price of Entergy Corporation on the date of vesting) under the LTIP and the vesting of shares of restricted stock in 2020.
|
| | | | | | | | | | | | | | |
| | | Options Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) |
| Name | | Number of Shares Acquired on Exercise | | Value Realized on Exercise | | Number of Shares Acquired on Vesting | | Value Realized on Vesting (1) |
| | | (#) | | ($) | | (#) | | ($) |
| A. Christopher Bakken, III | | 38,566 |
| |
| $1,377,860 |
| | 31,719 |
| |
| $3,543,240 |
|
| | | | | | | | | |
| Marcus V. Brown | | 145,031 |
| |
| $4,056,865 |
| | 24,484 |
| |
| $2,839,040 |
|
| | | | | | | | | |
| Leo P. Denault | | 105,000 |
| |
| $2,861,250 |
| | 123,760 |
| |
| $14,933,716 |
|
| | | | | | | | | |
| David D. Ellis | | — |
| |
| $— |
| | 1,271 |
| |
| $160,540 |
|
| | | | | | | | | |
| Haley R. Fisackerly | | 13,700 |
| |
| $280,882 |
| | 5,037 |
| |
| $596,349 |
|
| | | | | | | | | |
| Laura R. Landreaux | | — |
| |
| $— |
| | 3,431 |
| |
| $374,036 |
|
| | | | | | | | | |
| Andrew S. Marsh | | 17,100 |
| |
| $468,315 |
| | 24,554 |
| |
| $2,845,137 |
|
| | | | | | | | | |
| Phillip R. May, Jr. | | 18,900 |
| |
| $456,820 |
| | 8,146 |
| |
| $978,103 |
|
| | | | | | | | | |
| Sallie T. Rainer | | 15,667 |
| |
| $372,696 |
| | 5,055 |
| |
| $597,906 |
|
| | | | | | | | | |
| Roderick K. West | | — |
| |
| $— |
| | 23,347 |
| |
| $2,740,719 |
|
| |
(1) | Represents the value of performance units for the 2017-2019 performance period (payable solely in shares based on the closing stock price of Entergy Corporation on the date of vesting) under the Performance Unit Program and the vesting of shares of restricted stock in 2019. |
20192020 Pension Benefits
The following table shows the present value as of December 31, 2019,2020, of accumulated benefits payable to each of the Named Executive Officers,NEOs, including the number of years of service credited to each Named Executive Officer,NEO, 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 follows this table.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Name | | Plan Name | | Number of Years Credited Service | | Present Value of Accumulated Benefit | | Payments During 2020 |
| A. Christopher Bakken, III | | Cash Balance Equalization Plan | | 4.74 | | | $287,400 | | | $— | |
| | Cash Balance Plan | | 4.74 | | | $95,800 | | | $— | |
| | | | | | | | |
Marcus V. Brown(1) | | System Executive Retirement Plan | | 25.74 | | | $7,889,100 | | | $— | |
| | Entergy Retirement Plan | | 25.74 | | | $1,385,300 | | | $— | |
| | | | | | | | |
Leo P. Denault (1)(2) | | System Executive Retirement Plan | | 30.00 | | | $30,747,600 | | | $— | |
| | | Entergy Retirement Plan | | 21.83 | | | $1,230,700 | | | $— | |
| | | | | | | | |
| David D. Ellis | | Cash Balance Equalization Plan | | 2.06 | | | $15,200 | | | $— | |
| | Cash Balance Plan | | 2.06 | | | $35,600 | | | $— | |
| | | | | | | | |
Haley R. Fisackerly(1) | | System Executive Retirement Plan | | 25.08 | | | $2,338,800 | | | $— | |
| | | Entergy Retirement Plan | | 25.08 | | | $1,249,300 | | | $— | |
| | | | | | | | |
| Laura R. Landreaux | | Pension Equalization Plan | | 13.48 | | | $258,600 | | | $— | |
| | Entergy Retirement Plan | | 13.48 | | | $577,100 | | | $— | |
| | | | | | | | |
| Andrew S. Marsh | | System Executive Retirement Plan | | 22.37 | | | $6,543,400 | | | $— | |
| | Entergy Retirement Plan | | 22.37 | | | $944,000 | | | $— | |
| | | | | | | | |
Phillip R. May, Jr. (1)(3) | | System Executive Retirement Plan | | 30.00 | | | $3,747,400 | | | $— | |
| | Entergy Retirement Plan | | 34.56 | | | $1,827,300 | | | $— | |
| | | | | | | | |
Sallie T. Rainer (1)(3) | | System Executive Retirement Plan | | 30.00 | | | $1,850,000 | | | $— | |
| | | Entergy Retirement Plan | | 36.00 | | | $2,090,800 | | | $— | |
| | | | | | | | |
| Roderick K. West | | System Executive Retirement Plan | | 21.75 | | | $7,667,200 | | | $— | |
| | | Entergy Retirement Plan | | 21.75 | | | $994,300 | | | $— | |
(1)As of December 31, 2020, Mr. Brown, Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rainer were retirement eligible.
(2)In 2006, Mr. Denault entered into a retention agreement granting him additional years of service and permission to retire under the non-qualified System Executive Retirement Plan (“SERP”) 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 up to an additional 15 years of service under the SERP only if his Entergy employer grants him permission to retire subject to the overall 30 year cap on service credit under the SERP. The amount reflected in the table for the SERP is calculated based on 30 years of service. The additional years of service credited to Mr. Denault under his retention agreement increased the present value of Mr. Denault’s benefit by $4,020,200.
(3)Service under the SERP is granted from the date of hire. Service under the qualified Entergy Retirement Plan is granted from the later of the date of hire or the plan participation date. The SERP amounts reflected in the table for Mr. May and Ms. Rainer are calculated based on 30 years of service pursuant to the terms of the SERP.
|
| | | | | | | | | | | | | |
| Name | | Plan Name | | Number of Years Credited Service | | Present Value of Accumulated Benefit | | Payments During 2019 |
| A. Christopher Bakken, III | | Cash Balance Equalization Plan | | 3.74 |
| |
| $196,900 |
| |
| $— |
|
| | | Cash Balance Plan | | 3.74 |
| |
| $71,200 |
| |
| $— |
|
| | | | | | | | | |
Marcus V. Brown(1) | | System Executive Retirement Plan | | 24.74 |
| |
| $6,368,400 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 24.74 |
| |
| $1,160,000 |
| |
| $— |
|
| | | | | | | | | |
Leo P. Denault (1)(2) | | System Executive Retirement Plan | | 35.83 |
| |
| $26,526,500 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 20.83 |
| |
| $1,035,100 |
| |
| $— |
|
| | | | | | | | | |
| David D. Ellis | | Cash Balance Equalization Plan | | 1.06 |
| |
| $1,900 |
| |
| $— |
|
| | | Cash Balance Plan | | 1.06 |
| |
| $16,700 |
| |
| $— |
|
| | | | | | | | | |
| Haley R. Fisackerly | | System Executive Retirement Plan | | 24.08 |
| |
| $1,728,000 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 24.08 |
| |
| $1,023,900 |
| |
| $— |
|
| | | | | | | | | |
| Laura R. Landreaux | | Pension Equalization Plan | | 12.48 |
| |
| $86,300 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 12.48 |
| |
| $418,700 |
| |
| $— |
|
| | | | | | | | | |
| Andrew S. Marsh | | System Executive Retirement Plan | | 21.37 |
| |
| $4,694,700 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 21.37 |
| |
| $738,700 |
| |
| $— |
|
| | | | | | | | | |
Phillip R. May, Jr. (1) | | System Executive Retirement Plan | | 33.56 |
| |
| $2,964,100 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 33.56 |
| |
| $1,538,500 |
| |
| $— |
|
| | | | | | | | | |
Sallie T. Rainer (1)(3) | | System Executive Retirement Plan | | 35.38 |
| |
| $1,511,300 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 35.00 |
| |
| $1,766,400 |
| |
| $— |
|
| | | | | | | | | |
| Roderick K. West | | System Executive Retirement Plan | | 20.75 |
| |
| $5,892,400 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 20.75 |
| |
| $792,700 |
| |
| $— |
|
| |
(1) | As of December 31, 2019, Mr. Brown, Mr. Denault, Mr. May, and Ms. Rainer were retirement eligible. |
| |
(2) | In 2006, Mr. Denault entered into a 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 his Entergy employer grants him permission to retire. The additional 15 years of service increases the present value of his benefit by $3,887,900. |
| |
(3) | Service under the non-qualified System Executive Retirement Plan is granted from the date of hire. Service under the qualified Entergy Retirement Plan is granted from the later of the date of hire or the plan participation date. |
Retirement Benefits
The tables below contain summaries of the pension benefit plans sponsored by Entergy Corporation that the Named Executive OfficersNEOs participated in during 2019.2020. Benefits for the Named Executive OfficersNEOs who participate in these plans are determined using the same formulas as for other eligible employees.
Qualified Retirement Benefits
|
| | | | | | | | | | |
| Entergy Retirement Plan | Cash Balance Plan |
| Eligible Named Executive Officers | Marcus V. Brown
Haley R. Fisackerly
Leo P. Denault
Andrew S. Marsh
Laura R. Landreaux
| Phillip R. May, Jr.
Sallie T. Rainer
Roderick K. West
| A. Christopher Bakken, III
David D. Ellis
|
| Eligibility | Non-bargaining employees hired before July 1, 2014 | Non-bargaining employees hired on or after July 1, 2014 and before January 1, 2021. |
| 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 Internal Revenue 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%.
|
|
| | | | | | | | | | |
| Benefit Timing | Normal retirement age under the plan is 65.
A reduced terminated 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 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.
|
Non-qualified Retirement Benefits
The Named Executive OfficersNEOs are eligible to participate in certain non-qualified retirement benefit plans that provide retirement income, including the Pension Equalization Plan (“PEP”), the Cash Balance Equalization Plan, and the System Executive Retirement Plan.SERP. 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 may participate 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 PlanPEP and the System Executive Retirement PlanSERP 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.
|
| | | | | | | | | | | | | | | | |
| Pension Equalization Plan | Cash Balance Equalization Plan | System Executive Retirement Plan |
| Eligible Named Executive Officers | Marcus V. Brown
Haley R. Fisackerly
Leo P. Denault
Laura R. Landreaux
Andrew S. Marsh
| Phillip R. May, Jr.
Sallie T. Rainer
Roderick K. West
| A. Christopher Bakken, III
David D. Ellis
| Marcus V. Brown
Haley R. Fisackerly
Leo P. Denault
Andrew S. Marsh
| Phillip R. May, Jr.
Sallie T. Rainer
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 limitations of the Internal Revenue Code of 1986, as amended (the “Code”) 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. Executive annual incentive awards are taken into account as eligible earnings under this 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 the Code limitations on pension benefits and earnings that may be considered in calculating tax-qualified cash balance plan benefits, and the amount actually payable as a lump sum under the Cash Balance Plan. | 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 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 the Code Section 409A.
| Payable upon separation from service subject to 6 month delay required under the 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 Internal Revenue 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 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 Internal Revenue Code Section 409A. |
| |
(3) | The System Executive Retirement Plan was closed to new executive officers effective July 1, 2014. |
2019(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 accrued under the SERP, PEP, 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 Internal Revenue Code Section 409A.
(3)The SERP was closed to new executive officers effective July 1, 2014.
2020 Non-qualified Deferred Compensation
As of December 31, 2019,2020, Mr. May had a deferred account balance under a frozen Defined Contribution Restoration Plan. The amount is deemed invested, as chosen by Mr. May, in certain T. Rowe Price investment funds that are also available to the participant under the Savings Plan. Mr. May has elected to receive the deferred account balance after 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 2020 | | Registrant Contributions in 2020 | | Aggregate Earnings in 2020(1) | | Aggregate Withdrawals/Distributions | | Aggregate Balance at December 31, 2020 |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) |
| | | | | | | | | | | |
| Phillip R. May, Jr. | | $— | | | $— | | | $80 | | | $— | | | $3,067 | |
|
| | | | | | | | | | | | | | | | | | | | |
| Name | | Executive Contributions in 2019 | | Registrant Contributions in 2019 | | Aggregate Earnings in 2019(1) | | Aggregate Withdrawals/Distributions | | Aggregate Balance at December 31, 2019 |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) |
| | | | | | | | | | | |
| Phillip R. May, Jr. | |
| $— |
| |
| $— |
| |
| $805 |
| |
| $— |
| |
| $2,987 |
|
| |
(1) | Amounts in this column are not included in the Summary Compensation Table. |
2019
2020 Potential Payments Upon Termination or Change in Control
Entergy Corporation has plans and other arrangements that provide compensation to a Named Executive OfficerNEO if his or her employment terminates under specified conditions, including following a change in control of Entergy Corporation or its subsidiaries.
Change in Control
Under Entergy Corporation’s System Executive Continuity Plan (the “Continuity Plan”), ML 1-4 Officers are eligible to receive the severance benefits described below if their employment is terminated by their Entergy System employer other than for cause or if they terminate their employment for good reason during a period beginning with a potential change in control and ending 24 months following the effective date of a change in control (a “Qualifying Termination”). A participant will not be eligible for benefits under the Continuity Plan if such participant: 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 or violates his or her non-compete provision (which generally runs for two years but extends to three years if permissible under applicable law). Entergy Corporation does not have any plans or agreements that provide for payments or benefits to any of the Named Executive OfficersNEOs solely upon a change in control.
In the event of a Qualifying Termination, executive officers, including the Named Executive Officers,NEOs, generally will receive the benefits set forth below:
|
| | | | |
| Compensation Element | Payment |
| Severance* | A lump sum severance payment equal to a multiple of the sum of: (a) the participant’s 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 (b) the participant’s annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Planannual incentive program for the two calendar years immediately preceding the calendar year in which termination occurs. |
| Performance Units | Participants willUnder the 2015 EOP and the performance unit agreements in respect of the 2019 - 2021 performance period, participants would forfeit outstanding performance units, and in lieu of any payment for any outstanding performance period, willwould receive a single-lump sum payment calculated by multiplying the target performance units for the most recent performance period preceding (but not including) the calendar year in which termination occurs by the closing price of Entergy’s common stock as of the later of the date of such termination or the date of the Change in Control. Under the 2019 OIP and the performance unit agreements in respect of the 2020 - 2022 performance unit period, participants would receive a number of shares of Entergy common stock equal to the greater of (1) the target number of performance units subject to the performance unit agreement or (2) the number of units that would vest under the performance unit agreement calculated based on the performance of Entergy Corporation through the participant’s termination date, in either case pro-rated based on the portion of the performance period that occurs through the termination date. |
| Equity Awards | All unvested stock options, shares of restricted stock and restricted stock units will vest immediately upon a “double trigger” Qualifying Termination pursuant to the terms of the Equity Ownership Plan.2015 EOP and 2019 OIP. |
| Retirement Benefits | Benefits already accrued under the System Executive Retirement Plan, Pension Equalization PlanSERP, PEP and Cash Balance Equalization Plan, if any, will become fully vested. |
| Welfare Benefits | Participants who are not retirement-eligible would be eligible to receive Entergy-subsidized COBRA benefits for a period ranging from 12 to 18 months. |
| |
* | Cash severance payments are capped at 2.99 times the sum of (a) an executive’s annual base salary plus (b) the higher of his or her actual annual incentive payment under the Annual Incentive Plan or 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 termination occurs. Any cash severance payments to be paid under the Continuity Plan in excess of this cap will be forfeited by the participant. |
* Cash severance payments are capped at 2.99 times the sum of (a) an executive’s annual base salary plus (b) the higher of his or her actual annual incentive payment under the annual incentive program or his or her annual incentive, calculated using the average annual target opportunity derived under the annual incentive program for the two calendar years immediately preceding the calendar year in which termination occurs. Any cash severance payments to be paid under the Continuity Plan in excess of this cap will be forfeited by the participant.
To protect shareholders and Entergy Corporation’s business model, executives are required to comply with non-compete, non-solicitation, confidentiality and non-denigration provisions. If an executive discloses non-public data or information concerning Entergy Corporation or any of its subsidiaries or violates his or her non-compete provision, he or she will be required to repay any benefits previously received under the Continuity Plan.
For purposes of the Continuity Plan the following events are generally defined as:
| |
• | Change in Control: (a) the purchase of 30% or more of either Entergy Corporation’s common stock or the combined voting power of Entergy Corporation’s voting securities; (b) the merger or consolidation of Entergy Corporation (unless its Board members constitute at least a majority of the board members of the surviving entity); (c) the liquidation, dissolution or sale of all or substantially all of Entergy Corporation’s assets; or (d) 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 Entergy Corporation’s Board at the end of the period.
|
| |
• | Potential Change in Control: (a) Entergy Corporation or an affiliate enters into an agreement the consummation of which would constitute a Change in Control; (b) the Entergy Corporation Board adopts resolutions determining that, for purposes of the Continuity Plan, a potential Change in Control has occurred; (c) a System Company or other person or entity publicly announces an intention to take actions that would constitute a Change in Control; or (d) any person or entity becomes the beneficial owner (directly or indirectly) of Entergy Corporation’s outstanding shares of common stock constituting 20% or more of the voting power or value of the Entergy Corporation’s outstanding common stock.
|
•Change in Control: (a) the purchase of 30% or more of either Entergy Corporation’s common stock or the combined voting power of Entergy Corporation’s voting securities; (b) the merger or consolidation of Entergy Corporation (unless its Board members constitute at least a majority of the board members of the surviving entity); (c) the liquidation, dissolution or sale of all or substantially all of Entergy Corporation’s assets; or (d) 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 Entergy Corporation’s Board at the end of the period.
| |
• |
•Potential Change in Control: (a) Entergy Corporation or an affiliate enters into an agreement the consummation of which would constitute a Change in Control; (b) the Entergy Corporation Board adopts resolutions determining that, for purposes of the Continuity Plan, a potential Change in Control has occurred; (c) a System Company or other person or entity publicly announces an intention to take actions that would constitute a Change in Control; or (d) any person or entity becomes the beneficial owner (directly or indirectly)
of Entergy Corporation’s outstanding shares of common stock constituting 20% or more of the voting power or value of the Entergy Corporation’s outstanding common stock.
•Cause: The participant’s (a) willful and continuous failure to perform substantially his or her duties after written demand for performance; (b) engagement in conduct that is materially injurious to Entergy Corporation or any of its subsidiaries; (c) conviction or guilty or nolo contendere plea to a felony or other crime that materially and adversely affects either his or her ability to perform his or her duties or Entergy Corporation’s reputation; (d) material violation of any agreement with Entergy Corporation or any of its subsidiaries; or (e) disclosure of any of Entergy Corporation’s confidential information without authorization.
•The participant’s (a) willful and continuous failure to perform substantially his or her duties after written demand for performance; (b) engagement in conduct that is materially injurious to Entergy Corporation or any of its subsidiaries; (c) conviction or guilty or nolo contendere plea to a felony or other crime that materially and adversely affects either his or her ability to perform his or her duties or Entergy Corporation’s reputation; (d) material violation of any agreement with Entergy Corporation or any of its subsidiaries; or (e) disclosure of any of Entergy Corporation’s confidential information without authorization. |
| |
• | Good Reason: The participant’s (a) nature or status of duties and responsibilities is substantially altered or reduced; (b) salary is reduced by 5% or more; (c) primary work location is relocated outside the continental United States; (d) compensation plans are discontinued without an equitable replacement; (e) benefits or number of vacation days are substantially reduced; or (f) employment is terminated by an Entergy employer for reasons other than in accordance with the Continuity Plan. |
Other Termination Events
For termination events, other than in connection with a Change in Control, the executive officers, including the Named Executive Officers,NEOs, generally will receive the benefits set forth below:
|
| | | | | | | | | | | | | | | | |
| Termination Event | Compensation Element |
| Severance | Annual Incentive | Stock Options | Restricted Stock | Performance Units |
| Voluntary Resignation | None | Forfeited* | Unvested options are forfeited. Vested options expire on the earlier of (i) 90 days from the last day of active employment and (ii) the option’s normal expiration date. | Forfeited | Forfeited** |
| Termination for Cause | None | Forfeited | Forfeited | Forfeited | Forfeited |
| Retirement | None | Pro-rated based on number of days employed during the performance period
| Unvested stock options granted prior to 2020 vest on the retirement date and expire on the earlier of (i) five years from the Retirement retirement date and (ii) the option’s normal expiration date.
Unvested stock options granted in 2020 continue to vest following retirement, in accordance with the original vesting schedule and expire the earlier of (i) five years from the retirement date and (ii) the option’s normal expiration date. | Forfeited | Officers with a minimum of 12 months of participation are eligible for a pro-rated award based on actual performance and full months of service during the performance period |
| Death/Disability | None | Pro-rated based on number of days employed during the performance period
| Unvested stock options vest on the termination date and expire on the earlier of (i) five years from the termination date and (ii) the option’s normal expiration date
| Fully Vest | Officers are eligible for pro-rated award based on actual performance and full months of service during the performance period |
| |
* | If an officer resigns after the completion of an annual incentive plan, he or she may receive, at the Company’s discretion, an annual incentive payment. |
| |
** | If an officer resigns after the completion of a Long-Term Performance Unit Program performance period, he or she may receive a payout under the Long-Term Performance Unit Program based on the outcome of the performance period. |
* If an officer resigns after the completion of an annual incentive plan, he or she may receive, at Entergy Corporation’s discretion, an annual incentive payment.
** If an officer resigns after the completion of a LTIP performance period, he or she may receive a payout under the LTIP based on the outcome of the performance period.
Mr. Denault’s 2006 Retention Agreement
In 2006, Entergy Corporation entered into a retention agreement with Mr. Denault that provides benefits to him in addition to, or in lieu of, the benefits described above. Specifically, in the event of a Termination Event (as defined in his agreement): 1) Mr. Denault is entitled to a Target LTIP Award 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; and 2) all of Mr. Denault’s unvested stock options and shares of restricted stock will immediately vest.
In the event of death or disability, Mr. Denault would receive the greater of the Target LTIP Award calculated as described above or the 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.
Under the terms of his 2006 retention agreement, Mr. Denault’s employment may be terminated for cause upon Mr. Denault’s: (a) 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; (b) willfully engaging in conduct that is demonstrably and materially injurious to Entergy; (c) 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’s reputation; (d) material violation of any agreement that he has entered into with Entergy; or (e) unauthorized disclosure of Entergy’s confidential information.
Mr. Denault may terminate his employment for good reason upon: (a) 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; (b) a reduction of 5% or more in his base salary as in effect on the date of the retention agreement; (c) the relocation of his principal place of employment to a location other than the corporate headquarters; (d) the failure to continue to allow him to participate in programs or plans providing opportunities for equity awards, incentive compensation 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); (e) 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 under any of the 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 (f) any purported termination of his employment not taken in accordance with his retention agreement.
Aggregate Termination Payments
The tables below reflect the amount of compensation each of the Named Executive OfficersNEOs would have received if his or her employment had been terminated as of December 31, 20192020 under the various scenarios described above. For purposes of these tables, a stock price of $119.80$99.84 was used, which was the closing market price of Entergy Corporation stock on December 31, 2019,2020, the last trading day of the year.
| | | 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 | 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) | | | A. Christopher Bakken, III(1) | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $3,335,798 |
| Severance Payment | — | | — | | — | | — | | — | | — | | $3,435,870 | |
Performance Units(3) | — |
| — |
| — |
| — |
|
| $1,013,149 |
|
| $1,013,149 |
|
| $1,964,720 |
| Performance Units(3) | — | | — | | — | | — | | $895,065 | | $895,065 | | $1,086,858 | |
| Stock Options | — |
| — |
| — |
| — |
|
| $2,858,837 |
|
| $2,858,837 |
|
| $2,858,837 |
| Stock Options | — | | — | | — | | — | | $552,353 | | $552,353 | | $552,353 | |
| Restricted Stock | — |
| — |
| — |
| — |
|
| $1,113,669 |
|
| $1,113,669 |
|
| $1,113,669 |
| Restricted Stock | — | | — | | — | | — | | $764,339 | | $764,339 | | $764,339 | |
Welfare Benefits(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $22,248 |
| Welfare Benefits(5) | — | | — | | — | | — | | — | | — | | $22,248 | |
Unvested Restricted Stock Units(7) | — |
| — |
| — |
| — |
| — |
| — |
|
| $2,369,000 |
| Unvested Restricted Stock Units(7) | — | | — | | — | | — | | — | | — | | $1,996,800 | |
| | | | |
Marcus V. Brown(2) | | | Marcus V. Brown(2) | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $3,397,875 |
| Severance Payment | — | | — | | — | | — | | — | | — | | $3,570,750 | |
Performance Units(3) | — |
| — |
| — |
|
| $1,005,721 |
|
| $1,005,721 |
|
| $1,005,721 |
|
| $1,964,720 |
| Performance Units(3) | — | | — | | — | | $876,595 | | $876,595 | | $876,595 | | $1,080,668 | |
| Stock Options | — |
| — |
| — |
|
| $2,942,442 |
|
| $2,942,442 |
|
| $2,942,442 |
|
| $2,942,442 |
| Stock Options | — | | — | | — | | $547,368 | | $547,368 | | $547,368 | | $547,368 | |
| Restricted Stock | — |
| — |
| — |
| — |
|
| $1,145,708 |
|
| $1,145,708 |
|
| $1,145,708 |
| Restricted Stock | — | | — | | — | | — | | $751,664 | | $751,664 | | $751,664 | |
Welfare Benefits(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| Welfare Benefits(6) | — | | — | | — | | — | | — | | — | | — | |
| | | | |
Leo P. Denault(2) | | | Leo P. Denault(2) | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $9,870,588 |
| Severance Payment | — | | — | | — | | — | | — | | — | | $10,993,273 | |
Performance Units(3)(4) | — |
| — |
|
| $4,480,520 |
|
| $5,028,006 |
|
| $5,028,006 |
|
| $5,028,006 |
|
| $9,991,320 |
| Performance Units(3)(4) | — | | — | | $4,512,768 | | $3,736,712 | | $4,512,768 | | $4,512,768 | | $5,902,641 | |
| Stock Options | — |
| — |
|
| $12,314,200 |
|
| $12,314,200 |
|
| $12,314,200 |
|
| $12,314,200 |
|
| $12,314,200 |
| Stock Options | — | | — | | $2,306,895 | | $2,306,895 | | $2,306,895 | | $2,306,895 | | $2,306,895 | |
| Restricted Stock | — |
| — |
|
| $4,015,803 |
| — |
|
| $4,015,803 |
|
| $4,015,803 |
|
| $4,015,803 |
| Restricted Stock | — | | — | | $2,966,300 | | — | | $2,966,300 | | $2,966,300 | | $2,966,300 | |
Welfare Benefits(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| Welfare Benefits(6) | — | | — | | — | | — | | — | | — | | — | |
| | | | |
David D. Ellis(1) | | | David D. Ellis(1) | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $376,065 |
| Severance Payment | — | | — | | — | | — | | — | | — | | $386,219 | |
Performance Units(3) | — |
| — |
| — |
| — |
|
| $145,916 |
|
| $145,916 |
|
| $431,280 |
| Performance Units(3) | — | | — | | — | | — | | $128,194 | | $128,194 | | $216,353 | |
| Stock Options | — |
| — |
| — |
| — |
|
| $143,867 |
|
| $143,867 |
|
| $143,867 |
| Stock Options | — | | — | | — | | — | | $33,377 | | $33,377 | | $33,377 | |
| Restricted Stock | — |
| — |
| — |
| — |
|
| $62,022 |
|
| $62,022 |
|
| $62,022 |
| Restricted Stock | — | | — | | — | | — | | $87,425 | | $87,425 | | $87,425 | |
Welfare Benefits(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $19,908 |
| Welfare Benefits(5) | — | | — | | — | | — | | — | | — | | $19,908 | |
| | | | |
Haley R. Fisackerly(1) | | | |
Haley R. Fisackerly(2) | | Haley R. Fisackerly(2) | |
| Severance Payment | | Severance Payment | — | | — | | — | | — | | — | | — | | $543,541 | |
Performance Units(3) | | Performance Units(3) | — | | — | | — | | 128,194 | | $128,194 | | $128,194 | | $216,353 | |
| Stock Options | | Stock Options | — | | — | | — | | 91,899 | | $91,899 | | $91,899 | | $91,899 | |
| Restricted Stock | | Restricted Stock | — | | — | | — | | 150,174 | | $150,174 | | $150,174 | | $150,174 | |
Welfare Benefits(6) | | Welfare Benefits(6) | — | | — | | — | | — | | — | | — | | — | |
| Laura R. Landreaux(1) | | Laura R. Landreaux(1) | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $526,432 |
| Severance Payment | — | | — | | — | | — | | — | | — | | $457,457 | |
Performance Units(3) | — |
| — |
| — |
| — |
|
| $189,763 |
|
| $189,763 |
|
| $431,280 |
| Performance Units(3) | — | | — | | — | | — | | $128,194 | | $128,194 | | $216,353 | |
| Stock Options | — |
| — |
| — |
| — |
|
| $498,200 |
|
| $498,200 |
|
| $498,200 |
| Stock Options | — | | — | | — | | — | | $36,210 | | $36,210 | | $36,210 | |
| Restricted Stock | — |
| — |
| — |
| — |
|
| $182,045 |
|
| $182,045 |
|
| $182,045 |
| Restricted Stock | — | | — | | — | | — | | $157,978 | | $157,978 | | $157,978 | |
Welfare Benefits(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $19,908 |
| Welfare Benefits(5) | — | | — | | — | | — | | — | | — | | $19,908 | |
| | | | |
Laura R. Landreaux(1) | | | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $419,322 |
| |
Performance Units(3)(4) | — |
| — |
| — |
| — |
|
| $167,840 |
|
| $167,840 |
|
| $431,280 |
| |
| Stock Options | — |
| — |
| — |
| — |
|
| $156,111 |
|
| $156,111 |
|
| $156,111 |
| |
| Restricted Stock | — |
| — |
| — |
| — |
|
| $233,335 |
|
| $233,335 |
|
| $233,335 |
| |
Welfare Benefits(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $19,908 |
| |
| | | 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 | 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 |
Andrew S. Marsh(1) | | | Andrew S. Marsh(1) | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $3,315,000 |
| Severance Payment | — | | — | | — | | — | | — | | — | | $3,622,500 | |
Performance Units(3) | — |
| — |
| — |
| — |
|
| $1,105,035 |
|
| $1,105,035 |
|
| $1,964,720 |
| Performance Units(3) | — | | — | | — | | — | | $1,108,224 | | $1,108,224 | | $1,146,862 | |
| Stock Options | — |
| — |
| — |
| — |
|
| $3,468,531 |
|
| $3,468,531 |
|
| $3,468,531 |
| Stock Options | — | | — | | — | | — | | $676,227 | | $676,227 | | $676,227 | |
| Restricted Stock | — |
| — |
| — |
| — |
|
| $1,279,045 |
|
| $1,279,045 |
|
| $1,279,045 |
| Restricted Stock | — | | — | | — | | — | | $908,105 | | $908,105 | | $908,105 | |
Welfare Benefits(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $29,862 |
| Welfare Benefits(5) | — | | — | | — | | — | | — | | — | | $29,862 | |
Unvested Restricted Stock Units(8) | — |
| — |
| — |
| — |
|
| $2,527,780 |
|
| $2,527,780 |
|
| $2,527,780 |
| |
| | | | |
Phillip R. May, Jr.(2) | | | Phillip R. May, Jr.(2) | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $1,254,536 |
| Severance Payment | — | | — | | — | | — | | — | | — | | $1,295,309 | |
Performance Units(3) | — |
| — |
| — |
|
| $289,557 |
|
| $289,557 |
|
| $289,557 |
|
| $646,920 |
| Performance Units(3) | — | | — | | — | | $189,796 | | $189,796 | | $189,796 | | $361,121 | |
| Stock Options | — |
| — |
| — |
|
| $732,470 |
|
| $732,470 |
|
| $732,470 |
|
| $732,470 |
| Stock Options | — | | — | | — | | $137,838 | | $137,838 | | $137,838 | | $137,838 | |
| Restricted Stock | — |
| — |
| — |
| — |
|
| $247,721 |
|
| $247,721 |
|
| $247,721 |
| Restricted Stock | — | | — | | — | | — | | $215,243 | | $215,243 | | $215,243 | |
Welfare Benefits(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| Welfare Benefits(6) | — | | — | | — | | — | | — | | — | | — | |
| | | | |
Sallie T. Rainer(2) | | | Sallie T. Rainer(2) | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $486,390 |
| Severance Payment | — | | — | | — | | — | | — | | — | | $502,198 | |
Performance Units(3) | — |
| — |
| — |
|
| $189,763 |
|
| $189,763 |
|
| $189,763 |
|
| $431,280 |
| Performance Units(3) | — | | — | | — | | $128,194 | | $128,194 | | $128,194 | | $216,353 | |
| Stock Options | — |
| — |
| — |
|
| $501,452 |
|
| $501,452 |
|
| $501,452 |
|
| $501,452 |
| Stock Options | — | | — | | — | | $91,899 | | $91,899 | | $91,899 | | $91,899 | |
| Restricted Stock | — |
| — |
| — |
| — |
|
| $184,210 |
|
| $184,210 |
|
| $184,210 |
| Restricted Stock | — | | — | | — | | — | | $150,174 | | $150,174 | | $150,174 | |
Welfare Benefits(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| Welfare Benefits(6) | — | | — | | — | | — | | — | | — | | — | |
| | | | |
Roderick K. West(1) | | | Roderick K. West(1) | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $3,641,466 |
| Severance Payment | — | | — | | — | | — | | — | | — | | $3,732,501 | |
Performance Units(3) | — |
| — |
| — |
| — |
|
| $1,033,275 |
|
| $1,033,275 |
|
| $1,964,720 |
| Performance Units(3) | — | | — | | — | | — | | $950,177 | | $950,177 | | $1,108,324 | |
| Stock Options | — |
| — |
| — |
| — |
|
| $2,835,460 |
|
| $2,835,460 |
|
| $2,835,460 |
| Stock Options | — | | — | | — | | — | | $580,531 | | $580,531 | | $580,531 | |
| Restricted Stock | — |
| — |
| — |
| — |
|
| $1,064,329 |
|
| $1,064,329 |
|
| $1,064,329 |
| Restricted Stock | — | | — | | — | | — | | $811,984 | | $811,984 | | $811,984 | |
Welfare Benefits(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $29,862 |
| Welfare Benefits(5) | — | | — | | — | | — | | — | | — | | $29,862 | |
| |
1) | See “2019 Pension Benefits” for a description of the pension benefits Mr. Bakken, Mr. Ellis, Mr. Fisackerly, Ms. Landreaux, Mr. Marsh, and Mr. West may receive upon the occurrence of certain termination events. |
1)See “2020 Pension Benefits” for a description of the pension benefits Mr. Bakken, Mr. Ellis, Ms. Landreaux, Mr. Marsh, and Mr. West may receive upon the occurrence of certain termination events.
| |
2) | As of December 31, 2019, Mr. Brown, Mr. Denault, Mr. May, and Ms. Rainer are retirement eligible and would retire rather than voluntarily resign, and in addition to the payments and benefits in the table, Mr. Brown, Mr. Denault, Mr. May, and Ms. Rainer also would be entitled to receive their vested pension benefits under the Entergy Retirement Plan. For a description of these benefits, see “2019 Pension Benefits.” |
2)As of December 31, 2020, Mr. Brown, Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rainer are retirement eligible and would retire rather than voluntarily resign, and in addition to the payments and benefits in the table, Mr. Brown, Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rainer also would be entitled to receive their vested pension benefits under the Entergy Retirement Plan. For a description of these benefits, see “2020 Pension Benefits.”
| |
3) | 3)For purposes of the table, the table, in the event of a qualifying termination related to a change in control, each NEO would receive a payment in respect of his performance units for the 2019 – 2021 performance period and a number of performance units for the 2020 – 2022 performance period, calculated as follows.
For the 2019 – 2021 performance period, each NEO would be entitled to receive a single-lump sum payment calculated using the target number of performance units that the officer would have been entitled to receive under the 2015 EOP with respect to the most recent performance period that precedes and does not include the officer’s date of termination. The value of Mr. Denault’s payments was calculated by multiplying the target performance units for the 2017 – 2019 LTIP performance period (48,700) by multiplying the target performance units for the 2016-2018 Performance Unit Program (41,700) by the closing price of Entergy stock on December 31, 2019 ($119.80), which would equal a payment of $4,995,660 for the forfeited performance units for each performance period. The value of Mr. Bakken’s, Mr. Brown’s, Mr. Marsh’s, and Mr. West’s payments was calculated by multiplying the target performance units for the 2016-2018 Performance Unit Program (8,200) by the closing price of Entergy stock on December 31, 2019 ($119.80), which would equal a payment of $982,360 for the forfeited performance units for each performance period. The value of Mr. May’s payment was calculated by multiplying the target performance units for the 2016-2018 Performance Unit Program (2,700) by the closing price of Entergy stock on December 31, 2019 ($119.80), which would equal a payment of $323,460 for the forfeited performance units for each performance period. The value of the payments for the other Named Executives Officers was calculated by multiplying the target performance units for the 2016-2018 Performance Unit Program (1,800) by |
the closing price of Entergy Corporation stock on December 31, 20192020 ($119.80)99.84), which would equal a payment of $215,640$4,862,208 for the forfeited performance units for eachthe 2019 – 2021 performance period. The value of Mr. Bakken’s, Mr. Brown’s,
Mr. Marsh’s, and Mr. West’s was calculated by multiplying the target performance units for the 2017 – 2019 LTIP performance period (8,300) by the closing price of Entergy Corporation stock on December 31, 2020 ($99.84), which would equal a payment of $828,672 for the forfeited performance units for the 2019 – 2021 performance period. The value of Mr. May’s payment was calculated by multiplying the target performance units for the 2017 – 2019 LTIP performance period (3,150) by the closing price of Entergy Corporation stock on December 31, 2020 ($99.84), which would equal a payment of $314,496 for the forfeited performance units for the 2019 – 2021 performance period. The value of the payments for the other NEOs was calculated by multiplying the target performance units for the 2017 – 2019 LTIP performance period (1,850) by the closing price of Entergy Corporation stock on December 31, 2020 ($99.84), which would equal a payment of $184,704 for the forfeited performance units for the 2019 – 2021 performance period.
For the 2020 – 2022 performance period, in the event of a qualifying termination related to a change in control, each NEO would be entitled to receive a number of shares of Entergy Corporation stock equal to the greater of (1) the target number of performance units subject to the 2020 – 2022 performance unit agreement or (2) the number of performance units that would vest under the 2020 – 2022 performance unit agreement calculated based on Entergy Corporation’s actual performance through the NEO’s termination date, in either case pro-rated based on the portion of the performance period that occurs through the termination date. For purposes of the table, the values of the performance unit awards for the 2020 – 2022 performance period for each NEO were calculated as follows, based on the assumption that the target number of performance units was the greater number:
Mr. Bakken: 2,586 (12/36*7,758) performance units at target, assuming a stock price of $99.84 = $258,186
Mr. Brown: 2,524 (12/36*7,571) performance units at target, assuming a stock price of $99.84 = $251,996
Mr. Denault: 10,421 (12/36*31,263) performance units at target, assuming a stock price of $99.84 = $1,040,433
Mr. Ellis: 317 (12/36*950) performance units at target, assuming a stock price of $99.84 = $31,649
Mr. Fisackerly: 317 (12/36*950) performance units at target, assuming a stock price of $99.84 = $31,649
Ms. Landreaux: 317 (12/36*950) performance units at target, assuming a stock price of $99.84 = $31,649
Mr. May: 467 (12/36*1,400) performance units at target, assuming a stock price of $99.84 = $46,625
Mr. Marsh: 3,187 (12/36*9,560) performance units at target, assuming a stock price of $99.84 = $318,190
Ms. Rainer: 317 (12/36*950) performance units at target, assuming a stock price of $99.84 = $31,649
Mr. West: 2,801 (12/36*8,401) performance units at target, assuming a stock price of $99.84 = $279,652
The total values of the single sum payment for the 2019 – 2021 performance period and the performance units award for the 2020 – 2022 performance period upon a change in control for each NEO is as follows:
Mr. Bakken: $828,672 + $258,186 = $1,086,858
Mr. Brown: $828,672 + $251,996 = $1,080,668
Mr. Denault: $4,862,208 + $1,040,433 = $5,902,641
Mr. Ellis: $184,704 + $31,649 = $216,353
Mr. Fisackerly: $184,704 + $31,649 = $216,353
Ms. Landreaux: $184,704 + $31,649 = $216,353
Mr. May: $314,496 + $46,625 = $361,121
Mr. Marsh: $828,672 + $318,190 = $1,146,862
Ms. Rainer: $184,704 + $31,649 = $216,353
Mr. West: $828,672 + $279,652 = $1,108,324
For purposes of the table, the values of the awards payable in the event of retirement in the case of Mr. Denault, Mr. Brown, Mr. Denault,Fisackerly, Mr. May, or Ms. Rainer or upon death or disability, other than Mr. Denault, for each Named Executive OfficerNEO were calculated as follows:
Mr. Denault’s:Bakken’s:
2018-2020
2019 – 2021 LTIP Performance Period: 28,4676,379 (24/36 × 42,700)36*9,568) performance units at target, assuming a stock price of $119.80$99.84 = $636,879
2019-20212020 – 2022 LTIP Performance Period: 13,5032,586 (12/36 × 36*7,758) performance units at target, assuming a stock price of $99.84 = $258,186
Total: $895,065
Mr. Brown’s:
2019 – 2021 LTIP Performance Period: 6,256 (24/36*9,383) performance units at target, assuming a stock price of $99.84 = $$624,599
2020 – 2022 LTIP Performance Period: 2,524 (12/36*7,571) performance units at target, assuming a stock price of $99.84 = $251,996
Total: $876,595
Mr. Denault’s:
2019 – 2021 LTIP Performance Period: 27,006 (24/36*40,508) performance units at target, assuming a stock price of $119.80$99.84 = $2,696,279
Mr. Bakken’s:
2018-20202020 – 2022 LTIP Performance Period: 5,267 (24/36 × 7,900)10,421 (12/36*31,263) performance units at target, assuming a stock price of $119.80$99.84 = $1,040,433
2019-2021 Performance Period: 3,190 (12/36 × 9,568) performance units at target, assuming a stock price of $119.80Total: $3,736,712
Mr. Brown’s:
2018-2020 Performance Period: 5,267 (24/36 × 7,900) performance units at target, assuming a stock price of $119.80
2019-2021 Performance Period: 3,128 (12/36 ×9,383) performance units at target, assuming a stock price of $119.80
Mr. Marsh’s:
2018-2020
2019 – 2021 LTIP Performance Period: 5,2677,913 (24/36 × 7,900) performance units at target, assuming a stock price of $119.80
2019-2021 Performance Period: 3,957 (12/36 × 36*11,869) performance units at target, assuming a stock price of $119.80$99.84 = $790,034
Mr. West’s:
2018-20202020 – 2022 LTIP Performance Period: 5,267 (24/36 × 7,900)3,187 (12/36*9,560) performance units at target, assuming a stock price of $119.80$99.84 = $318,190
2019-2021Total: $1,108,224
Mr. May’s:
2019 – 2021 LTIP Performance Period: 3,3581,434 (24/36*2,150) performance units at target, assuming a stock price of $99.84 = $143,171
2020 – 2022 LTIP Performance Period: 467 (12/36 × 36*1,400) performance units at target, assuming a stock price of $99.84 = $46,625
Total: $189,796
Mr. Ellis’s, Mr. Fisackerly’s, Ms. Landreaux’s and Ms. Rainer’s:
2019 – 2021 LTIP Performance Period: 967 (24/36*1,450) performance units at target, assuming a stock price of $99.84 = $96,545
2020 – 2022 LTIP Performance Period: 317 (12/36*950) performance units at target, assuming a stock price of $99.84 = $31,649
Total: $128,194
Mr. West’s:
2019 – 2021 LTIP Performance Period: 6,716 (24/36*10,073) performance units at target, assuming a stock price of $119.80$99.84 = $670,525
Mr. May’s:
2018-20202020 – 2022 LTIP Performance Period: 1,700 (24/36 × 2,550)2,801 (12/36*8,401) performance units at target, assuming a stock price of $119.80$99.84 = $279,652
2019-2021 Performance Period: 717 (12/36 × 2,150)Total: $950,177
4)For purposes of the table, the value of Mr. Denault’s retention payment was calculated by taking an average of the target performance units at target, assuming a stockfrom the 2016 - 2018 LTIP (41,700) and from the 2017 - 2019 LTIP (48,700). This average number of units (45,200) multiplied by the closing price of $119.80Entergy stock on December 31, 2020 ($99.84) would equal a payment of $4,512,768.
5)Pursuant to the SERP, in the event of a termination related to a change in control, Mr. Fisackerly’sBakken, Mr. Marsh, and Mr. West would be eligible to receive Entergy-subsidized COBRA benefits for 18 months and Mr. Ellis and Ms. Rainer’s:Landreaux would be eligible to receive Entergy-subsidized COBRA benefits for 12 months.
2018-2020 Performance Period: 1,100 (24/36 × 1,650) performance
6)Upon retirement, Mr. Brown, Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rainer would be eligible for retiree medical and dental benefits, the same as all other retirees.
7)Mr. Bakken’s 20,000 restricted stock units at target, assumingvest in two equal installments on April 6, 2022 and April 6, 2025. In the event of a change in control, the unvested restricted stock priceunits will fully vest upon Mr. Bakken’s Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Bakken is subject to certain restrictions on his ability to compete with Entergy 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 and its affiliates. In the event of $119.80a 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 any shares of Entergy 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.
2019-2021 Performance Period: 484 (12/36 × 1,450) performance units at target, assuming a stock price of $119.80
Ms. Landreaux’s:
2018-2020 Performance Period: 917 (24/36 × 1,375) performance units at target, assuming a stock price of $119.80
2019-2021 Performance Period: 484 (12/36 × 1,450) performance units at target, assuming a stock price of $119.80
Mr. Ellis’s:
2018-2020 Performance Period: 734 (24/36 × 1,100) performance units at target, assuming a stock price of $119.80
2019-2021 Performance Period: 484 (12/36 × 1,450) performance units at target, assuming a stock price of $119.80
| |
4) | 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 2015-2017 Performance Unit Program (33,100) and from the 2016-2018 Performance Unit Program (41,700). This average number of units (37,400) multiplied by the closing price of Entergy stock on December 31, 2019 ($119.80) would equal a payment of $4,480,520. |
| |
5) | Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Bakken, Mr. Marsh, and Mr. West would be eligible to receive Entergy-subsidized COBRA benefits for 18 months and Mr. Ellis, Mr. Fisackerly, and Ms. Landreaux would be eligible to receive Entergy-subsidized COBRA benefits for 12 months. |
| |
6) | Upon retirement, Mr. Brown, Mr. Denault, Mr. May, and Ms. Rainer would be eligible for retiree medical and dental benefits, the same as all other retirees. |
| |
7) | Mr. Bakken’s 20,000 restricted stock units vest in two equal installments on April 6, 2022 and April 6, 2025. In the event of a change in control, the unvested restricted stock units will fully vest upon Mr. Bakken’s Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Bakken is subject to certain restrictions on his ability to compete with Entergy 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 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 any shares of Entergy 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. |
| |
8) | 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 or a Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Marsh is subject to certain restrictions on his ability to compete with Entergy and its affiliates during and for 12 months after his employment with Entergy, or to solicit its employees or customers during and for 24 months after his employment with Entergy. In addition, the restricted stock unit agreement limits Mr. Marsh’s ability to disparage Entergy 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 any shares of Entergy 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. |
Pay Ratio
As required by Section 953(b) of the 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. The pay ratio estimate for each of the Utility operating companies has been calculated in a manner consistent with Item 402(u) of Regulation S-K.
Identification of Median Employee
For each of the Utility operating companies, October 4, 20192, 2020 was selected as the date on which to determine the median employee. This date is different from the date used in the prior year; however, the methodology used to determine
the date is consistent with that used in the prior year. Both dates correspond to the first day of the three month period prior to fiscal year-end for which information can be obtained about employees and all subsidiaries have the same number of pay cycles. 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 isto be 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 median employee for each Utility operating company is the same calculation used to determine total compensation for purposes of the 20192020 Summary Compensation Table with respect to each of the Named Executive Officers.NEOs.
Entergy Arkansas Ratio
For 2019,2020,
| |
• | •The median of the annual total compensation of all of EntergyArkansas’semployees, other than Ms. Landreaux, was $135,370. •Arkansas’semployees, other than Ms. Landreaux, was $230,966. |
Ms. Landreaux’s annual total compensation, as reported in the Total column of the 20192020 Summary Compensation Table was $1,064,459.$1,150,511.
•Based on this information, the ratio of the annual total compensation of Mrs. Landreaux to the median of the annual total compensation of all employees is estimated to be 5:8:1.
Entergy Louisiana Ratio
For 2019,2020,
•The median of the annual total compensation of all of Entergy Louisiana’s employees, other than Mr. May, was $173,745.$131,155.
•Mr. May’s annual total compensation, as reported in the Total column of the 20192020 Summary Compensation Table, was $2,073,894.$2,257,961.
•Based on this information, the ratio of the annual total compensation of Mr. May to the median of the annual total compensation of all employees is estimated to be 12:17:1.
Entergy Mississippi Ratio
For 2019,2020,
•The median of the annual total compensation of all of Entergy Mississippi’s employees, other than Mr. Fisackerly, was $254,843.$111,238.
•Mr. Fisackerly’s annual total compensation, as reported in the Total column of the 20192020 Summary Compensation Table, was $1,579,844.$1,803,939.
•Based on this information, the ratio of the annual total compensation of Mr. Fisackerly to the median of the annual total compensation of all employees is estimated to be 6:16:1.
Entergy New Orleans Ratio
For 2019,2020,
| |
• | •The median of the annual total compensation of all of EntergyNew Orleans’semployees, other than Mr. Ellis, was $150,102. •New Orleans’semployees, other than Mr. Ellis, was $145,217. |
Mr. Ellis’s annual total compensation, as reported in the Total column of the 20192020 Summary Compensation Table was $732,040.$804,810.
•Based on this information, the ratio of the annual total compensation of Mr. Ellis to the median of the annual total compensation of all employees is estimated to be 5:1.
Entergy Texas Ratio
For 2019,2020,
•The median of the annual total compensation of all of Entergy Texas’s employees, other than Ms. Rainer, was $233,988.$160,680.
•Ms. Rainer’s annual total compensation, as reported in the Total column of the 20192020 Summary Compensation Table, was $1,467,716.$1,543,383.
•Based on this information, the ratio of the annual total compensation of Ms. Rainer to the median of the annual total compensation of all employees is estimated to be 6:10:1.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Entergy Corporation owns 100% of the outstanding common stock of registrant Entergy Texas and indirectly 100% of the outstanding common membership interests of registrants Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New 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 “Entergy Share Ownership - Beneficial Owners of More Than Five Percent of Entergy Common Stock” in the Entergy Corporation 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 stock of Entergy Corporation and stock-based units as of January 31, 20202021 for all directors and Named Executive Officers.NEOs. Unless otherwise noted, each person had sole voting and investment power over the number of shares of common stock and stock-based units of Entergy Corporation set forth across from his or her name.
| | | Name | | Shares (1)(2) | | Options Exercisable Within 60 Days | | Stock Units (3) | Name | | Shares (1)(2) | | Options Exercisable Within 60 Days | | Stock Units (3) |
| Entergy Corporation | | | | | | | Entergy Corporation | | | | | | |
| A. Christopher Bakken, III** | | 38,397 |
| | 38,174 |
| | — |
| A. Christopher Bakken, III** | | 18,115 | | | 35,399 | | | — | |
| Marcus V. Brown** | | 44,758 |
| | 40,075 |
| | — |
| Marcus V. Brown** | | 38,813 | | | 34,930 | | | — | |
| John R. Burbank* | | 2,417 |
| | — |
| | — |
| John R. Burbank* | | 3,353 | | | — | | | 563 | |
| Patrick J. Condon* | | 7,834 |
| | — |
| | — |
| Patrick J. Condon* | | 9,333 | | | — | | | — | |
| Leo P. Denault*** | | 265,416 |
| | 753,202 |
| | — |
| Leo P. Denault*** | | 324,528 | | | 899,634 | | | — | |
| Kirkland H. Donald* | | 7,721 |
| | — |
| | 2,949 |
| Kirkland H. Donald* | | 8,590 | | | — | | | 3,668 | |
| Brian W. Ellis* | | Brian W. Ellis* | | 64 | | |
| Philip L. Frederickson* | | 6,284 |
| | — |
| | 805 |
| Philip L. Frederickson* | | 7,889 | | | — | | | 805 | |
| Alexis M. Herman* | | 14,506 |
| | — |
| | — |
| Alexis M. Herman* | | 14,780 | | | — | | | — | |
| M. Elise Hyland* | | 727 |
| | | | | M. Elise Hyland* | | 1,663 | | | 563 |
| Stuart L. Levenick* | | 21,421 |
| | — |
| | — |
| Stuart L. Levenick* | | 22,920 | | | — | | | — | |
| Blanche L. Lincoln* | | 14,879 |
| | — |
| | — |
| Blanche L. Lincoln* | | 16,654 | | | — | | | — | |
| Andrew S. Marsh** | | 86,740 |
| | 241,726 |
| | — |
| Andrew S. Marsh** | | 90,482 | | | 281,147 | | | — | |
| Karen A. Puckett* | | 7,834 |
| | — |
| | — |
| Karen A. Puckett* | | 9,333 | | | — | | | — | |
| Roderick K. West** | | 64,999 |
| | 97,249 |
| | — |
| Roderick K. West** | | 33,757 | | | 37,517 | | | — | |
| All directors and executive officers as a group (19 persons) | | 656,574 |
| | 1,273,794 |
| | 3,754 |
| |
| All directors and executive officers as a group (20 persons) | | All directors and executive officers as a group (20 persons) | | 680,178 | | | 1,429,697 | | | 5,599 | |
| | | | | | | | |
| Entergy Arkansas | | |
| | |
| | |
| Entergy Arkansas | | | | | | |
| A. Christopher Bakken, III** | | 38,397 |
| | 38,174 |
| | — |
| A. Christopher Bakken, III** | | 18,115 | | | 35,399 | | | — | |
| Marcus V. Brown** | | 44,758 |
| | 40,075 |
| | — |
| Marcus V. Brown** | | 38,813 | | | 34,930 | | | — | |
| Leo P. Denault** | | 265,416 |
| | 753,202 |
| | — |
| Leo P. Denault** | | 324,528 | | | 899,634 | | | — | |
| Andrew S. Marsh*** | | 86,740 |
| | 241,726 |
| | — |
| Andrew S. Marsh*** | | 90,482 | | | 281,147 | | | — | |
| Laura R. Landreaux*** | | 5,866 |
| | 1,700 |
| | — |
| Laura R. Landreaux*** | | 5,678 | | | 4,833 | | | — | |
| Roderick K. West*** | | 64,999 |
| | 97,249 |
| | — |
| Roderick K. West*** | | 33,757 | | | 37,517 | | | — | |
| All directors and executive officers as a group (8 persons) | | 555,420 |
| | 1,242,596 |
| | — |
| All directors and executive officers as a group (8 persons) | | 556,160 | | | 1,390,535 | | | — | |
| | | | | | | | |
| Entergy Louisiana | | | | | | | Entergy Louisiana | |
| A. Christopher Bakken, III** | | 38,397 |
| | 38,174 |
| | — |
| A. Christopher Bakken, III** | | 18,115 | | | 35,399 | | | — | |
| Marcus V. Brown** | | 44,758 |
| | 40,075 |
| | — |
| Marcus V. Brown** | | 38,813 | | | 34,930 | | | — | |
| Leo P. Denault** | | 265,416 |
| | 753,202 |
| | — |
| Leo P. Denault** | | 324,528 | | | 899,634 | | | — | |
| Andrew S. Marsh*** | | 86,740 |
| | 241,726 |
| | — |
| Andrew S. Marsh*** | | 90,482 | | | 281,147 | | | — | |
| Phillip R. May, Jr.*** | | 25,880 |
| | 13,900 |
| | 13 |
| Phillip R. May, Jr.*** | | 23,383 | | | 8,833 | | | 13 | |
| Roderick K. West*** | | 64,999 |
| | 97,249 |
| | — |
| Roderick K. West*** | | 33,757 | | | 37,517 | | | — | |
| All directors and executive officers as a group (8 persons) | | 575,434 |
| | 1,254,796 |
| | 13 |
| All directors and executive officers as a group (8 persons) | | 573,865 | | | 1,394,535 | | | 13 | |
| | | Name | | Shares (1)(2) | | Options Exercisable Within 60 Days | | Stock Units (3) | Name | | Shares (1)(2) | | Options Exercisable Within 60 Days | | Stock Units (3) |
| Entergy Mississippi | | | | | | | Entergy Mississippi | | | | | | |
| Marcus V. Brown** | | 44,758 |
| | 40,075 |
| | — |
| Marcus V. Brown** | | 38,813 | | | 34,930 | | | — | |
| Leo P. Denault** | | 265,416 |
| | 753,202 |
| | — |
| Leo P. Denault** | | 324,528 | | | 899,634 | | | — | |
| Haley R. Fisackerly*** | | 9,847 |
| | 6,800 |
| | — |
| Haley R. Fisackerly*** | | 7,760 | | | 5,700 | | | — | |
| Andrew S. Marsh*** | | 86,740 |
| | 241,726 |
| | — |
| Andrew S. Marsh*** | | 90,482 | | | 281,147 | | | — | |
| Roderick K. West*** | | 64,999 |
| | 97,249 |
| | — |
| Roderick K. West*** | | 33,757 | | | 37,517 | | | — | |
| All directors and executive officers as a group (7 persons) | | 521,004 |
| | 1,209,522 |
| | — |
| All directors and executive officers as a group (7 persons) | | 540,127 | | | 1,356,003 | | | — | |
| | | | | | | | |
| Entergy New Orleans | | | | | | | Entergy New Orleans | | | | | | |
| Marcus V. Brown** | | 44,758 |
| | 40,075 |
| | — |
| Marcus V. Brown** | | 38,813 | | | 34,930 | | | — | |
| Leo P. Denault** | | 265,416 |
| | 753,202 |
| | — |
| Leo P. Denault** | | 324,528 | | | 899,634 | | | — | |
| David D. Ellis*** | | 1,812 |
| | 1,566 |
| | — |
| David D. Ellis*** | | 3,332 | | | 4,199 | | | — | |
| Andrew S. Marsh*** | | 86,740 |
| | 241,726 |
| | — |
| Andrew S. Marsh*** | | 90,482 | | | 281,147 | | | — | |
| Roderick K. West*** | | 64,999 |
| | 97,249 |
| | — |
| Roderick K. West*** | | 33,757 | | | 37,517 | | | — | |
| All directors and executive officers as a group (7 persons) | | 512,969 |
| | 1,204,288 |
| | — |
| All directors and executive officers as a group (7 persons) | | 535,699 | | | 1,354,502 | | | — | |
| | | | | | | | |
| Entergy Texas | | | | | | | Entergy Texas | | | | | | |
| Marcus V. Brown** | | 44,758 |
| | 40,075 |
| | — |
| Marcus V. Brown** | | 38,813 | | | 34,930 | | | — | |
| Leo P. Denault** | | 265,416 |
| | 753,202 |
| | — |
| Leo P. Denault** | | 324,528 | | | 899,634 | | | — | |
| Andrew S. Marsh*** | | 86,740 |
| | 241,726 |
| | — |
| Andrew S. Marsh*** | | 90,482 | | | 281,147 | | | — | |
| Sallie T. Rainer*** | | 10,799 |
| | 6,866 |
| | — |
| Sallie T. Rainer*** | | 13,437 | | | 12,566 | | | — | |
| Roderick K. West*** | | 64,999 |
| | 97,249 |
| | — |
| Roderick K. West*** | | 33,757 | | | 37,517 | | | — | |
| All directors and executive officers as a group (7 persons) | | 521,956 |
| | 1,209,588 |
| | — |
| All directors and executive officers as a group (7 persons) | | 545,804 | | | 1,362,869 | | | — | |
|
| | | | |
| * | Director of the respective Companycompany |
| ** | Named Executive OfficerNEO of the respective Companycompany |
| *** | Director and Named Executive OfficerNEO of the respective Companycompany |
| |
(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 or 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 Entergy Corporation’s equity ownership plans. 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. Messrs. Donald and Frederickson 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. |
(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 or 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 director or executive holds under the defined contribution restoration plan and the deferral provisions of Entergy Corporation’s equity ownership plans. 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. Messrs. Donald and Frederickson 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, 2019.2020. Information is included for equity compensation plans approved by the shareholders. There are no shares authorized for issuance under equity compensation plans not approved by the shareholders.
| | | | | | | | | | | | | | | | | | | | |
| Plan | | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a) | | Weighted Average Exercise Price (b)(2) | | Number of Securities Remaining Available for Future Issuance (excluding securities reflected in column (a))(c) |
Equity compensation plans approved by security holders (1) | | 2,399,379 | | | $89.63 | | 6,108,451 | |
| Equity compensation plans not approved by security holders | | — | | | — | | | — | |
| Total | | 2,399,379 | | | $89.63 | | 6,108,451 | |
(1)Includes the 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, the 2015 Equity Plan, and the 2019 Omnibus Incentive Plan. The 2007 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 12, 2006, and 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 only applied to awards granted between May 6, 2011 and May 7, 2015. The 2015 Equity Plan was approved by Entergy Corporation shareholders on May 8, 2015, and only applied to awards granted between May 8, 2015 and May 3, 2019. The 2019 Omnibus Incentive Plan was approved by the Entergy Corporation shareholders on May 3, 2019, and 7,300,000 shares of Entergy Corporation common stock can be issued from the 2019 Omnibus Incentive Plan, with all shares available for equity-based incentive awards. The 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, the 2015 Equity Plan, and the 2019 Omnibus Incentive Plan (collectively, 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 employer or an affiliate of Entergy Corporation. The Plans provide for the issuance of stock options, restricted stock, equity awards (units whose value is related to the value of shares of the common stock but do not represent actual shares of common stock), performance awards (performance shares or units valued by reference to shares of common stock or performance units valued by reference to financial measures or property other than common stock), restricted stock unit awards, and other stock-based awards.
(2)The weighted average exercise price reported in this column does not include outstanding performance awards.
|
| | | | | | | | | |
| Plan | | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a) | | Weighted Average Exercise Price (b)(2) | | Number of Securities Remaining Available for Future Issuance (excluding securities reflected in column (a))(c) |
Equity compensation plans approved by security holders (1) | | 2,448,913 |
| | $78.48 | | 7,266,822 |
|
| Equity compensation plans not approved by security holders | | — |
| | — |
| | — |
|
| Total | | 2,448,913 |
| | $78.48 | | 7,266,822 |
|
| |
(1) | Includes the 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, the 2015 Equity Plan, and the 2019 Omnibus Incentive Plan. The 2007 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 12, 2006, and 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 only applied to awards granted between May 6, 2011 and May 7, 2015. The 2015 Equity Plan was approved by Entergy Corporation shareholders on May 8, 2015, and only applied to awards granted between May 8, 2015 and May 3, 2019. The 2019 Omnibus Incentive Plan was approved by the Entergy Corporation shareholders on May 3, 2019, and 7,300,000 shares of Entergy Corporation common stock can be issued from the 2019 Omnibus Incentive Plan, with all shares available for equity-based incentive awards. The 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, the 2015 Equity Plan, and the 2019 Omnibus Incentive Plan (collectively, 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 employer or an affiliate of Entergy Corporation. The Plans provide for the issuance of stock options, restricted stock, equity awards (units whose value is related to the value of shares of the common stock but do not represent actual shares of common stock), performance awards (performance shares or units valued by reference to shares of common stock or performance units valued by reference to financial measures or property other than common stock), restricted stock unit awards, and other stock-based awards. |
| |
(2) | The weighted average exercise price reported in this column does not include outstanding performance awards. |
Item 13. Certain Relationships and Related Party Transactions and Director Independence
For information regarding certain relationship, related transactions and director independence of Entergy Corporation, see the Entergy Corporation Proxy Statement under the headings “Corporate Governance at Entergy - Director Independence” and “Corporate Governance - Corporate Governance Policies - Review and Approval of Related Party Transactions.”
Entergy Corporation’s Board of Directors has adopted a written Related Party Transaction Approval Policy that applies:
Toapplies to any transaction or series of transactions in which Entergy Corporation or a subsidiary is a participant;participant:
•When the amount involved exceeds $120,000; and
•When a Related Party (an Entergy Corporation director or executive officer, any nominee for director, any shareholder owning an excess of 5% of the total equity of Entergy Corporation and any immediate family member of any such person) has a direct or indirect material interest in such transaction(s) (other than solely as a result of being a director or a less than 10% beneficial owner of another entity).
The policy is administered by Entergy Corporation’s Corporate Governance Committee. The committee will consider relevant facts and circumstance in determining whether or not to approve or ratify such a transaction, and will approve or ratify only those transactions that are, in the Corporate Governance Committee’s judgment, appropriate or desirable under the circumstances. The Corporate Governance Committee has determined that certain types of transactions do not create or involve a direct or indirect material interest, including (i) compensation and related party transactions involving a director or an executive officer solely resulting from service as a director or employment with Entergy Corporation so long as the compensation is approved by the Entergy Corporation Board of Directors (or an appropriate committee); (ii) transactions involving public utility services at rates or charges fixed in conformity with law or governmental authority; or (iii) all business relationships between Entergy Corporation and a Related Party made in the ordinary course of business on terms and conditions generally available in the marketplace an in accordance with applicable law. To Entergy Corporation’s knowledge, since January 1, 2019,2020, neither Entergy Corporation nor any of its affiliates has participated in any Related Party transaction.
Item 14. Principal Accountant Fees and Services (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Aggregate fees billed to Entergy Corporation (consolidated), Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy for the years ended December 31, 20192020 and 20182019 by Deloitte & Touche LLP were as follows:
| | | | | | | | | | | |
| | 2020 | | 2019 |
| Entergy Corporation (consolidated) | | | |
| Audit Fees | $9,323,550 | | | $8,710,000 | |
| Audit-Related Fees (a) | 786,000 | | | 775,000 | |
| Total audit and audit-related fees | 10,109,550 | | | 9,485,000 | |
| Tax Fees | — | | | — | |
| All Other Fees (b) | 183,060 | | | 31,835 | |
| Total Fees (c) | $10,292,610 | | | $9,516,835 | |
| Entergy Arkansas | | | |
| Audit Fees | $1,137,507 | | | $1,015,125 | |
| Audit-Related Fees (a) | — | | | — | |
| Total audit and audit-related fees | 1,137,507 | | | 1,015,125 | |
| Tax Fees | — | | | — | |
| All Other Fees | — | | | — | |
| Total Fees (c) | $1,137,507 | | | $1,015,125 | |
| Entergy Louisiana | | | |
| Audit Fees | $2,302,851 | | | $1,871,918 | |
| Audit-Related Fees (a) | 360,000 | | | 360,000 | |
| Total audit and audit-related fees | 2,662,851 | | | 2,231,918 | |
| Tax Fees | — | | | — | |
| All Other Fees | — | | | — | |
| Total Fees (c) | $2,662,851 | | | $2,231,918 | |
| Entergy Mississippi | | | |
| Audit Fees | $982,507 | | | $1,005,125 | |
| Audit-Related Fees (a) | — | | | — | |
| Total audit and audit-related fees | 982,507 | | | 1,005,125 | |
| Tax Fees | — | | | — | |
| All Other Fees | — | | | — | |
| Total Fees (c) | $982,507 | | | $1,005,125 | |
| | | | | | | | 2020 | | 2019 |
| | 2019 | | 2018 | |
| Entergy Corporation (consolidated) | | | | |
| Entergy New Orleans | | Entergy New Orleans | | | |
| Audit Fees |
| $8,710,000 |
| |
| $8,801,895 |
| Audit Fees | $1,027,507 | | | $950,125 | |
| Audit-Related Fees (a) | 775,000 |
| | 1,067,119 |
| Audit-Related Fees (a) | — | | | — | |
| Total audit and audit-related fees | 9,485,000 |
| | 9,869,014 |
| Total audit and audit-related fees | 1,027,507 | | | 950,125 | |
| Tax Fees | — |
| | — |
| Tax Fees | — | | | — | |
| All Other Fees | 31,835 |
| | — |
| All Other Fees | — | | | — | |
| Total Fees (b) |
| $9,516,835 |
| |
| $9,869,014 |
| |
| Entergy Arkansas | | | | |
| Total Fees (c) | | Total Fees (c) | $1,027,507 | | | $950,125 | |
| Entergy Texas | | Entergy Texas | | | |
| Audit Fees |
| $1,015,125 |
| |
| $1,030,758 |
| Audit Fees | $1,258,220 | | | $1,165,125 | |
| Audit-Related Fees (a) | — |
| | — |
| Audit-Related Fees (a) | — | | | — | |
| Total audit and audit-related fees | 1,015,125 |
| | 1,030,758 |
| Total audit and audit-related fees | 1,258,220 | | | 1,165,125 | |
| Tax Fees | — |
| | — |
| Tax Fees | — | | | — | |
| All Other Fees | — |
| | — |
| All Other Fees | — | | | — | |
| Total Fees (b) |
| $1,015,125 |
| |
| $1,030,758 |
| |
| Entergy Louisiana | | | | |
| Total Fees (c) | | Total Fees (c) | $1,258,220 | | | $1,165,125 | |
| System Energy | | System Energy | | | |
| Audit Fees |
| $1,871,918 |
| |
| $1,916,517 |
| Audit Fees | $1,017,507 | | | $930,125 | |
| Audit-Related Fees (a) | 360,000 |
| | 500,000 |
| Audit-Related Fees (a) | — | | | — | |
| Total audit and audit-related fees | 2,231,918 |
| | 2,416,517 |
| Total audit and audit-related fees | 1,017,507 | | | 930,125 | |
| Tax Fees | — |
| | — |
| Tax Fees | — | | | — | |
| All Other Fees | — |
| | — |
| All Other Fees | — | | | — | |
| Total Fees (b) |
| $2,231,918 |
| |
| $2,416,517 |
| |
| Entergy Mississippi | | | | |
| Audit Fees |
| $1,005,125 |
| |
| $910,758 |
| |
| Audit-Related Fees (a) | — |
| | — |
| |
| Total audit and audit-related fees | 1,005,125 |
| | 910,758 |
| |
| Tax Fees | — |
| | — |
| |
| All Other Fees | — |
| | — |
| |
| Total Fees (b) |
| $1,005,125 |
| |
| $910,758 |
| |
| Total Fees (c) | | Total Fees (c) | $1,017,507 | | | $930,125 | |
(a)Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services.
(b)Includes fees for cybersecurity assessment and license fee for accounting research tool.
(c)100% of fees paid in 2020 and 2019 were pre-approved by the Entergy Corporation Audit Committee.
|
| | | | | | | |
| | 2019 | | 2018 |
| Entergy New Orleans | | | |
| Audit Fees |
| $950,125 |
| |
| $965,758 |
|
| Audit-Related Fees (a) | — |
| | — |
|
| Total audit and audit-related fees | 950,125 |
| | 965,758 |
|
| Tax Fees | — |
| | — |
|
| All Other Fees | — |
| | — |
|
| Total Fees (b) |
| $950,125 |
| |
| $965,758 |
|
| Entergy Texas | | | |
| Audit Fees |
| $1,165,125 |
| |
| $1,200,758 |
|
| Audit-Related Fees (a) | — |
| | — |
|
| Total audit and audit-related fees | 1,165,125 |
| | 1,200,758 |
|
| Tax Fees | — |
| | — |
|
| All Other Fees | — |
| | — |
|
| Total Fees (b) |
| $1,165,125 |
| |
| $1,200,758 |
|
| System Energy | | | |
| Audit Fees |
| $930,125 |
| |
| $850,758 |
|
| Audit-Related Fees (a) | — |
| | — |
|
| Total audit and audit-related fees | 930,125 |
| | 850,758 |
|
| Tax Fees | — |
| | — |
|
| All Other Fees | — |
| | — |
|
| Total Fees (b) |
| $930,125 |
| |
| $850,758 |
|
| |
(a) | Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services. |
| |
(b) | 100% of fees paid in 2019 and 2018 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: |
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:
aAggregate non-audit service fees are targeted at fifty percent or less of the approved audit service fee.
bAll other services should only be provided by the independent auditor if it is a highly qualified provider of that service or if the Audit Committee pre-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. |
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
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| | | | |
| (a)1. | Financial Statements and Independent Auditors’ Reports for Entergy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Table of Contents. |
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| (a)2. | Financial Statement Schedules |
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| Reports of Independent Registered Public Accounting Firm (see page 517)542) |
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| Financial Statement Schedules are listed in the Index to Financial Statement Schedules (see page S-1) |
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| (a)3. | Exhibits |
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| Exhibits for Entergy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Exhibit Index (see page 494520 and are incorporated by reference herein). 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 previously 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 Arkansas
Entergy Louisiana
Entergy Mississippi
Entergy New Orleans
(3) Articles of Incorporation and Bylaws
Entergy Corporation
System Energy
Entergy Arkansas
Entergy Louisiana
Entergy Mississippi
Entergy New Orleans
Entergy Texas
(4)Instruments Defining Rights of Security Holders, Including Indentures
Entergy Corporation
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| (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. |
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| (a) 2 -- | |
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| (a) 3 -- | |
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(a) 4 -- | |
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(a) 54 -- | |
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(a) 65 -- | |
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| (a) 6 -- | |
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| (a) 7 -- | |
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| (a) 8 -- | |
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| (a) 9 -- | Second Amended and Restated Credit Agreement dated as of September 14, 2018, among Entergy Corporation, as Borrower, the banks and other financial institutions listed on the signatures pages thereof, as Lenders, Citibank, N.A., as Administrative Agent and LC Issuing Bank, MUFG Bank, Ltd., as LC Issuing Bank, and the other LC Issuing Banks from time to time parties thereto (4(g) to Form 10-Q for the quarter ended September 30, 2018 in 1-11299). |
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(a) 810 -- | Extension Agreement, dated September 13, 2019, to Second Amended and Restated Credit Agreement dated as of September 14, 2018, among Entergy Corporation, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent and LC Issuing Bank, MUFG Bank, Ltd., as LC Issuing Bank, and the other LC Issuing Banks from time to time parties thereto (4(a) to Form 10-Q for the quarter ended September 30, 2019 in 1-11299). |
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*(a) 911 -- | |
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) 34 -- | |
Entergy Arkansas
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| (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); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Thirtieth); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Thirty-first); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Thirty-ninth); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (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(c)1 to Form 10-K for the year ended December 31, 2008 in 1-10764 (Sixty-eighth); 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); 4.05 to Form 8-K filed August 16, 2016 in 1-10764 (Seventy-ninth); 4(a) to Form 10-Q for the quarter ended September 30, 2018 (Eightieth); 4.1 to Form 8-K12B filed December 3, 2018 in 1-10764 (Eighty-first); and 4.39 to Form 8-K filed March 19, 2019 in 1-10764 (Eighty-second); and 4.49 to Form 8-K filed September 11, 2020 in 1-10764 (Eighty-third)). |
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| (c) 2 -- | Second Amended and Restated Credit Agreement dated as of September 14, 2018, among Entergy Arkansas, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., as LC Issuing Bank, and the other LC Issuing Banks from time to time parties thereto (4(h) to Form 10-Q for the quarter ended September 30, 2018 in 1-10764). |
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| (c) 3 -- | Borrower Assumption Agreement dated as of November 30, 2018 of Entergy Arkansas Power, LLC under the Second Amended and Restated Credit Agreement dated as of September 14, 2018, among Entergy Arkansas, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., as LC Issuing Bank, and the other LC Issuing Banks from time to time parties thereto (4.2 to Form 8-K12B filed December 3, 2018 in 1-10764). |
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| (c) 4 -- | Extension Agreement, dated September 13, 2019, to Second Amended and Restated Credit Agreement dated as of September 14, 2018, as supplemented by the Borrower Assumption Agreement of Entergy Arkansas Power, LLC dated as of November 30, 2018, among Entergy Arkansas, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., as LC Issuing Bank, and the other LC Issuing Banks from time to time parties thereto (4(b) to Form 10-Q for the quarter ended September 30, 2019 in 1-10764). |
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| (c) 5 -- | |
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| (c) 6 -- | |
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| *(c) 7 -- | |
Entergy Louisiana
|
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| (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); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Sixth); 2(c) in 2-34659 (Twelfth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Twenty-first); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Twenty-fifth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Twenty-ninth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (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); 4.43 to Form 8-K filed October 4, 2016 in 1-32718 (Eighty-seventh); 4.43 to Form 8-K filed May 23, 2017 in 1-32718 (Eighty-eighth); 4.43 to Form 8‑K filed March 23, 2018 in 1-32718 (Eighty-ninth); 4.43 to Form 8-K filed August 14, 2018 in 1-32718 (Ninetieth); and 4.43 to Form 8-K filed March 12, 2019 in 1-32718 (Ninety-first); 4.53to Form 8-K filed March 6, 2020 in 1-32718 (Ninety-second); 4.53(b) to Form 8-K filed November 13, 2020 in 1-32718 (Ninety-third); and 4.53 to Form 8-K filed November 24, 2020 in 1-32718 (Ninety-fourth)). |
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| (d) 2 -- | Second Amended and Restated Credit Agreement dated as of September 14, 2018, among Entergy Louisiana, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent, Wells Fargo Bank, National Association and BNP Paribas, as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4(i) to Form 10-Q for the quarter ended September 30, 2018 in 1-32718). |
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| (d) 3 -- | Extension Agreement, dated September 13, 2019, to Second Amended and Restated Credit Agreement dated as of September 14, 2018, among Entergy Louisiana, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent, Wells Fargo Bank, National Association and BNP Paribas, as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4(c) to Form 10-Q for the quarter ended September 30, 2019 in 1-32718). |
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| (d) 4 -- | |
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| (d) 5 -- | |
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| (d) 6 -- | |
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| (d) 7 -- | |
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| (d) 8 -- | |
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| (d) 9 -- | Indenture of Mortgage, dated September 1, 1926, as amended by the following Supplemental Indentures: (7-A-9 in Registration No. 2-6893 (Seventh); 4(d)15 to Form 10-K for the year ended December 31, 2017 in 1-32718 (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 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); 4.42 to Form 8-K filed May 23, 2017 in 1-32718 (Eighty-eighth); 4.42 to Form 8-K filed March 23, 2018 in 1-32718 (Eighty-ninth); 4.42 to Form 8-K filed August 14, 2018 in 1-32718 (Ninetieth); and 4.42 to Form 8-K filed March 12, 2019 in 1-32718 (Ninety-first); 4.52 to Form 8-K filed March 6, 2020 in 1-32718 (Ninety-second); and 4.52(b) to Form 8-K filed November 13, 2020 in 1-32718 (Ninety-third)). |
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| (d) 10 -- | 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) 11 -- | 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); 4.41 to Form 8-K filed May 23, 2017 in 1-32718 (Eighth); 4.41 to Form 8-K filed March 23, 2018 in 1-32718 (Ninth); 4.41 to Form 8-K filed August 14, 2018 in 1-32718 (Tenth); and 4.41 to Form 8-K filed March 12, 2019 in 1-32718 (Eleventh); 4.51 to Form 8-K filed March 6, 2020in1-32718 (Twelfth); 4.51(b) to Form 8-K filed November 13, 2020 in 1-32718 (Thirteenth); and 4.51 to Form 8-K filed November 24, 2020 in 1-32718 (Fourteenth)). |
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| (d) 12 -- | |
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| (d) 13 -- | |
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| (d) 14 -- | |
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| (d) 15 -- | |
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| (d) 16 -- | |
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| (d) 17 -- | |
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| (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 -- | |
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| *(d) 24 -- | |
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: (4(e)1 to Form 10-K for the year ended December 31, 2017 in 1-31508 (Mortgage); 4(e)1 to Form 10-K for the year ended December 31, 2017 in 1-31508 (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); 4.16 to Form 8-K filed November 14, 2017 in 1-31508 (Thirty-fourth); 4.1 to Form 8-K filed November 21, 2018 in 1-31508 (Thirty-fifth); 4.1 to Form 8-K12B filed December 3, 2018 in 1-31508 (Thirty-sixth); 4(a) to Form 8-K filed December 12, 2018 in 1-31508 (Thirty-seventh); and 4.46 to Form 8-K filed June 5, 2019 in 1-31508 (Thirty-eighth); and 4.56 to Form 8-K filed May 22, 2020 in 1-31508 (Thirty-ninth)). |
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| *(e) 2 -- | |
Entergy New Orleans
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| (f) 1 -- | Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by the following Supplemental Indentures: (4(f)1 to Form 10-K for the year ended December 31, 2017 in 1-35747 (Mortgage); 4(f)1 to Form 10-K for the year ended December 31, 2017 in 1-35747 (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); 4.1 to Form 8-K12B filed December 1, 2017 in 1-35747 (Twenty-first); and 4(a) to Form 8-K filed September 27, 2018 in 1-35747 (Twenty-second); and 4(a) to Form 8-K filed March 26, 2020 in 1-35747 (Twenty-third)). |
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| (f) 2 -- | Second Amended and Restated Credit Agreement dated as of November 16, 2018, among Entergy New Orleans, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Bank of America, N.A., as Administrative Agent and LC Issuing Bank, and the other LC Issuing Banks from time to time parties thereto (4(f)2 to Form 10-K for the year ended December 31, 2018 in 1-35747). |
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Entergy Texas
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(g) 54 -- | |
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(g) 65 -- | |
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(g) 76 -- | |
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(g) 87 -- | |
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(g) 98 -- | |
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| (g) 9 -- | |
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| (g) 10 -- | Second Amended and Restated Credit Agreement dated as of September 14, 2018, among Entergy Texas, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., BNP Paribas, Mizuho Bank, Ltd., and The Bank of Nova Scotia, as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4(j) to Form 10-Q for the quarter ended September 30, 2018 in 1-34360). |
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| (g) 11 -- | Extension Agreement, dated September 13, 2019, to Second Amended and Restated Credit Agreement dated as of September 14, 2018, among Entergy Texas, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., BNP Paribas, Mizuho Bank, Ltd., and The Bank of Nova Scotia, as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4(d) to Form 10-Q for the quarter ended September 30, 2019 in 1-34360). |
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(10) Material Contracts
Entergy Corporation
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+(a) 1 --1-- | |
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System Energy
System Energy
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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 -- | Thirty-eighth Assignment of Availability Agreement, Consent and Agreement, dated as of December 9, 2020, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee (4.60 to Form 8-K filed December 9, 2020 in 1-09067). |
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| (b) 9 -- | |
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(b) 1112 -- | |
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(b) 1314 -- | |
(14) Code of Ethics
Entergy Corporation
(23) Consents of Experts and Counsel
(31) Rule 13a-14(a)/15d-14(a) Certifications
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(32) Section 1350 Certifications
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(101) Interactive Data File
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| *INS - | Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
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| *SCH - | Inline XBRL Schema Document. |
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| *CAL - | Inline XBRL Calculation Linkbase Document. |
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| *DEF - | Inline XBRL Definition Linkbase Document. |
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| *LAB - | Inline XBRL Label Linkbase Document. |
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| *PRE - | Inline XBRL Presentation Linkbase Document. |
*(104) Cover Page Interactive Data File (formatted in Inline XBRL and contained in Exhibits 101)
_________________
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| * | Filed herewith. |
| ** | Furnished, not 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 |
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| ENTERGY CORPORATION |
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| By /s/ Kimberly A. Fontan |
| Kimberly A. Fontan |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 21, 202026, 2021 |
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/ Kimberly A. Fontan Kimberly A. Fontan
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 21, 202026, 2021 |
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); John R. Burbank, Patrick J. Condon, Kirkland H. Donald, Brian W. Ellis, Philip L. Frederickson, Alexis M. Herman, M. Elise Hyland, Stuart L. Levenick, Blanche L. Lincoln, and Karen A. Puckett (Directors).
|
| | | | |
By: /s/ Kimberly A. Fontan | February 21, 202026, 2021 |
| (Kimberly A. Fontan, Attorney-in-fact) | |
ENTERGY ARKANSAS, 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 ARKANSAS, LLC |
| |
| ENTERGY ARKANSAS, LLC |
| |
| By /s/ Kimberly A. Fontan |
| Kimberly A. Fontan |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 21, 202026, 2021 |
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/ Kimberly A. Fontan Kimberly A. Fontan
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 21, 202026, 2021 |
Laura R. Landreaux (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); Paul D. Hinnenkamp and Roderick K. West (Directors).
|
| | | | |
By: /s/ Kimberly A. Fontan | February 21, 202026, 2021 |
| (Kimberly A. Fontan, 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 |
| |
| ENTERGY LOUISIANA, LLC |
| |
| By /s/ Kimberly A. Fontan |
| Kimberly A. Fontan |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 21, 202026, 2021 |
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/ Kimberly A. Fontan Kimberly A. Fontan
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 21, 202026, 2021 |
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); Paul D. Hinnenkamp and Roderick K. West (Directors).
|
| | | | |
By: /s/ Kimberly A. Fontan | February 21, 202026, 2021 |
| (Kimberly A. Fontan, Attorney-in-fact) | |
ENTERGY MISSISSIPPI, 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 MISSISSIPPI, LLC |
| |
| ENTERGY MISSISSIPPI, LLC |
| |
| By /s/ Kimberly A. Fontan |
| Kimberly A. Fontan |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 21, 202026, 2021 |
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/ Kimberly A. Fontan Kimberly A. Fontan
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 21, 202026, 2021 |
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); Paul D. Hinnenkamp and Roderick K. West (Directors).
|
| | | | |
By: /s/ Kimberly A. Fontan | February 21, 202026, 2021 |
| (Kimberly A. Fontan, Attorney-in-fact) | |
ENTERGY NEW ORLEANS, 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, LLC |
| |
| ENTERGY NEW ORLEANS, LLC |
| |
| By /s/ Kimberly A. Fontan |
| Kimberly A. Fontan |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 21, 202026, 2021 |
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/ Kimberly A. Fontan Kimberly A. Fontan
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 21, 202026, 2021 |
David D. Ellis (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); Paul D. Hinnenkamp and Roderick K. West (Directors).
|
| | | | |
By: /s/ Kimberly A. Fontan | February 21, 202026, 2021 |
| (Kimberly A. Fontan, 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. |
| |
| ENTERGY TEXAS, INC. |
| |
| By /s/ Kimberly A. Fontan |
| Kimberly A. Fontan |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 21, 202026, 2021 |
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/ Kimberly A. Fontan Kimberly A. Fontan
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 21, 202026, 2021 |
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); Paul D. Hinnenkamp and Roderick K. West (Directors).
|
| | | | |
By: /s/ Kimberly A. Fontan | February 21, 202026, 2021 |
| (Kimberly A. Fontan, 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. |
| |
| SYSTEM ENERGY RESOURCES, INC. |
| |
| By /s/ Kimberly A. Fontan |
| Kimberly A. Fontan |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 21, 202026, 2021 |
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/ Kimberly A. Fontan Kimberly A. Fontan
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 21, 202026, 2021 |
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); A. Christopher Bakken, III and Steven C. McNeal (Directors).
|
| | | | |
By: /s/ Kimberly A. Fontan | February 21, 202026, 2021 |
| (Kimberly A. Fontan, Attorney-in-fact) | |
EXHIBIT 23(a)
CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333-233403 on Form S-3 and in Registration Statements Nos. 333-140183, 333-174148, 333-204546, 333-206556, 333-227150333-231800 and 333-231800333-251819 on Form S-8 of our reports dated February 21, 2020,26, 2021, relating to the 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, 2019.2020.
We consent to the incorporation by reference in Registration Statement No. 333-233403-05 on Form S-3 of our reports dated February 21, 2020,26, 2021, relating to the financial statements and financial statement schedule of Entergy Arkansas, LLC and Subsidiaries appearing in this Annual Report on Form 10-K of Entergy Arkansas, LLC for the year ended December 31, 2019.2020.
We consent to the incorporation by reference in Registration Statement No. 233403-04 on Form S-3 of our reports dated February 21, 2020,26, 2021, relating to the 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, 2019.2020.
We consent to the incorporation by reference in Registration Statement No. 233403-03 on Form S-3 of our reports dated February 21, 2020,26, 2021, relating to the financial statements and financial statement schedule of Entergy Mississippi, LLC appearing in this Annual Report on Form 10‑K of Entergy Mississippi, LLC for the year ended December 31, 2019.2020.
We consent to the incorporation by reference in Registration Statement No. 233403-02 on Form S-3 of our reports dated February 21, 2020,26, 2021, relating to the 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, 2019.2020.
We consent to the incorporation by reference in Registration Statement No. 233403-01 on Form S-3 of our report dated February 21, 2020,26, 2021, 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, 2019.2020.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202026, 2021
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors 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, 20192020 and 2018,2019, and for each of the three years in the period ended December 31, 2019,2020, and the Corporation’s internal control over financial reporting as of December 31, 2019,2020, and have issued our reports thereon dated February 21, 2020.26, 2021. Our audits also included the consolidated financial statement schedule of the Corporation listed in Item 15. This consolidated financial statement schedule 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 schedule, when considered in relation to the consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202026, 2021
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors of
Entergy Texas, Inc. and Subsidiaries
To the member and Board of Directors of
Entergy Arkansas, LLC and Subsidiaries
Entergy Louisiana, LLC and Subsidiaries
Entergy Mississippi, LLC
Entergy New Orleans, LLC and Subsidiaries
Opinion on the Financial Statement Schedules
We have audited the consolidated financial statements of Entergy Arkansas, LLC 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 Mississippi, LLC (collectively the “Companies”) as of December 31, 20192020 and 2018,2019, and for each of the three years in the period ended December 31, 2019,2020, and have issued our reports thereon dated February 21, 2020.26, 2021. 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’ 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 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 21, 202026, 2021
INDEX TO FINANCIAL STATEMENT SCHEDULES
|
| | | | | | | |
| Schedule | | Page |
| | |
| II | Valuation and Qualifying Accounts 2020, 2019, 2018, and 2017:2018: | |
| | |
| | |
| | |
| | |
| | |
| | |
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, 2019, 2018, and 2017 |
| (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 | | | | | | | | |
| 2019 | |
| $7,322 |
| |
| $2,806 |
| |
| $2,724 |
| |
| $7,404 |
|
| 2018 | |
| $13,587 |
| |
| $3,936 |
| |
| $10,201 |
| |
| $7,322 |
|
| 2017 | |
| $11,924 |
| |
| $4,211 |
| |
| $2,548 |
| |
| $13,587 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2019, 2018, and 2017 |
| (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 | | | | | | | | |
| 2019 | |
| $1,264 |
| |
| $1,000 |
| |
| $1,095 |
| |
| $1,169 |
|
| 2018 | |
| $1,063 |
| |
| $810 |
| |
| $609 |
| |
| $1,264 |
|
| 2017 | |
| $1,211 |
| |
| $503 |
| |
| $651 |
| |
| $1,063 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2020, 2019, and 2018 |
| (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
(1) | | Deductions (2) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2020 | | $7,404 | | | $111,687 | | | $1,297 | | | $117,794 | |
| 2019 | | $7,322 | | | $2,806 | | | $2,724 | | | $7,404 | |
| 2018 | | $13,587 | | | $3,936 | | | $10,201 | | | $7,322 | |
| Notes: | | | | | | | | |
| (1) A portion of the charges to income are deferred as a regulatory asset. |
| (2) 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, 2019, 2018, and 2017 |
| (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 | | | | | | | | |
| 2019 | |
| $1,813 |
| |
| $762 |
| |
| $673 |
| |
| $1,902 |
|
| 2018 | |
| $8,430 |
| |
| $2,395 |
| |
| $9,012 |
| |
| $1,813 |
|
| 2017 | |
| $6,277 |
| |
| $3,108 |
| |
| $955 |
| |
| $8,430 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2019, 2018, and 2017 |
| (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 | | | | | | | | |
| 2019 | |
| $563 |
| |
| $406 |
| |
| $333 |
| |
| $636 |
|
| 2018 | |
| $574 |
| |
| $265 |
| |
| $276 |
| |
| $563 |
|
| 2017 | |
| $549 |
| |
| $255 |
| |
| $230 |
| |
| $574 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2020, 2019, and 2018 |
| (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
(1) | | Deductions (2) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2020 | | $1,169 | | | $17,307 | | | $142 | | | $18,334 | |
| 2019 | | $1,264 | | | $1,000 | | | $1,095 | | | $1,169 | |
| 2018 | | $1,063 | | | $810 | | | $609 | | | $1,264 | |
| Notes: | | | | | | | | |
| (1) A portion of the charges to income are deferred as a regulatory asset. |
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2019, 2018, and 2017 |
| (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 | | | | | | | | |
| 2019 | |
| $3,222 |
| |
| $316 |
| |
| $312 |
| |
| $3,226 |
|
| 2018 | |
| $3,057 |
| |
| $187 |
| |
| $22 |
| |
| $3,222 |
|
| 2017 | |
| $3,059 |
| |
| $152 |
| |
| $154 |
| |
| $3,057 |
|
| 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, 2019, 2018, and 2017 |
| (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 | | | | | | | | |
| 2019 | |
| $461 |
| |
| $321 |
| |
| $311 |
| |
| $471 |
|
| 2018 | |
| $463 |
| |
| $279 |
| |
| $281 |
| |
| $461 |
|
| 2017 | |
| $828 |
| |
| $192 |
| |
| $557 |
| |
| $463 |
|
| 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, 2020, 2019, and 2018 |
| (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
(1) | | Deductions (2) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2020 | | $1,902 | | | $44,542 | | | $751 | | | $45,693 | |
| 2019 | | $1,813 | | | $762 | | | $673 | | | $1,902 | |
| 2018 | | $8,430 | | | $2,395 | | | $9,012 | | | $1,813 | |
| Notes: | | | | | | | | |
| (1) A portion of the charges to income are deferred as a regulatory asset. |
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2020, 2019, and 2018 |
| (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
(1) | | Deductions (2) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2020 | | $636 | | | $19,081 | | | $190 | | | $19,527 | |
| 2019 | | $563 | | | $406 | | | $333 | | | $636 | |
| 2018 | | $574 | | | $265 | | | $276 | | | $563 | |
| Notes: | | | | | | | | |
| (1) A portion of the charges to income are deferred as a regulatory asset. |
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2020, 2019, and 2018 |
| (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
(1) | | Deductions (2) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2020 | | $3,226 | | | $14,204 | | | $0 | | | $17,430 | |
| 2019 | | $3,222 | | | $316 | | | $312 | | | $3,226 | |
| 2018 | | $3,057 | | | $187 | | | $22 | | | $3,222 | |
| Notes: | | | | | | | | |
| (1) A portion of the charges to income are deferred as a regulatory asset. |
| (2) 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, 2020, 2019, and 2018 |
| (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
(1) | | Deductions (2) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2020 | | $471 | | | $16,554 | | | $215 | | | $16,810 | |
| 2019 | | $461 | | | $321 | | | $311 | | | $471 | |
| 2018 | | $463 | | | $279 | | | $281 | | | $461 | |
| Notes: | | | | | | | | |
| (1) A portion of the charges to income are deferred as a regulatory asset. |
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |