UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended September 30, 20152016
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____
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Commission | | Registrants; States of Incorporation; | | I.R.S. Employer |
File Number | | Address and Telephone Number | | Identification Nos. |
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1-3525 | | AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation) | | 13-4922640 |
1-3457 | | APPALACHIAN POWER COMPANY (A Virginia Corporation) | | 54-0124790 |
1-3570 | | INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) | | 35-0410455 |
1-6543 | | OHIO POWER COMPANY (An Ohio Corporation) | | 31-4271000 |
0-343 | | PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation) | | 73-0410895 |
1-3146 | | SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) | | 72-0323455 |
| | 1 Riverside Plaza, Columbus, Ohio 43215-2373 | | |
| | Telephone (614) 716-1000 | | |
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Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. |
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Yes | X | | No | | |
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Indicate by check mark whether the registrants have submitted electronically and posted on their corporate websites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). |
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Yes | X | | No | | |
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Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. |
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Large accelerated filer | X | | Accelerated filer | | |
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Non-accelerated filer | | | Smaller reporting company | | |
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Indicate by check mark whether Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers or smaller reporting companies. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. |
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Large accelerated filer | | | Accelerated filer | | |
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Non-accelerated filer | X | | Smaller reporting company | | |
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Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act). |
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Yes | | | No | X | |
Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.
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| Number of shares of common stock outstanding of the registrantsRegistrants as of
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| October 22, 2015November 1, 2016 |
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American Electric Power Company, Inc. | 490,817,402491,711,533 |
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| ($6.50 par value) |
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Appalachian Power Company | 13,499,500 |
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| (no par value) |
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Indiana Michigan Power Company | 1,400,000 |
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| (no par value) |
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Ohio Power Company | 27,952,473 |
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| (no par value) |
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Public Service Company of Oklahoma | 9,013,000 |
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| ($15 par value) |
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Southwestern Electric Power Company | 7,536,640 |
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| ($18 par value) |
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES |
INDEX OF QUARTERLY REPORTS ON FORM 10-Q |
September 30, 20152016 |
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Glossary of Terms | |
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Forward-Looking Information | |
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Part I. FINANCIAL INFORMATION | |
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| Items 1, 2, 3 and 4 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Controls and Procedures: | |
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American Electric Power Company, Inc. and Subsidiary Companies: | |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
| Condensed Consolidated Financial Statements | |
| Index of Condensed Notes to Condensed Consolidated Financial Statements | |
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Appalachian Power Company and Subsidiaries: | |
| Management’s Narrative Discussion and Analysis of Results of Operations | |
| Condensed Consolidated Financial Statements | |
| Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | |
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Indiana Michigan Power Company and Subsidiaries: | |
| Management’s Narrative Discussion and Analysis of Results of Operations | |
| Condensed Consolidated Financial Statements | |
| Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | |
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Ohio Power Company and Subsidiaries: | |
| Management’s Narrative Discussion and Analysis of Results of Operations | |
| Condensed Consolidated Financial Statements | |
| Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | |
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Public Service Company of Oklahoma: | |
| Management’s Narrative Discussion and Analysis of Results of Operations | |
| Condensed Financial Statements | |
| Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | |
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Southwestern Electric Power Company Consolidated: | |
| Management’s Narrative Discussion and Analysis of Results of Operations | |
| Condensed Consolidated Financial Statements | |
| Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | |
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Index of Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants | |
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Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries | |
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Controls and Procedures | |
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Part II. OTHER INFORMATION | |
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| Item 1. | Legal Proceedings | |
| Item 1A. | Risk Factors | |
| Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | |
| Item 4. | Mine Safety Disclosures | |
| Item 5. | Other Information | |
| Item 6. | Exhibits: | |
| | | Exhibit 10(a) | |
| | | Exhibit 10(b) | |
| | | Exhibit 10(c) | |
| | | Exhibit 10(d) | |
| | | Exhibit 12 | |
| | | Exhibit 31(a) | |
| | | Exhibit 31(b) | |
| | | Exhibit 32(a) | |
| | | Exhibit 32(b) | |
| | | Exhibit 95 | |
| | | Exhibit 101.INS | |
| | | Exhibit 101.SCH | |
| | | Exhibit 101.CAL | |
| | | Exhibit 101.DEF | |
| | | Exhibit 101.LAB | |
| | | Exhibit 101.PRE | |
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SIGNATURE | | | |
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This combined Form 10-Q is separately filed by American Electric Power Company, Inc., Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants. |
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
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Term | | Meaning |
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AEGCo | | AEP Generating Company, an AEP electric utility subsidiary. |
AEP or Parent | | American Electric Power Company, Inc., an investor-owned electric public utility holding company. |
AEP Consolidated | | AEPcompany which includes American Electric Power Company, Inc. (Parent) and its majority owned consolidated subsidiaries and consolidated affiliates. |
AEP Credit | | AEP Credit, Inc., a consolidated variable interest entity of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies. |
AEP East Companies | | APCo, I&M, KPCo and OPCo. |
AEP Energy | | AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States. |
AEPRO | | AEP River Operations, LLC. |
AEP System | | American Electric Power System, an electric system, owned and operated by AEP subsidiaries. |
AEP Transmission Holdco | | AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP. |
AEPEP | | AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in the deregulated Ohio and Texas market. |
AEPRO | | AEP River Operations, LLC. |
AEPSC | | American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries. |
AEPTCo | | AEP Transmission Company, LLC, a subsidiary of AEP Transmission Holdco and an intermediate holding company that owns seven wholly-owned transmission companies. |
AFUDC | | Allowance for Funds Used During Construction. |
AGR | | AEP Generation Resources Inc., a nonregulatedcompetitive AEP subsidiary in the Generation & Marketing segment. |
AFUDC | | Allowance for Funds Used During Construction. |
AOCI | | Accumulated Other Comprehensive Income. |
APCo | | Appalachian Power Company, an AEP electric utility subsidiary. |
Appalachian Consumer Rate Relief Funding | | Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance. |
APSC | | Arkansas Public Service Commission. |
ASU | | Accounting Standards Update. |
CAA | | Clean Air Act. |
CLECO | | Central Louisiana Electric Company, a nonaffiliated utility company. |
CO2 | | Carbon dioxide and other greenhouse gases. |
Cook Plant | | Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M. |
CRES provider | | Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service. |
CWIP | | Construction Work in Progress. |
DCC Fuel | | DCC Fuel IV LLC, DCC Fuel VI LLC, DCC Fuel VII, DCC Fuel VIII and DCC Fuel VIII LLC,IX, consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. |
Desert Sky | | Desert Sky Wind Farm, a 160.5 MW wind electricity generation facility located on Indian Mesa in Pecos County, Texas. |
DHLC | | Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo. |
EIS | | Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entity of AEP. |
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Term | | Meaning |
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ENEC | | Expanded Net Energy Charge.Cost. |
Energy Supply | | AEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP. |
ERCOT | | Electric Reliability Council of Texas regional transmission organization. |
ESP | | Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO. |
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Term | | Meaning |
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ETT | | Electric Transmission Texas, LLC, an equity interest joint venture between AEPParent and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT. |
FAC | | Fuel Adjustment Clause. |
FASB | | Financial Accounting Standards Board. |
Federal EPA | | United States Environmental Protection Agency. |
FERC | | Federal Energy Regulatory Commission. |
FGD | | Flue Gas Desulfurization or scrubbers. |
FTR | | Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices. |
GAAP | | Accounting Principles Generally Accepted in the United States of America. |
I&M | | Indiana Michigan Power Company, an AEP electric utility subsidiary. |
IEU | | Industrial Energy Users-Ohio. |
IGCC | | Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas. |
IMT | | International Marine Terminals, an equity method investment of AEPRO. |
Interconnection Agreement | | An agreement by and among APCo, I&M, KPCo and OPCo, which defined the sharing of costs and benefits associated with their respective generation plants. This agreement was terminated January 1, 2014. |
IRS | | Internal Revenue Service. |
IURC | | Indiana Utility Regulatory Commission. |
KGPCo | | Kingsport Power Company, an AEP electric utility subsidiary. |
KPCo | | Kentucky Power Company, an AEP electric utility subsidiary. |
KPSC | | Kentucky Public Service Commission. |
KWh | | Kilowatthour. |
LPSC | | Louisiana Public Service Commission. |
MISO | | Midwest Independent Transmission System Operator. |
MMBtu | | Million British Thermal Units. |
MPSC | | Michigan Public Service Commission. |
MTM | | Mark-to-Market. |
MW | | Megawatt. |
MWh | | Megawatthour. |
NOx | | Nitrogen oxide. |
Nonutility Money Pool | | Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries. |
NSR | | New Source Review. |
OCC | | Corporation Commission of the State of Oklahoma. |
Ohio Phase-in-Recovery Funding | | Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property. |
OPCo | | Ohio Power Company, an AEP electric utility subsidiary. |
OPEB | | Other Postretirement Benefit Plans. |
OTC | | Over the counter. |
OVEC | | Ohio Valley Electric Corporation, which is 43.47% owned by AEP. |
Parent | | American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation. |
PIRR | | Phase-In Recovery Rider. |
PJM | | Pennsylvania – New Jersey – Maryland regional transmission organization. |
PM | | Particulate Matter. |
PPA | | Power Purchase and Sale Agreement. |
Price River | | Rights and interests in certain coal reserves located in Carbon County, Utah. |
PSO | | Public Service Company of Oklahoma, an AEP electric utility subsidiary. |
PUCO | | Public Utilities Commission of Ohio. |
PUCT | | Public Utility Commission of Texas. |
Registrant Subsidiaries | | AEP subsidiaries which are SEC registrants; APCo, I&M, OPCo, PSO and SWEPCo. |
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Term | | Meaning |
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PUCT | | Public Utility Commission of Texas. |
Putnam | | Rights and interests in certain coal reserves located in Putnam, Mason and Jackson Counties, West Virginia. |
Registrant Subsidiaries | | AEP subsidiaries which are SEC registrants: APCo, I&M, OPCo, PSO and SWEPCo. |
Registrants | | SEC registrants: AEP, APCo, I&M, OPCo, PSO and SWEPCo. |
Risk Management Contracts | | Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges. |
Rockport Plant | | A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2. |
RPM | | Reliability Pricing Model. |
RSR | | Retail Stability Rider. |
RTO | | Regional Transmission Organization, responsible for moving electricity over large interstate areas. |
Sabine | | Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo. |
SEC | | U.S. Securities and Exchange Commission. |
SEET | | Significantly Excessive Earnings Test. |
SNF | | Spent Nuclear Fuel. |
SO2 | | Sulfur dioxide. |
SPP | | Southwest Power Pool regional transmission organization. |
SSO | | Standard service offer. |
Stall Unit | | J. Lamar Stall Unit at Arsenal Hill Plant, a 534 MW natural gas unit owned by SWEPCo. |
SWEPCo | | Southwestern Electric Power Company, an AEP electric utility subsidiary. |
TCC | | AEP Texas Central Company, an AEP electric utility subsidiary. |
Texas Restructuring Legislation | | Legislation enacted in 1999 to restructure the electric utility industry in Texas. |
TNC | | AEP Texas North Company, an AEP electric utility subsidiary. |
TRA | | Tennessee Regulatory Authority. |
Transition Funding | | AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. |
Transource Energy | | Transource Energy, LLC, a consolidated variable interest entity formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. |
Transource Missouri | | A 100% wholly-owned subsidiary of Transource Energy. |
Trent | | Trent Wind Farm, a 150 MW wind electricity generation facility located between Abilene and Sweetwater in West Texas. |
Turk Plant | | John W. Turk, Jr. Plant, a 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo. |
Utility Money Pool | | Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries. |
VIE | | Variable Interest Entity. |
Virginia SCC | | Virginia State Corporation Commission. |
WPCo | | Wheeling Power Company, an AEP electric utility subsidiary. |
WVPSC | | Public Service Commission of West Virginia. |
FORWARD-LOOKING INFORMATION
This report made by AEP and its Registrant Subsidiariesthe Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 20142015 Annual Report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook. These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected. Forward-looking statements in this document are presented as of the date of this document. Except to the extent required by applicable law, we undertakemanagement undertakes no obligation to update or revise any forward-looking statement. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:
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Ÿ | The economic climate, growth or contraction within and changes in market demand and demographic patterns in ourAEP service territory.territories. |
Ÿ | Inflationary or deflationary interest rate trends. |
Ÿ | Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt. |
Ÿ | The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material. |
Ÿ | Electric load, customer growth and the impact of competition, including competition for retail customers. |
Ÿ | Weather conditions, including storms and drought conditions, and ourthe ability to recover significant storm restoration costs. |
Ÿ | The cost of fuel and its transportation and the creditworthiness and performance of fuel suppliers and transporters. |
Ÿ | Availability of necessary generation capacity and the performance of our generation plants. |
Ÿ | OurThe ability to recover fuel and other energy costs through regulated or competitive electric rates. |
Ÿ | OurThe ability to build transmission lines and facilities (including ourthe ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs. |
Ÿ | New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation, cost recovery and/or profitability of our generation plants and related assets. |
Ÿ | Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel. |
Ÿ | A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers. |
Ÿ | Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance. |
Ÿ | Resolution of litigation. |
Ÿ | OurThe ability to constrain operation and maintenance costs. |
Ÿ | OurThe ability to develop and execute a strategy based on a view regarding prices of electricity and other energy-related commodities.gas. |
Ÿ | Prices and demand for power that we generategenerated and sellsold at wholesale. |
Ÿ | Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation. |
Ÿ | OurThe ability to recover through rates or market prices any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives. |
Ÿ | Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas and capacity auction returns. |
Ÿ | Changes in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP. |
Ÿ | The market for generation in Ohio and PJM and ourthe ability to recover investments in our Ohio generation assets. |
Ÿ | OurThe ability to successfully and profitably manage our competitive generation assets, including ourthe evaluation and execution of strategic alternatives for these assets as some of the alternatives could result in a loss. |
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Ÿ | Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market. |
Ÿ | Actions of rating agencies, including changes in the ratings of our debt. |
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Ÿ | The impact of volatility in the capital markets on the value of the investments held by ourthe pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements. |
Ÿ | Accounting pronouncements periodically issued by accounting standard-setting bodies. |
Ÿ | Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events. |
The forward lookingforward-looking statements of AEP and its Registrant Subsidiariesthe Registrants speak only as of the date of this report or as of the date they are made. AEP and its Registrant SubsidiariesThe Registrants expressly disclaim any obligation to update any forward-looking information. For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 20142015 Annual Report and in Part II of this report.
Investors should note that the Registrants announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, the Registrants may use the Investors section of AEP’s website (www.aep.com) to communicate with investors about the Registrants. It is possible that the financial and other information posted there could be deemed to be material information. The information on AEP’s website is not part of this report.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
EXECUTIVE OVERVIEW
Customer Demand
OurAEP’s weather-normalized retail sales volumes for the third quarter of 2015 increased2016 decreased by 0.9%0.5% from the third quarter of 2014. Our2015. AEP’s third quarter 20152016 industrial sales increased 0.7%decreased 2.6% compared to the third quarter of 20142015 primarily due to increaseddecreased sales to customers in oil and gas related sectors.the manufacturing sector. Weather-normalized commercial and residential sales increased 1.3%by 1.2% and 0.8%commercial sales decreased by 0.5% in the third quarter of 2015,2016, respectively, from the third quarter of 2014.2015.
Our
AEP’s weather-normalized retail sales volumes for the nine months ended September 30, 2015 increased 0.1%2016 decreased by 0.4% compared to the nine months ended September 30, 2014. Industrial2015. AEP’s industrial sales volumes increased 0.8%for the nine months ended September 30, 2016 decreased 1.9% compared to 2014, while weather-normalizedthe nine months ended September 30, 2015 primarily due to decreased sales to customers in the manufacturing sector. Weather-normalized residential and commercial sales increased by 1.0%. Weather-normalized residential sales decreased 1.1% in comparison0.5% and 0.4%, respectively, for the nine months ended September 30, 2016 compared to nine months ended September 30, 2015.
June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024
In March 2016, a contested stipulation agreement related to the first nine months of 2014.
Merchant Fleet Alternatives
AEPPPA rider application was modified and approved by the PUCO. The approved PPA rider is evaluating strategic alternatives for its merchant generation fleet,effective April 2016 through May 2024, subject to audit and review by the PUCO. The stipulation agreement, as approved, included (a) an Affiliate PPA between OPCo and AGR to be included in the Generation & Marketing segment, which primarily includes AGR’sPPA rider, (b) OPCo’s OVEC PPA to be included in the PPA rider, (c) potential additional contingent customer credits of up to $100 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions.
In March 2016, a group of merchant generation fleetowners filed a complaint at the FERC against PJM seeking revisions to the Minimum Offer Price Rule (MOPR) in PJM’s tariff. Although the complaint requested the FERC act in advance of the May 2016 Base Residual Auction for the 2019/2020 delivery year, the complaint is still pending without a decision from the FERC. If approved as proposed, the revised MOPR could affect future bidding behavior for units with cost recovery mechanisms.
In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and AEGCo's Lawrenceburg Plant, bothOPCo. The FERC order rescinded the waivers of which operatethe FERC’s affiliate rules as to the affiliate PPA between AGR and OPCo. As a result, AGR and OPCo cannot implement the affiliate PPA without the FERC review, in PJM as well asaccordance with FERC’s rules governing affiliate transactions. As a purchased power agreementresult of the April 2016 FERC order, management does not intend to pursue the affiliate PPA.
In May 2016, OPCo filed an application for rehearing with the PUCO related to certain aspects of the March 2016 PUCO order. The application included a 54.7% interestproposed OVEC-only PPA Rider that included an option for the rider to be bypassable. The proposed OVEC-only PPA Rider included (a) the elimination of the PUCO-imposed customer-specific rate impact cap of 5% through May 2018, (b) modifications to proportionately decrease the amount of the potential customer credits and (c) the inclusion of PJM capacity performance penalties within the PPA rider. Also in May 2016, intervenors filed applications for rehearing with the PUCO opposing the modified and approved stipulation agreement.
OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO does not accept the requested modifications.
Consistent with the terms of the modified and approved stipulation agreement, in May 2016, OPCo filed an amended ESP that proposed to extend the ESP through May 2024. The amended ESP included (a) an extension of the PPA rider, which includes only OPCo’s entitlements to its ownership percentage of OVEC, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the Oklaunion Plant which operatesJune 2015 - May 2018 ESP, (d) proposed increases in ERCOT. Potential alternatives may include, but arerate caps related to OPCo’s Distribution Investment Rider and (e) the addition of various new riders, including a Generation Resource Rider. Based upon a September 2016 PUCO order, OPCo will refile its ESP extension application and supporting testimony in November 2016.
If OPCo is ultimately not limitedpermitted to continued ownershipfully collect all components of the merchant generation fleet, executing a purchased power agreement with a regulated affiliate for certain merchant generation units in Ohio, a spin-off of the merchant generation fleet or a sale of the merchant generation fleet. We have not made a decision regarding the potential alternatives, nor have we set a specific time frame for a decision. Certain of these alternatives could result in a loss whichits ESP rates, it could reduce future net income and cash flowflows and impact financial condition. See “Ohio Electric Security Plan Filings” section of Note 4.
Ohio Electric Security Plan Filings
2009 - 2011 ESP
In 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and remanded the matter back to the PUCO for reinstatement of the WACC rate. In June 2016, the PUCO approved OPCo’s proposed increase to the PIRR rates, in accordance with the Supreme Court of Ohio ruling. The increase to PIRR rates included $146 million in additional carrying charges and the recovery of $40 million in additional under-recovered fuel costs resulting from a decrease in customer demand. The increase is effective July 2016 through December 2018. In July 2016, intervenors filed requests for rehearing with the PUCO, which the PUCO granted in August 2016.
If the PUCO determines after rehearing that the additional PIRR carrying charges are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Disposition of AEP River OperationsJune 2012 - May 2015 ESP Including Capacity Charge
In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. In 2013, this ruling was generally upheld in PUCO rehearing orders.
In July 2012, the PUCO issued an order in a separate capacity proceeding requiring OPCo to charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The OPCo RPM price collected from CRES providers, which included reserve margins, was approximately $34/MW day through May 2014 and $150/MW day from June 2014 through May 2015. In April 2016, the Supreme Court of Ohio issued two opinions related to the deferral of OPCo’s capacity charges. In one of the opinions, the Supreme Court of Ohio ruled that the PUCO must reconsider an energy credit that was used to determine OPCo’s authorized capacity deferral threshold of $188.88/MW day during the August 2012 through May 2015 period. The PUCO reduced OPCo’s authorized capacity deferral threshold to $188.88/MW day largely due to an offset for an energy credit of $147.41/MW day. The Supreme Court of Ohio directed the PUCO to substantively address OPCo’s arguments that the $147.41/MW day credit was overstated by approximately $100/MW day due to various inaccuracies affecting input data and assumptions.
As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50/MWh through May 2014 and at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that modified and approved OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. As of September 30, 2016, OPCo’s net deferred capacity costs balance was $239 million,
including debt carrying costs. In April 2016, the second Supreme Court of Ohio opinion rejected a portion of OPCo’s RSR revenues collected during the period September 2012 through May 2015 and directed the PUCO to reduce OPCo’s deferred capacity costs by these previously collected RSR revenues. The Supreme Court of Ohio was not able to determine the amount of the reduction to OPCo’s deferred capacity costs and remanded the issue to the PUCO to determine the appropriate reduction. As directed by the PUCO, in May 2016, OPCo submitted revised RSR tariffs that reflect the RSR being collected subject to refund.
In April 2016, the Supreme Court of Ohio also ruled favorably on OPCo’s cross-appeal regarding a previously PUCO-imposed SEET threshold under the ESP and remanded this issue to the PUCO. See “Significantly Excessive Earnings Test Filings” section of Note 4.
In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.
In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report with the PUCO for the period August 2012 through May 2015. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo’s $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report.
In June 2016, OPCo filed a request with the PUCO that requested a consolidated procedural schedule to resolve interrelated proceedings including (a) OPCo’s deferral of capacity costs for the period August 2012 through May 2015, we(b) the implementation of OPCo’s RSR and (c) the concerns related to the recovery of fixed fuel costs through both the FAC and the approved capacity charges. As part of the filing, OPCo requested that its net deferred capacity costs balance as of May 31, 2015 increase by $157 million, including carrying charges through September 2016. This net increase consists of a $327 million decrease due to the non-deferral portion of the RSR collections and an increase of $484 million for the correction of the energy credit. Recovery of the $157 million was requested to be effective October 2016 through December 2018. Additionally, OPCo filed testimony supporting the position that double recovery of fixed fuel costs could not have occurred because OPCo was unable to fully recover its capacity costs, which included fixed fuel costs, even with a corrected energy credit.
Due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, management believes that the PUCO will rule upon these issues together. Further, management believes that the net impact of these issues will not result in a material future reduction of OPCo’s net income. The recovery of fixed fuel costs will be addressed in a separate hearing scheduled for January 2017. See “2012 and 2013 Fuel Adjustment Clause Audits” section of Note 4.
If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filings” section of Note 4.
Merchant Generation Assets
In September 2016, AEP signed an agreement to sell our commercial barge transportation subsidiary, AEPRO,Darby, Gavin, Lawrenceburg and Waterford Plants (“Disposition Plants”) totaling 5,326 MWs of competitive generation for approximately $2.2 billion to a nonaffiliated party. The sale of AEPRO is subject to regulatory approval includingapprovals from the FERC, the IURC and federal clearance pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Upon close1976 (HSR). In October 2016, the Federal Trade Commission granted the sale early termination of the sale,HSR waiting period thereby satisfying the nonaffiliated party will acquire AEPRO by purchasing allHSR conditions to close the transaction. As of September 30, 2016, the common stocknet book value of these assets, including related materials and supplies inventory and CWIP, was $1.8 billion. AEP Resources, Inc., the parent companyexpects to receive net proceeds of AEPRO. The nonaffiliated party will assume certain assets and liabilities of AEPRO, excluding the equity method investment in International Marine Terminals (IMT) which is a bulk commodity transfer facility jointly owned with Kinder Morgan L.P. "C", pension and benefit assets and liabilities and debt obligations. We expect to net approximately $400 million$1.2 billion in cash after taxes, debt retirement and transaction fees. AEP is evaluating options to invest these proceeds, including reinvestment in regulated businesses and renewable energy projects and additional debt retirement. The sale is expected to close in the fourthfirst quarter of 2015.2017. An after tax gain ranging fromof approximately $100 million to $150 million is expected from the sale subject to working capitalinventory true-ups, income tax and other adjustments.
AEPRO'sThe assets and liabilities included in the sale transaction have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on our condensedthe balance sheetssheet as of September 30, 20152016. See “Assets and December 31, 2014. The results of operations of AEPRO have been classified as Discontinued Operations on our condensed statements of income. See "AEPRO (AEP River Operations Segment)"Liabilities Held for Sale” section of Note 6 for additional information.
In September 2016, due to AEP’s ongoing evaluation of strategic alternatives for its merchant generation assets, declining forecasts of future energy and capacity prices, and a decreasing likelihood of cost recovery through regulatory proceedings or legislation in the state of Ohio providing for the recovery of AEP’s existing Ohio merchant generation assets, AEP performed an impairment analysis at the unit level on the remaining merchant generation assets in accordance with accounting guidance for impairments of long-lived assets. The evaluation was performed using generating unit specific estimated future cash flows and resulted in a material impairment of certain merchant generation fleet assets. As a result, AEP recorded a pretax impairment of $2.3 billion ($1.5 billion, net of tax) in Asset Impairments and Other Related Charges on the statement of operations related to 2,684 MWs of Ohio merchant generation including Cardinal Unit 1, 43.5% ownership interest in Conesville Unit 4, Conesville Units 5-6, 26.0% ownership interest in Stuart Units 1-4, and 25.4% ownership interest in Zimmer Unit 1, as well as Putnam coal and I&M’s Price River coal reserves, Desert Sky and Trent Wind Farms and the merchant generation portion of the Oklaunion Plant. As of September 30, 2016, the remaining net book value of these assets is $50 million. See “Merchant Generating Assets (Generation & Marketing Segment)” section of Note 6 for additional information.
Management continues to evaluate potential alternatives for the remaining merchant generation assets. These potential alternatives may include, but are not limited to, propose restructuring of Ohio electricity regulations to allow certain of these assets to be acquired by OPCo for the benefit of its customers, transfer or sale of AEP’s ownership interests, or a wind down of merchant coal-fired generation fleet operations. AEP is also continuing a separate strategic review and evaluating alternatives related to the 48 MW Racine Hydroelectric Plant. Management has not set a specific time frame for a decision on these assets. These alternatives could result in additional losses which could reduce future net income and cash flows and impact financial condition.
Renewable Generation Portfolio
The growth of AEP’s renewable generation portfolio reflects the company’s strategy to diversify generation resources to provide clean energy options to customers that meet both their energy and capacity needs.
AEP has formed two new subsidiaries within the Generation & Marketing segment to further develop its renewable portfolio. AEP OnSite Partners, LLC works directly with wholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies. AEP OnSite Partners, LLC pursues projects where a suitable termed agreement is entered into with a credit-worthy counterparty. AEP Renewables, LLC develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with credit-worthy counterparties. These subsidiaries have approximately 4 MW of renewable generation projects in operation and 56 MW of renewable generation projects under construction with an estimated financial commitment of approximately $119 million. As of September 30, 2016, $49 million of costs have been incurred related to these projects.
Merchant Portion of Turk Plant
SWEPCo constructed the Turk Plant, a base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012 and is included in the Vertically Integrated Utilities segment. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.
The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This share of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under cost-based rate recovery in Texas, Louisiana, and through SWEPCo’s wholesale customers under FERC-based rates. As of September 30, 2016, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP.
If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.
Ohio Electric Security Plan Filings
2009 - 2011 ESP
In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. In June 2015, the Supreme Court of Ohio issued a decision that reversed, as requested by OPCo, the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. In September 2015, the Supreme Court of Ohio denied the IEU's request for reconsideration and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate.
June 2012 - May 2015 Ohio ESP Including Capacity Charge
In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in PUCO rehearing orders in January and March 2013.
In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and $150/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio, which has scheduled oral arguments for the fourth quarter of 2015.
As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50/MWh through May 2014 and at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR. In April 2015, the PUCO issued an order that approved, with modifications, OPCo's July 2014 application to collect the unrecovered portion of the deferred capacity costs. In May 2015, the PUCO granted intervenors requests for rehearing. As of September 30, 2015, OPCo’s net deferred capacity costs balance was $392 million, including debt carrying costs. Through September 30, 2015, OPCo has collected $183 million in deferred capacity costs, and related carrying charges.
In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.
In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report.
If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.
June 2015 - May 2018 ESP Including PPA Application
In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA.
In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the Distribution Investment Rider (DIR) with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo's and various intervenors' requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider.
In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. A hearing at the PUCO related to the PPA commenced in September 2015. In October 2015, the PUCO staff submitted testimony that opposed the PPA application as currently proposed but concluded that, with changes, a PPA could be in the public interest.
If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filings” section of Note 4.
2012 Texas Base Rate Case
Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million. In May 2014, intervenors filed appeals of the order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned it could reduce future net income and cash flows and impact financial condition. See the “2012 Texas Base Rate Case” section of Note 4.
2012 Louisiana Formula Rate Filing
In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant. In February 2013, a settlement was approved by the LPSC that increased SWEPCo'sSWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013. The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC willwould review base rates in 2014 and 2015 and that SWEPCo willwould recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million, primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for March 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. See the “2012 Louisiana Formula Rate Filing” section of Note 4.
Welsh Plant - Environmental Impact
Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost approximately $850 million, excluding AFUDC. As of September 30, 2016, SWEPCo had incurred costs of $395 million, including AFUDC, and had remaining contractual construction obligations of $14 million related to these projects. As part of this investment, in 2016 SWEPCo completed construction of environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $370 million, excluding AFUDC. Management continues to evaluate the impact of environmental rules and related project cost estimates. In March 2016, SWEPCo filed a request with the APSC to recover $69 million in environmental costs related to the Arkansas retail jurisdictional share of Welsh Plant, Units 1 and 3, which was approved by the APSC in August 2016. SWEPCo began recovering the Arkansas jurisdictional share of these costs in March 2016, subject to review in the next filed base rate proceeding. In September 2016, SWEPCo filed an additional request to increase the Arkansas retail jurisdictional share of the environmental investment by $10 million, for a total of $79 million. SWEPCo implemented the increase in September 2016. SWEPCo will seek recovery of the remaining project costs from customers at the state commissions and the FERC. See “Mercury and Other Hazardous Air Pollutants (HAPs) Regulation” and “Climate Change, CO2 Regulation and Energy Policy” sections of “Environmental Issues” below.
As of September 30, 2016, the net book value of Welsh Plant, Units 1 and 3 was $632 million, before cost of removal, including materials and supplies inventory and CWIP. In April 2016, Welsh Plant, Unit 2 was retired. Upon retirement, $76 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Welsh Plant, Unit 2 and the related asset retirement obligation costs. Management will seek recovery of the remaining regulatory assets in future rate proceedings.
If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.
2015 Oklahoma Base Rate Case
In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million, which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the2016. The proposed $44 million forincrease related to environmental investments which iswas effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls gowere placed in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million, excluding AFUDC. As of September 30, 2016, PSO had incurred costs of $180 million and $43 million, including AFUDC, for Northeastern Plant, Unit 3 and Comanche Plant, respectively.
In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million, will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4, in April 2016, which would be recovered through the FAC. In April 2016, Northeastern Plant, Unit 4 was retired. Upon retirement, $87 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Northeastern Plant, Unit 4. These regulatory assets are pending regulatory approval.
In October 2015, testimony was filed by OCC staffJune 2016, an Administrative Law Judge (ALJ) issued a report related to PSO’s base rate case filing and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million, based upon returnssubsequently provided an additional supplemental report in August 2016. The ALJ recommended a 9.25% return on common equity ranging from 8.75% to 9.3%,equity. The ALJ found that PSO’s environmental compliance plan is prudent and increases to depreciation expense ranging from $23 million to $46 million. Additionally, recommendations by certain intervenors included (a) noprovided for cost recovery of PSO’sthe investment in this case with a recommended investment cap of $210 million on environmental controls installed at Northeastern Plant, Unit 3 environmental controls, (b) no recovery of3. Additionally, the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certain intervenors did not support anALJ recommendations included (a) a $14 million increase in depreciation expense, for the(b) continued depreciation of Northeastern Plant, Units 3 and 4 through 2040 (no accelerated depreciation), (c) return of, but no return on, the remaining net book value of Northeastern Plant, Unit 4, (d) elimination of the rider to permit costrecover advanced metering starting in December 2016, without inclusion in base rates and (e) elimination of the system reliability rider through consolidation in base rates, without addressing a transition for recovery by Unit 3’s 2026 retirement date asof rider costs, including deferred costs. The estimated annual revenue increase resulting from the proposals called for no change in existing cost recovery by 2040. Hearings atALJ recommendations is approximately $47 million.
In June and September 2016, PSO, the OCC are scheduled for December 2015. staff, the Attorney General and intervenors filed exceptions to the ALJ reports. The OCC staff filed exceptions that supported the full recovery of Northeastern Plant, Unit 4, including a return, and recommended a $32 million increase in annual revenues. An order from the OCC is anticipated in the fourth quarter of 2016.
If any of these costs, including a return on Northeastern Plant, Unit 4, are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2015 Oklahoma Base Rate Case"Case” section of Note 4.
2015
Indiana Amended PJM Settlement Agreement
In September 2016, I&M and certain intervenors filed an amended settlement agreement with the IURC. This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017.
The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018. Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018. A hearing at the IURC was held in October 2016.
Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR)
In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NOx from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs, depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates.
TCC and TNC Merger
In June 2016, TCC and TNC filed applications with the PUCT and FERC that requested approval to merge TCC and TNC into AEP Utilities, Inc. Upon merger, AEP Utilities, Inc. will change its name to AEP Texas Inc. The proposed merger would be effective December 31, 2016. The applications proposed no changes to current TCC and TNC rates. A hearing at the PUCT was held in August 2016. In September 2016, the FERC issued an order approving the merger application. In October 2016, the ALJ issued a proposal for decision that recommends approval of the merger provided certain post-merger conditions are imposed. The conditions recommended by the ALJ include a) the sharing of certain interest rate savings with customers and b) an annual credit to customers of approximately $630 thousand for savings resulting from an expected reduction in post-merger debt issuance costs, effective until the next base rate case. Management is evaluating the conditions recommended by the ALJ. A decision from the PUCT is expected in the fourth quarter of 2016.
FERC Transmission Complaint
In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM Open Access Transmission Tariff (OATT) is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. Management is reviewing the filing and evaluating a response to the complaint. Management is unable to determine a range of potential losses, if any, that is reasonably possible of occurring. If the FERC orders revenue reductions, including refunds from the date of filing, it could reduce future net income and cash flows and impact financial condition.
Kingsport Base Rate Case
In September 2015,January 2016, KGPCo filed a request with the TRA to increase base rates by $12 million annually based upon a proposed return on common equity of 10.66%. In August 2016, the TRA approved a settlement agreement that included an $8 million annual increase in base rates with the new rates expected to be implemented by Julya 9.85% return on common equity effective September 2016. See the “2015 Kingsport Base Rate Case" section of Note 4.
New Virginia Legislation Affecting Biennial Reviews
In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo'sAPCo’s financial statements adequately address the impact of these amendments. The new law providesamendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA.
Kentucky Fuel Adjustment Clause Review
In January 2015,February 2016, certain APCo industrial customers filed a petition with the KPSCVirginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning in 2016. In July 2016, the Virginia SCC issued an order disallowingthat denied the petition. In July 2016, intervenors, including certain FAC costs during the period of January 2014 through May 2015 while KPCo owned and operated both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCoAPCo industrial customers, filed an appeal of thisthe order with the Franklin County Circuit Court. In September 2015,Supreme Court of Virginia. Management is unable to predict the Franklin County Circuit Court issued an order that dismissed all appeals filed related to this FAC review, as agreed to by the partiesoutcome of these challenges to the stipulation agreementVirginia legislation. If the biennial review process is reinstated in the "2014 Kentucky Base Rate Case" discussed in Note 4.advance of March 2020, it could reduce future net income and cash flows and impact financial condition.
PJM Capacity Market
AGR is required to offer all of its available generation capacity in the PJM Reliability Pricing Model (RPM) auction, which is conducted three years in advance of the delivery year.
Through May 2015, AGR provided generation capacity to OPCo for both switched and non-switched OPCo generation customers. For switched customers, OPCo paid AGR $188.88/MW day for capacity. For non-switched OPCo generation customers, OPCo paid AGR its blended tariff rate for capacity consisting of $188.88/MW day for auctioned load and the non-fuel generation portion of its base rate for non-auctioned load. As of June 2015, AGR's generation resources are compensated through the PJM capacity auction. Shown below are the RPM results through the June 2017 through May 2018 period:
|
| | |
| | PJM |
PJM Auction Period | | Auction Price |
| | (per MW day) |
June 2013 through May 2014 | | $27.73 |
June 2014 through May 2015 | | 125.99 |
June 2015 through May 2016 | | 136.00 |
June 2016 through May 2017 | | 59.37 |
June 2017 through May 2018 | | 120.00 |
In June 2015, FERC approved PJM’s proposal to create a new Capacity Performance (CP) product, intended to improve generator performance and reliability during emergency events by allowing higher offers into the RPM auction and imposing greater charges for non-performance during emergency events. PJM will procureprocured approximately 80% CP and 20% Base Capacity for the June 2018 through May 2019 and June 2019 through May 2020 periods, while transitioning to 100% CP with the June 2020 through May 2021 period. FERC also approved transition incremental auctions to procure CP for the June 2016 through May 2017 and June 2017 through May 2018 periods.
In the third quarter of 2015, PJM conducted the two transition auctions. The transition auctions allowed generators, including AGR, to re-offer cleared capacity that qualifies as CP. Shown below are the results of the two transition auctions:
|
| | |
| | Capacity Performance Transition |
PJM Auction Period | | Incremental Auction Price |
| | (dollars per MW day) |
June 2016 through May 2017 | | $134.00 |
June 2017 through May 2018 | | 151.50 |
AGR cleared 7,169MW at $134/MW-day for the June 2016 through May 2017 period, replacing the original auction clearing price of $59.37/MW-day. AGR cleared 6,495MW for the June 2017 through May 2018 period at $151.50/MW-day, replacing the original auction clearing price of $120/MW-day.
In August 2015, PJM held its first Base Residual Auctionbase residual auction implementing CP rules for the June 2018 through May 2019 period. PJM cleared approximately 81% of the capacity for the June 2018 through May 2019 period as CP and 19% as Base Capacity. AGR cleared 7,209 MW at the CP auction price of $164.77/MW-day. The base residual auction for the June 2019 through May 2020 period was conducted in May 2016. AGR cleared 7,301 MW at the CP auction price of $100/MW-day. Shown below are the results for the June 2018 through May 2019 period:and June 2019 through May 2020 periods:
| | | | Capacity Performance | | Base Capacity | | Capacity Performance | | Base Capacity |
PJM Auction Period | | Auction Price | | Auction Price | | Auction Price | | Auction Price |
| | (per MW day) | | (per MW day) | | (dollars per MW day) | | (dollars per MW day) |
June 2018 through May 2019 | | $164.77 | | $150.00 | | 164.77 | | 150.00 |
June 2019 through May 2020 | | | 100.00 | | 80.00 |
Once the pending sale of the Darby, Gavin, Lawrenceburg and Waterford Plants is closed, AGR will not be responsible for or receive capacity revenue for the portion of the cleared capacity associated with these plants.
The FERC order exempted Fixed Resource Requirement (FRR) entities, including APCo, I&M, KPCo and WPCo, from the CP rules through the delivery period ending May 2019. Beginning in June 2018 through May 2019, period. In July 2015, AEP filed a request seeking rehearing of the FERC order approvingFRR entities are subject to CP and will continue to advocate for further improvements through the PJM stakeholder process.rules.
Welsh Plant, Units 1 and 3 - Environmental Projects
To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2024 for Welsh Plant, Units 1 and 3 will cost approximately $700 million, excluding AFUDC. As of September 30, 2015, SWEPCo has incurred costs of $303 million, including AFUDC, and has remaining contractual construction obligations of $62 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. See "Mercury and Other Hazardous Air Pollutants (HAPs) Regulation" and "Climate Change, CO2 Regulation and Energy Policy" sections of “Environmental Issues” below. As of September 30, 2015, the net book value of Welsh Plant, Units 1 and 3 was $529 million, before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
LITIGATION
In the ordinary course of business, we areAEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, wemanagement cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. We assessManagement assesses the probability of loss for each contingency and accrueaccrues a liability for cases that have a probable likelihood of loss if the loss can be estimated. For details on ourthe regulatory proceedings and pending litigation see Note 4 - Rate Matters, Note 6 - Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 20142015 Annual Report. Additionally, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies included herein. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.
Rockport Plant Litigation
In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted oura motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’plaintiff’s claims. Several claims remain,remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. PlaintiffsThe plaintiff subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. We will continueIn November 2015, AEGCo and I&M filed a motion to defend againststrike the plaintiff’s motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims. Weclaims with prejudice and the court subsequently entered a final judgment. In May 2016, Plaintiffs filed a notice of appeal on whether AEGCo and
I&M are in breach of certain contract provisions that Plaintiffs allege operate to protect the Plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing Plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. This matter is currently pending before the U.S. Court of Appeals for the Sixth Circuit. Management is unable to determine a range of potential losses that are reasonably possible of occurring.
ENVIRONMENTAL ISSUES
We areAEP is implementing a substantial capital investment program and incurring additional operational costs to comply with environmental control requirements. WeAdditional investments and operational changes will need to make additional investments and operational changesbe made in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM, CO2and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, rules governing the beneficial use and disposal of coal combustion products, proposed and final clean water rules and renewal permits for certain water discharges that are currently under appeal.discharges.
We areAEP is engaged in litigation about environmental issues, have beenwas notified of potential responsibility for the clean-up of contaminated sites and incurincurred costs for disposal of SNF and future decommissioning of ourthe nuclear units. We,AEP, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court. We areManagement is also engaged in the development of possible future requirements including the items discussed below and reductions ofstate plans to reduce CO2 emissions to address concerns about global climate change. We believeManagement believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.
See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 20142015 Annual Report. WeAEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If we areAEP is unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.
Environmental Controls Impact on the Generating Fleet
The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System. We continueManagement continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of September 30, 2015,2016, the AEP System had a total generating capacity of approximately 32,10031,000 MWs, of which approximately 18,20016,000 MWs are coal-fired. We continueManagement continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on ourthe fossil generating facilities. Based upon ourmanagement estimates, AEP’s investment to meet these proposed requirements ranges from approximately $2.8 billion to $3.3$3.4 billion through 2020. These amounts2025. Management continues to evaluate the impact of the merchant fleet operations on this range. The estimates include investments to convert some of ourthe coal generation to natural gas.
The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules. The cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans (SIPs) or federal implementation plans (FIPs) that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on ourthe units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors. In addition, we aremanagement is continuing to evaluate the economic feasibility of environmental investments on both regulated and nonregulatedcompetitive plants.
In May 2015, we retired the following plants or units of plants:plants were retired:
|
| | | | | |
| | | | Generating |
Company | | Plant Name and Unit | | Capacity |
| | | | (in MWs) |
AGR | | Kammer Plant | | 630 |
|
AGR | | Muskingum River Plant | | 1,440 |
|
AGR | | Picway Plant | | 100 |
|
APCo | | Clinch River Plant, Unit 3 | | 235 |
|
APCo | | Glen Lyn Plant | | 335 |
|
APCo | | Kanawha River Plant | | 400 |
|
APCo/AGR | | Sporn Plant | | 600 |
|
I&M | | Tanners Creek Plant | | 995 |
|
KPCo | | Big Sandy Plant, Unit 2 | | 800 |
|
Total | | | | 5,535 |
|
As of September 30, 2015,2016, the net book value of the AGR units listed above was zero. The net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of the regulated plants in the table above has beenwas approved for recovery, except for $147$144 million which is pendingmanagement plans to seek regulatory approval.
Subject to the factors listed above and based upon our continuing evaluation, we intend to retireIn April 2016, AEP retired the following units of plants during 2016:plants:
|
| | | | | |
| | | | Generating |
Company | | Plant Name and Unit | | Capacity |
| | | | (in MWs) |
PSO | | Northeastern Station, Unit 4 | | 470 |
|
SWEPCo | | Welsh Plant, Unit 2 | | 528 |
|
Total | | | | 998 |
|
As of September 30, 2015, the net book value of the PSO and SWEPCo units listed above before cost of removal, including related materials and supplies inventory and CWIP balances, was $177 million. Volatility in fuel prices, pending environmental rules and other market factors could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of coal-fired units. For Northeastern Station, Unit 4 and Welsh Plant, Unit 2, we are seeking regulatory recovery of remaining net book values.
We are in the process of obtaining permits following the KPSC's approval for the conversion of KPCo's 278 MW Big Sandy Plant, Unit 1 to natural gas. We expect to begin conversion of Big Sandy Plant, Unit 1 in the fourth quarter of 2015. We expect to begin operations as a natural gas unit in the second quarter of 2016. As of September 30, 2015,2016, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of the PSO and SWEPCo units listed above was $161 million. For Northeastern Station, Unit 4, PSO is seeking regulatory recovery of remaining net book values. For Welsh Plant, Unit 2, SWEPCo will seek regulatory recovery of remaining net book values.
In October 2015, KPCo obtained permits following the KPSC’s approval to convert its 278 MW Big Sandy Plant, Unit 1 was $110 million.to natural gas. Big Sandy Plant, Unit 1 began operations as a natural gas unit in May 2016.
We are also in the process of obtainingAPCo obtained permits following the Virginia SCCSCC’s and WVPSC'sWVPSC’s approval for the conversion of APCo'sto convert its 470 MW Clinch River Plant, Units 1 and 2 to natural gas. In Septemberthe third and fourth quarters of 2015, weAPCo retired the coal-related assets of Clinch River Plant, Units 1 and 2. Of the coal-relatedretired coal related assets retired in September 2015, $14 million is pending regulatory approval. We expect to begin operations as a natural gas unit in the first quarter of 2016 for Clinch River
Plant, Unit 1 and the second quarter of 2016 for Clinch River Plant, Unit 2. As of September 30, 2015, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of Clinch River Plant, Units 1 and 2, was $148management plans to seek regulatory approval for $24 million. Clinch River Plant, Unit 1 and Unit 2 began operations as natural gas units in February 2016 and April 2016, respectively.
To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows and impact financial condition.
Clean Air Act Requirements
The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements.
The Federal EPA issued the Clean Air Interstate Rule (CAIR) in 2005 requiring specific reductions in SO2 and NOx emissions from power plants. The Federal EPA issued the Cross-State Air Pollution Rule (CSAPR) in August 2011 to replace CAIR. The CSAPR was challenged in the courts. In 2012, a panel of the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing CAIR until a replacement rule is finalized. That decision was appealed to the U.S. Supreme Court, which reversed the decision and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit ordered CSAPR to take effect on January 1, 2015 while the remand proceeding was still pending. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit remanded the rule to the Federal EPA. In September 2016, the Federal EPA finalized its response to the remand for ozone season NOx budgets. All of the states in which ourAEP’s power plants are located are covered by CSAPR. See "Cross-State“Cross-State Air Pollution Rule (CSAPR)"Rule” section below.
The Federal EPA issued the final maximum achievable control technology (MACT) standards for coal and oil-fired power plants in 2012.2012, but the rule was remanded to the Federal EPA upon further review. The Federal EPA issued a supplemental finding, received comments and affirmed its decision on the MACT standards for power plants. That decision has been challenged in the courts but the rule remains in effect. See “Mercury and Other Hazardous Air Pollutants (HAPs) Regulation” section below.
The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) will address regional haze in federal parks and other protected areas. BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. CAVR will be implemented through SIPs or, if SIPs are not adequate or are not developed on schedule, through FIPs. The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas. In March 2012, the Federal EPA disapproved certain portions of the Arkansas regional haze SIP. In April 2015, the Federal EPA published a proposed FIP to replace the disapproved portions, including revised BART determinations for the Flint Creek Plant that arewere consistent with the environmental controls currently under construction. In September 2016, the Federal EPA published a final FIP that retains its BART determinations, but accelerates the schedule for implementation of certain required controls. In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the CSAPR trading programs to use those programs in place of source-specific BART for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states. This rule is being challenged in the U.S. Court of Appeals for the District of Columbia Circuit. In July 2015, we submitted comments to the proposed Arkansas FIP and participate in comments filed by industry associations of which we are members. We supportManagement supports compliance with CSAPR programs as satisfaction of the BART requirements. The Federal EPA also proposed revisions to the requirements for submission of visibility SIPs by the states for future planning periods.
In 2009, theThe Federal EPA issued a final mandatory reporting rulerules for CO2 and other greenhouse gases covering a broad range of facilities emitting in excess of 25,000 tons of CO2emissions per year. The Federal EPA issued a final endangerment finding for greenhouse gas emissions from new motor vehicles in 2009. The Federal EPA determined that greenhouse gasemissions from stationary sources will be subject to regulation under the CAA beginning January 2011 and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, SIP calls and FIPs. This rule was overturned by the U.S. Supreme Court. The Federal EPA proposed to include CO2 emissions in standards that apply to new and existing electric utility units. See "Climate“Climate Change, CO2 Regulation and Energy Policy"Policy” section below.
The Federal EPA also issued new, more stringent national ambient air quality standards (NAAQS) for PM, SO2and ozone. In October 2015, the Federal EPA announced a lower final NAAQS for ozone of 70 parts per billion. States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for our facilities as a result of those evaluations. WeManagement cannot currently predict the nature, stringency or timing of those requirements.
Notable developments in significant CAA regulatory requirements affecting ourAEP’s operations are discussed in the following sections.
Cross-State Air Pollution Rule (CSAPR)
In 2011, the Federal EPA issued CSAPR. Certain revisions to the rule were finalized in 2012. CSAPR relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states. Interstate trading of allowances is allowed on a restricted sub-regional basis. Arkansas and Louisiana are subject only to the seasonal NOx program in the rule. Texas is subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program. The annual SO2 allowance budgets in Indiana, Ohio and West Virginia were reduced significantly in the rule. A supplemental rule includes Oklahoma in the seasonal
NOx program. The supplemental rule was finalized in December 2011 with an increased NOx emission budget for the 2012 compliance year. The Federal EPA issued a final Error Corrections Rule and further CSAPR revisions in 2012 to make corrections to state budgets and unit allocations and to remove the restrictions on interstate trading in the first phase of CSAPR.
Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit. In 2012, the court issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing CAIR until a replacement rule is finalized. The majority determined that the CAA does not allow the Federal EPA to “overcontrol” emissions in an upwind state and that the Federal EPA exceeded its statutory authority by failing to allow states an opportunity to develop their own implementation plans before issuing a FIP. TheA petition for review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013. In April 2014, the U.S. Supreme Court issued a decision reversing in part the decision of the U.S. Court of Appeals for the District of Columbia Circuit and remanding the case for further proceedings consistent with the opinion. The Federal EPA filed a motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. The court granted the Federal EPA'sEPA’s motion. The parties filed briefs and presented oral arguments. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit found that the Federal EPA over-controlled the SO2 and/or NOxbudgets of 14 states. The U.S. Court of Appeals for the District of Columbia Circuit remanded the rule to the Federal EPA to timely revise the rule consistent with the court’s opinion while CSAPR remains in place. The
In December 2015, the Federal EPA is reviewingissued a proposal to revise the decisionozone season NOx budgets in 23 states beginning in 2017 to address transport issues associated with the 2008 ozone standard and will take further action once their review is complete. Separate appealsthe budget errors identified in the U.S. Court of Appeals for the District of Columbia Circuit’s July 2015 decision. The proposal was open for public comment through February 1, 2016. A final rule has been signed that addressed some of the Error Corrections Ruleconcerns raised in comments, but will significantly reduce ozone season budgets in many states and discounts the value of banked CSAPR ozone season allowances. Management believes that there are flaws in the underlying analysis of and justification for this rule. Management is evaluating compliance options for the 2017 ozone season, including any opportunity to further revisions were filed but no briefing schedules have been established.optimize NOx emissions and availability of allowances.
Mercury and Other Hazardous Air Pollutants (HAPs) Regulation
In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule establishes unit-specific emission rates for units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of nonmercury metals) and hydrogen chloride (as a surrogate for acid gases). In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. The effective date of the final rule was April 16, 2012 and compliance was required within three years. The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and the revised rule provides alternative work practice standards for operators during start-up and shut down periods. We haveManagement obtained a one-year administrative extension at several units to facilitate the installation of controls or to avoid a serious reliability problem. In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades. We remain concerned about the availability of compliance extensions, the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines and the lack of coordination among the Mercury and Air Toxics Standards (MATS) schedule and other environmental requirements.
Petitions for administrative reconsideration and judicial review of the final rule were filed. In 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards. The Federal EPA issued revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions in March 2013. A final rule on reconsideration was issued in 2014 and a proposed rule containing technical corrections was issued in early 2015. In April 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the April 2012 final rule. Industry trade groups and several states filed petitions for further review in the U.S. Supreme Court and the court granted those petitions in November 2014.
In June 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit and remanded the MATSMercury and Air Toxics Standards (MATS) rule for further proceedings consistent with itsthe U.S. Supreme Court’s decision that the Federal EPA was unreasonable in refusing to consider costs in its determination whether to regulate emissions of HAPs from power plants. The case hasFederal EPA issued notice of a supplemental finding concluding that it is appropriate and necessary to regulate HAP emissions from coal-fired and oil-fired units. Management submitted comments on the proposal. In April 2016, the Federal EPA affirmed its determination that regulation of HAPs from electric generating units is necessary and appropriate. Petitions for review of the Federal EPA’s April 2016 determination have been remanded tofiled in the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings consistent with the U.S. Supreme Court’s decision. We will continue to evaluate the impact of this decision and until further action by the U.S. Court of Appeals for the District of Columbia Circuit, theCircuit. The rule remains in place.effect.
Climate Change, CO2 Regulation and Energy Policy
Several states have adopted programs that directly regulate CO2 emissions from power plants. The majority of the states where we haveAEP has generating facilities have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions. We areManagement is taking steps to comply with these requirements, including increasing our wind power purchases and broadening ourthe AEP System’s portfolio of energy efficiency programs.
In the absence of comprehensive federal climate change or energy policy legislation, President Obama issued a memorandum to the Administrator of the Federal EPA directing the agency to develop and issue a new proposal regulating carbon emissions from new electric generating units under the CAA. The new proposal was issued in September 2013 and requires new large natural gas units to meet a limit of 1,000 pounds of CO2 per MWh of electricity generated and small natural gas units to meet a limit of 1,100 pounds of CO2 per MWh. New coal-fired units are required to meet a limit of 1,100 pounds of CO2 per MWh, with the option to meet a 1,000 pound per MWh limit if they choose to average emissions over multiple years.
The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from modified and reconstructed electric generating units (EGUs) and to issue guidelines for existing EGUs before June 2014, to finalize those standards by June 2015 and to require states to submit plans implementing the guidelines no later than June 2016.
In AugustOctober 2015, the Federal EPA announcedpublished the final standards for new, modified and reconstructed fossil fired steam generating units and combustion turbines, and final guidelines for the development of state plans to regulate CO2 emissions from existing sources and proposed two options for a federal plan. The rules will become effective 60 days following publication.sources. The final standard for new combustion turbines is 1,000 pounds of CO2 per MWh and the final standard for new fossil steam units is 1,400 pounds of CO2 per MWh. Reconstructed turbines are subject to the same standard as new units and no standard for modified combustion turbines was issued. Reconstructed fossil steam units are subject to a standard of 1,800 pounds of CO2 per MWh for larger units and 2,000 pounds of CO2 per MWh for smaller units. Modified fossil steam units will be subject to a site specific standard no lower than the standards that would be applied if the units were reconstructed.
The final emissions guidelines for existing sources, known as the Clean Power Plan (CPP), are based on a series of declining performance standardsemission rates that are implemented beginning in 2022 through 2029. Affected units must achieve a standard ofThe final emission rate is 771 pounds of CO2 per MWh for existing natural gas combined cycle units and 1,305 pounds of CO2 per MWh for existing fossil steam units by 2030.in 2030 and thereafter. The Federal EPA also developed a set of rate-based and mass-based state goals and hasgoals.
The Federal EPA also published proposed “model” rules that can be adopted by the states that would allow sources within “trading ready” state programs to trade, bank or sell
allowances or credits issued by the statesstates. These rules would also be the basis for any federal plan issued by the Federal EPA in a state that fails to submit or Federal EPA.receive approval for a state plan. The Federal EPA intends to finalize either a rate-based or mass-based trading program that can be enforced in states that fail to submit approved plans by the deadlines established in the final guidelines. States are required to submit final plansThe Federal EPA established a 90-day public comment period on the proposed rules and management submitted comments. In June 2016, the Federal EPA issued a separate proposal for the Clean Energy Incentive Program (CEIP) that was included in the model rules. The Federal EPA will accept comments on the proposed rules through November 1, 2016. Through the CEIP, states could issue allowances or an extension request by September 2016credits for eligible actions prior to the Federal EPA. States receiving an extension request must submit final plans by September 2018. We are reviewingfirst compliance period under the pre-publication versionCPP. Management is evaluating the potential impacts of the final ruleCPP and evaluating the rule’s impactsproposed CEIP, as well as the anticipated actions by states where our assets are located. The final rule was alreadyrules are being challenged in the courts and we expect additional lawsuits oncecourts. In February 2016, the ruleU.S. Supreme Court issued a stay on the final Clean Power Plan, including all of the deadlines for submission of initial or final state plans. The stay will remain in effect until a final decision is published in the Federal Register.
In 2012,issued by the U.S. Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO2 emissions from new motor vehicles and its plan to phase in regulation of CO2 emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. In June 2014, the U.S. Supreme Court determined that the Federal EPA was not compelled to regulate CO2 emissions from stationary sources under the Title V or PSD programs as a result of its adoption of the motor vehicle standards, but that sources otherwise required to obtain a PSD permit may be required to perform a Best Available Control Technology (BACT) analysisconsiders any petition for CO2 emissions if they exceed a reasonable level. The Federal EPA removed those provisions of the final rule from the Code of Federal Regulations that were inconsistent with the U.S. Supreme Court’s decision but continues to apply a 75,000 ton per year threshold to trigger the need for a BACT analysis. Petitions were filed with the U.S. Court of Appeals for the District of Columbia Circuit seeking to amend the judgment in the case to require Federal EPA to establish a reasonable minimumlevel. Those petitions were denied.review.
Federal and state legislation or regulations that mandate limits on the emission of CO2 could result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force our utility subsidiariesAEP to close some coal-fired facilities and could lead to possible impairment of assets.
Coal Combustion Residual Rule
In 2010,April 2015, the Federal EPA published a proposedfinal rule to regulate the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The proposed rule contained two alternative proposals. One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management. Both proposals would impose stringent requirements for the construction of new coal ash landfills and existing unlined surface impoundments.
In theThe final rule thebecame effective in October 2015. The Federal EPA elected to regulateregulates CCR as a non-hazardous solid waste and issuedby its issuance of new minimum federal solid waste management standards. On the effective date, theThe rule applies to new and existing active CCR landfills and CCR surface impoundments at operating electric utility or independent power production facilities. The rule imposes new and additional construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements. The rule does not apply to inactive CCR landfills, and inactive surface impoundments at retired generating stations
or the beneficial use of CCR. The rule is self-implementing so state action is not required. Because of this self-implementing feature, the rule contains extensive record keeping, notice and internet posting requirements. The CCR rule requirements contain a compliance schedule spanning an approximate four year implementation period. If CCR units do not meet these standards within the timeframes provided, they will be required to close. Extensions of time for closure are available provided there is no alternative disposal capacity or the owner can certify cessation of a boiler by a certain date. Challenges to the rule by industry associations of which AEP is a member are proceeding. In April 2016, the parties entered into a settlement agreement that would require the Federal EPA to reconsider certain aspects of the rule. In June 2016, the U.S. Court of Appeals for the District of Columbia issued an order granting the voluntary remand of certain provisions including the Federal EPA’s issuance of a rule vacating the provision creating specific closure requirements for inactive surface impoundments that complete closure by April 17, 2018. In August 2016, the Federal EPA proposed a direct final rule to extend the deadlines for these facilities to comply with the CCR standards. The proposed rule received no adverse comments and became effective 60 days following publication. Management does not believe the direct final rule will have a significant impact on its planned pond closures. The Federal EPA will also use its best efforts to complete reconsideration of all of the affected provisions within three years.
Because weAEP currently useuses surface impoundments and landfills to manage CCR materials at our generating facilities, wesignificant costs will incur significant costsbe incurred to upgrade or close and replace these existing facilities at some point in the future as the new rule is implemented. Management recorded a $95 million increase in asset retirement obligations in the second quarter of 2015 primarily due to the publication of the final rule. Management will continue to evaluate the rule’s impact on operations.
In February 2014, the Federal EPA completed a risk evaluation of the beneficial uses of coal fly ash in concrete and FGD gypsum in wallboard and concluded that the Federal EPA supports these beneficial uses. Currently, approximately 40% of the coal ash and other residual products from ourAEP’s generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses. Encapsulated beneficial uses are not materially impacted by the new rule but additional demonstrations may be required to continue land applications in significant amounts except in road construction projects.
The final rule was published in the Federal Register in April 2015 and becomes effective six months after publication. The final rule provides for a staggered compliance schedule for the implementation of the rule’s many requirements. We recorded a $95 million increase in asset retirement obligations in the second quarter of 2015 primarily due to the publication of the final rule. Given the schedule for implementation, we will continue to evaluate the rule's impact on operations.
Clean Water Act (CWA) Regulations
In 2014, the Federal EPA issued a final rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress. The final rule affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to comply with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures at facilities withdrawing more than 125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, are not expected to require any technology changes. Facilities subject to both the impingement standard and site-specific entrainment studies will typically be given at least three years to conduct and submit the results of those studies to the permit agency. Compliance timeframes will then be established by the permit agency through each facility’s National Pollutant Discharge Elimination System (NPDES) permit for installation of any required technology changes, as those permits are renewed over the next five to eight years. Petitions for review of the final rule were filed by industry and environmental groups and are currently pending in the U.S. Court of Appeals for the Second Circuit. Briefs by the various parties are due during the fourth quarter of 2016.
In addition, the Federal EPA developed revised effluent limitation guidelines for electricity generating facilities. A pre-publication copy of the final rule was announced and made availableissued in SeptemberNovember 2015. The rule has been challenged in the U.S. Court of Appeals for the Fifth Circuit. Industry petitioners, including SWEPCo, have filed a joint motion for reconsideration of the single judge order denying the motion to complete the administrative record. In addition to other requirements, in the final rule the Federal EPA establishes limits on flue gas desulfurization wastewater, zero discharge for fly ash and bottom ash transport water and flue gas mercury control wastewater. Compliance with the final ruleThe applicability of these requirements is as soon as possible after November 2018 and no later than December 2023. These new requirements will be implemented through each facility’s wastewater discharge permit. We continueManagement continues to review the final rule in detail to evaluate whether our plants are currently meeting the proposed limitations, what technologies have been incorporated into our long-range plansassess technology additions and what additional costs might be incurred.retrofits.
In June 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This jurisdictional definition applies to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are: permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. The final definition continues to recognize traditional navigable waters of the U.S. as jurisdictional as well as certain exclusions. The rule also contains a number of new specific definitions and criteria for determining whether certain other waters are jurisdictional because of a “significant nexus." We believe” Management believes that clarity and efficiency in the permitting process is needed. We remainManagement remains concerned that the rule introduces new concepts and could subject more of ourAEP’s operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. The final rule is being challenged in both courts of appeal and district courts. Challengers include industry associations of which we are members.AEP is a member. The U.S. Court of AppealAppeals for the Sixth Circuit has granted a nationwide stay of the rule pending jurisdictional determinations. In February 2016, the U.S. Court of Appeals for the Sixth Circuit issued a decision holding that it has exclusive jurisdiction to decide the challenges to the “waters of the United States” rule. Industry, state and related associations have filed petitions for a rehearing of the jurisdictional decision. In April 2016, the U.S. Court of Appeals for the Sixth Circuit denied the petitions and proceeded to issue a case management order for the merits of the case. In September 2016, the case management order was held in abeyance pending the court’s ruling on the outstanding motions to complete the administrative record. In October 2016, the U.S. Court of Appeals for the Sixth Circuit issued an order granting in part and denying in part the motions to complete the record. Following this order, a revised case management order was issued scheduling briefing to be completed by March 2017. No date for oral argument has been set.
RESULTS OF OPERATIONS
SEGMENTS
OurAEP’s primary business is the generation, transmission and distribution of electricity. Within ourits Vertically Integrated Utilities segment, weAEP centrally dispatchdispatches generation assets and manage ourmanages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.
OurAEP’s reportable segments and their related business activities are outlined below:
Vertically Integrated Utilities
Generation, transmission and distributionof electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.
Transmission and Distribution Utilities
Transmission and distributionof electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load.
AEP Transmission Holdco
Development, construction and operation of transmission facilities through investments in ourAEP’s wholly-owned transmissiontransmission-only subsidiaries and transmission onlytransmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.
Generation & Marketing
NonregulatedCompetitive generation in ERCOT and PJM.
Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO.
The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP River Operations
Commercial barging operations that transport liquids, coalutility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and dry bulk commodities primarily oninterest expense and other nonallocated costs. With the Ohio, Illinois and lower Mississippi Rivers.
In Octobersale of AEPRO in November 2015, we signed an agreementthe activities related to sell AEPRO to a nonaffiliated party. Thethe AEP River Operations segment is comprised entirely of AEPRO. However, we will retain AEPRO's investment in IMT.have been moved to Corporate and Other for the periods presented. See "AEPRO (AEP River Operations“AEPRO (Corporate and Other Segment)"” section of Note 6 for additional information.
14The following discussion of AEP’s results of operations by operating segment includes an analysis of gross margin, which is a non-GAAP financial measure. Gross margin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation as well as Purchased Electricity for Resale, as presented in AEP’s statements of operations. These expenses are generally collected from customers through cost recovery mechanisms. As such, management uses gross margin for internal reporting analysis as it excludes the fluctuations in revenue caused by changes in these expenses. Operating income, which is presented in accordance with GAAP in AEP’s statements of operations, is the most directly comparable GAAP financial measure to the presentation of gross margin. AEP’s definition of gross margin may not be directly comparable to similarly titled financial measures used by other companies.
The table below presents Earnings (Loss) Attributable to AEP Common Shareholders by segment for the three and nine months ended September 30, 20152016 and 2014.2015.
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Vertically Integrated Utilities | $ | 274 |
| | $ | 219 |
| | $ | 780 |
| | $ | 651 |
| $ | 342.3 |
| | $ | 273.5 |
| | $ | 829.3 |
| | $ | 779.7 |
|
Transmission and Distribution Utilities | 113 |
| | 92 |
| | 288 |
| | 279 |
| 155.5 |
| | 113.0 |
| | 388.1 |
| | 287.8 |
|
AEP Transmission Holdco | 46 |
| | 43 |
| | 147 |
| | 114 |
| 69.0 |
| | 45.6 |
| | 207.5 |
| | 146.6 |
|
Generation & Marketing | 91 |
| | 117 |
| | 360 |
| | 378 |
| (1,369.2 | ) | | 91.6 |
| | (1,248.8 | ) | | 360.3 |
|
AEP River Operations | 4 |
| | 11 |
| | 16 |
| | 17 |
| |
Corporate and Other (a) | (9 | ) | | 11 |
| | (13 | ) | | 4 |
| |
Earnings Attributable to AEP Common Shareholders | $ | 519 |
| | $ | 493 |
| | $ | 1,578 |
| | $ | 1,443 |
| |
Corporate and Other | | 36.6 |
| | (5.4 | ) | | 61.4 |
| | 3.1 |
|
Earnings (Loss) Attributable to AEP Common Shareholders | | $ | (765.8 | ) | | $ | 518.3 |
| | $ | 237.5 |
| | $ | 1,577.5 |
|
| |
(a) | While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. |
AEP CONSOLIDATED
Third Quarter of 20152016 Compared to Third Quarter of 20142015
Earnings (Loss) Attributable to AEP Common Shareholders increaseddecreased from $493income of $518 million in 20142015 to $519a loss of $766 million in 20152016 primarily due to:
Successful rate proceedingsAn impairment of certain merchant generation assets.
A decrease in various jurisdictions.weather-normalized sales.
An increase
These decreases were partially offset by:
A decrease in revenuessystem income taxes primarily due to annual formula rate adjustments.reduced pretax book income as a result of the impairment of certain merchant generation assets as well as the reversal of valuation allowances related to the pending sale of certain merchant generation assets, as well as favorable 2015 income tax return adjustments related to AEP’s commercial barging operations.
An increase in weather-related usage.
A decreaseFavorable rate proceedings in expensesAEP’s various jurisdictions.
An increase due to a settlementincreased revenues from Ohio transmission and revision of certain asset retirement obligations.distribution riders.
An increase in income at AEP Transmission Holdco as a result of increased transmission investment which resultedand related increases in higher revenues and income.recoverable operating expenses.
These increases were partially offset by:Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015
Earnings (Loss) Attributable to AEP Common Shareholders decreased from income of $1.6 billion in 2015 to income of $238 million in 2016 primarily due to:
An impairment of certain merchant generation assets.
A decrease in generation revenues due to lower capacity revenue.revenue and a decrease in wholesale energy prices.
A decrease in off-system sales margins due to lower market prices and reduced sales volumes.
An increase in employee-related expenses.
Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
Earnings Attributable to AEP Common Shareholders increased from $1.4 billion in 2014 to $1.6 billion in 2015 primarily due to:
Successful rate proceedings in various jurisdictions.
An increase in revenues due to annual formula rate adjustments.
An increase in weather-related usage.
A decrease in expenses due to a settlement and revision of certain asset retirement obligations.
An increase in transmission investment which resulted in higher revenues and income.
Favorable retail, trading and marketing activity.
These increasesdecreases were partially offset by:
A decrease in generation revenuessystem income taxes primarily due to lower capacity revenue.reduced pretax book income as a result of the impairment of certain merchant generation assets as well as the reversal of valuation allowances related to the pending sale of certain merchant generation assets and the settlement of a 2011 audit issue with the IRS, as well as favorable 2015 income tax return adjustments related to AEP’s commercial barging operations.
A decrease in off-system sales marginsAn increase due to lower market pricesincreased revenues from Ohio transmission and reduced sales volumes.distribution riders.
A decreaseAn increase in weather normalized sales.income at AEP Transmission Holdco as a result of increased transmission investment as well as an increase due to annual formula rate true-up adjustments.
OurAEP’s results of operations by operating segment are discussed below.
VERTICALLY INTEGRATED UTILITIES
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
Vertically Integrated Utilities | | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
Revenues | | $ | 2,471 |
| | $ | 2,450 |
| | $ | 7,159 |
| | $ | 7,288 |
| | $ | 2,556.3 |
| | $ | 2,471.5 |
| | $ | 6,927.8 |
| | $ | 7,159.1 |
|
Fuel and Purchased Electricity | | 931 |
| | 1,010 |
| | 2,695 |
| | 3,038 |
| | 858.3 |
| | 931.0 |
| | 2,299.8 |
| | 2,694.8 |
|
Gross Margin | | 1,540 |
| | 1,440 |
| | 4,464 |
| | 4,250 |
| | 1,698.0 |
| | 1,540.5 |
| | 4,628.0 |
| | 4,464.3 |
|
Other Operation and Maintenance | | 653 |
| | 615 |
| | 1,844 |
| | 1,809 |
| | 673.0 |
| | 652.8 |
| | 1,926.9 |
| | 1,843.4 |
|
Asset Impairments and Other Related Charges | | | 10.5 |
| | — |
| | 10.5 |
| | — |
|
Depreciation and Amortization | | 264 |
| | 257 |
| | 802 |
| | 772 |
| | 277.7 |
| | 264.0 |
| | 815.5 |
| | 802.4 |
|
Taxes Other Than Income Taxes | | 97 |
| | 95 |
| | 288 |
| | 278 |
| | 99.0 |
| | 97.6 |
| | 295.0 |
| | 288.2 |
|
Operating Income | | 526 |
| | 473 |
| | 1,530 |
| | 1,391 |
| | 637.8 |
| | 526.1 |
| | 1,580.1 |
| | 1,530.3 |
|
Interest and Investment Income | | 1 |
| | 2 |
| | 4 |
| | 3 |
| | 0.8 |
| | 0.7 |
| | 2.4 |
| | 3.9 |
|
Carrying Costs Income | | 4 |
| | 1 |
| | 9 |
| | 2 |
| | 0.8 |
| | 3.4 |
| | 8.1 |
| | 8.5 |
|
Allowance for Equity Funds Used During Construction | | 16 |
| | 12 |
| | 46 |
| | 33 |
| | 10.0 |
| | 15.4 |
| | 35.4 |
| | 45.5 |
|
Interest Expense | | (130 | ) | | (133 | ) | | (392 | ) | | (396 | ) | | (136.7 | ) | | (129.1 | ) | | (399.9 | ) | | (391.5 | ) |
Income Before Income Tax Expense and Equity Earnings | | 417 |
| | 355 |
| | 1,197 |
| | 1,033 |
| | 512.7 |
| | 416.5 |
| | 1,226.1 |
| | 1,196.7 |
|
Income Tax Expense | | 142 |
| | 135 |
| | 416 |
| | 380 |
| | 172.0 |
| | 142.4 |
| | 398.4 |
| | 416.1 |
|
Equity Earnings of Unconsolidated Subsidiaries | | — |
| | — |
| | 2 |
| | 1 |
| | 2.7 |
| | 0.4 |
| | 4.9 |
| | 2.1 |
|
Net Income | | 275 |
| | 220 |
| | 783 |
| | 654 |
| | 343.4 |
| | 274.5 |
| | 832.6 |
| | 782.7 |
|
Net Income Attributable to Noncontrolling Interests | | 1 |
| | 1 |
| | 3 |
| | 3 |
| | 1.1 |
| | 1.0 |
| | 3.3 |
| | 3.0 |
|
Earnings Attributable to AEP Common Shareholders | | $ | 274 |
| | $ | 219 |
| | $ | 780 |
| | $ | 651 |
| | $ | 342.3 |
| | $ | 273.5 |
| | $ | 829.3 |
| | $ | 779.7 |
|
Summary of KWh Energy Sales for Vertically Integrated Utilities
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in millions of KWhs) | (in millions of KWhs) |
Retail: | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
Residential | 9,019 |
| | 8,505 |
| | 26,070 |
| | 26,126 |
| 9,575 |
| | 9,019 |
| | 25,373 |
| | 26,070 |
|
Commercial | 7,008 |
| | 6,743 |
| | 19,315 |
| | 18,980 |
| 7,137 |
| | 7,008 |
| | 19,207 |
| | 19,315 |
|
Industrial | 8,882 |
| | 8,962 |
| | 26,178 |
| | 26,319 |
| 8,655 |
| | 8,882 |
| | 25,576 |
| | 26,178 |
|
Miscellaneous | 616 |
| | 608 |
| | 1,739 |
| | 1,740 |
| 634 |
| | 616 |
| | 1,740 |
| | 1,739 |
|
Total Retail | 25,525 |
| | 24,818 |
| | 73,302 |
| | 73,165 |
| 26,001 |
| | 25,525 |
| | 71,896 |
| | 73,302 |
|
| | | | | | | | | | | | | | |
Wholesale (a) | 6,577 |
| | 8,632 |
| | 20,748 |
| | 27,418 |
| 6,765 |
| | 6,577 |
| | 17,253 |
| | 20,748 |
|
| | | | | | | | |
Total KWhs | | 32,766 |
| | 32,102 |
| | 89,149 |
| | 94,050 |
|
| |
(a) | Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers. |
Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues. In general, degree day changes in ourthe eastern region have a larger effect on revenues than changes in ourthe western region due to the relative size of the two regions and the number of customers within each region.
Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in degree days) | (in degree days) |
Eastern Region | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
Actual – Heating (a) | — |
| | 2 |
| | 2,138 |
| | 2,248 |
| — |
| | — |
| | 1,684 |
| | 2,138 |
|
Normal – Heating (b) | 5 |
| | 5 |
| | 1,748 |
| | 1,736 |
| 5 |
| | 5 |
| | 1,775 |
| | 1,748 |
|
| | | | | | | | | | | | | | |
Actual – Cooling (c) | 702 |
| | 559 |
| | 1,104 |
| | 921 |
| 954 |
| | 702 |
| | 1,306 |
| | 1,104 |
|
Normal – Cooling (b) | 728 |
| | 733 |
| | 1,057 |
| | 1,062 |
| 726 |
| | 728 |
| | 1,058 |
| | 1,057 |
|
| | | | | | | | | | | | | | |
Western Region | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
Actual – Heating (a) | — |
| | — |
| | 1,049 |
| | 1,233 |
| — |
| | — |
| | 685 |
| | 1,049 |
|
Normal – Heating (b) | 1 |
| | 1 |
| | 912 |
| | 921 |
| 1 |
| | 1 |
| | 927 |
| | 912 |
|
| | | | | | | | | | | | | | |
Actual – Cooling (c) | 1,472 |
| | 1,246 |
| | 2,190 |
| | 1,926 |
| 1,519 |
| | 1,472 |
| | 2,262 |
| | 2,190 |
|
Normal – Cooling (b) | 1,398 |
| | 1,399 |
| | 2,114 |
| | 2,109 |
| 1,400 |
| | 1,398 |
| | 2,116 |
| | 2,114 |
|
| |
(a) | Eastern Region and Western Region heatingHeating degree days are calculated on a 55 degree temperature base. |
temperature base.
| |
(b) | Normal Heating/Cooling represents the thirty-year average of degree days. |
| |
(c) | Eastern Region and Western Region coolingCooling degree days are calculated on a 65 degree temperature base. |
temperature base.
Third Quarter of 20152016 Compared to Third Quarter of 20142015
| | Reconciliation of Third Quarter of 2014 to Third Quarter of 2015 | |
Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 | | Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 |
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities | (in millions) | | | | | |
Third Quarter of 2014 | | $ | 219 |
| |
Third Quarter of 2015 | | | $ | 273.5 |
|
| | |
| | |
|
Changes in Gross Margin: | | |
| | |
|
Retail Margins | | 128 |
| | 136.2 |
|
Off-system Sales | | (24 | ) | | 3.5 |
|
Transmission Revenues | | (10 | ) | | 13.4 |
|
Other Revenues | | 6 |
| | 4.4 |
|
Total Change in Gross Margin | | 100 |
| | 157.5 |
|
| | |
| | |
|
Changes in Expenses and Other: | | |
| | |
|
Other Operation and Maintenance | | (38 | ) | | (20.2 | ) |
Asset Impairments and Other Related Charges | | | (10.5 | ) |
Depreciation and Amortization | | (7 | ) | | (13.7 | ) |
Taxes Other Than Income Taxes | | (2 | ) | | (1.4 | ) |
Interest and Investment Income | | (1 | ) | | 0.1 |
|
Carrying Costs Income | | 3 |
| | (2.6 | ) |
Allowance for Equity Funds Used During Construction | | 4 |
| | (5.4 | ) |
Interest Expense | | 3 |
| | (7.6 | ) |
Total Change in Expenses and Other | | (38 | ) | | (61.3 | ) |
| | |
| | |
|
Income Tax Expense | | (7 | ) | | (29.6 | ) |
Equity Earnings | | | 2.3 |
|
Net Income Attributable to Noncontrolling Interests | | | (0.1 | ) |
| | | | |
Third Quarter of 2015 | | $ | 274 |
| |
Third Quarter of 2016 | | | $ | 342.3 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
Retail Margins increased $128$136 million primarily due to the following:
The effect of successful rate proceedings in ourAEP’s service territories which include:included:
A $40$35 million increase primarily due to increases in rates in West Virginia offset by decreases in rates in Virginia and formula rates in both jurisdictions.Virginia.
A $25$24 million increase for PSO due to interim base rate increases.
A $17 million increase for I&M due to increases in riders in the Indiana service territory.
A $16 million increase for KPCo primarily due to increases in base rates and riders.
A $6 million increase for SWEPCo primarily due to revenue increases from rate riders in LouisianaTexas and Texas.
A $20 million increase for I&M primarily due to rate increases from Indiana rate riders and annual formula rate adjustments.
An $11 million increase for PSO primarily due to revenue increases from rate riders.Arkansas.
For the increases described above, $30$55 million relate to riders/trackers which have corresponding increases in expense items below.
A $51$53 million increase in weather-related usage.
A $3 million increase for SWEPCo in municipal and cooperative revenues due to formula rate adjustments.
These increases were partially offset by:
A $19$27 million decrease primarily due to lower weather-normalized retail sales in our western region.margins.
Margins from Off-system Sales decreased $24increased $4 million primarily due to lower market prices and decreasedincreased sales volumes.
Transmission Revenues decreased $10increased $13 million primarily due to decreased PJM revenues, partiallythe following:
A $5 million accrual for SPP sponsor-funded transmission upgrades. This increase was offset by ana corresponding increase in Other Operation and Maintenance expenses below.
A $5 million increase due to higher Network Integration Transmission Service revenues associated with increased transmission investments.
A $4 million increase in SPP margins.
Non-Affiliated Base Plan Funding associated with increased transmission investments. This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.Other Revenues increased $6$4 million primarily due to a 2014 MPSC order disallowing $4 million of 2012 to 2014 lost revenue related toincreased revenues from Demand Side Management (DSM). programs in Kentucky.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $38$20 million primarily due to the following:
A $20 million increase in employee-related expenses.
A $17$51 million increase in recoverable expenses, primarily including PJM, Big Sandy Unit 1 operation rider, energy efficiency and vegetation management expenses currently fully recovered in rate recovery riders/trackers,trackers.
A $17 million increase associated with amortization of deferred transmission costs in accordance with the Virginia Transmission Rate Adjustment Clause effective January 2016. This increase in expense is offset within Retail Margins above.
A $12 million accrual for SPP sponsor-funded transmission upgrades. This increase was partially offset by lower River Transportation Division (RTD) barging costs.
A $5 milliona corresponding increase in SPP transmission services.
A $4 million increase in storm expenses.Transmission Revenues above.
These increases were partially offset by:
An $8A $33 million decrease in employee and AEPSC related expenses.
An $18 million decrease in plant outages and maintenance primarily in the eastern region.
A $6 million decrease in vegetation management expenses.
Asset Impairments and Other Related Charges increased $11 million due to a 2014 accrual for expected environmental remediation costs atthe impairment of I&M.&M’s Price River Coal reserves.
Depreciation and Amortization expenses increased $7$14 million primarily due to:
A $12 million increase due to a higher depreciable base.
A $9 million increase in depreciation primarily related to interim rate increases in Oklahoma.
These increases were partially offset by:
A $3 million decrease in amortization related to anthe advanced metering rider implementedinfrastructure projects in November 2014Oklahoma.
A $3 million decrease in Oklahoma as well as an overall higher depreciable base.
the amortization of capitalized software due to prior year retirements.Allowance for Equity Funds Used During Construction increased $4decreased $5 million primarily due to increasesthe completion of environmental projects at SWEPCo.
Interest Expense increased $8 million primarily due to the following:
A $4 million increase due to higher long-term debt balances at I&M.
A $4 million increase due to a decrease in the debt component of AFUDC as a result of decreased environmental construction and transmission projects.
projects at SWEPCo.Income Tax Expense increased $7$30 million primarily due to an increase in pretax book income, partially offset by the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis.income.
Nine Months Ended September 30, 20152016 Compared to Nine Months Ended September 30, 20142015
| | Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015 | |
Reconciliation of Nine Months Ended September 30, 2015 to Nine Months Ended September 30, 2016 | | Reconciliation of Nine Months Ended September 30, 2015 to Nine Months Ended September 30, 2016 |
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities | (in millions) | | | | | |
Nine Months Ended September 30, 2014 | | $ | 651 |
| |
Nine Months Ended September 30, 2015 | | | $ | 779.7 |
|
| | |
| | |
|
Changes in Gross Margin: | | |
| | |
|
Retail Margins | | 340 |
| | 191.9 |
|
Off-system Sales | | (118 | ) | | (19.7 | ) |
Transmission Revenues | | (9 | ) | | (14.3 | ) |
Other Revenues | | 1 |
| | 5.8 |
|
Total Change in Gross Margin | | 214 |
| | 163.7 |
|
| | |
| | |
|
Changes in Expenses and Other: | | |
| | |
|
Other Operation and Maintenance | | (35 | ) | | (83.5 | ) |
Asset Impairments and Other Related Charges | | | (10.5 | ) |
Depreciation and Amortization | | (30 | ) | | (13.1 | ) |
Taxes Other Than Income Taxes | | (10 | ) | | (6.8 | ) |
Interest and Investment Income | | 1 |
| | (1.5 | ) |
Carrying Costs Income | | 7 |
| | (0.4 | ) |
Allowance for Equity Funds Used During Construction | | 13 |
| | (10.1 | ) |
Interest Expense | | 4 |
| | (8.4 | ) |
Total Change in Expenses and Other | | (50 | ) | | (134.3 | ) |
| | |
| | |
|
Income Tax Expense | | (36 | ) | | 17.7 |
|
Equity Earnings | | 1 |
| | 2.8 |
|
Net Income Attributable to Noncontrolling Interests | | | (0.3 | ) |
| | | | |
Nine Months Ended September 30, 2015 | | $ | 780 |
| |
Nine Months Ended September 30, 2016 | | | $ | 829.3 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
Retail Margins increased $340$192 million primarily due to the following:
The effect of successful rate proceedings in ourAEP’s service territories which include:
A $108$120 million increase primarily due to increases in rates in West Virginia and Virginia, which includes recognition of deferred billing in West Virginia as well as anapproved by the WVPSC in June 2016. This increase is partially offset by a prior year adjustment due toaffected by the amended Virginia law impactingthat has an impact on biennial reviews.
A $74$45 million increase for I&M primarily due to rate increases from Indiana rate riders and annual formula rate adjustments.
A $68 million increase for SWEPCoKPCo primarily due to increases in municipalbase rates and cooperative revenues due to annual formula rate adjustments and revenue increases from SWEPCo rate riders in Louisiana and Texas.riders.
A $27$43 million increase for PSO primarilydue to interim base rate increases.
A $29 million increase for I&M due to increases in riders in the Indiana service territory.
A $16 million increase for SWEPCo due to revenue increases from rate riders.riders in Arkansas and Texas.
For the increases described above, $77$139 million relate to riders/trackers which have corresponding increases in expense items below.
A $52 million increase in weather-related usage.
These increases were partially offset by:
A $25$29 million decrease in weather-related usage.
A $14 million decrease in weather-normalized loadmargins primarily due to lower residential sales in the eastern region.
A $22 million decrease for SWEPCo in municipal and cooperative revenues due to a true-up of formula rates in 2015.
A $12 million decrease for I&M in FERC municipal and cooperative revenues due to annual formula rate adjustments offset by increased formula rate changes.
Margins from Off-system Sales decreased $118$20 million primarily due to lower market prices and decreased sales volumes.
Transmission Revenues decreased $9$14 million primarily due to decreased PJM revenues,the following:
A $26 million decrease due to lower Network Integration Transmission Service revenues.
This decrease was partially offset by anby:
A $9 million increase in SPP margins.Non-Affiliated Base Plan Funding associated with increased transmission investments. This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.
A $5 million accrual for SPP sponsor-funded transmission upgrades. This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.
Other Revenues increased $6 million primarily due to increased revenues from DSM programs in Kentucky.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $35$84 million primarily due to the following:
A $54$72 million increase in recoverable expenses, primarily including PJM, expenses and vegetation management, energy efficiency and storm expenses currently fully recovered in rate recovery riders/trackers, partially offset by lower RTD barging costs.trackers.
A $13$41 million increase associated with amortization of deferred transmission costs in accordance with the Virginia Transmission Rate Adjustment Clause effective January 2016. This increase in expense is offset within Retail Margins above.
A $27 million increase in SPP and PJM transmission services.services expense.
A $12 million accrual for SPP sponsor-funded transmission upgrades. This increase was partially offset by a corresponding increase in Transmission Revenues above.
A $9 million increase in distribution expenses primarily due to increased asset inspections.
A $6 million increase due to the reduction of an environmental liability in 2015 at I&M.
A $6 million increase in storm expenses, primarily in the APCo region.
These increases were partially offset by:
An $18A $60 million decrease in plant outages, primarily planned outages in the eastern region.
A $13 million decrease in vegetation management expenses and storm expenses.
A $14$6 million decrease due to a 2014 accrual for expected environmental remediation costsgain on the sale of property in the current year in the APCo region.
Asset Impairments and a 2015 reductionOther Related Charges increased $11 million due to the impairment of an environmental liability at I&M.&M’s Price River Coal reserves.
Depreciation and Amortization expenses increased $30$13 millionprimarily due to:
A $25 million increase in depreciation primarily related to interim rate increases in Oklahoma.
A $12 million increase due to a higher depreciable base.
These increases were partially offset by the following:
An $11 million decrease in the amortization of capitalized software due to prior year retirements.
A $6 million decrease in amortization related to anthe advanced metering rider implementedinfrastructure projects in November 2014Oklahoma.
A $5 million revision in Oklahoma as well as an overall higher depreciable base.I&M’s nuclear asset retirement obligation (ARO) estimate, which has a corresponding increase in Other Operation and Maintenance expenses above.
A $4 million decrease in the ARO expense due to steam plant retirements in 2015.
Taxes Other Than Income Taxes increased $10$7 million primarily due to an increase in property taxes.
Carrying Costs Incometaxes as a result of increased $7 million primarily due to increased riders and trackers in our jurisdictions, including the Indiana and Michigan Life Cycle Management Riders, the Kentucky Environmental Surcharge Rider, the Indiana Dry Sorbent Injection Rider, as well as an increase in carrying charges related to West Virginia ENEC deferrals.property investment.
Allowance for Equity Funds Used During Construction increased $13decreased $10 million primarily due to increasesthe completion of environmental projects at SWEPCo.
Interest Expense increased $8 million primarily due to higher long-term debt balances in environmental construction and transmission projects.I&M.
Income Tax Expense increased $36decreased $18 million primarily due to the recording of federal and state income tax adjustments and other book/tax differences which are accounted for on a flow-through basis, partially offset by an increase in pretax book income, partially offset by the regulatory accounting treatment of state income taxes.income.
TRANSMISSION AND DISTRIBUTION UTILITIES
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
Transmission and Distribution Utilities | | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
Revenues | | $ | 1,189 |
| | $ | 1,231 |
| | $ | 3,520 |
| | $ | 3,580 |
| | $ | 1,275.6 |
| | $ | 1,188.6 |
| | $ | 3,468.5 |
| | $ | 3,519.4 |
|
Fuel and Purchased Electricity | | 229 |
| | 377 |
| | 920 |
| | 1,123 |
| |
Purchased Electricity | | | 253.6 |
| | 228.2 |
| | 662.2 |
| | 919.5 |
|
Amortization of Generation Deferrals | | 55 |
| | 27 |
| | 122 |
| | 83 |
| | 66.1 |
| | 55.4 |
| | 173.0 |
| | 122.2 |
|
Gross Margin | | 905 |
| | 827 |
| | 2,478 |
| | 2,374 |
| | 955.9 |
| | 905.0 |
| | 2,633.3 |
| | 2,477.7 |
|
Other Operation and Maintenance | | 348 |
| | 329 |
| | 956 |
| | 920 |
| | 357.9 |
| | 347.9 |
| | 1,008.2 |
| | 955.5 |
|
Depreciation and Amortization | | 198 |
| | 182 |
| | 536 |
| | 499 |
| | 181.4 |
| | 197.6 |
| | 505.0 |
| | 535.7 |
|
Taxes Other Than Income Taxes | | 122 |
| | 117 |
| | 362 |
| | 344 |
| | 132.0 |
| | 122.3 |
| | 373.0 |
| | 362.2 |
|
Operating Income | | 237 |
| | 199 |
| | 624 |
| | 611 |
| | 284.6 |
| | 237.2 |
| | 747.1 |
| | 624.3 |
|
Interest and Investment Income | | 2 |
| | 3 |
| | 5 |
| | 9 |
| | 1.0 |
| | 1.4 |
| | 4.3 |
| | 4.7 |
|
Carrying Costs Income (Expense) | | (2 | ) | | 6 |
| | 10 |
| | 20 |
| | 0.9 |
| | (1.6 | ) | | 4.0 |
| | 10.0 |
|
Allowance for Equity Funds Used During Construction | | 3 |
| | 3 |
| | 11 |
| | 8 |
| | 2.2 |
| | 3.6 |
| | 10.6 |
| | 11.3 |
|
Interest Expense | | (68 | ) | | (68 | ) | | (206 | ) | | (210 | ) | | (63.2 | ) | | (68.7 | ) | | (195.8 | ) | | (206.3 | ) |
Income Before Income Tax Expense | | 172 |
| | 143 |
| | 444 |
| | 438 |
| | 225.5 |
| | 171.9 |
| | 570.2 |
| | 444.0 |
|
Income Tax Expense | | 59 |
| | 51 |
| | 156 |
| | 159 |
| | 70.0 |
| | 58.9 |
| | 182.1 |
| | 156.2 |
|
Net Income | | 113 |
| | 92 |
| | 288 |
| | 279 |
| | 155.5 |
| | 113.0 |
| | 388.1 |
| | 287.8 |
|
Net Income Attributable to Noncontrolling Interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Earnings Attributable to AEP Common Shareholders | | $ | 113 |
| | $ | 92 |
| | $ | 288 |
| | $ | 279 |
| | $ | 155.5 |
| | $ | 113.0 |
| | $ | 388.1 |
| | $ | 287.8 |
|
Summary of KWh Energy Sales for Transmission and Distribution Utilities
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in millions of KWhs) | (in millions of KWhs) |
Retail: | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
Residential | 7,590 |
| | 7,194 |
| | 20,486 |
| | 20,280 |
| 8,325 |
| | 7,590 |
| | 20,575 |
| | 20,486 |
|
Commercial | 7,033 |
| | 6,796 |
| | 19,320 |
| | 19,012 |
| 7,287 |
| | 7,033 |
| | 19,676 |
| | 19,320 |
|
Industrial | 5,665 |
| | 5,489 |
| | 16,754 |
| | 16,262 |
| 5,518 |
| | 5,665 |
| | 16,522 |
| | 16,754 |
|
Miscellaneous | 194 |
| | 187 |
| | 532 |
| | 540 |
| 187 |
| | 194 |
| | 528 |
| | 532 |
|
Total Retail (a) | 20,482 |
| | 19,666 |
| | 57,092 |
| | 56,094 |
| 21,317 |
| | 20,482 |
| | 57,301 |
| | 57,092 |
|
| | | | | | | | | | | | | | |
Wholesale (b) | 497 |
| | 575 |
| | 1,460 |
| | 1,727 |
| 654 |
| | 497 |
| | 1,389 |
| | 1,460 |
|
| | | | | | | | |
Total KWhs | | 21,971 |
| | 20,979 |
| | 58,690 |
| | 58,552 |
|
| |
(a) | Represents energy delivered to distribution customers. |
| |
(b) | Ohio'sPrimarily Ohio’s contractually obligated purchases of OVEC power sold into PJM. |
Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues. In general, degree day changes in ourthe eastern region have a larger effect on revenues than changes in ourthe western region due to the relative size of the two regions and the number of customers within each region.
Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in degree days) | (in degree days) |
Eastern Region | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
Actual – Heating (a) | — |
| | 1 |
| | 2,575 |
| | 2,540 |
| |
Actual �� Heating (a) | | — |
| | — |
| | 1,929 |
| | 2,575 |
|
Normal – Heating (b) | 6 |
| | 7 |
| | 2,073 |
| | 2,074 |
| 7 |
| | 6 |
| | 2,110 |
| | 2,073 |
|
| | | | | | | | | | | | | | |
Actual – Cooling (c) | 620 |
| | 581 |
| | 970 |
| | 943 |
| 900 |
| | 620 |
| | 1,209 |
| | 970 |
|
Normal – Cooling (b) | 666 |
| | 663 |
| | 956 |
| | 946 |
| 664 |
| | 666 |
| | 956 |
| | 956 |
|
| | | | | | | | | | | | | | |
Western Region | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
Actual – Heating (a) | — |
| | — |
| | 320 |
| | 302 |
| — |
| | — |
| | 123 |
| | 320 |
|
Normal – Heating (b) | — |
| | — |
| | 192 |
| | 200 |
| — |
| | — |
| | 198 |
| | 192 |
|
| | | | | | | | | | | | | | |
Actual – Cooling (d) | 1,476 |
| | 1,367 |
| | 2,380 |
| | 2,309 |
| 1,534 |
| | 1,476 |
| | 2,619 |
| | 2,380 |
|
Normal – Cooling (b) | 1,355 |
| | 1,346 |
| | 2,381 |
| | 2,358 |
| 1,358 |
| | 1,355 |
| | 2,384 |
| | 2,381 |
|
| |
(a) | Heating degree days are calculated on a 55 degree temperature base. |
| |
(b) | Normal Heating/Cooling represents the thirty-year average of degree days. |
| |
(c) | Eastern Region cooling degree days are calculated on a 65 degree temperature base. |
| |
(d) | Western Region cooling degree days are calculated on a 70 degree temperature base. |
Third Quarter of 20152016 Compared to Third Quarter of 20142015
| | Reconciliation of Third Quarter of 2014 to Third Quarter of 2015 | |
Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 | | Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 |
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities | (in millions) | | | | | |
Third Quarter of 2014 | | $ | 92 |
| |
Third Quarter of 2015 | | | $ | 113.0 |
|
| | |
| | |
|
Changes in Gross Margin: | | |
| | |
|
Retail Margins | | 117 |
| | 54.3 |
|
Off-system Sales | | (9 | ) | | 8.6 |
|
Transmission Revenues | | (33 | ) | | 12.4 |
|
Other Revenues | | 3 |
| | (24.4 | ) |
Total Change in Gross Margin | | 78 |
| | 50.9 |
|
| | |
| | |
|
Changes in Expenses and Other: | | |
| | |
|
Other Operation and Maintenance | | (19 | ) | | (10.0 | ) |
Depreciation and Amortization | | (16 | ) | | 16.2 |
|
Taxes Other Than Income Taxes | | (5 | ) | | (9.7 | ) |
Interest and Investment Income | | (1 | ) | | (0.4 | ) |
Carrying Costs Income | | (8 | ) | | 2.5 |
|
Allowance for Equity Funds Used During Construction | | | (1.4 | ) |
Interest Expense | | | 5.5 |
|
Total Change in Expenses and Other | | (49 | ) | | 2.7 |
|
| | |
| | |
|
Income Tax Expense | | (8 | ) | | (11.1 | ) |
| | |
| | |
|
Third Quarter of 2015 | | $ | 113 |
| |
Third Quarter of 2016 | | | $ | 155.5 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
Retail Margins increased $117$54 million primarily due to the following:
An $18 million increase in collections of the Ohio PIRR as a result of the June 2016 PUCO order.
A $4 million increase in revenues associated with the Ohio Distribution Investment Rider (DIR).
A $10 million increase in Ohio transmission and PJM revenues, partially offset by a corresponding decrease in other expense items below.
A $9 million increase in the Universal Service Fund (USF) rider in Ohio. This increase in Retail Margins is primarily offset by an increase in Other Operation and Maintenance expenses below.
A $4 million increase in TCC and TNC revenues primarily due to the recovery of ERCOT transmission expenses, offset in Other Operation and Maintenance expenses below.
A $4 million increase in TCC and TNC revenues primarily due to the recovery of distribution expenses.
A $3 million increase in Texas weather-normalized margins in the residential class.
Margins from Off-system Sales increased $9 million primarily due to prior year losses from a power contract with OVEC.
Transmission Revenues increased $12 million primarily due to the following:
A $65$9 million increase primarily due to increased transmission investment in ERCOT.
A $4 million increase in Ohio primarily due to increased investment in the transmission system.
Other Revenues decreased $24 million primarily due to the following:
A $29 million decrease due to a decrease in Texas securitization revenue due to the final maturity of the first Texas securitization bond, offset in Depreciation and Amortization and other expense items below.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $10 million primarily due to the following:
| |
• | A $22 million increase in recoverable expenses, primarily including gridSMART®, ERCOT and PJMexpenses, currently fully recovered in rate recovery riders/trackers. |
A $9 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins above.
These increases were partially offset by:
A $14 million decrease in employee and AEPSC related expenses.
A $4 million decrease in vegetation management expenses.
Depreciation and Amortization expenses decreased $16 millionprimarily due to the following:
A $25 million decrease in TCC’s securitization transition asset due to the final maturity of TCC’s first securitization bond, which is offset in Other Revenues above.
| |
• | A $5 million decrease in recoverable gridSMART® depreciation expenses in Ohio. |
These decreases were partially offset by:
A $6 million increase in Ohio DIR recoveries.
A $6 million increase in depreciation expense primarily due to an increase in depreciable base of transmission and distribution assets.
Taxes Other Than Income Taxes increased $10 million primarily due to the following:
A $5 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.
A $4 million increase in state excise taxes in Ohio due to an increase in metered KWh.
Interest Expense decreased $6 million due to maturities of debt in Ohio and Texas.
Income Tax Expense increased $11 million primarily due to an increase in pretax book income partially offset by the recording of federal income tax adjustments and other book/tax differences which are accounted for on a flow-through basis.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2015 to Nine Months Ended September 30, 2016 |
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities |
(in millions) |
| | |
Nine Months Ended September 30, 2015 | | $ | 287.8 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins | | 235.6 |
|
Off-system Sales | | (9.1 | ) |
Transmission Revenues | | (10.8 | ) |
Other Revenues | | (60.1 | ) |
Total Change in Gross Margin | | 155.6 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | (52.7 | ) |
Depreciation and Amortization | | 30.7 |
|
Taxes Other Than Income Taxes | | (10.8 | ) |
Interest and Investment Income | | (0.4 | ) |
Carrying Costs Income | | (6.0 | ) |
Allowance for Equity Funds Used During Construction | | (0.7 | ) |
Interest Expense | | 10.5 |
|
Total Change in Expenses and Other | | (29.4 | ) |
| | |
|
Income Tax Expense | | (25.9 | ) |
| | |
|
Nine Months Ended September 30, 2016 | | $ | 388.1 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
Retail Margins increased $236 million primarily due to the following:
A $128 million increase in Ohio transmission and PJM revenues primarily due to the energy supplied as a result of the Ohio auction and a regulatory change which resulted in revenues collected through a non-bypassable transmission rider, partially offset by a corresponding decrease in Transmission Revenues below.
| |
• | A $31 million increase in Ohio riders such as Universal Service Fund (USF) and gridSMART®. This increase in Retail Margins is primarily offset by an increase in Other Operation and Maintenance expenses below. |
A $33$21 million Ohioincrease due to a reversal of a regulatory provision recordedresulting from a favorable court decision in 2014.Ohio.
An $18 million increase in collections of the Ohio PIRR as a result of the June 2016 PUCO order.
A $7$16 million increase in revenues associated with the Ohio Distribution Investment Rider (DIR).DIR.
| |
• | A $7 million increase in revenues associated with the gridSMART®, Enhanced Service Reliability and Retail Stability Riders. These riders have corresponding increases in other expense items below.An $18 million increase in Texas weather-normalized margins primarily in the residential class. |
A $6$13 million increase in TCC and TNC revenues primarily due to the recovery of ERCOT transmission expenses, offset in Other Operation and Maintenance expenses below.
A $4$10 million increase in commercial sales in Ohio.carrying charges due to the collection of carrying costs on Ohio deferred capacity charges beginning June 2015.
A $4 million increase in weather-related usage in Texas.TCC and TNC revenues primarily due to the recovery of distribution expenses.
These increases were partially offset by:
A $14 million decrease in base rates due to the discontinuance of seasonal rates in Ohio.
A $14$16 million decrease in revenues associated with the recovery of 2012 storm costs under the Ohio Storm Damage Recovery Rider which ended in April 2015. This decrease in Retail Margins is primarily offset by a decrease in Other Operation and Maintenance expenses below.
A $6 million decrease in weather-related usage in Texas.
Margins from Off-system Sales decreased $9 million primarily due to increased losses from a legacy OPCo power contract.contract with OVEC.
Transmission Revenues decreased $33$11 million primarily due to:to the following:
A $37$55 million decrease in Network Integrated Transmission Service (NITS)NITS revenue primarily due to OPCo assuming the responsibility for items determined to be cost-based transmission-related charges that were the responsibility of the CRES providers prior to June 2015, partially offset by a corresponding increase in Retail Margins above.
This decrease was partially offset by:
A $5$27 million increase primarily due to increased transmission investment in ERCOT.
A $19 million increase in Ohio due to a settlement recorded in 2015, a decrease in amortization of the formula rate true-up and the recording of the current year formula rate true-up in 2016.
24Other Revenues decreased $60 million primarily due to a decrease in Texas securitization revenue as a result of the final maturity of the first Texas securitization bond, offset in Depreciation and Amortization and other expense items below.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $19$53 million primarily due to the following:
A $24 million increase primarily due to PJM and ERCOT expenses fully recovered in rate recovery riders/trackers.
A $7 million increase in employee-related expenses.
These increases were partially offset by:
A $14 million decrease due to the completion of the amortization of 2012 deferred Ohio storm expenses in April 2015. This decrease was offset by a corresponding decrease in Retail Margins above.
Depreciation and Amortization expenses increased $16 millionprimarily due to the following:
A $7 million increase due to an increase in the depreciable base of transmission and distribution assets.
A $4 million increase in amortization of TCC's securitization transition asset, partially offset in Other Revenues above.
| |
• | A $3An $88 million increase in Ohiorecoverable expenses, primarily including PJM expenses and gridSMART® capital carrying charges primarily due to a riderexpenses, currently fully recovered in rate increase effective June 2015. This increase was offset by a corresponding increase in Retail Margins above.recovery riders/trackers.
|
Taxes Other Than Income Taxes increased $5 million primarily due to an increase in property taxes.
Carrying Costs Income decreased $8 million primarily due to the collection of carrying costs on deferred capacity charges beginning June 2015.
Income Tax Expense increased $8 million primarily due to an increase in pretax book income.
Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015 |
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities |
(in millions) |
| | |
Nine Months Ended September 30, 2014 | | $ | 279 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins | | 161 |
|
Off-system Sales | | (13 | ) |
Transmission Revenues | | (54 | ) |
Other Revenues | | 10 |
|
Total Change in Gross Margin | | 104 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | (36 | ) |
Depreciation and Amortization | | (37 | ) |
Taxes Other Than Income Taxes | | (18 | ) |
Interest and Investment Income | | (4 | ) |
Carrying Costs Income | | (10 | ) |
Allowance for Equity Funds Used During Construction | | 3 |
|
Interest Expense | | 4 |
|
Total Change in Expenses and Other | | (98 | ) |
| | |
|
Income Tax Expense | | 3 |
|
| | |
|
Nine Months Ended September 30, 2015 | | $ | 288 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
Retail Margins increased $161 million primarily due to the following:
A $91$15 million increase in Ohio transmission and PJM revenues primarily due to the energy supplied as result of the Ohio auction and a regulatory change which resulted in revenues collected through a non-bypassable transmission rider, partially offset by a corresponding decrease in Transmission Revenues below.
A $33 million Ohio regulatory provision recorded in 2014.
A $24 million increase in TCC and TNC revenues primarily due to the recovery of ERCOT transmission expenses, offset in Other Operation and Maintenance expenses below.
A $22 million increase in revenues associated with the Ohio DIR.
A $5 million increase in weather-related usage in Texas.
These increases were partially offset by:
A $19 million decrease in the Energy Efficiency (EE), Peak Demand Reduction Cost Recovery Rider (PDR) revenues in Ohio and associated deferrals. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
An $11 million decrease in revenues associated with the recovery of 2012 storm costs under the Ohio Storm Damage Recovery Rider which ended in April 2015. This decrease in Retail Margins is primarily offset by a decrease in Other Operation and Maintenance expenses below.
Margins from Off-system Sales decreased $13 million primarily due to losses from a legacy OPCo power contract.
Transmission Revenues decreased $54 million primarily due to the following:
A $44 million decrease in NITS revenue primarily due to OPCo assuming the responsibility for items determined to be cost-based transmission-related charges that were the responsibility of the CRES providers prior to June 2015, partially offset by a corresponding increase in Retail Margins above.
A $12 million decrease in Ohio revenues related to a lower annual transmission formula rate true-up.
A $9 million OPCo transmission regulatory settlement in 2015.
These decreases were partially offset by:
An $18 million increase primarily due to increased transmission investment in ERCOT.
Other Revenues increased $10 million primarily due to $5 million of increased pole attachment revenue for OPCo and a $3 million increase in Texas securitization revenues, offset in Depreciation and Amortization below.
Expenses and Other changed between years as follows:
Other Operation and Maintenance expenses increased $36 million primarily due to the following:
A $36 million increase primarily due to PJM and ERCOT expenses fully recovered in rate recovery riders/trackers.
A $13 million increase in distribution expenses including system improvements and vegetation management expenses.
An $8 million increase in PJM and SPP transmission services.
A $6 million increase due to PUCO ordered contributions to the Ohio Growth Fund.
These increases were partially offset by:
A $19 million decrease in EE and PDR costs and associated deferrals. This decrease was offset by a corresponding decrease in Retail Margins above.
A $6 million decrease in remitted Universal Service FundUSF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins above.
These increases were partially offset by:
A $14 million decrease due to the completion of the Ohio amortization of 2012 deferred storm expenses. This decrease was offset by a corresponding decrease in Retail Margins above.
A $13 million decrease in distribution expenses primarily related to prior year asset inspections.
A $9 million decrease in vegetation management expenses.
A $6 million decrease due to a PUCO ordered contribution to the Ohio Growth Fund recorded in 2015.
Depreciation and Amortization expenses increased $37decreased $31 million primarily due to the following:
A $19$49 million decrease in TCC’s securitization transition asset due to the final maturity of TCC’s first securitization bond, which is offset in Other Revenues above.
| |
• | An $11 million decrease in recoverable gridSMART® depreciation expenses in Ohio. |
These decreases were partially offset by:
A $17 million increase in depreciation expense primarily due to an increase in the depreciable base of transmission and distribution assets.
An $11$8 million increase due to recoveries of Ohio transmission cost rider carrying costs. This increase was offset by a corresponding increase in Retail Margins above.
A $6 million increase in amortization expenses for the collection of TCC's securitization transition asset, partiallycarrying costs on Ohio deferred capacity charges beginning June 2015. This increase was offset by a corresponding increase in Other Revenues.Retail Margins above.
Taxes Other Than Income Taxes increased $18$11 million primarily due to increased property taxes.taxes resulting from additional investments in transmission and distribution assets and higher tax rates.
Carrying Costs Income decreased $10$6 million primarily due to the following:
A $10 million decrease due to the collection of carrying costs on Ohio deferred capacity charges beginning June 2015.
This decrease was partially offset by:
| |
• | A $4 million increase primarily due to an unfavorable prior period adjustment related to gridSMART® capital carrying charges in Ohio. |
Interest Expense decreased $11 million primarily due to:
An $11 million decrease in TCC’s securitization transition assets due to the final maturity of the first Texas securitization bond. This decrease was offset by a corresponding decrease in Other Revenues above.
A $7 million decrease due to the maturity of an OPCo senior unsecured note in June 2016.
| |
• | A $3 million decrease in recoverable gridSMART® interest expenses in Ohio. |
These decreases were partially offset by the following:
An $11 million increase due to issuances of senior unsecured notes by TCC and TNC.
27Income Tax Expense increased $26 million primarily due to an increase in pretax book income partially offset by the recording of state and federal income tax adjustments and other book/tax differences which are accounted for on a flow-through basis.
AEP TRANSMISSION HOLDCO
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
AEP Transmission Holdco | | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
Transmission Revenues | | $ | 88 |
| | $ | 55 |
| | $ | 245 |
| | $ | 140 |
| | $ | 132.4 |
| | $ | 87.5 |
| | $ | 382.7 |
| | $ | 244.9 |
|
Other Operation and Maintenance | | 11 |
| | 7 |
| | 27 |
| | 18 |
| | 12.2 |
| | 11.0 |
| | 32.7 |
| | 26.8 |
|
Depreciation and Amortization | | 12 |
| | 6 |
| | 30 |
| | 17 |
| | 17.1 |
| | 11.7 |
| | 48.4 |
| | 30.3 |
|
Taxes Other Than Income Taxes | | 17 |
| | 10 |
| | 50 |
| | 23 |
| | 22.7 |
| | 16.4 |
| | 65.7 |
| | 49.2 |
|
Operating Income | | 48 |
| | 32 |
| | 138 |
| | 82 |
| | 80.4 |
| | 48.4 |
| | 235.9 |
| | 138.6 |
|
Carrying Costs Expense | | | — |
| | — |
| | (0.2 | ) | | (0.1 | ) |
Allowance for Equity Funds Used During Construction | | 14 |
| | 12 |
| | 40 |
| | 33 |
| | 13.5 |
| | 13.6 |
| | 39.8 |
| | 39.6 |
|
Interest Expense | | (10 | ) | | (6 | ) | | (27 | ) | | (16 | ) | | (12.2 | ) | | (9.9 | ) | | (35.4 | ) | | (27.0 | ) |
Income Before Income Tax Expense and Equity Earnings | | 52 |
| | 38 |
| | 151 |
| | 99 |
| | 81.7 |
| | 52.1 |
| | 240.1 |
| | 151.1 |
|
Income Tax Expense | | 23 |
| | 17 |
| | 66 |
| | 47 |
| | 35.2 |
| | 23.4 |
| | 103.2 |
| | 66.2 |
|
Equity Earnings of Unconsolidated Subsidiaries | | 17 |
| | 22 |
| | 63 |
| | 62 |
| | 23.0 |
| | 17.2 |
| | 72.6 |
| | 62.8 |
|
Net Income | | 46 |
| | 43 |
| | 148 |
| | 114 |
| | 69.5 |
| | 45.9 |
| | 209.5 |
| | 147.7 |
|
Net Income Attributable to Noncontrolling Interests | | — |
| | — |
| | 1 |
| | — |
| | 0.5 |
| | 0.3 |
| | 2.0 |
| | 1.1 |
|
Earnings Attributable to AEP Common Shareholders | | $ | 46 |
| | $ | 43 |
| | $ | 147 |
| | $ | 114 |
| | $ | 69.0 |
| | $ | 45.6 |
| | $ | 207.5 |
| | $ | 146.6 |
|
Summary of Net Plant in Service and CWIP for AEP Transmission Holdco
| | | | As of September 30, | | September 30, |
| | 2015 | | 2014 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
Net Plant in Service | | $ | 2,253 |
| | $ | 1,308 |
| | $ | 3,242.4 |
| | $ | 2,252.6 |
|
CWIP | | 1,298 |
| | 1,050 |
| | 1,565.8 |
| | 1,298.5 |
|
Third Quarter of 20152016 Compared to Third Quarter of 20142015
Reconciliation of Third Quarter of 20142015 to Third Quarter of 20152016
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
| | Third Quarter of 2014 | | $ | 43 |
| |
Third Quarter of 2015 | | | $ | 45.6 |
|
| | | | |
Changes in Transmission Revenues: | | | | |
Transmission Revenues | | 33 |
| | 44.9 |
|
Total Change in Transmission Revenues | | 33 |
| | 44.9 |
|
| | | | |
Changes in Expenses and Other: | | | | |
Other Operation and Maintenance | | (4 | ) | | (1.2 | ) |
Depreciation and Amortization | | (6 | ) | | (5.4 | ) |
Taxes Other Than Income Taxes | | (7 | ) | | (6.3 | ) |
Allowance for Equity Funds Used During Construction | | 2 |
| | (0.1 | ) |
Interest Expense | | (4 | ) | | (2.3 | ) |
Total Change in Expenses and Other | | (19 | ) | | (15.3 | ) |
| | | | |
Income Tax Expense | | (6 | ) | | (11.8 | ) |
Equity Earnings | | (5 | ) | | 5.8 |
|
Net Income Attributable to Noncontrolling Interests | | | (0.2 | ) |
| | | | |
Third Quarter of 2015 | | $ | 46 |
| |
Third Quarter of 2016 | | | $ | 69.0 |
|
The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and non-affiliates, were as follows:
Transmission Revenues increased $33$45 million primarily due to an increaseformula rate increases driven by continued investment in projects placed in-service by our wholly-owned transmission subsidiaries.assets and the related increases in recoverable operating expenses.
Expenses and Other, Income Tax Expense and Equity Earnings changed between years as follows:
Other Operation and Maintenance expenses increased $4 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $6$5 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $7$6 million primarily due to increased property taxes.
Interest Expense increased $4 million primarily due to higher outstanding long-term debt balances.taxes as a result of additional transmission investment.
Income Tax Expense increased $6$12 million primarily due to an increase in pretax book income and by the recording of federal and state income tax adjustments in the third quarter of 2015 compared to the third quarter of 2014.income.
Equity Earnings decreased $5increased $6 million primarily due to increased expense related to cross-arms on ETT transmission lines.investment by ETT.
Nine Months Ended September 30, 20152016 Compared to Nine Months Ended September 30, 20142015
Reconciliation of Nine Months Ended September 30, 20142015 to Nine Months Ended September 30, 20152016
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
| | Nine Months Ended September 30, 2014 | | $ | 114 |
| |
Nine Months Ended September 30, 2015 | | | $ | 146.6 |
|
| | | | |
Changes in Transmission Revenues: | | | | |
Transmission Revenues | | 105 |
| | 137.8 |
|
Total Change in Transmission Revenues | | 105 |
| | 137.8 |
|
| | | | |
Changes in Expenses and Other: | | | | |
Other Operation and Maintenance | | (9 | ) | | (5.9 | ) |
Depreciation and Amortization | | (13 | ) | | (18.1 | ) |
Taxes Other Than Income Taxes | | (27 | ) | | (16.5 | ) |
Carrying Costs Expense | | | (0.1 | ) |
Allowance for Equity Funds Used During Construction | | 7 |
| | 0.2 |
|
Interest Expense | | (11 | ) | | (8.4 | ) |
Total Change in Expenses and Other | | (53 | ) | | (48.8 | ) |
| | | | |
Income Tax Expense | | (19 | ) | | (37.0 | ) |
Equity Earnings | | 1 |
| | 9.8 |
|
Net Income Attributable to Noncontrolling Interests | | (1 | ) | | (0.9 | ) |
| | | | |
Nine Months Ended September 30, 2015 | | $ | 147 |
| |
Nine Months Ended September 30, 2016 | | | $ | 207.5 |
|
The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and non-affiliates, were as follows:
Transmission Revenues increased $105$138 million primarily due to the following:
A $110 million increase due to formula rate increases driven by continued investment in transmission assets and the related increases in recoverable operating expenses.
A $28 million increase due to AEPTCo annual formula rate true-up adjustments.
Expenses and Other, Income Tax Expense and Equity Earnings changed between years as follows:
Other Operation and Maintenance expenses increased $6 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $18 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $17 million primarily due to increased property taxes as a result of additional transmission investment.
Interest Expense increased $8 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $37 million primarily due to an increase in projects placed in-servicepretax book income.
Equity Earnings increased $10 million primarily due to increased transmission investment by our wholly-owned transmission subsidiaries.ETT.
GENERATION & MARKETING
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Generation & Marketing | | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) |
Revenues | | $ | 859.4 |
| | $ | 836.0 |
| | $ | 2,291.2 |
| | $ | 2,806.7 |
|
Fuel, Purchased Electricity and Other | | 567.4 |
| | 564.4 |
| | 1,490.6 |
| | 1,771.3 |
|
Gross Margin | | 292.0 |
| | 271.6 |
| | 800.6 |
| | 1,035.4 |
|
Other Operation and Maintenance | | 95.8 |
| | 60.2 |
| | 290.2 |
| | 276.6 |
|
Asset Impairments and Other Related Charges | | 2,254.4 |
| | — |
| | 2,254.4 |
| | — |
|
Depreciation and Amortization | | 50.5 |
| | 50.9 |
| | 149.8 |
| | 151.8 |
|
Taxes Other Than Income Taxes | | 8.7 |
| | 10.5 |
| | 29.0 |
| | 30.4 |
|
Operating Income (Loss) | | (2,117.4 | ) | | 150.0 |
| | (1,922.8 | ) | | 576.6 |
|
Other Income | | 0.3 |
| | 0.6 |
| | 1.2 |
| | 2.2 |
|
Interest Expense | | (9.5 | ) | | (10.4 | ) | | (27.1 | ) | | (31.0 | ) |
Income (Loss) Before Income Tax Expense | | (2,126.6 | ) | | 140.2 |
| | (1,948.7 | ) | | 547.8 |
|
Income Tax Expense (Credit) | | (757.4 | ) | | 48.6 |
| | (699.9 | ) | | 187.5 |
|
Net Income (Loss) | | (1,369.2 | ) | | 91.6 |
| | (1,248.8 | ) | | 360.3 |
|
Net Income Attributable to Noncontrolling Interests | | — |
| | — |
| | — |
| | — |
|
Earnings (Loss) Attributable to AEP Common Shareholders | | $ | (1,369.2 | ) | | $ | 91.6 |
| | $ | (1,248.8 | ) | | $ | 360.3 |
|
Summary of MWhs Generated for Generation & Marketing
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2016 | | 2015 | | 2016 | | 2015 |
| (in millions of MWhs) |
Fuel Type: | |
| | |
| | |
| | |
|
Coal | 8 |
| | 7 |
| | 19 |
| | 23 |
|
Natural Gas | 4 |
| | 3 |
| | 11 |
| | 10 |
|
Wind | — |
| | 1 |
| | — |
| | 1 |
|
Total MWhs | 12 |
| | 11 |
| | 30 |
| | 34 |
|
Third Quarter of 2016 Compared to Third Quarter of 2015
|
| | | | |
Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 |
Earnings Attributable to AEP Common Shareholders from Generation & Marketing |
(in millions) |
| | |
Third Quarter of 2015 | | $ | 91.6 |
|
| | |
|
Changes in Gross Margin: | | |
|
Generation | | (2.8 | ) |
Retail, Trading and Marketing | | 25.0 |
|
Other | | (1.8 | ) |
Total Change in Gross Margin | | 20.4 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | (35.6 | ) |
Asset Impairments and Other Related Charges | | (2,254.4 | ) |
Depreciation and Amortization | | 0.4 |
|
Taxes Other Than Income Taxes | | 1.8 |
|
Other Income | | (0.3 | ) |
Interest Expense | | 0.9 |
|
Total Change in Expenses and Other | | (2,287.2 | ) |
| | |
|
Income Tax Expense | | 806.0 |
|
| | |
|
Third Quarter of 2016 | | $ | (1,369.2 | ) |
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain cost of service for retail operations were as follows:
Retail, Trading and Marketing increased $25 million primarily due to the impact of favorable wholesale trading and marketing performance and higher retail margins and volume.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $9$36 million primarily due to increased transmission investment.the prior year sale of certain assets and revision of the related asset retirement obligations.
DepreciationAsset Impairments and AmortizationOther Related Charges expenses increased $13 million primarily$2.3 billion due to higher depreciable base.
Taxes Other Than Income Taxes increased $27 million primarily due to increased property taxes.
Allowance for Equity Funds Used During Construction increased $7 million primarily due to increased transmission investment.
Interest Expense increased $11 million primarily due to higher outstanding long-term debt balances.an asset impairment of certain merchant generation assets.
Income Tax Expense increased $19decreased $806 million primarily due to an increase inreduced pretax book income.income as a result of the impairment of certain merchant generation assets.
GENERATION & MARKETINGNine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Generation & Marketing | | 2015 | | 2014 | | 2015 | | 2014 |
| | (in millions) |
Revenues | | $ | 835 |
| | $ | 901 |
| | $ | 2,806 |
| | $ | 3,065 |
|
Fuel, Purchased Electricity and Other | | 564 |
| | 529 |
| | 1,771 |
| | 1,894 |
|
Gross Margin | | 271 |
| | 372 |
| | 1,035 |
| | 1,171 |
|
Other Operation and Maintenance | | 61 |
| | 122 |
| | 277 |
| | 363 |
|
Depreciation and Amortization | | 51 |
| | 56 |
| | 152 |
| | 169 |
|
Taxes Other Than Income Taxes | | 10 |
| | 12 |
| | 30 |
| | 37 |
|
Operating Income | | 149 |
| | 182 |
| | 576 |
| | 602 |
|
Interest and Investment Income | | — |
| | 2 |
| | 2 |
| | 4 |
|
Interest Expense | | (10 | ) | | (12 | ) | | (31 | ) | | (35 | ) |
Income Before Income Tax Expense | | 139 |
| | 172 |
| | 547 |
| | 571 |
|
Income Tax Expense | | 48 |
| | 55 |
| | 187 |
| | 193 |
|
Net Income | | 91 |
| | 117 |
| | 360 |
| | 378 |
|
Net Income Attributable to Noncontrolling Interests | | — |
| | — |
| | — |
| | — |
|
Earnings Attributable to AEP Common Shareholders | | $ | 91 |
| | $ | 117 |
| | $ | 360 |
| | $ | 378 |
|
Summary of MWhs Generated for Generation & Marketing
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
| (in millions of MWhs) |
Fuel Type: | |
| | |
| | |
| | |
|
Coal | 7 |
| | 16 |
| | 23 |
| | 37 |
|
Natural Gas | 3 |
| | 2 |
| | 10 |
| | 6 |
|
Wind | 1 |
| | — |
| | 1 |
| | — |
|
Total MWhs | 11 |
| | 18 |
| | 34 |
| | 43 |
|
Third Quarter of 2015 Compared to Third Quarter of 2014
| | Reconciliation of Third Quarter of 2014 to Third Quarter of 2015 | |
Reconciliation of Nine Months Ended September 30, 2015 to Nine Months Ended September 30, 2016 | | Reconciliation of Nine Months Ended September 30, 2015 to Nine Months Ended September 30, 2016 |
Earnings Attributable to AEP Common Shareholders from Generation & Marketing | (in millions) | | | | | |
Third Quarter of 2014 | | $ | 117 |
| |
Nine Months Ended September 30, 2015 | | | $ | 360.3 |
|
| | |
| | |
|
Changes in Gross Margin: | | |
| | |
|
Generation | | (96 | ) | | (227.5 | ) |
Retail, Trading and Marketing | | (6 | ) | | (3.0 | ) |
Other | | 1 |
| | (4.3 | ) |
Total Change in Gross Margin | | (101 | ) | | (234.8 | ) |
| | |
| | |
|
Changes in Expenses and Other: | | |
| | |
|
Other Operation and Maintenance | | 61 |
| | (13.6 | ) |
Asset Impairments and Other Related Charges | | | (2,254.4 | ) |
Depreciation and Amortization | | 5 |
| | 2.0 |
|
Taxes Other Than Income Taxes | | 2 |
| | 1.4 |
|
Interest and Investment Income | | (2 | ) | |
Other Income | | | (1.0 | ) |
Interest Expense | | 2 |
| | 3.9 |
|
Total Change in Expenses and Other | | 68 |
| | (2,261.7 | ) |
| | |
| | |
|
Income Tax Expense | | 7 |
| | 887.4 |
|
| | |
| | |
|
Third Quarter of 2015 | | $ | 91 |
| |
Nine Months Ended September 30, 2016 | | | $ | (1,248.8 | ) |
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain cost of service for retail operations were as follows:
Generation decreased $96$228 million primarily due to lower capacity revenuerevenues due to plant retirements and the terminationtransition of the Power Supply Agreement between AGROhio Standard Service offer to full market pricing and OPCo on May 31, 2015.
Retail, Trading and Marketing decreased $6 million primarily due to decreaseda decrease in wholesale trading and marketing performance.energy prices partially offset by favorable hedging activity.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses decreased $61increased $14 million primarily due to a settlementthe prior year sale of certain assets and revision of certainthe related asset retirement obligations, and decreasedpartially offset by a decrease in maintenance due to plant outage and maintenance costs.retirements in June 2015.
DepreciationAsset Impairments and AmortizationOther Related Charges expensesincreased $2.3 billion due to an asset impairment of certain merchant generation assets.
Interest Expense decreased $5$4 million primarily due to reduced plant in-service.decreased long-term debt balances.
Income Tax Expense decreased $7 million primarily due to a decrease in pretax book income, partially offset by the recording of federal and state income tax adjustments.
Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015 |
Earnings Attributable to AEP Common Shareholders from Generation & Marketing |
(in millions) |
| | |
Nine Months Ended September 30, 2014 | | $ | 378 |
|
| | |
|
Changes in Gross Margin: | | |
|
Generation | | (172 | ) |
Retail, Trading and Marketing | | 40 |
|
Other | | (4 | ) |
Total Change in Gross Margin | | (136 | ) |
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | 86 |
|
Depreciation and Amortization | | 17 |
|
Taxes Other Than Income Taxes | | 7 |
|
Interest and Investment Income | | (2 | ) |
Interest Expense | | 4 |
|
Total Change in Expenses and Other | | 112 |
|
| | |
|
Income Tax Expense | | 6 |
|
| | |
|
Nine Months Ended September 30, 2015 | | $ | 360 |
|
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain cost of service for retail operations were as follows:
Generation decreased $172 million primarily due to lower capacity revenue due to the termination of the Power Supply Agreement between AGR and OPCo on May 31, 2015.
Retail, Trading and Marketing increased $40 million primarily due to favorable wholesale trading and marketing performance as well as an increase in retail volumes.
Expenses and Other changed between years as follows:
Other Operation and Maintenance expenses decreased $86 million primarily due to a settlement and revision of certain asset retirement obligations and decreased plant outage and maintenance costs.
Depreciation and Amortization expenses decreased $17$887 million primarily due to reduced plant in-service.
Taxes Other Than Income Taxes decreased $7 million primarily due to a decrease in property taxes.
Income Tax Expense decreased $6 million primarily due to a decrease in pretax book income partially offset byas a result of the recordingimpairment of federal and state income tax adjustments.certain merchant generation assets.
AEP RIVER OPERATIONS
Third Quarter of 2015 Compared to Third Quarter of 2014
Earnings Attributable to AEP Common Shareholders from our AEP River Operations segment decreased from $11 million in 2014 to $4 million in 2015 primarily due to a loss on AEPRO's equity investment in IMT due to bankruptcy of an IMT customer.
Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
Earnings Attributable to AEP Common Shareholders from our AEP River Operations segment decreased from $17 million in 2014 to $16 million in 2015 primarily due to a loss on AEPRO's equity investment in IMT due to bankruptcy of an IMT customer, partially offset by lower fuel prices and reduced consumption.
CORPORATE AND OTHER
Third Quarter of 20152016 Compared to Third Quarter of 20142015
Earnings Attributable to AEP Common Shareholders from Corporate and Other decreasedincreased from income of $11 million in 2014 to a loss of $9$6 million in 2015 to a gain of $36 million in 2016 primarily due to an increase in reserves for our captive insurance program the reversal of capital loss valuation allowances related to the pending sale of certain merchant generation assets as well as tax return adjustments related to the impactprior year disposition of a 2014 tax adjustment.AEP’s commercial barging operations. This was partly offset by decreased income from the discontinued operations of AEP’s commercial barging operations which was sold in November 2015.
Nine Months Ended September 30, 20152016 Compared to Nine Months Ended September 30, 20142015
Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from income of $4 million in 2014 to a loss of $13$3 million in 2015 to income of $61 million in 2016 primarily due to the reversal of capital loss valuation allowances related to an increase in reserves for our captive insurance programthe settlement of a 2011 audit issue with the IRS and the impact of the pending sale of certain merchant generation assets as well as 2015 tax return adjustments related to the impactdisposition of a 2014 tax adjustment.AEP’s commercial barging operations. This was partly offset by charges related to the final accounting of the disposition of AEP’s commercial barging operations and decreased income from the discontinued operations of AEP’s commercial barging operations which was sold in November 2015.
AEP SYSTEM INCOME TAXES
Third Quarter of 20152016 Compared to Third Quarter of 20142015
Income Tax Expense increased $11decreased $810 million primarily due to an increase inreduced pretax book income as a result of the impairment of certain merchant generation assets and by the recordingreversal of federal and state income tax adjustments in the third quarter of 2015 comparedcapital loss valuation allowances related to the third quarterpending sale of 2014, partially offset bycertain merchant generation assets as well as 2015 tax return adjustments related to the regulatory accounting treatmentdisposition of state income taxes.AEP’s commercial barging operations.
Nine Months Ended September 30, 20152016 Compared to Nine Months Ended September 30, 20142015
Income Tax Expense increased $44decreased $961 million primarily due to an increase inreduced pretax book income as a result of the impairment of certain merchant generation assets and by the recordingreversal of federalcapital loss valuation allowances related to the pending sale of certain merchant generation assets and state incomethe settlement of a 2011 audit issue with the IRS as well as 2015 tax return adjustments in 2015 comparedrelated to 2014, partially offset by the regulatory accounting treatmentdisposition of state income taxes.AEP’s commercial barging operations.
FINANCIAL CONDITION
We measure ourAEP measures financial condition by the strength of ourits balance sheet and the liquidity provided by ourits cash flows.
LIQUIDITY AND CAPITAL RESOURCES
Debt and Equity Capitalization
| | | September 30, 2015 | | December 31, 2014 | September 30, 2016 | | December 31, 2015 |
| (dollars in millions) | (dollars in millions) |
Long-term Debt, including amounts due within one year (a) | $ | 19,507 |
| | 51.3 | % | | $ | 18,684 |
| | 50.7 | % | $ | 19,839.5 |
| (a) | 51.3 | % | | $ | 19,572.7 |
| | 51.1 | % |
Short-term Debt | 782 |
| | 2.1 |
| | 1,346 |
| | 3.6 |
| 1,478.3 |
| | 3.8 |
| | 800.0 |
| | 2.1 |
|
Total Debt (a) | 20,289 |
| | 53.4 |
| | 20,030 |
| | 54.3 |
| 21,317.8 |
| (a) | 55.1 |
| | 20,372.7 |
| | 53.2 |
|
AEP Common Equity | 17,699 |
| | 46.6 |
| | 16,820 |
| | 45.7 |
| 17,321.9 |
| | 44.8 |
| | 17,891.7 |
| | 46.8 |
|
Noncontrolling Interests | 10 |
| | — |
| | 4 |
| | — |
| 21.1 |
| | 0.1 |
| | 13.2 |
| | — |
|
Total Debt and Equity Capitalization | $ | 37,998 |
| | 100.0 | % | | $ | 36,854 |
| | 100.0 | % | $ | 38,660.8 |
| | 100.0 | % | | $ | 38,277.6 |
| | 100.0 | % |
| |
(a) | Amounts include debt related to AEPROthe Lawrenceburg Plant that havehas been classified as Liabilities Held for Sale on the condensed balance sheets.sheet. See "AEPRO (AEP River Operations“Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)"” section of Note 6 for additional information. |
Our
AEP’s ratio of debt-to-total capital improved from 54.3% as of December 31, 2014 to 53.4% as of September 30, 2015changed primarily due to an increasea decrease in our common equity from earnings.as a result of the impairment of certain merchant generation assets.
Liquidity
Liquidity, or access to cash, is an important factor in determining ourAEP’s financial stability. We believe we haveManagement believes AEP has adequate liquidity under ourits existing credit facilities. As of September 30, 2015, we2016, AEP had $3.5 billion in aggregate credit facility commitments to support ourits operations. Additional liquidity is available from cash from operations and a receivables securitization agreement. We areManagement is committed to maintaining adequate liquidity. WeAEP generally useuses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, sale-and-leasebacksale-leaseback or leasing agreements or common stock.
Commercial Paper Credit Facilities
We manage ourAEP manages liquidity by maintaining adequate external financing commitments. As of September 30, 2015, our2016, available liquidity was approximately $3.6$3 billion as illustrated in the table below:
| | | | Amount | | Maturity | | Amount | | Maturity |
| | (in millions) | | | (in millions) | |
Commercial Paper Backup: | Commercial Paper Backup: | |
| | | Commercial Paper Backup: | |
| | |
| Revolving Credit Facility | $ | 1,750 |
| | June 2017 | Revolving Credit Facility | $ | 3,000.0 |
| | June 2021 |
| Revolving Credit Facility | 1,750 |
| | July 2018 | Revolving Credit Facility | 500.0 |
| | June 2018 |
Total | Total | 3,500 |
| | | Total | 3,500.0 |
| | |
Cash and Cash Equivalents | Cash and Cash Equivalents | 178 |
| | | Cash and Cash Equivalents | 212.2 |
| | |
Total Liquidity Sources | Total Liquidity Sources | 3,678 |
| | | Total Liquidity Sources | 3,712.2 |
| | |
Less: | AEP Commercial Paper Outstanding | 32 |
| | | AEP Commercial Paper Outstanding | 728.3 |
| | |
| Letters of Credit Issued | 33 |
| | | | | |
| | | | |
Net Available Liquidity | Net Available Liquidity | $ | 3,613 |
| | | Net Available Liquidity | $ | 2,983.9 |
| | |
We haveAEP has two credit facilities totaling $3.5 billion to support ourits commercial paper program. The $3 billion credit facilities allow usfacility allows management to issue letters of credit in an amount up to $1.2 billion.
We use ourAEP uses its commercial paper program to meet the short-term borrowing needs of ourits subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of thecertain nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. The maximum amount of commercial paper outstanding during the first nine months of 20152016 was $788 million.$1.5 billion. The weighted-average interest rate for ourAEP’s commercial paper during 20152016 was 0.45%0.77%.
Other Credit Facilities
We issue letters of credit under two uncommitted facilities totaling $150 million. As of September 30, 2015, the maximum future payment for letters of credit issued under the uncommitted facilities was $122 million with maturities ranging from October 2015 to September 2016. An uncommitted facility gives the issuer of the facility the right to accept or decline each request we makemade under the facility. AEP issues letters of credit under four uncommitted facilities totaling $300 million. As of September 30, 2016, the maximum future payment for letters of credit issued under the uncommitted facilities was $147 million with maturities ranging from October 2016 to September 2017.
Securitized Accounts Receivable
OurAEP’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement expires in June 2017.2018.
Debt Covenants and Borrowing Limitations
OurAEP’s credit agreements contain certain covenants and require usit to maintain oura percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually defined in ourAEP’s credit agreements. Debt as defined in the revolving credit agreements excludes securitization bonds and debt of AEP Credit. As of September 30, 2015,2016, this contractually-defined percentage was 50.6%52.7%. Nonperformance under these covenants could result in an event of default under these credit agreements. As of September 30, 2015, we complied with all of the covenants contained in these credit agreements. In addition, the acceleration of ourAEP’s payment obligations, or the obligations of certain of ourAEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements. This condition also applies in a majority of ourAEP’s non-exchange traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable. However, a default under ourAEP’s non-exchange traded commodity contracts doeswould not cause an event of default under ourits credit agreements.
The revolving credit facilities do not permit the lenders to refuse a draw on any facility if a material adverse change occurs.
Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders and we manage ourAEP manages its borrowings to stay within those authorized limits.
Dividend Policy and Restrictions
The Board of Directors declared a quarterly dividend of $0.56$0.59 per share in October 2015.2016. Future dividends may vary depending upon ourAEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. OurParent’s income primarily derives from our common stock equity in the earnings of ourits utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utilitythe subsidiaries to transfer funds to usParent in the form of dividends.
We doManagement does not believe these restrictions related to ourAEP’s various financing arrangements and regulatory requirements will have any significant impact on Parent’sits ability to access cash to meet the payment of dividends on its common stock.
Credit Ratings
We doAEP does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but ourits access to the commercial paper market may depend on ourtheir credit ratings. In addition, downgrades in ourAEP’s credit ratings by one of the rating agencies could increase ourits borrowing costs. Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject usAEP to additional collateral demands under adequate assurance clauses under ourits derivative and non-derivative energy contracts.
CASH FLOW
Managing ourAEP relies primarily on cash flows is a major factor in maintaining ourfrom operations, debt issuances and its existing cash and cash equivalents to fund its liquidity strength.and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders.
| | | Nine Months Ended September 30, | Nine Months Ended September 30, |
| 2015 | | 2014 | 2016 | | 2015 |
| (in millions) | (in millions) |
Cash and Cash Equivalents at Beginning of Period | $ | 163 |
| | $ | 118 |
| $ | 176.4 |
| | $ | 162.5 |
|
Net Cash Flows from Operating Activities | 3,910 |
| | 3,715 |
| |
Net Cash Flows Used for Investing Activities | (3,248 | ) | | (3,079 | ) | |
Net Cash Flows Used for Financing Activities | (647 | ) | | (560 | ) | |
Net Cash Flows from Continuing Operating Activities | | 3,421.0 |
| | 3,910.7 |
|
Net Cash Flows Used for Continuing Investing Activities | | (3,428.7 | ) | | (3,248.4 | ) |
Net Cash Flows from (Used for) Continuing Financing Activities | | 46.0 |
| | (647.3 | ) |
Net Cash Flows from (Used for) Discontinued Operations | | (2.5 | ) | | 0.3 |
|
Net Increase in Cash and Cash Equivalents | 15 |
| | 76 |
| 35.8 |
| | 15.3 |
|
Cash and Cash Equivalents at End of Period | $ | 178 |
| | $ | 194 |
| $ | 212.2 |
| | $ | 177.8 |
|
Cash from operations
AEP uses short-term debt, including commercial paper, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and short-term borrowings provides working capital and allows us to meet other short-termthe impact of fluctuations in cash needs.flows.
Operating Activities
| | | Nine Months Ended September 30, | Nine Months Ended September 30, |
| 2015 | | 2014 | 2016 | | 2015 |
| (in millions) | (in millions) |
Net Income | $ | 1,564 |
| | $ | 1,430 |
| |
Income from Continuing Operations | | $ | 245.3 |
| | $ | 1,563.4 |
|
Depreciation and Amortization | 1,528 |
| | 1,418 |
| 1,550.2 |
| | 1,528.0 |
|
Deferred Income Taxes | | (47.0 | ) | | 528.6 |
|
Asset Impairments and Other Related Charges | | 2,264.9 |
| | — |
|
Fuel, Materials and Supplies | | 11.6 |
| | 193.8 |
|
Accrued Taxes, Net | | (393.0 | ) | | (68.3 | ) |
Other | 818 |
| | 867 |
| (211.0 | ) | | 165.2 |
|
Net Cash Flows from Operating Activities | $ | 3,910 |
| | $ | 3,715 |
| |
Net Cash Flows from Continuing Operating Activities | | $ | 3,421.0 |
| | $ | 3,910.7 |
|
Net Cash Flows from Continuing Operating Activities were $3.4 billion in 2016 consisting primarily of Net Income of $245 million and $1.6 billion of noncash Depreciation and Amortization. AEP also had asset impairments of $2.3 billion during the third quarter of 2016. See Note 6 - Dispositions, Assets and Liabilities Held for Sale and Impairments for a complete discussion of asset impairments and other related charges. Accrued Taxes decreased primarily due to the impacts of bonus depreciation related to the Protecting Americans from Tax Hikes Act of 2015. Deferred Income Taxes decreased primarily due to the tax effect of the asset impairment partially offset by an increase in tax versus book temporary differences from operations, which includes provisions related to the Protecting Americans from Tax Hikes Act of 2015. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.
Net Cash Flows from Continuing Operating Activities were $3.9 billion in 2015 consisting primarily of Net Income of $1.6 billion and $1.5 billion of noncash Depreciation and Amortization. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. Deferred Income Taxes increased primarily due to provisions in the Taxpayer Relief Act of 2014 and an increase in tax/book temporary differences from operations. The reduction in Fuel, Materials and Supplies balances reflects a decrease in fuel inventory due to the cold winter weather and plants retired during the second quarter of 2015.
Net Cash Flows from Operating Activities were $3.7 billion in 2014 consisting primarily of Net Income of $1.4 billion and $1.4 billion of noncash Depreciation and Amortization partially offset by $106 million of Ohio capacity deferrals as a result of the PUCO's July 2012 approval of a capacity deferral mechanism. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. Deferred Income Taxes increased primarily due to provisions in the Taxpayer Relief Act of 2012 and an increase in tax/book temporary differences from operations. The reduction in Fuel, Material and Supplies balances reflects a decrease in fuel inventory due to the cold winter weather and increased generation.
Investing Activities
| | | Nine Months Ended September 30, | Nine Months Ended September 30, |
| 2015 | | 2014 | 2016 | | 2015 |
| (in millions) | (in millions) |
Construction Expenditures | $ | (3,283 | ) | | $ | (2,897 | ) | $ | (3,387.0 | ) | | $ | (3,282.7 | ) |
Acquisitions of Nuclear Fuel | (53 | ) | | (109 | ) | (127.6 | ) | | (53.3 | ) |
Acquisitions of Assets/Businesses | (1 | ) | | (45 | ) | |
Other | 89 |
| | (28 | ) | 85.9 |
| | 87.6 |
|
Net Cash Flows Used for Investing Activities | $ | (3,248 | ) | | $ | (3,079 | ) | |
Net Cash Flows Used for Continuing Investing Activities | | $ | (3,428.7 | ) | | $ | (3,248.4 | ) |
Net Cash Flows Used for Continuing Investing Activities were $3.4 billion in 2016 primarily due to Construction Expenditures for environmental, distribution and transmission investments.
Net Cash Flows Used for Continuing Investing Activities were $3.2 billion in 2015 primarily due to Construction Expenditures for environmental, distribution and transmission investments.
Net Cash Flows Used for Investing Activities were $2.9 billion in 2014 primarily due to Construction Expenditures for environmental, distribution and transmission investments. We also purchased transmission assets for $38 million.
Financing Activities
| | | Nine Months Ended September 30, | Nine Months Ended September 30, |
| 2015 | | 2014 | 2016 | | 2015 |
| (in millions) | (in millions) |
Issuance of Common Stock, Net | $ | 68 |
| | $ | 63 |
| |
Issuance of Common Stock | | $ | 34.2 |
| | $ | 67.9 |
|
Issuance of Debt, Net | 236 |
| | 195 |
| 930.3 |
| | 235.7 |
|
Dividends Paid on Common Stock | (783 | ) | | (736 | ) | (829.8 | ) | | (783.4 | ) |
Other | (168 | ) | | (82 | ) | (88.7 | ) | | (167.5 | ) |
Net Cash Flows Used for Financing Activities | $ | (647 | ) | | $ | (560 | ) | |
Net Cash Flows from (Used for) Continuing Financing Activities | | $ | 46.0 |
| | $ | (647.3 | ) |
Net Cash Flows from Continuing Financing Activities in 2016 were $46 million. AEP’s net debt issuances were $930 million. The net issuances included an increase in short-term borrowing of $678 million, issuances of $950 million of senior unsecured notes, $191 million of pollution control bonds and $430 million of other debt notes offset by retirements of $507 million of senior unsecured notes, $289 million of securitization bonds, $251 million of pollution control bonds and $261 million of other debt notes. AEP paid common stock dividends of $830 million. See Note 12 - Financing Activities for a complete discussion of long-term debt issuances and retirements.
Net Cash Flows Used for Continuing Financing Activities in 2015 were $647 million. OurAEP’s net debt issuances were $236 million. The net issuances included issuances of $2.1 billion of senior unsecured notes, $140 million of pollution control bonds and $757 million of other debt notes offset by retirements of $907 million of senior unsecured notes, $308 million of securitization bonds, $229 million of pollution control bonds and $687 of other debt notes and a decrease in short term borrowing of $564 million. WeAEP paid common stock dividends of $783 million. Other includes a make whole premium payment on the extinguishment of long-term debt of $93 million in addition to capital lease principal payments of $74 million. See Note 12 - Financing Activities for a complete discussion of long-term debt issuances and retirements.
Net Cash Flows Used for Financing Activities in 2014 were $560 million. Our net debt issuances were $195 million. The net issuances included issuances of $650 million of senior unsecured notes, $343 million of pollution control bonds and $224 million of other debt notes and an increase in short-term borrowing of $525 million offset by retirements of $951 million of senior unsecured and other debt notes, $312 million of pollution control bonds and $273 million of securitization bonds. We paid common stock dividends of $736 million. See Note 12 - Financing Activities for a complete discussion of long-term debt issuances and retirements.
In October 2015, KPCo drew the remaining $252016, I&M retired $16 million on an existing $75 million variable rate credit facility due in 2018.
In October 2015, Transource Missouri drew $6 million on an existing $300 million variable rate credit facility due in 2018.
BUDGETED CONSTRUCTION EXPENDITURES
In July 2015, we increased our forecast for construction expenditures by $200 millionof Notes Payable related to approximately $4.6 billion for 2015. The increase is primarily for transmission investment in the Vertically Integrated Utilities, Transmission and Distribution Utilities, and AEP Transmission Holdco segments.DCC Fuel.
OFF-BALANCE SHEET ARRANGEMENTS
OurAEP’s current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that we enterAEP enters in the normal course of business. The following identifies significant off-balance sheet arrangements:
| | | September 30, 2015 | | December 31, 2014 | September 30, 2016 | | December 31, 2015 |
| (in millions) | (in millions) |
Rockport Plant, Unit 2 Future Minimum Lease Payments | $ | 1,110 |
| | $ | 1,184 |
| $ | 960.1 |
| | $ | 1,034.0 |
|
Railcars Maximum Potential Loss from Lease Agreement | 19 |
| | 19 |
| 18.1 |
| | 18.1 |
|
For complete information on each of these off-balance sheet arrangements, see the “Off-balance Sheet Arrangements” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 20142015 Annual Report.
CONTRACTUAL OBLIGATION INFORMATION
A summary of our contractual obligations is included in our 2014the 2015 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 20142015 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.
Long-Lived Assets
Nature of Estimates Required
In accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the Registrants evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable including planned abandonments and a probable disallowance for rate-making on a plant under construction or the assets meet the held-for-sale criteria. The Registrants utilize a group composite method of depreciation to estimate the useful lives of long-lived assets. The evaluations of long-lived, held and used assets may result from abandonments, significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operations analyses. If the carrying amount is not recoverable, the Registrants record an impairment to the extent that the fair value of the asset is less than its book value. Performing an impairment evaluation involves a significant degree of estimation and judgment in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets and developing the undiscounted and discounted future cash flows (used to estimate fair value in the absence of market-based value, in some instances) associated with the asset. For assets held for sale, an impairment is recognized if the expected net sales price is less than its book value. For regulated assets, the earnings impact of an impairment charge could be offset by the establishment of a regulatory asset, if rate recovery is probable. For nonregulated assets, any impairment charge is recorded against earnings.
Assumptions and Approach Used
The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, the Registrants estimate fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals. Cash flow estimates are based on relevant information available at the time the estimates are made. Estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. Also, when measuring fair value, management evaluates the characteristics of the asset or liability to determine if market participants would take those characteristics into account when pricing the asset or liability at the measurement date. Such characteristics include, for example, the condition and location of the asset or restrictions of the use of the asset. The Registrants perform depreciation studies that include a review of any external factors that may affect the useful life to determine composite depreciation rates and related lives which are subject to periodic review by state regulatory commissions for cost-based regulated assets. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.
Effect if Different Assumptions Used
In connection with the evaluation of long-lived assets in accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the fair value of the asset can vary if different estimates and assumptions would have been used in the applied valuation techniques. The estimate for depreciation rates takes into account the history of interim capital replacements and the amount of salvage expected. In cases of impairment, the best estimate of fair value was made using valuation methods based on the most current information at that time. Fluctuations in realized
sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including, but not limited to, differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions and management’s analysis of the benefits of the transaction.
ACCOUNTING PRONOUNCEMENTS
New Accounting Pronouncements Adopted During the First Quarter of 20152016
The FASB issued ASU 2014-08 “Presentation2015-01 “Income Statement – Extraordinary and Unusual Items” eliminating the concept of Financial Statements and Property, Plant and Equipment” changingextraordinary items for presentation on the presentationface of discontinued operations on the statements of income and other requirements for reporting discontinued operations.income. Under the new standard, a disposal of a componentmaterial event or a group of components of an entitytransaction that is required tounusual in nature, infrequent or both shall be reported in discontinued operations if the disposal representsas a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significantseparate component of an entity that does not qualify for discontinuedincome from continuing operations. WeAlternatively, it may be disclosed in the notes to financial statements. Management adopted ASU 2014-082015-01 effective January 1, 2015.2016.
39The FASB issued ASU 2015-05 “Customer’s Accounting for Fees paid in a Cloud Computing Arrangement” providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-05 prospectively, effective January 1, 2016, with no impact on results of operations, financial position or cash flows.
Pronouncements Effective in the Future
The FASB issued ASU 2014-09 “Revenue from Contracts with Customers” clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted for annual periods beginning after December 15, 2016. We areManagement is analyzing the impact of this new standard and atthe related ASUs that clarify guidance in the standard. At this time, management cannot estimate the impact of adoption on revenue or net income. We planManagement plans to adopt ASU 2014-09 effective January 1, 2018.
The FASB issued ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. We plan to adopt ASU 2015-01 effective January 1, 2016.
The FASB issued ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” to simplify the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. We include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. We intend to early adopt ASU 2015-03 for the 2015 Form 10-K.
The FASB issued ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. We plan to adopt ASU 2015-05 effective January 1, 2016.
The FASB issued ASU 2015-11 “Simplifying the Measurement of Inventory” to simplify the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. WeManagement does not expect the new standard to impact the Registrants’ results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017.
The FASB issued ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. We planManagement plans to adopt ASU 2015-112016-01 effective January 1, 2018.
The FASB issued ASU 2016-02 “Accounting for Leases” increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented as well as a number of optional practical expedients that entities may elect to apply. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management expects the new standard to impact the Registrants’ financial position, but not the Registrants’ results of operations or cash flows. Management plans to adopt ASU 2016-02 effective January 1, 2019.
The FASB issued ASU 2016-09 “Compensation – Stock Compensation” simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. The new accounting guidance is effective for annual periods beginning after December 15, 2016. Early adoption is permitted in any interim or annual period. Certain provisions require retrospective/modified retrospective transition while others are to be applied prospectively. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management plans to adopt ASU 2016-09 effective January 1, 2017.
The FASB issued ASU 2015-13 “Application2016-13 “Measurement of the Normal PurchasesCredit Losses on Financial Instruments” requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchasesreasonable and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under thesupportable forecasts. The new standard also makes revisions to the useother than temporary impairment model for available-for-sale debt securities. Disclosures of locational marginal pricingcredit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by an independent system operator does not cause a contract to fail to meet the physical delivery criterionyear of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale.origination. The new accounting guidance is effective upon issuancefor interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied prospectively. We have analyzedthrough a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, determined that it will have noat this time, cannot estimate the impact on the accounting of our contracts. Additionally, adoption has no impact on net income. We adoptedManagement plans to adopt ASU 2015-13 upon its issuance date.2016-13 effective January 1, 2020.
Future Accounting Changes
The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, wemanagement cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes. The FASB is currently working on several projects including financial instruments, leases, insurance, hedge accounting, consolidation policyconsolidations and balance sheet classification of deferred taxes.pension and postretirement benefits. The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risks
OurThe Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through its transactions in power, coal, natural gas and marketing contracts. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk and credit risk. In addition, we arethis segment is exposed to foreign currency exchange risk as wefrom occasionally procureprocuring various services and materials used in ourits energy business from foreign suppliers. These risks represent the risk of loss that may impact usthis segment due to changes in the underlying market prices or rates.
OurThe Transmission and Distribution Utilities segment wasis exposed to FTR price risk as it related to RTO congestion during the June 2012 - May 2015 Ohio ESP period. Additional risks include energy procurement risk and interest rate risk.
OurThe Generation & Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. This segment is exposed to certain market risks as a marketer of wholesale and retail electricity. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk and credit risk. These risks represent the risk of loss that may impact usthis segment due to changes in the underlying market prices or rates. In addition, ourthe Generation & Marketing segment is also exposed to certain market risks as a major power producer and through its transactions in wholesale electricity, natural gas and coal trading and marketing contracts.
We employManagement employs risk management contracts including physical forward purchase-and-sale contracts and financial forward purchase-and-sale contracts. We engageManagement engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline diesel and other commodity contracts to manage the risk associated with ourthe energy business. As a result, we areAEP is subject to price risk. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of ourthe Board of Directors. OurAEPSC’s market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, and Chief Risk Officer in addition to Energy Supply’s President and Vice President. When commercial activities exceed predetermined limits, we modify the positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee.
The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2014:2015:
| | MTM Risk Management Contract Net Assets (Liabilities) | Nine Months Ended September 30, 2015 | |
Nine Months Ended September 30, 2016 | | Nine Months Ended September 30, 2016 |
| | | | | | | | | | | | | | |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | Generation & Marketing | | Total | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | Generation & Marketing | | Total |
| (in millions) | (in millions) |
Total MTM Risk Management Contract Net Assets as of December 31, 2014 | $ | 36 |
| | $ | 46 |
| | $ | 140 |
| | $ | 222 |
| |
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period | (30 | ) | | (5 | ) | | (22 | ) | | (57 | ) | |
Total MTM Risk Management Contract Net Assets as of December 31, 2015 | | $ | 8.6 |
| | $ | 14.4 |
| | $ | 143.2 |
| | $ | 166.2 |
|
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | (12.4 | ) | | 3.5 |
| | (9.7 | ) | | (18.6 | ) |
Fair Value of New Contracts at Inception When Entered During the Period (a) | — |
| | — |
| | 54 |
| | 54 |
| — |
| | — |
| | 30.5 |
| | 30.5 |
|
Changes in Fair Value Due to Market Fluctuations During the Period (b) | — |
| | — |
| | (17 | ) | | (17 | ) | — |
| | — |
| | 0.7 |
| | 0.7 |
|
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | 23 |
| | (27 | ) | | — |
| | (4 | ) | 1.3 |
| | (63.7 | ) | | — |
| | (62.4 | ) |
Total MTM Risk Management Contract Net Assets as of September 30, 2015 | $ | 29 |
| | $ | 14 |
| | $ | 155 |
| | 198 |
| |
Total MTM Risk Management Contract Net Assets as of September 30, 2016 | | $ | (2.5 | ) | | $ | (45.8 | ) | | $ | 164.7 |
| | 116.4 |
|
Commodity Cash Flow Hedge Contracts | | | |
| | |
| | (17 | ) | | | |
| | |
| | (41.9 | ) |
Interest Rate and Foreign Currency Cash Flow Hedge Contracts | | | |
| | |
| | (1 | ) | | | |
| | |
| | (0.2 | ) |
Fair Value Hedge Contracts | | | |
| | |
| | 1 |
| |
Collateral Deposits | | | |
| | |
| | 43 |
| | | |
| | |
| | 28.9 |
|
Elimination of Affiliated MTM Risk Management Contracts | | | | | | | (4 | ) | |
Total MTM Derivative Contract Net Assets as of September 30, 2015 | | | |
| | |
| | $ | 220 |
| |
Total MTM Derivative Contract Net Assets as of September 30, 2016 | | | | |
| | |
| | $ | 103.2 |
|
| |
(a) | Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged. |
| |
(b) | Market fluctuations are attributable to various factors such as supply/demand, weather, etc. |
| |
(c) | Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. |
See Note 9 – Derivatives and Hedging and Note 10 – Fair Value Measurements for additional information related to our risk management contracts. The following tables and discussion provide information on our credit risk and market volatility risk.
Credit Risk
We limit creditCredit risk is limited in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. We useManagement uses Moody’s Investors Service, Standard & Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.
We haveAEP has risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. As of September 30, 2015, our2016, credit exposure net of collateral to sub investment grade counterparties was approximately 7%7.1%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss). As of September 30, 2015,2016, the following table approximates ourAEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:
| | Counterparty Credit Quality | | Exposure Before Credit Collateral | | Credit Collateral | | Net Exposure | | Number of Counterparties >10% of Net Exposure | | Net Exposure of Counterparties >10% | | Exposure Before Credit Collateral | | Credit Collateral | | Net Exposure | | Number of Counterparties >10% of Net Exposure | | Net Exposure of Counterparties >10% |
| | (in millions, except number of counterparties) | | (in millions, except number of counterparties) |
Investment Grade | | $ | 727 |
| | $ | 1 |
| | $ | 726 |
| | 2 |
| | $ | 269 |
| | $ | 751.8 |
| | $ | 5.0 |
| | $ | 746.8 |
| | 3 |
| | $ | 378.8 |
|
Split Rating | | 25 |
| | — |
| | 25 |
| | 1 |
| | 25 |
| | 16.9 |
| | — |
| | 16.9 |
| | 1 |
| | 15.6 |
|
Noninvestment Grade | | 1 |
| | 1 |
| | — |
| | — |
| | — |
| |
No External Ratings: | | |
| | |
| |
|
| | |
| | |
| | |
| | |
| |
|
| | |
| | |
|
Internal Investment Grade | | 123 |
| | — |
| | 123 |
| | 3 |
| | 66 |
| | 113.2 |
| | — |
| | 113.2 |
| | 2 |
| | 57.3 |
|
Internal Noninvestment Grade | | 83 |
| | 18 |
| | 65 |
| | 2 |
| | 36 |
| | 81.5 |
| | 14.9 |
| | 66.6 |
| | 3 |
| | 43.1 |
|
Total as of September 30, 2015 | | $ | 959 |
| | $ | 20 |
| | $ | 939 |
| | 8 |
| | $ | 396 |
| |
| | | | | | | | | | | |
Total as of December 31, 2014 | | $ | 817 |
| | $ | 21 |
| | $ | 796 |
| | 8 |
| | $ | 347 |
| |
Total as of September 30, 2016 | | | $ | 963.4 |
| | $ | 19.9 |
| | $ | 943.5 |
| |
|
| |
|
|
In addition, we areAEP is exposed to credit risk related to our participation in RTOs. For each of the RTOs in which we participate,AEP participates, this risk is generally determined based on ourthe proportionate share of member gross activity over a specified period of time.
Value at Risk (VaR) Associated with Risk Management Contracts
We useManagement uses a risk measurement model, which calculates VaR, to measure ourAEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of September 30, 2015,2016, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.
Management calculates the VaR for both a trading and non-trading portfolio. The trading portfolio consists primarily of contracts related to energy trading and marketing activities. The non-trading portfolio consists primarily of economic hedges of generation and retail supply activities. The following tables show the end, high, average and low market risk as measured by VaR for the periods indicated:
VaR Model
Trading Portfolio
| | Nine Months Ended | Nine Months Ended | | Twelve Months Ended | Nine Months Ended | | Twelve Months Ended |
September 30, 2015 | | December 31, 2014 | |
September 30, 2016 | | September 30, 2016 | | December 31, 2015 |
End | End | | High | | Average | | Low | | End | | High | | Average | | Low | End | | High | | Average | | Low | | End | | High | | Average | | Low |
(in millions) | (in millions) | | (in millions) | (in millions) | | (in millions) |
$ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3 |
| | $ | 1 |
| | $ | — |
| 0.1 |
| | $ | 1.1 |
| | $ | 0.2 |
| | $ | 0.1 |
| | $ | 0.2 |
| | $ | 0.9 |
| | $ | 0.2 |
| | $ | 0.1 |
|
VaR Model
Non-Trading Portfolio
| | Nine Months Ended | Nine Months Ended | | Twelve Months Ended | Nine Months Ended | | Twelve Months Ended |
September 30, 2015 | | December 31, 2014 | |
September 30, 2016 | | September 30, 2016 | | December 31, 2015 |
End | End | | High | | Average | | Low | | End | | High | | Average | | Low | End | | High | | Average | | Low | | End | | High | | Average | | Low |
(in millions) | (in millions) | | (in millions) | (in millions) | | (in millions) |
$ | 1 |
| | $ | 2 |
| | $ | 1 |
| | $ | — |
| | $ | 2 |
| | $ | 3 |
| | $ | 1 |
| | $ | — |
| 0.9 |
| | $ | 2.8 |
| | $ | 0.9 |
| | $ | 0.4 |
| | $ | 1.1 |
| | $ | 2.4 |
| | $ | 0.9 |
| | $ | 0.4 |
|
We back-test our
Management back-tests VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.
As ourthe VaR calculation captures recent price movements, wemanagement also performperforms regular stress testing of the trading portfolio to understand ourAEP’s exposure to extreme price movements. We employ aA historical-based method is employed whereby the current trading portfolio is subjected to actual, observed price movements from the last several years in order to ascertain which historical price movements translated into the largest potential MTM loss. WeManagement then researchresearches the underlying positions, price movements and market events that created the most significant exposure and reportreports the findings to the Risk Executive Committee, Regulated Risk Committee, or Competitive Risk Committee as appropriate.
Interest Rate Risk
We utilizeManagement utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which our interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. As calculated on debt outstanding as of September 30, 20152016 and December 31, 2014,2015, the estimated EaR on ourAEP’s debt portfolio for the following twelve months was $34$30 million and $33$25 million, respectively.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOMEOPERATIONS
For the Three and Nine Months Ended September 30, 20152016 and 20142015
(in millions, except per-share and share amounts)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
REVENUES | | | | | | | | | | | | | | | | |
Vertically Integrated Utilities | | $ | 2,436 |
| | $ | 2,432 |
| | $ | 7,082 |
| | $ | 7,217 |
| | $ | 2,538.3 |
| | $ | 2,435.8 |
| | $ | 6,864.6 |
| | $ | 7,081.8 |
|
Transmission and Distribution Utilities | | 1,164 |
| | 1,163 |
| | 3,378 |
| | 3,388 |
| | 1,245.4 |
| | 1,163.6 |
| | 3,398.9 |
| | 3,377.9 |
|
Generation & Marketing | | 802 |
| | 538 |
| | 2,289 |
| | 1,932 |
| | 823.3 |
| | 801.8 |
| | 2,192.5 |
| | 2,288.6 |
|
Other Revenues | | 30 |
| | 28 |
| | 90 |
| | 22 |
| | 45.2 |
| | 30.2 |
| | 134.0 |
| | 90.2 |
|
TOTAL REVENUES | | 4,432 |
| | 4,161 |
| | 12,839 |
| | 12,559 |
| | 4,652.2 |
| | 4,431.4 |
| | 12,590.0 |
| | 12,838.5 |
|
| | | | | | | | | | | | | | | | |
EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Fuel and Other Consumables Used for Electric Generation | | 955 |
| | 1,080 |
| | 2,782 |
| | 3,291 |
| | 880.1 |
| | 955.9 |
| | 2,236.1 |
| | 2,782.4 |
|
Purchased Electricity for Resale | | 731 |
| | 449 |
| | 2,050 |
| | 1,560 |
| | 774.0 |
| | 730.8 |
| | 2,134.6 |
| | 2,050.0 |
|
Other Operation | | 691 |
| | 685 |
| | 1,955 |
| | 1,985 |
| | 771.1 |
| | 689.9 |
| | 2,150.7 |
| | 1,954.6 |
|
Maintenance | | 312 |
| | 313 |
| | 923 |
| | 929 |
| | 286.3 |
| | 311.5 |
| | 854.4 |
| | 923.1 |
|
Asset Impairments and Other Related Charges | | | 2,264.9 |
| | — |
| | 2,264.9 |
| | — |
|
Depreciation and Amortization | | 535 |
| | 499 |
| | 1,528 |
| | 1,418 |
| | 539.3 |
| | 534.9 |
| | 1,550.2 |
| | 1,528.0 |
|
Taxes Other Than Income Taxes | | 248 |
| | 230 |
| | 733 |
| | 679 |
| | 264.4 |
| | 248.2 |
| | 767.9 |
| | 733.3 |
|
TOTAL EXPENSES | | 3,472 |
| | 3,256 |
| | 9,971 |
| | 9,862 |
| | 5,780.1 |
| | 3,471.2 |
| | 11,958.8 |
| | 9,971.4 |
|
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | 960 |
| | 905 |
| | 2,868 |
| | 2,697 |
| |
OPERATING INCOME (LOSS) | | | (1,127.9 | ) | | 960.2 |
| | 631.2 |
| | 2,867.1 |
|
| | | | | | | | | | | | | | | | |
Other Income (Expense): | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Interest and Investment Income | | 2 |
| | 1 |
| | 6 |
| | 5 |
| | 2.0 |
| | 1.6 |
| | 6.5 |
| | 6.1 |
|
Carrying Costs Income | | 1 |
| | 7 |
| | 18 |
| | 22 |
| | 1.7 |
| | 1.8 |
| | 11.9 |
| | 18.4 |
|
Allowance for Equity Funds Used During Construction | | 33 |
| | 27 |
| | 97 |
| | 74 |
| | 25.6 |
| | 32.6 |
| | 86.1 |
| | 96.4 |
|
Interest Expense | | (221 | ) | | (217 | ) | | (659 | ) | | (650 | ) | | (225.3 | ) | | (220.2 | ) | | (667.2 | ) | | (658.1 | ) |
| | | | | | | | | | | | | | | | |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS | | 775 |
| | 723 |
| | 2,330 |
| | 2,148 |
| |
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS | | | (1,323.9 | ) | | 776.0 |
| | 68.5 |
| | 2,329.9 |
|
| | | | | | | | | | | | | | | | |
Income Tax Expense | | 275 |
| | 264 |
| | 827 |
| | 783 |
| |
Income Tax Expense (Credit) | | | (534.5 | ) | | 275.6 |
| | (134.0 | ) | | 827.1 |
|
Equity Earnings of Unconsolidated Subsidiaries | | 12 |
| | 24 |
| | 61 |
| | 65 |
| | 25.2 |
| | 11.4 |
| | 42.8 |
| | 60.6 |
|
| | | | | | | | | | | | | | | | |
INCOME FROM CONTINUING OPERATIONS | | 512 |
| | 483 |
| | 1,564 |
| | 1,430 |
| |
INCOME (LOSS) FROM CONTINUING OPERATIONS | | | (764.2 | ) | | 511.8 |
| | 245.3 |
| | 1,563.4 |
|
| | | | | | | | | | | | | | | | |
INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX | | 8 |
| | 11 |
| | 18 |
| | 16 |
| |
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF TAX | | | — |
| | 7.8 |
| | (2.5 | ) | | 18.2 |
|
| | | | | | | | | | | | | | | | |
NET INCOME | | 520 |
| | 494 |
| | 1,582 |
| | 1,446 |
| |
NET INCOME (LOSS) | | | (764.2 | ) | | 519.6 |
| | 242.8 |
| | 1,581.6 |
|
| | | | | | | | | | | | | | | | |
Net Income Attributable to Noncontrolling Interests | | 1 |
| | 1 |
| | 4 |
| | 3 |
| | 1.6 |
| | 1.3 |
| | 5.3 |
| | 4.1 |
|
| | | | | | | | | | | | | | | | |
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 519 |
| | $ | 493 |
| | $ | 1,578 |
| | $ | 1,443 |
| |
EARNINGS (LOSS) ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | | $ | (765.8 | ) | | $ | 518.3 |
| | $ | 237.5 |
| | $ | 1,577.5 |
|
| | | | | | | | | | | | | | | | |
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | | 490,648,929 |
| | 488,912,892 |
| | 490,155,315 |
| | 488,361,017 |
| | 491,697,809 |
| | 490,648,929 |
| | 491,422,921 |
| | 490,155,315 |
|
| | | | | | | | | | | | | | | | |
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS | | $ | 1.04 |
| | $ | 0.99 |
| | $ | 3.18 |
| | $ | 2.92 |
| |
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS | | $ | 0.02 |
| | $ | 0.02 |
| | $ | 0.04 |
| | $ | 0.03 |
| |
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 1.06 |
| | $ | 1.01 |
| | $ | 3.22 |
| | $ | 2.95 |
| |
BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS | | | $ | (1.56 | ) | | $ | 1.04 |
| | $ | 0.49 |
| | $ | 3.18 |
|
BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS | | | $ | — |
| | $ | 0.02 |
| | $ | (0.01 | ) | | $ | 0.04 |
|
TOTAL BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | | $ | (1.56 | ) | | $ | 1.06 |
| | $ | 0.48 |
| | $ | 3.22 |
|
| | | | | | | | | | | | | | | | |
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | | 490,800,335 |
| | 488,970,647 |
| | 490,411,020 |
| | 488,597,178 |
| | 491,813,858 |
| | 490,800,335 |
| | 491,596,861 |
| | 490,411,020 |
|
| | | | | | | | | | | | | | | | |
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS | | $ | 1.04 |
| | $ | 0.99 |
| | $ | 3.18 |
| | $ | 2.92 |
| |
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS | | $ | 0.02 |
| | $ | 0.02 |
| | $ | 0.04 |
| | $ | 0.03 |
| |
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 1.06 |
| | $ | 1.01 |
| | $ | 3.22 |
| | $ | 2.95 |
| |
DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS | | | $ | (1.56 | ) | | $ | 1.04 |
| | $ | 0.49 |
| | $ | 3.18 |
|
DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS | | | $ | — |
| | $ | 0.02 |
| | $ | (0.01 | ) | | $ | 0.04 |
|
TOTAL DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | | $ | (1.56 | ) | | $ | 1.06 |
| | $ | 0.48 |
| | $ | 3.22 |
|
| | | | | | | | | | | | | | | | |
CASH DIVIDENDS DECLARED PER SHARE | | $ | 0.53 |
| | $ | 0.50 |
| | $ | 1.59 |
| | $ | 1.50 |
| | $ | 0.56 |
| | $ | 0.53 |
| | $ | 1.68 |
| | $ | 1.59 |
|
|
| | | | | | | | |
See Condensed Notes to Condensed Consolidated Financial Statements of Registrants beginning on page 51113. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20152016 and 20142015
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 |
Net Income | | $ | 520 |
| | $ | 494 |
| | $ | 1,582 |
| | $ | 1,446 |
|
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | |
| | |
| | |
| | |
|
Cash Flow Hedges, Net of Tax of $3 and $1 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $6 and $3 for the Nine Months Ended September 30, 2015 and 2014, Respectively | | (6 | ) | | (2 | ) | | (11 | ) | | 6 |
|
Securities Available for Sale, Net of Tax of $1 and $0 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $1 and $0 for the Nine Months Ended September 30, 2015 and 2014, Respectively | | (1 | ) | | — |
| | (1 | ) | | 1 |
|
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $1 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $0 and $2 for the Nine Months Ended September 30, 2015 and 2014, Respectively | | — |
| | 1 |
| | 1 |
| | 3 |
|
| | | | | | | | |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | | (7 | ) | | (1 | ) | | (11 | ) | | 10 |
|
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | 513 |
| | 493 |
| | 1,571 |
| | 1,456 |
|
| | | | | | | | |
Total Comprehensive Income Attributable to Noncontrolling Interests | | 1 |
| | 1 |
| | 4 |
| | 3 |
|
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 512 |
| | $ | 492 |
| | $ | 1,567 |
| | $ | 1,453 |
|
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
Net Income (Loss) | | $ | (764.2 | ) | | $ | 519.6 |
| | $ | 242.8 |
| | $ | 1,581.6 |
|
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | |
| | |
| | |
| | |
|
Cash Flow Hedges, Net of Tax of $(15.4) and $(2.9) for the Three Months Ended September 30, 2016 and 2015, Respectively, and $(11.2) and $(5.8) for the Nine Months Ended September 30, 2016 and 2015, Respectively | | (28.6 | ) | | (5.3 | ) | | (20.8 | ) | | (10.7 | ) |
Securities Available for Sale, Net of Tax of $0.3 and $(0.7) for the Three Months Ended September 30, 2016 and 2015, Respectively, and $1 and $(0.5) for the Nine Months Ended September 30, 2016 and 2015, Respectively | | 0.5 |
| | (1.3 | ) | | 1.7 |
| | (1.0 | ) |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0.1 and $0.2 for the Three Months Ended September 30, 2016 and 2015, Respectively, and $0.2 and $0.5 for the Nine Months Ended September 30, 2016 and 2015, Respectively | | 0.2 |
| | 0.3 |
| | 0.4 |
| | 0.9 |
|
| | | | | | | | |
TOTAL OTHER COMPREHENSIVE LOSS | | (27.9 | ) | | (6.3 | ) | | (18.7 | ) | | (10.8 | ) |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME (LOSS) | | (792.1 | ) | | 513.3 |
| | 224.1 |
| | 1,570.8 |
|
| | | | | | | | |
Total Comprehensive Income Attributable to Noncontrolling Interests | | 1.6 |
| | 1.3 |
| | 5.3 |
| | 4.1 |
|
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | (793.7 | ) | | $ | 512.0 |
| | $ | 218.8 |
| | $ | 1,566.7 |
|
|
| | | | | | | | |
See Condensed Notes to Condensed Consolidated Financial Statements of Registrants beginning on page51113. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 20152016 and 20142015
(in millions)
(Unaudited)
| | | AEP Common Shareholders | | | | | AEP Common Shareholders | | | | |
| Common Stock | | | | | | Accumulated Other Comprehensive Income (Loss) | | | | | Common Stock | | | | | | Accumulated Other Comprehensive Income (Loss) | | | | |
| Shares | | Amount | | Paid-in Capital | | Retained Earnings | | Noncontrolling Interests | | Total | |
TOTAL EQUITY - DECEMBER 31, 2013 | 508 |
| | $ | 3,303 |
| | $ | 6,131 |
| | $ | 6,766 |
| | $ | (115 | ) | | $ | 1 |
| | $ | 16,086 |
| |
| | | | | | | | | | | | | | |
Issuance of Common Stock | 2 |
| | 9 |
| | 54 |
| | |
| | |
| | |
| | 63 |
| |
Common Stock Dividends | |
| | |
| | |
| | (733 | ) | | |
| | (3 | ) | | (736 | ) | |
Other Changes in Equity | |
| | |
| | 6 |
| | (6 | ) | | |
| | 3 |
| | 3 |
| |
Net Income | | | | | | | 1,443 |
| | |
| | 3 |
| | 1,446 |
| |
Other Comprehensive Income | |
| | |
| | |
| | |
| | 10 |
| | |
| | 10 |
| |
TOTAL EQUITY - SEPTEMBER 30, 2014 | 510 |
| | $ | 3,312 |
| | $ | 6,191 |
| | $ | 7,470 |
| | $ | (105 | ) | | $ | 4 |
| | $ | 16,872 |
| |
| | | | | | | | | | | | | | Shares | | Amount | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interests | | Total |
TOTAL EQUITY - DECEMBER 31, 2014 | 510 |
| | $ | 3,313 |
| | $ | 6,204 |
| | $ | 7,406 |
| | $ | (103 | ) | | $ | 4 |
| | $ | 16,824 |
| 509.7 |
| | $ | 3,313.3 |
| | $ | 6,203.4 |
| | $ | 7,406.6 |
| | $ | 4.3 |
| | $ | 16,824.5 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Issuance of Common Stock | 1 |
| | 9 |
| | 59 |
| | |
| | |
| | |
| | 68 |
| 1.4 |
| | 9.1 |
| | 58.8 |
| | |
| | |
| | |
| | 67.9 |
|
Common Stock Dividends | |
| | |
| | |
| | (780 | ) | | |
| | (3 | ) | | (783 | ) | |
| | |
| | |
| | (780.3 | ) | | |
| | (3.1 | ) | | (783.4 | ) |
Other Changes in Equity | |
| | |
| | 19 |
| | | | |
| | 5 |
| | 24 |
| |
| | |
| | 19.6 |
| | | | |
| | 5.0 |
| | 24.6 |
|
Net Income | | | | | | | 1,578 |
| | |
| | 4 |
| | 1,582 |
| | | | | | | 1,577.5 |
| | |
| | 4.1 |
| | 1,581.6 |
|
Other Comprehensive Loss | |
| | |
| | |
| | |
| | (11 | ) | | |
| | (11 | ) | |
| | |
| | |
| | |
| | (10.8 | ) | | |
| | (10.8 | ) |
Pension and OPEB Adjustment Related to Mitchell Plant | | | | | | | | | 5 |
| | | | 5 |
| | | | | | | | | 5.1 |
| | | | 5.1 |
|
TOTAL EQUITY - SEPTEMBER 30, 2015 | 511 |
| | $ | 3,322 |
| | $ | 6,282 |
| | $ | 8,204 |
| | $ | (109 | ) | | $ | 10 |
| | $ | 17,709 |
| 511.1 |
| | $ | 3,322.4 |
| | $ | 6,281.8 |
| | $ | 8,203.8 |
| | $ | (108.8 | ) | | $ | 10.3 |
| | $ | 17,709.5 |
|
| | | | | | | | | | | | | | |
TOTAL EQUITY - DECEMBER 31, 2015 | | 511.4 |
| | $ | 3,324.0 |
| | $ | 6,296.5 |
| | $ | 8,398.3 |
| | $ | (127.1 | ) | | $ | 13.2 |
| | $ | 17,904.9 |
|
| | | | | | | | | | | | | | |
Issuance of Common Stock | | 0.6 |
| | 4.3 |
| | 29.9 |
| | |
| | |
| | |
| | 34.2 |
|
Common Stock Dividends | | |
| | |
| | |
| | (826.4 | ) | | |
| | (3.4 | ) | | (829.8 | ) |
Other Changes in Equity | | |
| | |
| | 3.6 |
| | | | |
| | 6.0 |
| | 9.6 |
|
Net Income | | | | | | | | 237.5 |
| | |
| | 5.3 |
| | 242.8 |
|
Other Comprehensive Loss | | |
| | |
| | |
| | |
| | (18.7 | ) | | |
| | (18.7 | ) |
TOTAL EQUITY - SEPTEMBER 30, 2016 | | 512.0 |
| | $ | 3,328.3 |
| | $ | 6,330.0 |
| | $ | 7,809.4 |
| | $ | (145.8 | ) | | $ | 21.1 |
| | $ | 17,343.0 |
|
|
| | | | | | | | | | | | | |
See Condensed Notes to Condensed Consolidated Financial Statements of Registrants beginning on page 51113. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20152016 and December 31, 20142015
(in millions)
(Unaudited)
| | | | September 30, | | December 31, | | September 30, | | December 31, |
| | 2015 | | 2014 | | 2016 | | 2015 |
CURRENT ASSETS | | |
| | |
| | |
| | |
|
Cash and Cash Equivalents | | $ | 178 |
| | $ | 163 |
| | $ | 212.2 |
| | $ | 176.4 |
|
Other Temporary Investments (September 30, 2015 and December 31, 2014 Amounts Include $307 and $371, Respectively, Related to Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and EIS) | | 315 |
| | 386 |
| |
Other Temporary Investments (September 30, 2016 and December 31, 2015 Amounts Include $270.5 and $376.6, Respectively, Related to Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, EIS and Sabine) | | | 279.2 |
| | 386.8 |
|
Accounts Receivable: | | |
| | |
| | |
| | |
|
Customers | | 662 |
| | 637 |
| | 628.4 |
| | 615.9 |
|
Accrued Unbilled Revenues | | 147 |
| | 146 |
| | 166.7 |
| | 31.2 |
|
Pledged Accounts Receivable – AEP Credit | | 987 |
| | 987 |
| | 1,065.5 |
| | 940.3 |
|
Miscellaneous | | 84 |
| | 85 |
| | 59.9 |
| | 82.1 |
|
Allowance for Uncollectible Accounts | | (27 | ) | | (20 | ) | | (40.5 | ) | | (29.0 | ) |
Total Accounts Receivable | | 1,853 |
| | 1,835 |
| | 1,880.0 |
| | 1,640.5 |
|
Fuel | | 376 |
| | 581 |
| | 468.0 |
| | 600.8 |
|
Materials and Supplies | | 729 |
| | 736 |
| | 556.8 |
| | 738.6 |
|
Risk Management Assets | | 143 |
| | 178 |
| | 110.8 |
| | 134.4 |
|
Accrued Tax Benefits | | | 214.9 |
| | 58.9 |
|
Regulatory Asset for Under-Recovered Fuel Costs | | 105 |
| | 127 |
| | 107.4 |
| | 115.2 |
|
Margin Deposits | | 85 |
| | 95 |
| | 56.5 |
| | 107.3 |
|
Assets Held for Sale | | 608 |
| | 103 |
| | 1,915.3 |
| | — |
|
Prepayments and Other Current Assets | | 156 |
| | 274 |
| | 148.1 |
| | 113.5 |
|
TOTAL CURRENT ASSETS | | 4,548 |
| | 4,478 |
| | 5,949.2 |
| | 4,072.4 |
|
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | |
| | |
| | |
| | |
|
Electric: | | |
| | |
| | |
| | |
|
Generation | | 25,665 |
| | 25,727 |
| | 19,684.2 |
| | 25,559.8 |
|
Transmission | | 13,305 |
| | 12,433 |
| | 15,157.8 |
| | 14,247.9 |
|
Distribution | | 17,812 |
| | 17,157 |
| | 18,639.0 |
| | 18,046.9 |
|
Other Property, Plant and Equipment (September 30, 2015 and December 31, 2014 Amounts Include Plant to be Retired, Coal Mining and Nuclear Fuel, December 31, 2014 Amount Includes 2015 Plant Retirement) | | 4,036 |
| | 5,074 |
| |
Other Property, Plant and Equipment (September 30, 2016 and December 31, 2015 Amounts Include Coal Mining and Nuclear Fuel, December 31, 2015 Amount Includes 2016 Plant Retirements) | | | 3,467.5 |
| | 3,722.9 |
|
Construction Work in Progress | | 4,008 |
| | 3,215 |
| | 3,651.3 |
| | 3,903.9 |
|
Total Property, Plant and Equipment | | 64,826 |
| | 63,606 |
| | 60,599.8 |
| | 65,481.4 |
|
Accumulated Depreciation and Amortization | | 19,588 |
| | 19,971 |
| | 16,337.6 |
| | 19,348.2 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 45,238 |
| | 43,635 |
| | 44,262.2 |
| | 46,133.2 |
|
| | | | | | | | |
OTHER NONCURRENT ASSETS | | |
| | |
| | |
| | |
|
Regulatory Assets | | 4,950 |
| | 4,264 |
| | 5,182.4 |
| | 5,140.3 |
|
Securitized Assets | | 1,841 |
| | 2,072 |
| | 1,559.0 |
| | 1,749.9 |
|
Spent Nuclear Fuel and Decommissioning Trusts | | 2,047 |
| | 2,096 |
| | 2,230.8 |
| | 2,106.4 |
|
Goodwill | | 53 |
| | 53 |
| | 52.5 |
| | 52.5 |
|
Long-term Risk Management Assets | | 353 |
| | 294 |
| | 311.7 |
| | 321.8 |
|
Assets Held for Sale | | — |
| | 522 |
| |
Deferred Charges and Other Noncurrent Assets | | 2,069 |
| | 2,219 |
| | 1,894.2 |
| | 2,106.6 |
|
TOTAL OTHER NONCURRENT ASSETS | | 11,313 |
| | 11,520 |
| | 11,230.6 |
| | 11,477.5 |
|
| | | | | | | | |
TOTAL ASSETS | | $ | 61,099 |
| | $ | 59,633 |
| | $ | 61,442.0 |
| | $ | 61,683.1 |
|
|
| | | | |
See Condensed Notes to Condensed Consolidated Financial Statements of Registrants beginning on page 51113. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 20152016 and December 31, 20142015
(dollars in millions)
(Unaudited)
| | | | | | | | September 30, | | December 31, | | | | | | September 30, | | December 31, |
| | 2015 | | 2014 | | 2016 | | 2015 |
CURRENT LIABILITIES | CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
Accounts Payable | | $ | 1,274 |
| | $ | 1,258 |
| | $ | 1,340.3 |
| | $ | 1,418.0 |
|
Short-term Debt: | | | | | | | | |
Securitized Debt for Receivables – AEP Credit | | 750 |
| | 744 |
| | 750.0 |
| | 675.0 |
|
Other Short-term Debt | | 32 |
| | 602 |
| | 728.3 |
| | 125.0 |
|
Total Short-term Debt | | 782 |
| | 1,346 |
| | 1,478.3 |
| | 800.0 |
|
Long-term Debt Due Within One Year (September 30, 2015 and December 31, 2014 Amounts Include $424 and $431, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine) | | 1,826 |
| | 2,500 |
| |
Long-term Debt Due Within One Year (September 30, 2016 and December 31, 2015 Amounts Include $393.4 and $410.4, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine) | | Long-term Debt Due Within One Year (September 30, 2016 and December 31, 2015 Amounts Include $393.4 and $410.4, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine) | | 2,384.8 |
| | 1,831.8 |
|
Risk Management Liabilities | | 75 |
| | 92 |
| | 79.3 |
| | 87.1 |
|
Customer Deposits | | 335 |
| | 324 |
| | 341.6 |
| | 346.6 |
|
Accrued Taxes | | 748 |
| | 863 |
| | 666.2 |
| | 979.1 |
|
Accrued Interest | | 236 |
| | 238 |
| | 230.2 |
| | 226.9 |
|
Regulatory Liability for Over-Recovered Fuel Costs | Regulatory Liability for Over-Recovered Fuel Costs | | 74 |
| | 55 |
| Regulatory Liability for Over-Recovered Fuel Costs | | 7.9 |
| | 113.9 |
|
Liabilities Held for Sale | | 474 |
| | 85 |
| | 231.0 |
| | — |
|
Other Current Liabilities | | 1,234 |
| | 1,206 |
| | 1,019.8 |
| | 1,305.1 |
|
TOTAL CURRENT LIABILITIES | | 7,058 |
| | 7,967 |
| | 7,779.4 |
| | 7,108.5 |
|
| | | | | | | | | | |
NONCURRENT LIABILITIES | NONCURRENT LIABILITIES | | | | | NONCURRENT LIABILITIES | | | | |
Long-term Debt (September 30, 2015 and December 31, 2014 Amounts Include $2,004 and $2,260, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy and Sabine) | | 17,600 |
| | 16,101 |
| |
Long-term Debt (September 30, 2016 and December 31, 2015 Amounts Include $1,727.6 and $1,971.4, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy and Sabine) | | Long-term Debt (September 30, 2016 and December 31, 2015 Amounts Include $1,727.6 and $1,971.4, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy and Sabine) | | 17,319.9 |
| | 17,740.9 |
|
Long-term Risk Management Liabilities | | 201 |
| | 131 |
| | 240.0 |
| | 179.1 |
|
Deferred Income Taxes | | 11,425 |
| | 10,892 |
| | 11,815.1 |
| | 11,733.2 |
|
Regulatory Liabilities and Deferred Investment Tax Credits | Regulatory Liabilities and Deferred Investment Tax Credits | | 3,762 |
| | 3,892 |
| Regulatory Liabilities and Deferred Investment Tax Credits | | 3,887.5 |
| | 3,736.1 |
|
Asset Retirement Obligations | | 1,944 |
| | 1,951 |
| | 1,858.0 |
| | 1,806.5 |
|
Employee Benefits and Pension Obligations | | 535 |
| | 630 |
| | 497.0 |
| | 583.3 |
|
Liabilities Held for Sale | | — |
| | 350 |
| |
Deferred Credits and Other Noncurrent Liabilities | Deferred Credits and Other Noncurrent Liabilities | | 865 |
| | 895 |
| Deferred Credits and Other Noncurrent Liabilities | | 702.1 |
| | 890.6 |
|
TOTAL NONCURRENT LIABILITIES | | 36,332 |
| | 34,842 |
| | 36,319.6 |
| | 36,669.7 |
|
| | | | | | | | |
TOTAL LIABILITIES | | 43,390 |
| | 42,809 |
| | 44,099.0 |
| | 43,778.2 |
|
| | | | | | | | |
Rate Matters (Note 4) | |
| |
| |
| |
|
Commitments and Contingencies (Note 5) | |
| |
| |
| |
|
| | | | | | | | |
EQUITY | EQUITY | | | | | EQUITY | | | | |
Common Stock – Par Value – $6.50 Per Share: | | | | | | | | |
| | 2015 | | 2014 | | | | | | 2016 | | 2015 | | | | |
Shares Authorized | | 600,000,000 | | 600,000,000 | | | | | | 600,000,000 | | 600,000,000 | | | | |
Shares Issued | | 511,141,256 | | 509,739,159 | | | | | | 512,046,044 | | 511,389,173 | | | | |
(20,336,592 Shares were Held in Treasury as of September 30, 2015 and December 31, 2014) | | 3,322 |
| | 3,313 |
| |
(20,336,592 Shares were Held in Treasury as of September 30, 2016 and December 31, 2015) | | (20,336,592 Shares were Held in Treasury as of September 30, 2016 and December 31, 2015) | | 3,328.3 |
| | 3,324.0 |
|
Paid-in Capital | | 6,282 |
| | 6,204 |
| | 6,330.0 |
| | 6,296.5 |
|
Retained Earnings | | 8,204 |
| | 7,406 |
| | 7,809.4 |
| | 8,398.3 |
|
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) | | (109 | ) | | (103 | ) | Accumulated Other Comprehensive Income (Loss) | | (145.8 | ) | | (127.1 | ) |
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY | TOTAL AEP COMMON SHAREHOLDERS’ EQUITY | | 17,699 |
| | 16,820 |
| TOTAL AEP COMMON SHAREHOLDERS’ EQUITY | | 17,321.9 |
| | 17,891.7 |
|
| | | | | | | | |
Noncontrolling Interests | | 10 |
| | 4 |
| | 21.1 |
| | 13.2 |
|
| | | | | | | | |
TOTAL EQUITY | | 17,709 |
| | 16,824 |
| | 17,343.0 |
| | 17,904.9 |
|
| | | | | | | | |
TOTAL LIABILITIES AND EQUITY | | $ | 61,099 |
| | $ | 59,633 |
| | $ | 61,442.0 |
| | $ | 61,683.1 |
|
|
| | | | | | | | | |
See Condensed Notes to Condensed Consolidated Financial Statements of Registrants beginning on page 51113. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20152016 and 20142015
(in millions)
(Unaudited)
| | | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2016 | | 2015 |
OPERATING ACTIVITIES | | |
| | |
| | |
| | |
|
Net Income | | $ | 1,582 |
| | $ | 1,446 |
| | $ | 242.8 |
| | $ | 1,581.6 |
|
Income from Discontinued Operations | | 18 |
| | 16 |
| |
Income (Loss) from Discontinued Operations | | | (2.5 | ) | | 18.2 |
|
Income from Continuing Operations | | 1,564 |
| | 1,430 |
| | 245.3 |
| | 1,563.4 |
|
Adjustments to Reconcile Income from Continuing Operations to Net Cash Flows from Operating Activities: | | | | | |
Adjustments to Reconcile Income from Continuing Operations to Net Cash Flows from Continuing Operating Activities: | | | | | |
Depreciation and Amortization | | 1,528 |
| | 1,418 |
| | 1,550.2 |
| | 1,528.0 |
|
Deferred Income Taxes | | 529 |
| | 385 |
| | (47.0 | ) | | 528.6 |
|
Asset Impairments and Other Related Charges | | | 2,264.9 |
| | — |
|
Carrying Costs Income | | (18 | ) | | (22 | ) | | (11.9 | ) | | (18.4 | ) |
Allowance for Equity Funds Used During Construction | | (97 | ) | | (74 | ) | | (86.1 | ) | | (96.4 | ) |
Mark-to-Market of Risk Management Contracts | | 18 |
| | 15 |
| | 56.6 |
| | 17.7 |
|
Amortization of Nuclear Fuel | | 102 |
| | 114 |
| | 109.7 |
| | 101.6 |
|
Pension Contributions to Qualified Plan Trust | | (92 | ) | | (70 | ) | | (84.8 | ) | | (91.8 | ) |
Property Taxes | | 247 |
| | 220 |
| | 288.3 |
| | 247.1 |
|
Fuel Over/Under-Recovery, Net | | 93 |
| | (77 | ) | |
Deferred Fuel Over/Under-Recovery, Net | | | (28.5 | ) | | 93.3 |
|
Deferral of Ohio Capacity Costs, Net | | 35 |
| | (106 | ) | | 108.8 |
| | 35.0 |
|
Change in Other Noncurrent Assets | | (106 | ) | | (41 | ) | | (231.5 | ) | | (114.3 | ) |
Change in Other Noncurrent Liabilities | | (1 | ) | | 271 |
| | 41.3 |
| | 8.9 |
|
Changes in Certain Components of Working Capital: | | | | | |
Changes in Certain Components of Continuing Working Capital: | | | | | |
Accounts Receivable, Net | | (18 | ) | | (19 | ) | | (240.8 | ) | | (17.5 | ) |
Fuel, Materials and Supplies | | 194 |
| | 222 |
| | 11.6 |
| | 193.8 |
|
Accounts Payable | | (13 | ) | | (40 | ) | | 47.8 |
| | (13.3 | ) |
Accrued Taxes, Net | | (68 | ) | | 20 |
| | (393.0 | ) | | (68.3 | ) |
Other Current Assets | | 11 |
| | — |
| | 31.5 |
| | 10.5 |
|
Other Current Liabilities | | 2 |
| | 69 |
| | (211.4 | ) | | 2.8 |
|
Net Cash Flows from Operating Activities | | 3,910 |
| | 3,715 |
| |
Net Cash Flows from Continuing Operating Activities | | | 3,421.0 |
| | 3,910.7 |
|
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | (3,283 | ) | | (2,897 | ) | | (3,387.0 | ) | | (3,282.7 | ) |
Change in Other Temporary Investments, Net | | 81 |
| | 37 |
| | 109.2 |
| | 80.8 |
|
Purchases of Investment Securities | | (1,489 | ) | | (791 | ) | | (2,454.5 | ) | | (1,489.4 | ) |
Sales of Investment Securities | | 1,437 |
| | 746 |
| | 2,427.0 |
| | 1,437.3 |
|
Acquisitions of Nuclear Fuel | | (53 | ) | | (109 | ) | | (127.6 | ) | | (53.3 | ) |
Acquisitions of Assets/Businesses | | (1 | ) | | (45 | ) | |
Other Investing Activities | | 60 |
| | (20 | ) | | 4.2 |
| | 58.9 |
|
Net Cash Flows Used for Investing Activities | | (3,248 | ) | | (3,079 | ) | |
Net Cash Flows Used for Continuing Investing Activities | | | (3,428.7 | ) | | (3,248.4 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Common Stock, Net | | 68 |
| | 63 |
| |
Issuance of Common Stock | | | 34.2 |
| | 67.9 |
|
Issuance of Long-term Debt | | 2,931 |
| | 1,206 |
| | 1,559.6 |
| | 2,931.1 |
|
Change in Short-term Debt, Net | | (564 | ) | | 525 |
| | 678.3 |
| | (564.0 | ) |
Retirement of Long-term Debt | | (2,131 | ) | | (1,536 | ) | | (1,307.6 | ) | | (2,131.4 | ) |
Make Whole Premium on Extinguishment of Long-term Debt | | (93 | ) | | — |
| | — |
| | (92.7 | ) |
Principal Payments for Capital Lease Obligations | | (74 | ) | | (85 | ) | | (81.9 | ) | | (73.9 | ) |
Dividends Paid on Common Stock | | (783 | ) | | (736 | ) | | (829.8 | ) | | (783.4 | ) |
Other Financing Activities | | (1 | ) | | 3 |
| | (6.8 | ) | | (0.9 | ) |
Net Cash Flows Used for Financing Activities | | (647 | ) | | (560 | ) | |
Net Cash Flows from (Used for) Continuing Financing Activities | | | 46.0 |
| | (647.3 | ) |
| | | | | |
Net Cash Flows from (Used for) Discontinued Operating Activities | | | (2.5 | ) | | 10.1 |
|
Net Cash Flows from Discontinued Investing Activities | | | — |
| | 2.5 |
|
Net Cash Flows Used for Discontinued Financing Activities | | | — |
| | (12.3 | ) |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | 15 |
| | 76 |
| | 35.8 |
| | 15.3 |
|
Cash and Cash Equivalents at Beginning of Period | | 163 |
| | 118 |
| | 176.4 |
| | 162.5 |
|
Cash and Cash Equivalents at End of Period | | $ | 178 |
| | $ | 194 |
| | $ | 212.2 |
| | $ | 177.8 |
|
| | | | | | | | |
CASH FLOWS FROM DISCONTINUED OPERATIONS | | | | | |
Operating Activities | | $ | 10 |
| | $ | 10 |
| |
Investing Activities | | 2 |
| | (2 | ) | |
Financing Activities | | (12 | ) | | (8 | ) | |
Net Change in Cash and Cash Equivalents from Discontinued Operations | | — |
| | — |
| |
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period | | — |
| | — |
| |
Cash and Cash Equivalents from Discontinued Operations - End of Period | | $ | — |
| | $ | — |
| |
SUPPLEMENTARY INFORMATION | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | | $ | 637.0 |
| | $ | 639.1 |
|
Net Cash Paid for Income Taxes | | | 32.2 |
| | 115.6 |
|
Noncash Acquisitions Under Capital Leases | | | 65.8 |
| | 96.9 |
|
Construction Expenditures Included in Current Liabilities as of September 30, | | | 604.8 |
| | 579.4 |
|
Construction Expenditures Included in Noncurrent Liabilities as of September 30, | | | — |
| | 66.3 |
|
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | | | 0.3 |
| | 31.1 |
|
|
| | | | |
See Condensed Notes to Condensed Consolidated Financial Statements of Registrants beginning on page 51113. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
| |
| Page
Number
|
| |
Significant Accounting Matters | |
New Accounting Pronouncements | |
Comprehensive Income | |
Rate Matters | |
Commitments, Guarantees and Contingencies | |
Disposition, Assets and Liabilities Held for Sale and Discontinued Operations | |
Benefit Plans | |
Business Segments | |
Derivatives and Hedging | |
Fair Value Measurements | |
Income Taxes | |
Financing Activities | |
Variable Interest Entities | |
Property, Plant and Equipment | |
Disposition Plant Severance | |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING MATTERS
General
The unaudited condensed consolidated financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.
In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods. Net income for the three and nine months ended September 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015. The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2014 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 20, 2015.
Revenue Recognition
Electricity Supply and Delivery Activities - Transactions with PJM
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. For regulated and nonregulated operations, we recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.
APCo, I&M, KPCo and WPCo sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary’s retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenue on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement on January 1, 2014, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices.
AEP’s nonregulated subsidiaries also purchase power from PJM and sell power to PJM. With the exception of certain dedicated load bilateral power supply contracts, these transactions are reported as gross purchases and sales.
Earnings Per Share (EPS)
Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.
The following tables present our basic and diluted EPS calculations included on our condensed statements of income:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, |
| 2015 | | 2014 |
| (in millions, except per share data) |
| |
| | $/share | | | | $/share |
Income from Continuing Operations | $ | 512 |
| | | | $ | 483 |
| | |
Less: Net Income Attributable to Noncontrolling Interests | 1 |
| | | | 1 |
| | |
Earnings Attributable to AEP Common Shareholders from Continuing Operations | $ | 511 |
| | |
| | $ | 482 |
| | |
|
| | | | | | | |
Weighted Average Number of Basic Shares Outstanding | 490.6 |
| | $ | 1.04 |
| | 488.9 |
| | $ | 0.99 |
|
Weighted Average Dilutive Effect of Restricted Stock Units | 0.2 |
| | — |
| | 0.1 |
| | — |
|
Weighted Average Number of Diluted Shares Outstanding | 490.8 |
| | $ | 1.04 |
| | 489.0 |
| | $ | 0.99 |
|
|
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2015 | | 2014 |
| (in millions, except per share data) |
| |
| | $/share | | | | $/share |
Income from Continuing Operations | $ | 1,564 |
| | | | $ | 1,430 |
| | |
Less: Net Income Attributable to Noncontrolling Interests | 4 |
| | | | 3 |
| | |
Earnings Attributable to AEP Common Shareholders from Continuing Operations | $ | 1,560 |
| | | | $ | 1,427 |
| | |
| | | | | | | |
Weighted Average Number of Basic Shares Outstanding | 490.2 |
| | $ | 3.18 |
| | 488.4 |
| | $ | 2.92 |
|
Weighted Average Dilutive Effect of Restricted Stock Units | 0.2 |
| | — |
| | 0.2 |
| | — |
|
Weighted Average Number of Diluted Shares Outstanding | 490.4 |
| | $ | 3.18 |
| | 488.6 |
| | $ | 2.92 |
|
There were no antidilutive shares outstanding as of September 30, 2015 and 2014.
Supplementary Cash Flow Information
|
| | | | | | | | |
| | Nine Months Ended September 30, |
Cash Flow Information | | 2015 | | 2014 |
| | (in millions) |
Cash Paid (Received) for: | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 639 |
| | $ | 649 |
|
Net Cash Paid for Income Taxes | | 116 |
| | 109 |
|
Noncash Investing and Financing Activities: | | | | |
Noncash Acquisitions Under Capital Leases | | 97 |
| | 80 |
|
Construction Expenditures Included in Current Liabilities as of September 30, | | 579 |
| | 515 |
|
Construction Expenditures Included in Noncurrent Liabilities as of September 30, | | 66 |
| | — |
|
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | | 31 |
| | — |
|
2. NEW ACCOUNTING PRONOUNCEMENTS
Upon issuance of final pronouncements, we review the new accounting literature to determine its relevance, if any, to our business. The following final pronouncements will impact our financial statements.
ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08)
In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date.
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of our financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. We adopted ASU 2014-08 effective January 1, 2015.
ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09)
In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts.
The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. We plan to adopt ASU 2014-09 effective January 1, 2018.
ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01)
In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements.
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. We plan to adopt ASU 2015-01 effective January 1, 2016.
ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03)
In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. We include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt.
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. We intend to early adopt ASU 2015-03 for the 2015 Form 10-K.
ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05)
In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. We plan to adopt ASU 2015-05 effective January 1, 2016.
ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11)
In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. We plan to adopt ASU 2015-11 effective January 1, 2017.
ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13)
In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale.
The new accounting guidance is effective upon issuance and applied prospectively. We have analyzed the impact of this new standard and determined that it will have no impact on the accounting of our contracts. Additionally, adoption has no impact on net income. We adopted ASU 2015-13 upon its issuance date.
3. COMPREHENSIVE INCOME
Presentation of Comprehensive Income
The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2015 and 2014. All amounts in the following tables are presented net of related income taxes.
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2015
|
| | | | | | | | | | | | | | | | | | | |
| Cash Flow Hedges | | | | | | |
| Commodity | | Interest Rate and Foreign Currency | | Securities Available for Sale | | Pension and OPEB | | Total |
| (in millions) |
Balance in AOCI as of June 30, 2015 | $ | (5 | ) | | $ | (18 | ) | | $ | 8 |
| | $ | (87 | ) | | $ | (102 | ) |
Change in Fair Value Recognized in AOCI | (3 | ) | | — |
| | (1 | ) | | — |
| | (4 | ) |
Amounts Reclassified from AOCI | (3 | ) | | — |
| | — |
| | — |
| | (3 | ) |
Net Current Period Other Comprehensive Loss | (6 | ) | | — |
| | (1 | ) | | — |
| | (7 | ) |
Balance in AOCI as of September 30, 2015 | $ | (11 | ) | | $ | (18 | ) | | $ | 7 |
| | $ | (87 | ) | | $ | (109 | ) |
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2014
|
| | | | | | | | | | | | | | | | | | | |
| Cash Flow Hedges | | | | | | |
| Commodity | | Interest Rate and Foreign Currency | | Securities Available for Sale | | Pension and OPEB | | Total |
| (in millions) |
Balance in AOCI as of June 30, 2014 | $ | 6 |
| | $ | (21 | ) | | $ | 8 |
| | $ | (97 | ) | | $ | (104 | ) |
Change in Fair Value Recognized in AOCI | 3 |
| | — |
| | — |
| | — |
| | 3 |
|
Amounts Reclassified from AOCI | (6 | ) | | 1 |
| | — |
| | 1 |
| | (4 | ) |
Net Current Period Other Comprehensive Income (Loss) | (3 | ) | | 1 |
| | — |
| | 1 |
| | (1 | ) |
Balance in AOCI as of September 30, 2014 | $ | 3 |
| | $ | (20 | ) | | $ | 8 |
| | $ | (96 | ) | | $ | (105 | ) |
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2015
|
| | | | | | | | | | | | | | | | | | | |
| Cash Flow Hedges | | | | | | |
| Commodity | | Interest Rate and Foreign Currency | | Securities Available for Sale | | Pension and OPEB | | Total |
| (in millions) |
Balance in AOCI as of December 31, 2014 | $ | 1 |
| | $ | (19 | ) | | $ | 8 |
| | $ | (93 | ) | | $ | (103 | ) |
Change in Fair Value Recognized in AOCI | (2 | ) | | — |
| | (1 | ) | | — |
| | (3 | ) |
Amounts Reclassified from AOCI | (10 | ) | | 1 |
| | — |
| | 1 |
| | (8 | ) |
Net Current Period Other Comprehensive Income (Loss) | (12 | ) | | 1 |
| | (1 | ) | | 1 |
| | (11 | ) |
Pension and OPEB Adjustment Related to Mitchell Plant | — |
| | — |
| | — |
| | 5 |
| | 5 |
|
Balance in AOCI as of September 30, 2015 | $ | (11 | ) | | $ | (18 | ) | | $ | 7 |
| | $ | (87 | ) | | $ | (109 | ) |
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2014
|
| | | | | | | | | | | | | | | | | | | |
| Cash Flow Hedges | | | | | | |
| Commodity | | Interest Rate and Foreign Currency | | Securities Available for Sale | | Pension and OPEB | | Total |
| (in millions) |
Balance in AOCI as of December 31, 2013 | $ | — |
| | $ | (23 | ) | | $ | 7 |
| | $ | (99 | ) | | $ | (115 | ) |
Change in Fair Value Recognized in AOCI | (8 | ) | | — |
| | 1 |
| | — |
| | (7 | ) |
Amounts Reclassified from AOCI | 11 |
| | 3 |
| | — |
| | 3 |
| | 17 |
|
Net Current Period Other Comprehensive Income | 3 |
| | 3 |
| | 1 |
| | 3 |
| | 10 |
|
Balance in AOCI as of September 30, 2014 | $ | 3 |
| | $ | (20 | ) | | $ | 8 |
| | $ | (96 | ) | | $ | (105 | ) |
Reclassifications from Accumulated Other Comprehensive Income
The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2015 and 2014. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details.
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2015 and 2014
|
| | | | | | | | |
| | Amount of (Gain) Loss Reclassified from AOCI |
| | Three Months Ended September 30, |
| | 2015 | | 2014 |
Gains and Losses on Cash Flow Hedges | | (in millions) |
Commodity: | | |
| | |
Generation & Marketing Revenues | | $ | (19 | ) | | $ | — |
|
Purchased Electricity for Resale | | 14 |
| | (9 | ) |
Subtotal – Commodity | | (5 | ) | | (9 | ) |
| | |
| | |
Interest Rate and Foreign Currency: | | |
| | |
Interest Expense | | — |
| | 2 |
|
Subtotal – Interest Rate and Foreign Currency | | — |
| | 2 |
|
| | | | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (5 | ) |
| (7 | ) |
Income Tax (Expense) Credit | | (2 | ) | | (2 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (3 | ) | | (5 | ) |
| | | | |
Pension and OPEB | | |
| | |
Amortization of Prior Service Cost (Credit) | | (5 | ) | | (5 | ) |
Amortization of Actuarial (Gains)/Losses | | 5 |
| | 7 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | — |
| | 2 |
|
Income Tax (Expense) Credit | | — |
| | 1 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | — |
| | 1 |
|
| | |
| | |
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | $ | (3 | ) | | $ | (4 | ) |
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2015 and 2014
|
| | | | | | | | |
| | Amount of (Gain) Loss Reclassified from AOCI |
| | Nine Months Ended September 30, |
| | 2015 | | 2014 |
Gains and Losses on Cash Flow Hedges | | (in millions) |
Commodity: | | |
| | |
Generation & Marketing Revenues | | $ | (36 | ) | | $ | — |
|
Purchased Electricity for Resale | | 20 |
| | 20 |
|
Regulatory Assets/(Liabilities), Net (a) | | — |
| | (3 | ) |
Subtotal – Commodity | | (16 | ) | | 17 |
|
| | |
| | |
Interest Rate and Foreign Currency: | | |
| | |
Interest Expense | | 1 |
| | 6 |
|
Subtotal – Interest Rate and Foreign Currency | | 1 |
| | 6 |
|
| | | | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (15 | ) |
| 23 |
|
Income Tax (Expense) Credit | | (6 | ) | | 9 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (9 | ) | | 14 |
|
| | | | |
Pension and OPEB | | |
| | |
Amortization of Prior Service Cost (Credit) | | (15 | ) | | (15 | ) |
Amortization of Actuarial (Gains)/Losses | | 16 |
| | 21 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | 1 |
| | 6 |
|
Income Tax (Expense) Credit | | — |
| | 3 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 1 |
| | 3 |
|
| | |
| | |
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | $ | (8 | ) | | $ | 17 |
|
| |
(a) | Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
4. RATE MATTERS
As discussed in the 2014 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2014 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2015 and updates the 2014 Annual Report.
Regulatory Assets Pending Final Regulatory Approval
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2015 | | 2014 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Storm Related Costs | | $ | 24 |
| | $ | 20 |
|
Material and Supplies Related to Retired Plants | | 20 |
| | — |
|
West Virginia Vegetation Management Program | | — |
| | 20 |
|
Regulatory Assets Currently Not Earning a Return | | |
| | |
|
Asset Retirement Obligation Costs Related to Retired Plants | | 59 |
| | — |
|
Virginia Peak Demand Reduction/Energy Efficiency | | 12 |
| | 9 |
|
Ormet Special Rate Recovery Mechanism | | 10 |
| | 10 |
|
Storm Related Costs | | 7 |
| | 100 |
|
Carbon Capture and Storage Product Validation Facility | | — |
| | 13 |
|
IGCC Pre-Construction Costs | | — |
| | 11 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | 27 |
| | 43 |
|
Total Regulatory Assets Pending Final Regulatory Approval | $ | 159 |
| | $ | 226 |
|
If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.
OPCo Rate Matters
Ohio Electric Security Plan Filings
2009 – 2011 ESP
The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018.
In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. In September 2015, the Supreme Court of Ohio denied the IEU's request for reconsideration and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate.
June 2012 – May 2015 ESP Including Capacity Charge
In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013.
In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and $150/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio, which has scheduled oral arguments for the fourth quarter of 2015.
As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50/MWh through May 2014 and at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that approved, with modifications, OPCo's July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00/MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million. In May 2015, the PUCO granted intervenors requests for rehearing. As of September 30, 2015, OPCo's net deferred capacity costs balance of $392 million, including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. Through September 30, 2015, OPCo has collected $183 million in deferred capacity costs, and related carrying charges.
In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015.
In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.
In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report.
If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.
June 2015 - May 2018 ESP Including PPA Application
In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets.
In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo's and various intervenors' requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider.
In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. A hearing at the PUCO related to the PPA commenced in September 2015. In October 2015, the PUCO staff submitted testimony that opposed the PPA application as currently proposed but concluded that, with changes, a PPA could be in the public interest.
If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.
Significantly Excessive Earnings Test Filings
In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending.
In June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements.
Corporate Separation
In October 2012, the PUCO issued an order which approved the corporate separation and transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo’s generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition.
2009 Fuel Adjustment Clause Audit
In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.
In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.
2012 and 2013 Fuel Adjustment Clause Audits
In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June 2012 - May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition.
Ormet
Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of September 30, 2015, is recorded in Regulatory Assets on the condensed balance sheet. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement was held in May 2014.
In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.
To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition.
SWEPCo Rate Matters
2012 Texas Base Rate Case
In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally,
the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of September 30, 2015, the net book value of Welsh Plant, Unit 2 was $83 million, before cost of removal, including materials and supplies inventory and CWIP.
Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million. In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses.
If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.
2012 Louisiana Formula Rate Filing
In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit. The rates are subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC review base rates in 2014 and 2015 and that SWEPCo recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million, primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition.
2014 Louisiana Formula Rate Filing
In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase, which was effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2015 Louisiana Formula Rate Filing
In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Welsh Plant, Units 1 and 3 – Environmental Projects
To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2024 for Welsh Plant, Units 1 and 3 will cost approximately $700 million, excluding AFUDC. As of September 30, 2015, SWEPCo has incurred costs of $303 million, including AFUDC, and has remaining contractual construction obligations of $62 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of September 30, 2015, the net book value of Welsh Plant, Units 1 and 3 was $529 million, before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
APCo and WPCo Rate Matters
2014 West Virginia Base Rate Case
In May 2015, the WVPSC issued an order on APCo and WPCo's base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $99 million based upon a 9.75% return on common equity. The order included a delayed billing of $25 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $25 million delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $45 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $89 million in previously recorded regulatory assets, which will predominantly be recovered over five years.
2015 Virginia Regulatory Asset Proceeding
In January 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets. In February and March 2015, briefs related to this proceeding were filed by various parties. As of September 30, 2015, APCo’s authorized regulatory assets under review in this proceeding were $11 million. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition.
New Virginia Legislation Affecting Biennial Reviews
In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA.
PSO Rate Matters
2015 Oklahoma Base Rate Case
In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million, which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base
rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million, excluding AFUDC. As of September 30, 2015, PSO has incurred costs of $162 million related to these projects, including AFUDC.
In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million, will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of September 30, 2015, the net book value of Northeastern Plant, Unit 4 was $94 million, before cost of removal, including materials and supplies inventory and CWIP.
In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million, based upon returns on common equity ranging from 8.75% to 9.3%, and increases to depreciation expense ranging from $23 million to $46 million. Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certain intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC are scheduled for December 2015.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2014 Oklahoma Base Rate Case
In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014.
I&M Rate Matters
Tanners Creek Plant
In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates.
In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval.
Transmission, Distribution and Storage System Improvement Charge (TDSIC)
In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million. In April 2015, I&M filed a notice with the IURC to exclude $117 million related to certain projects. In September 2015, the IURC granted I&M's motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals.
KPCo Rate Matters
Plant Transfer
In October 2013, the KPSC issued an order that approved a modified settlement agreement which included the approval to transfer to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed. In December 2013, the Attorney General filed an appeal of the order with the Franklin County Circuit Court. In April 2015, the Franklin County Circuit Court issued an order that affirmed the KPSC's October 2013 order. In May 2015, the Attorney General filed an appeal with the Franklin County Circuit Court of the April 2015 order that had affirmed the KPSC's order.
Consistent with KPCo’s December 2012 plant transfer filing that was approved by the KPSC, Big Sandy Plant, Unit 2 was retired in May 2015. Upon retirement, $194 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Big Sandy Plant, Unit 2 and the related asset retirement obligations, costs of removal and materials and supplies. These regulatory assets will be amortized over 25 years, effective July 2015.
If any part of the KPSC order is overturned, it could reduce future net income and cash flows and impact financial condition.
Kentucky Fuel Adjustment Clause Review
In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owned and operated both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court. In September 2015, the Franklin County Circuit Court issued an order that dismissed all appeals filed related to this FAC review, as agreed to by the parties to the stipulation agreement in the "2014 Kentucky Base Rate Case" discussed below.
2014 Kentucky Base Rate Case
In December 2014, KPCo filed a request with the KPSC for a net increase in rates of $70 million. In April 2015, a non-unanimous stipulation agreement between KPCo and certain intervenors was filed with the KPSC. The parties to the stipulation recommended a net revenue increase of $45 million, which consisted of a $68 million increase in rider rates, offset by a $23 million decrease in annual base rates, to be effective July 2015. The proposed net increase reflects KPCo's ownership interest in the Mitchell Plant, riders to recover the Big Sandy Plant retirement and operational costs and the inclusion of an environmental compliance plan. Additionally, the agreement included (a) recovery of $12 million of deferred storm costs, (b) any difference between the actual off-system sales margins and the $15 million
included in the proposed annual base rates to be shared with 75% to the customer and 25% to KPCo and (c) dismissal of the KPCo and the Kentucky Industrial Utility Customers appeals of the KPSC order in the KPCo fuel adjustment clause review. See "Kentucky Fuel Adjustment Clause Review" discussed above.
In June 2015, the KPSC issued an order that approved a modified stipulation agreement. The order approved a net revenue increase of $45 million, as proposed in the stipulation agreement, and contained modifications that included (a) approval to recover $2 million of IGCC and certain carbon capture study costs, both over 25 years, (b) no deferral of certain PJM costs and (c) denial of the recovery of certain potential purchased power costs through a rider.
KGPCo Rate Matters
2015 Kingsport Base Rate Case
In September 2015, KGPCo filed a request with the TRA to increase base rates by $12 million annually based upon a proposed return on common equity of 10.66% with the new rates expected to be implemented by July 2016. If KGPCo does not recover its costs, it could reduce future net income and cash flows and impact financial condition.
5. COMMITMENTS, GUARANTEES AND CONTINGENCIES
We are subject to certain claims and legal actions arising in our ordinary course of business. In addition, our business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against us cannot be predicted. We accrue contingent liabilities only when we conclude that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When we determine that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, we disclose such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent our maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.
For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on our financial statements. The Commitments, Guarantees and Contingencies note within our 2014 Annual Report should be read in conjunction with this report.
GUARANTEES
We record liabilities for guarantees in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.
Letters of Credit
We enter into standby letters of credit with third parties. As Parent, we issue all of these letters of credit in our ordinary course of business on behalf of our subsidiaries. These letters of credit cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.
We have two revolving credit facilities totaling $3.5 billion, under which we may issue up to $1.2 billion as letters of credit. As of September 30, 2015, the maximum future payments for letters of credit issued under the revolving credit facilities were $33 million with maturities ranging from December 2015 to November 2016.
We issue letters of credit under two uncommitted facilities totaling $150 million. As of September 30, 2015, the maximum future payments for letters of credit issued under the uncommitted facilities were $122 million with maturities ranging from October 2015 to September 2016. An uncommitted facility gives the issuer of the facility the right to accept or decline each request we make under the facility.
We have $477 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $483 million. The letters of credit have maturities ranging from March 2016 to July 2017.
Guarantees of Third-Party Obligations
SWEPCo
As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $58 million. Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2015, SWEPCo has collected $65 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $49 million is recorded in Asset Retirement Obligations on our condensed balance sheets.
Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause.
Indemnifications and Other Guarantees
Contracts
We enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the sale price. As of September 30, 2015, there were no material liabilities recorded for any indemnifications.
Master Lease Agreements
We lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, we are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2015, the maximum potential loss for these lease agreements was $35 million assuming the fair value of the equipment is zero at the end of the lease term.
Railcar Lease
In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2015.
Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, we believe that the fair value would produce a sufficient sales price to avoid any loss.
ENVIRONMENTAL CONTINGENCIES
The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation
By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, our generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. We currently incur costs to dispose of these substances safely.
In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed
remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of September 30, 2015, I&M's accrual for all of these sites is approximately $8 million. As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. We cannot predict the amount of additional cost, if any.
NUCLEAR CONTINGENCIES
I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. We have a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.
OPERATIONAL CONTINGENCIES
Rockport Plant Litigation
In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted our motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. Plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. We will continue to defend against the remaining claims. We are unable to determine a range of potential losses that are reasonably possible of occurring.
Natural Gas Markets Lawsuits
In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) is among the companies named as defendants in some of these cases. We settled, received summary judgment or were dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court's dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court's orders in these cases. The appellate court reversed the district court's holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases. Defendants in these cases, including AEP, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue. AEP also subsequently filed a separate petition with the U.S. Supreme Court seeking review of the personal jurisdiction issue. In July 2014, the U.S. Supreme Court granted the defendants' previously filed petition for further review with the U.S. Supreme
Court on the preemption issue. Oral argument occurred in January 2015. In April 2015, the U.S. Supreme Court affirmed the judgment of the U.S. Court of Appeals for the Ninth Circuit on the preemption issue, holding that the plaintiffs' state antitrust claims were not preempted by the Natural Gas Act. The U.S. Supreme Court denied AEP's petition for review of the personal jurisdiction issue shortly thereafter. The cases have been remanded to the district court for further proceedings. We will continue to defend the cases. We believe the provision we have is adequate. We are unable to determine the amount of potential additional losses that are reasonably possible of occurring.
Wage and Hours Lawsuit
In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount.
In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. We will continue to defend the case. We do not believe a loss is probable. If there is an unfavorable outcome contrary to our expectations, we estimate possible losses of up to $30 million.
National Do Not Call Registry Lawsuit
In May 2014, AEP Energy was served with a complaint filed in the U.S. District Court for the Northern District of Illinois, alleging violations of the Telephone Consumer Protection Act (TCPA). The plaintiff alleges that he received telemarketing calls on behalf of AEP Energy despite having registered his telephone number on the National Do Not Call Registry. Plaintiff seeks to represent a class of persons who allegedly received such calls. Plaintiff seeks statutory damages under the TCPA on behalf of himself and the alleged class as well as injunctive relief. As a result of a mediation held in October 2014, the parties reached an agreement in principle, subject to final documentation and preliminary and final court approval. In April 2015, we filed a motion with the court for preliminary approval of the settlement. In June 2015, the court granted preliminary approval of the settlement. In September 2015, the court granted final approval of the settlement, reserving decision on the appropriate fee for plaintiff's counsel.
Gavin Landfill Litigation
In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, we filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied our motion. We appealed that decision to the West Virginia Supreme Court. We will continue to defend against the claims. We are unable to determine a range of potential losses that are reasonably possible of occurring.
6. DISPOSITION, ASSETS AND LIABILITIES HELD FOR SALE AND DISCONTINUED OPERATIONS
DISPOSITION
2015
Muskingum River Plant (Generation & Marketing Segment)
In August 2015, AGR sold its retired Muskingum River Plant site including its associated asset retirement obligations to a nonaffiliated party. AGR paid $48 million and the nonaffiliated party took ownership of the Muskingum River Plant site assets and assumed responsibility for environmental liabilities and AROs, including ash pond closure, asbestos abatement and decommissioning and demolition. As a result of the sale, a net gain of $32 million was recognized and recorded in Other Operation on the condensed consolidated statements of income. The cash paid was recorded in Operating Activities on the condensed consolidated statements of cash flows.
ASSETS AND LIABILITIES HELD FOR SALE
AEPRO (AEP River Operations Segment)
During the third quarter of 2015, we evaluated bids from prospective buyers, selected a buyer and received approval from AEP's Board of Directors to proceed with the sale to the nonaffiliated party. In October 2015, we signed an agreement to sell our commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale of AEPRO is subject to regulatory approval including federal clearance pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Upon close of the sale, the nonaffiliated party will acquire AEPRO by purchasing all of the common stock of AEP Resources, Inc., the parent company of AEPRO. The nonaffiliated party will assume certain assets and liabilities of AEPRO, excluding the equity method investment in IMT, pension and benefit assets and liabilities and debt obligations. We will retain ownership of our captive barge fleet that delivers coal to the company's regulated coal-fueled power plant units owned or leased by AEGCo, APCo, I&M, KPCo and WPCo. We signed a contract with the nonaffiliated party to dispatch and schedule our captive barge fleet for the company's regulated coal-fueled power plant units. We also contracted with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2016. The sale is expected to close in the fourth quarter of 2015.
Upon evaluation, management concluded that the AEPRO business met the classification as held for sale in the third quarter of 2015. Accordingly, AEPRO's assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on our condensed consolidated balance sheets as of September 30, 2015 and December 31, 2014 and as shown in the following table:
|
| | | | | | | | |
| | September 30, 2015 | | December 31, 2014 |
Assets: | | (in millions) |
Accounts Receivable | | $ | 55 |
| | $ | 91 |
|
Property, Plant and Equipment – Net | | 506 |
| | 482 |
|
Other Classes of Assets That Are Not Major | | 47 |
| | 52 |
|
Total Assets Classified as Held for Sale on the Condensed Consolidated Balance Sheets | | $ | 608 |
|
| $ | 625 |
|
| | | | |
Liabilities: | | | | |
Long-term Debt | | $ | 81 |
| | $ | 83 |
|
Obligations Under Capital Leases | | 228 |
| | 189 |
|
Other Classes of Liabilities That Are Not Major | | 165 |
| | 163 |
|
Total Liabilities Classified as Held for Sale on the Condensed Consolidated Balance Sheets | | $ | 474 |
| | $ | 435 |
|
DISCONTINUED OPERATIONS
Management periodically assesses the overall AEP business model and makes decisions regarding our continued support and funding of our various businesses and operations. When it is determined that we will seek to exit a particular business or activity and we have met the accounting requirements for reclassification, we will reclassify the operations of those businesses or operations as discontinued operations. The assets and liabilities of these discontinued operations are classified as Assets Held for Sale and Liabilities Held for Sale until the time they are sold. In the third quarter of 2015, AEPRO was determined to be discontinued operations and has been classified as such for third quarter 2015 reporting. Results of operations of AEPRO have been classified as discontinued operations in our condensed consolidated statements of income for the three and nine months ended September 30, 2015 and 2014 as shown in the following table:
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | |
| | 2015 | | 2014 | | 2015 | | 2014 |
| | (in millions) |
Other Revenues | | $ | 129 |
| | $ | 141 |
| | $ | 372 |
| | $ | 435 |
|
| | | | | | | | |
Other Operation Expense | | 96 |
| | 102 |
| | 273 |
| | 342 |
|
Maintenance Expense | | 4 |
| | 8 |
| | 20 |
| | 24 |
|
Depreciation and Amortization Expense | | 9 |
| | 8 |
| | 27 |
| | 23 |
|
Other Expense | | 8 |
| | 7 |
| | 24 |
| | 22 |
|
Total Expenses | | 117 |
| | 125 |
| | 344 |
| | 411 |
|
| | | | | | | | |
Pretax Income of Discontinued Operations | | 12 |
|
| 16 |
|
| 28 |
|
| 24 |
|
Income Tax Expense | | 4 |
| | 5 |
| | 10 |
| | 8 |
|
Total Income on Discontinued Operations as Presented on the Condensed Consolidated Statements of Income | | $ | 8 |
|
| $ | 11 |
|
| $ | 18 |
|
| $ | 16 |
|
7. BENEFIT PLANS
We sponsor a qualified pension plan and two unfunded nonqualified pension plans. Substantially all of our employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. We sponsor OPEB plans to provide health and life insurance benefits for retired employees.
Components of Net Periodic Benefit Cost
The following tables provide the components of our net periodic benefit cost (credit) for the plans for the three and nine months ended September 30, 2015 and 2014:
|
| | | | | | | | | | | | | | | |
| Pension Plans | | Other Postretirement Benefit Plans |
| Three Months Ended September 30, | | Three Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
| (in millions) |
Service Cost | $ | 23 |
| | $ | 18 |
| | $ | 3 |
| | $ | 4 |
|
Interest Cost | 51 |
| | 55 |
| | 15 |
| | 16 |
|
Expected Return on Plan Assets | (69 | ) | | (65 | ) | | (28 | ) | | (28 | ) |
Amortization of Prior Service Cost (Credit) | 1 |
| | 1 |
| | (18 | ) | | (18 | ) |
Amortization of Net Actuarial Loss | 27 |
| | 31 |
| | 5 |
| | 6 |
|
Net Periodic Benefit Cost (Credit) | $ | 33 |
| | $ | 40 |
| | $ | (23 | ) | | $ | (20 | ) |
|
| | | | | | | | | | | | | | | |
| Pension Plans | | Other Postretirement Benefit Plans |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
| (in millions) |
Service Cost | $ | 70 |
| | $ | 54 |
| | $ | 9 |
| | $ | 11 |
|
Interest Cost | 154 |
| | 166 |
| | 43 |
| | 50 |
|
Expected Return on Plan Assets | (206 | ) | | (196 | ) | | (83 | ) | | (84 | ) |
Amortization of Prior Service Cost (Credit) | 2 |
| | 2 |
| | (52 | ) | | (52 | ) |
Amortization of Net Actuarial Loss | 80 |
| | 93 |
| | 14 |
| | 17 |
|
Net Periodic Benefit Cost (Credit) | $ | 100 |
| | $ | 119 |
| | $ | (69 | ) | | $ | (58 | ) |
8. BUSINESS SEGMENTS
Our primary business is the generation, transmission and distribution of electricity. Within our Vertically Integrated Utilities segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.
Our reportable segments and their related business activities are outlined below:
Vertically Integrated Utilities
Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.
Transmission and Distribution Utilities
Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load.
AEP Transmission Holdco
Development, construction and operation of transmission facilities through investments in our wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.
Generation & Marketing
Nonregulated generation in ERCOT and PJM.
Marketing, risk management and retail activities in ERCOT, PJM and MISO.
AEP River Operations
Commercial barging operations that transports liquids, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.
In October 2015, we signed an agreement to sell AEPRO to a nonaffiliated party. The AEP River Operations segment is comprised entirely of AEPRO. However, we will retain AEPRO's investment in IMT. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information.
The remainder of our activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
The tables below present our reportable segment income statement information for the three and nine months ended September 30, 2015 and 2014 and reportable segment balance sheet information as of September 30, 2015 and December 31, 2014. These amounts include certain estimates and allocations where necessary.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Vertically Integrated Utilities |
| Transmission and Distribution Utilities |
| AEP Transmission Holdco |
| Generation & Marketing |
| AEP River Operations |
| Corporate and Other (a) |
| Reconciling Adjustments |
| Consolidated |
| | (in millions) |
Three Months Ended September 30, 2015 | | | | | | | | | | | | | | | | |
Revenues from: | | |
| | |
| | |
| | |
| | |
| | |
| | | | |
|
External Customers | | $ | 2,436 |
| | $ | 1,164 |
| | $ | 27 |
| | $ | 802 |
| | $ | — |
| | $ | 3 |
| | $ | — |
| (c) | $ | 4,432 |
|
Other Operating Segments | | 35 |
| | 25 |
| | 61 |
| | 33 |
| | — |
| | 21 |
| | (175 | ) | | — |
|
Total Revenues | | $ | 2,471 |
| | $ | 1,189 |
| | $ | 88 |
| | $ | 835 |
| | $ | — |
| | $ | 24 |
| | $ | (175 | ) | | $ | 4,432 |
|
| | | | | | | | | | | | | | | | |
Income (Loss) from Continuing Operations | | $ | 275 |
| | $ | 113 |
| | $ | 46 |
| | $ | 91 |
| | $ | (4 | ) | | $ | (9 | ) | | $ | — |
| | $ | 512 |
|
Income from Discontinued Operations, Net of Tax | | — |
| | — |
| | — |
| | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
Net Income (Loss) | | $ | 275 |
| | $ | 113 |
| | $ | 46 |
| | $ | 91 |
| | $ | 4 |
| | $ | (9 | ) | | $ | — |
| | $ | 520 |
|
| | | | | | | | | | | | | | | | |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | AEP River Operations | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| | (in millions) |
Three Months Ended September 30, 2014 | | | | | | | | | | | | | | | | |
Revenues from: | | |
| | |
| | |
| | |
| | |
| | |
| | | | |
|
External Customers | | $ | 2,432 |
| (b) | $ | 1,163 |
| | $ | 21 |
| | $ | 538 |
| (b) | $ | — |
| | $ | 7 |
| | $ | — |
| (c) | $ | 4,161 |
|
Other Operating Segments | | 18 |
| (b) | 68 |
| | 34 |
| | 363 |
| (b) | — |
| | 19 |
| | (502 | ) | | — |
|
Total Revenues | | $ | 2,450 |
| | $ | 1,231 |
| | $ | 55 |
| | $ | 901 |
| | $ | — |
| | $ | 26 |
| | $ | (502 | ) | | $ | 4,161 |
|
| | | | | | | | | | | | | | | | |
Income from Continuing Operations | | $ | 220 |
| | $ | 92 |
| | $ | 43 |
| | $ | 117 |
| | $ | — |
| | $ | 11 |
| | $ | — |
| | $ | 483 |
|
Income from Discontinued Operations, Net of Tax | | — |
| | — |
| | — |
| | — |
| | 11 |
| | — |
| | — |
| | 11 |
|
Net Income | | $ | 220 |
| | $ | 92 |
| | $ | 43 |
| | $ | 117 |
| | $ | 11 |
| | $ | 11 |
| | $ | — |
| | $ | 494 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | AEP River Operations | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| | (in millions) |
Nine Months Ended September 30, 2015 | | | | | | | | | | | | | | | | |
Revenues from: | | |
| | |
| | | | |
| | |
| | |
| | |
| | |
|
External Customers | | $ | 7,082 |
|
| $ | 3,378 |
| | $ | 74 |
| | $ | 2,289 |
| | $ | — |
| | $ | 16 |
| | $ | — |
| (c) | $ | 12,839 |
|
Other Operating Segments | | 77 |
| | 142 |
| | 171 |
| | 517 |
| | — |
| | 58 |
| | (965 | ) | | — |
|
Total Revenues | | $ | 7,159 |
| | $ | 3,520 |
| | $ | 245 |
| | $ | 2,806 |
| | $ | — |
| | $ | 74 |
| | $ | (965 | ) | | $ | 12,839 |
|
| | | | | | | | | | | | | | | | |
Income (Loss) from Continuing Operations | | $ | 783 |
| | $ | 288 |
| | $ | 148 |
| | $ | 360 |
| | $ | (2 | ) | | $ | (13 | ) | | $ | — |
| | $ | 1,564 |
|
Income from Discontinued Operations, Net of Tax | | — |
| | — |
| | — |
| | — |
| | 18 |
| | — |
| | — |
| | 18 |
|
Net Income (Loss) | | $ | 783 |
| | $ | 288 |
| | $ | 148 |
| | $ | 360 |
| | $ | 16 |
| | $ | (13 | ) | | $ | — |
| | $ | 1,582 |
|
| | | | | | | | | | | | | | | | |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | AEP River Operations | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| | (in millions) |
Nine Months Ended September 30, 2014 | | | | | | | | | | | | | | | | |
Revenues from: | | |
| | |
| | | | |
| | |
| | |
| | |
| | |
|
External Customers | | $ | 7,217 |
| (b) | $ | 3,388 |
| | $ | 54 |
| | $ | 1,932 |
| (b) | $ | — |
| | $ | 19 |
| | $ | (51 | ) | (c) | $ | 12,559 |
|
Other Operating Segments | | 71 |
| (b) | 192 |
| | 86 |
| | 1,133 |
| (b) | — |
| | 55 |
| | (1,537 | ) | | — |
|
Total Revenues | | $ | 7,288 |
| | $ | 3,580 |
| | $ | 140 |
| | $ | 3,065 |
| | $ | — |
| | $ | 74 |
| | $ | (1,588 | ) | | $ | 12,559 |
|
| | | | | | | | | | | | | | | | |
Income from Continuing Operations | | $ | 654 |
| | $ | 279 |
| | $ | 114 |
| | $ | 378 |
| | $ | 1 |
| | $ | 4 |
| | $ | — |
| | $ | 1,430 |
|
Income from Discontinued Operations, Net of Tax | | — |
| | — |
| | — |
| | — |
| | 16 |
| | — |
| | — |
| | 16 |
|
Net Income | | $ | 654 |
| | $ | 279 |
| | $ | 114 |
| | $ | 378 |
| | $ | 17 |
| | $ | 4 |
| | $ | — |
| | $ | 1,446 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Vertically Integrated Utilities |
| Transmission and Distribution Utilities |
| AEP Transmission Holdco |
| Generation & Marketing |
| AEP River Operations | |
| Corporate and Other (a) |
| Reconciling Adjustments |
| Consolidated | |
| (in millions) | |
September 30, 2015 | |
| | |
| | |
| | |
| | | | | |
| | |
| | |
| |
Total Property, Plant and Equipment | $ | 39,981 |
| | $ | 13,707 |
| | $ | 3,594 |
| | $ | 7,474 |
| | $ | — |
| | | $ | 349 |
| | $ | (279 | ) | (d) | $ | 64,826 |
| |
Accumulated Depreciation and Amortization | 12,483 |
| | 3,603 |
| | 43 |
| | 3,390 |
| | — |
| | | 178 |
| | (109 | ) | (d) | 19,588 |
| |
Total Property, Plant and Equipment - Net | $ | 27,498 |
| | $ | 10,104 |
| | $ | 3,551 |
| | $ | 4,084 |
| | $ | — |
| | | $ | 171 |
| | $ | (170 | ) | (d) | $ | 45,238 |
| |
| | | | | | | | | | | | | | | | | |
Assets Held for Sale | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 608 |
| | | $ | — |
| | $ | — |
| | $ | 608 |
| |
Total Assets | 35,272 |
| | 14,441 |
| | 4,362 |
| | 5,531 |
| | 772 |
| (f) | | 21,810 |
| | (21,089 | ) | (d) (e) | 61,099 |
| |
| | | | | | | | | | | | | | | | | |
Long-term Debt Due Within One Year: | | | | | | | | | | | | | | | | | |
Affiliated | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
| | $ | — |
| | $ | — |
| |
Nonaffiliated | 949 |
| | 724 |
| | — |
| | 151 |
| | — |
| | | 2 |
| | — |
| | 1,826 |
| |
| | | | | | | | | | | | | | | | | |
Long-term Debt: | | | | | | | | | | | | | | | | | |
Affiliated | 20 |
| | — |
| | — |
| | 32 |
| | — |
| | | — |
| | (52 | ) | | — |
| |
Nonaffiliated | 9,900 |
| | 4,888 |
| | 1,323 |
| | 641 |
| | — |
| | | 848 |
| | — |
| | 17,600 |
| |
| | | | | | | | | | | | | | | | | |
Total Long-term Debt | $ | 10,869 |
| | $ | 5,612 |
| | $ | 1,323 |
| | $ | 824 |
| | $ | — |
| | | $ | 850 |
| | $ | (52 | ) | | $ | 19,426 |
| |
| | | | | | | | | | | | | | | | | |
Liabilities Held for Sale | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 474 |
| | | $ | — |
| | $ | — |
| | $ | 474 |
| (g) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | AEP River Operations | | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated | |
| (in millions) | |
December 31, 2014 | |
| | |
| | |
| | |
| | | | | |
| | |
| | |
| |
Total Property, Plant and Equipment | $ | 39,402 |
| | $ | 13,024 |
| | $ | 2,714 |
| | $ | 8,394 |
| | $ | — |
| | | $ | 343 |
| | $ | (271 | ) | (d) | $ | 63,606 |
| |
Accumulated Depreciation and Amortization | 12,773 |
| | 3,481 |
| | 25 |
| | 3,603 |
| | — |
| | | 188 |
| | (99 | ) | (d) | 19,971 |
| |
Total Property, Plant and Equipment - Net | $ | 26,629 |
| | $ | 9,543 |
| | $ | 2,689 |
| | $ | 4,791 |
| | $ | — |
| | | $ | 155 |
| | $ | (172 | ) | (d) | $ | 43,635 |
| |
| | | | | | | | | | | | | | | | | |
Assets Held for Sale | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 625 |
| | | $ | — |
| | $ | — |
| | $ | 625 |
| |
Total Assets | 33,750 |
| | 14,495 |
| | 3,575 |
| | 6,329 |
| | 749 |
| (f) | | 21,081 |
| | (20,346 | ) | (d) (e) | 59,633 |
| |
| | | | | | | | | | | | | | | | | |
Long-term Debt Due Within One Year: | | | | | | | | | | | | | | | | | |
Affiliated | $ | 111 |
| | $ | — |
| | $ | — |
| | $ | 86 |
| | $ | — |
| | | $ | — |
| | $ | (197 | ) | | $ | — |
| |
Nonaffiliated | 1,352 |
| | 405 |
| | — |
| | 740 |
| | — |
| | | 3 |
| | — |
| | 2,500 |
| |
| | | | | | | | | | | | | | | | | |
Long-term Debt: | | | | | | | | | | | | | | | | | |
Affiliated | 20 |
| | — |
| | — |
| | 32 |
| | — |
| | | — |
| | (52 | ) | | — |
| |
Nonaffiliated | 8,634 |
| | 5,256 |
| | 1,153 |
| | 217 |
| | — |
| | | 841 |
| | — |
| | 16,101 |
| |
| | | | | | | | | | | | | | | | | |
Total Long-term Debt | $ | 10,117 |
| | $ | 5,661 |
| | $ | 1,153 |
| | $ | 1,075 |
| | $ | — |
| | | $ | 844 |
| | $ | (249 | ) | | $ | 18,601 |
| |
| | | | | | | | | | | | | | | | | |
Liabilities Held for Sale | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 435 |
| | | $ | — |
| | $ | — |
| | $ | 435 |
| (g) |
| |
(a) | Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. |
| |
(b) | Includes the impact of corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. |
| |
(c) | Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. |
| |
(d) | Includes eliminations due to an intercompany capital lease. |
| |
(e) | Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies. |
| |
(f) | Amounts include intercompany advances to affiliates and intercompany accounts receivable that will be settled prior to or upon the close of the sale of AEPRO. |
| |
(g) | Amounts include debt related to AEPRO. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information.
|
9. DERIVATIVES AND HEDGING
OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS
We are exposed to certain market risks as a major power producer and participant in the wholesale electricity, natural gas, coal and emission allowance markets. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates. We manage these risks using derivative instruments.
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES
Risk Management Strategies
Our strategy surrounding the use of derivative instruments primarily focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. Our risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact. To accomplish our objectives, we primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.
We enter into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with our energy business. We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities. We also engage in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.
The following table represents the gross notional volume of our outstanding derivative contracts as of September 30, 2015 and December 31, 2014:
Notional Volume of Derivative Instruments
|
| | | | | | | | | | |
| | Volume | | |
| | September 30, 2015 | | December 31, 2014 | | Unit of Measure |
Primary Risk Exposure | | (in millions) | | |
Commodity: | | | | |
| | |
Power | | 371 |
| | 334 |
| | MWhs |
Coal | | 4 |
| | 3 |
| | Tons |
Natural Gas | | 46 |
| | 106 |
| | MMBtus |
Heating Oil and Gasoline | | 9 |
| | 6 |
| | Gallons |
Interest Rate | | $ | 114 |
| | $ | 152 |
| | USD |
| | | | | | |
Interest Rate and Foreign Currency | | $ | 560 |
| | $ | 815 |
| | USD |
Fair Value Hedging Strategies
We enter into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
Cash Flow Hedging Strategies
We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. We monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect profit margins for a portion of future electricity sales and energy purchases. We do not hedge all commodity price risk.
Our vehicle fleet and barge operations are exposed to gasoline and diesel fuel price volatility. We enter into financial heating oil and gasoline derivative contracts in order to mitigate price risk of our future fuel purchases. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. We do not hedge all fuel price risk.
We enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate. We also enter into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. Our forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure.
At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers. In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. We do not hedge all foreign currency exposure.
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS
The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of our derivative instruments, we also apply valuation adjustments for discounting, liquidity and credit quality.
Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with our estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of our risk management contracts.
According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2015 and December 31, 2014 condensed balance sheets, we netted $4 million and $4 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $47 million and $35 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.
The following tables represent the gross fair value impact of our derivative activity on our condensed balance sheets as of September 30, 2015 and December 31, 2014:
Fair Value of Derivative Instruments
September 30, 2015
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency (a) | | | |
| | (in millions) |
Current Risk Management Assets | | $ | 311 |
| | $ | 9 |
| | $ | 2 |
| | $ | 322 |
| | $ | (179 | ) | | $ | 143 |
|
Long-term Risk Management Assets | | 443 |
| | 3 |
| | — |
| | 446 |
| | (93 | ) | | 353 |
|
Total Assets | | 754 |
| | 12 |
| | 2 |
| | 768 |
| | (272 | ) | | 496 |
|
| | | | | | | | | | | | |
Current Risk Management Liabilities | | 267 |
| | 7 |
| | 1 |
| | 275 |
| | (200 | ) | | 75 |
|
Long-term Risk Management Liabilities | | 293 |
| | 22 |
| | 1 |
| | 316 |
| | (115 | ) | | 201 |
|
Total Liabilities | | 560 |
| | 29 |
| | 2 |
| | 591 |
| | (315 | ) | | 276 |
|
| | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 194 |
| | $ | (17 | ) | | $ | — |
| | $ | 177 |
| | $ | 43 |
| | $ | 220 |
|
| | | | | | | | | | | | |
Fair Value of Derivative Instruments |
December 31, 2014 |
| | | | | | | | | | | | |
| | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency (a) | | | |
| | (in millions) |
Current Risk Management Assets | | $ | 392 |
| | $ | 30 |
| | $ | 3 |
| | $ | 425 |
| | $ | (247 | ) | | $ | 178 |
|
Long-term Risk Management Assets | | 367 |
| | 3 |
| | — |
| | 370 |
| | (76 | ) | | 294 |
|
Total Assets | | 759 |
| | 33 |
| | 3 |
| | 795 |
| | (323 | ) | | 472 |
|
| | | | | | | | | | | | |
Current Risk Management Liabilities | | 329 |
| | 23 |
| | 1 |
| | 353 |
| | (261 | ) | | 92 |
|
Long-term Risk Management Liabilities | | 208 |
| | 8 |
| | 9 |
| | 225 |
| | (94 | ) | | 131 |
|
Total Liabilities | | 537 |
| | 31 |
| | 10 |
| | 578 |
| | (355 | ) | | 223 |
|
| | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 222 |
| | $ | 2 |
| | $ | (7 | ) | | $ | 217 |
| | $ | 32 |
| | $ | 249 |
|
| |
(a) | Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." |
| |
(b) | Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." |
| |
(c) | There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. |
The table below presents our activity of derivative risk management contracts for the three and nine months ended September 30, 2015 and 2014:
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three and Nine Months Ended September 30, 2015 and 2014
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
Location of Gain (Loss) | | 2015 | | 2014 | | 2015 | | 2014 |
| | (in millions) |
Vertically Integrated Utilities Revenues | | $ | — |
| | $ | 7 |
| | $ | 7 |
| | $ | 29 |
|
Transmission and Distribution Utilities Revenues | | (1 | ) | | — |
| | (1 | ) | | — |
|
Generation & Marketing Revenues | | 1 |
| | 21 |
| | 60 |
| | 69 |
|
Other Operation Expense | | — |
| | — |
| | (1 | ) | | — |
|
Maintenance Expense | | (1 | ) | | — |
| | (2 | ) | | — |
|
Purchased Electricity for Resale | | 1 |
| | — |
| | 4 |
| | — |
|
Regulatory Assets (a) | | — |
| | (6 | ) | | — |
| | (6 | ) |
Regulatory Liabilities (a) | | (20 | ) | | (7 | ) | | 33 |
| | 111 |
|
Total Gain (Loss) on Risk Management Contracts | | $ | (20 | ) | | $ | 15 |
| | $ | 100 |
| | $ | 203 |
|
| |
(a) | Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis.
Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, we designate a hedging instrument as a fair value hedge or a cash flow hedge.
For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
Accounting for Fair Value Hedging Strategies
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change.
We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our condensed statements of income. The following table shows the results of our hedging gains (losses) during the three and nine months ended September 30, 2015 and 2014:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
| (in millions) |
Gain (Loss) on Fair Value Hedging Instruments | $ | 4 |
| | $ | (2 | ) | | $ | 7 |
| | $ | 2 |
|
Gain (Loss) on Fair Value Portion of Long-term Debt | (4 | ) | | 2 |
| | (7 | ) | | (2 | ) |
During the three and nine months ended September 30, 2015 and 2014, hedge ineffectiveness was immaterial.
Accounting for Cash Flow Hedging Strategies
For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets until the period the hedged item affects Net Income. We recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).
Realized gains and losses on derivative contracts for the purchase and sale of power and natural gas designated as cash flow hedges are included in Revenues or Purchased Electricity for Resale on our condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on our condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2015 and 2014, we designated power derivatives as cash flow hedges but did not designate natural gas derivatives as cash flow hedges.
We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our condensed statements of income. The impact of cash flow hedge accounting for these derivative contracts was immaterial and discontinued effective March 31, 2014.
We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Interest Expense on our condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2015 and 2014, we designated interest rate derivatives as cash flow hedges.
The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Depreciation and Amortization expense on our condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2015 and 2014, we did not designate any foreign currency derivatives as cash flow hedges.
During the three and nine months ended September 30, 2015 and 2014, hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies disclosed above.
For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2015 and 2014, see Note 3.
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2015 and December 31, 2014 were:
|
| | | | | | | | | | | |
Impact of Cash Flow Hedges on the Condensed Balance Sheet |
September 30, 2015 |
| | | | | |
| Commodity | | Interest Rate and Foreign Currency | | Total |
| (in millions) |
Hedging Assets (a) | $ | 7 |
| | $ | — |
| | $ | 7 |
|
Hedging Liabilities (a) | 24 |
| | 1 |
| | 25 |
|
AOCI Loss Net of Tax | (11 | ) | | (18 | ) | | (29 | ) |
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 1 |
| | (1 | ) | | — |
|
| | | | | |
Impact of Cash Flow Hedges on the Condensed Balance Sheet |
December 31, 2014 |
| | | | | |
| Commodity | | Interest Rate and Foreign Currency | | Total |
| (in millions) |
Hedging Assets (a) | $ | 16 |
| | $ | — |
| | $ | 16 |
|
Hedging Liabilities (a) | 14 |
| | 1 |
| | 15 |
|
AOCI Gain (Loss) Net of Tax | 1 |
| | (19 | ) | | (18 | ) |
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 4 |
| | (2 | ) | | 2 |
|
| |
(a) | Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. |
The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. As of September 30, 2015, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions was 87 months.
Credit Risk
We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. We use Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.
When we use standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
Collateral Triggering Events
Under the tariffs of the RTOs and Independent System Operators (ISOs), we are obligated to post an additional amount of collateral for a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads and guaranties for contractual obligations if our credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and our total exposure. On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP and its subsidiaries have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. The following table represents our exposure if our credit ratings were to decline below a specified rating threshold as of September 30, 2015 and December 31, 2014:
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2015 | | 2014 |
| | (in millions) |
Fair Value of Contracts with Credit Downgrade Triggers | | $ | — |
| | $ | — |
|
Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement | | — |
| | — |
|
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs | | 35 |
| | 36 |
|
Amount of Collateral Attributable to Other Contracts (a) | | 299 |
| | 281 |
|
| |
(a) | Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contracts. |
In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts. The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of September 30, 2015 and December 31, 2014:
|
| | | | | | | |
| September 30, 2015 | | December 31, 2014 |
| (in millions) |
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements | $ | 307 |
| | $ | 235 |
|
Amount of Cash Collateral Posted | 10 |
| | 9 |
|
Additional Settlement Liability if Cross Default Provision is Triggered | 251 |
| | 178 |
|
10. FAIR VALUE MEASUREMENTS
Fair Value Hierarchy and Valuation Techniques
The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors. Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President.
For our commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated. We typically obtain multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, we average the quoted bid and ask prices. In certain circumstances, we may discard a broker quote if it is a clear outlier. We use a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, we include these locations within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of our contracts being classified as Level 3 is the inability to substantiate our energy price curves in the market. A significant portion of our Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.
We utilize our trustee’s external pricing service in our estimate of the fair value of the underlying investments held in the nuclear trusts. Our investment managers review and validate the prices utilized by the trustee to determine fair value. We perform our own valuation testing to verify the fair values of the securities. We receive audit reports of our trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts.
Assets in the nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and
matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Value Measurements of Long-term Debt
The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange.
The book values and fair values of Long-term Debt as of September 30, 2015 and December 31, 2014 are summarized in the following table:
|
| | | | | | | | | | | | | | | |
| September 30, 2015 | | December 31, 2014 |
| Book Value (a) | | Fair Value | | Book Value (a) | | Fair Value |
| (in millions) |
Long-term Debt | $ | 19,507 |
| | $ | 21,257 |
| | $ | 18,684 |
| | $ | 21,075 |
|
| |
(a) | Amounts include debt related to AEPRO that have been classified as Liabilities Held for Sale on the condensed balance sheets. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. |
Fair Value Measurements of Other Temporary Investments
Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that we intend to hold for less than one year and investments by our protected cell of EIS.
The following is a summary of Other Temporary Investments:
|
| | | | | | | | | | | | | | | | |
| | September 30, 2015 |
Other Temporary Investments | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value |
| | (in millions) |
Restricted Cash (a) | | $ | 201 |
| | $ | — |
| | $ | — |
| | $ | 201 |
|
Fixed Income Securities – Mutual Funds | | 90 |
| | — |
| | — |
| | 90 |
|
Equity Securities – Mutual Funds | | 14 |
| | 10 |
| | — |
| | 24 |
|
Total Other Temporary Investments | | $ | 305 |
| | $ | 10 |
| | $ | — |
| | $ | 315 |
|
| | | | | | | | |
| | December 31, 2014 |
Other Temporary Investments | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value |
| | (in millions) |
Restricted Cash (a) | | $ | 280 |
| | $ | — |
| | $ | — |
| | $ | 280 |
|
Fixed Income Securities – Mutual Funds | | 81 |
| | — |
| | — |
| | 81 |
|
Equity Securities – Mutual Funds | | 13 |
| | 12 |
| | — |
| | 25 |
|
Total Other Temporary Investments | | $ | 374 |
| | $ | 12 |
| | $ | — |
| | $ | 386 |
|
| |
(a) | Primarily represents amounts held for the repayment of debt. |
The following table provides the activity for our fixed income and equity securities within Other Temporary Investments for the three and nine months ended September 30, 2015 and 2014:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
| (in millions) |
Proceeds from Investment Sales | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Purchases of Investments | 10 |
| | — |
| | 10 |
| | 1 |
|
Gross Realized Gains on Investment Sales | — |
| | — |
| | — |
| | — |
|
Gross Realized Losses on Investment Sales | — |
| | — |
| | — |
| | — |
|
As of September 30, 2015 and December 31, 2014, we had no Other Temporary Investments with an unrealized loss position. As of September 30, 2015, fixed income securities were primarily debt based mutual funds with short and intermediate maturities. Mutual funds may be sold and do not contain maturity dates.
For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2015 and 2014, see Note 3.
Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal
Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:
Acceptable investments (rated investment grade or above when purchased).
Maximum percentage invested in a specific type of investment.
Prohibition of investment in obligations of AEP or its affiliates.
Withdrawals permitted only for payment of decommissioning costs and trust expenses.
We maintain trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.
I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in the trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds.
The following is a summary of nuclear trust fund investments as of September 30, 2015 and December 31, 2014:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2015 | | December 31, 2014 |
| Fair Value | | Gross Unrealized Gains | | Other-Than- Temporary Impairments | | Fair Value | | Gross Unrealized Gains | | Other-Than- Temporary Impairments |
| (in millions) |
Cash and Cash Equivalents | $ | 164 |
| | $ | — |
| | $ | — |
| | $ | 20 |
| | $ | — |
| | $ | — |
|
Fixed Income Securities: | |
| | |
| | |
| | | | |
| | |
|
United States Government | 704 |
| | 45 |
| | (2 | ) | | 697 |
| | 45 |
| | (5 | ) |
Corporate Debt | 62 |
| | 4 |
| | (1 | ) | | 48 |
| | 4 |
| | (1 | ) |
State and Local Government | 50 |
| | 1 |
| | — |
| | 208 |
| | 1 |
| | — |
|
Subtotal Fixed Income Securities | 816 |
| | 50 |
| | (3 | ) | | 953 |
| | 50 |
| | (6 | ) |
Equity Securities – Domestic | 1,067 |
| | 516 |
| | (80 | ) | | 1,123 |
| | 599 |
| | (79 | ) |
Spent Nuclear Fuel and Decommissioning Trusts | $ | 2,047 |
| | $ | 566 |
| | $ | (83 | ) | | $ | 2,096 |
| | $ | 649 |
| | $ | (85 | ) |
The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2015 and 2014:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
| (in millions) |
Proceeds from Investment Sales | $ | 921 |
| | $ | 263 |
| | $ | 1,437 |
| | $ | 746 |
|
Purchases of Investments | 938 |
| | 281 |
| | 1,479 |
| | 790 |
|
Gross Realized Gains on Investment Sales | 15 |
| | 8 |
| | 34 |
| | 25 |
|
Gross Realized Losses on Investment Sales | 13 |
| | 1 |
| | 23 |
| | 10 |
|
The adjusted cost of fixed income securities was $766 million and $903 million as of September 30, 2015 and December 31, 2014, respectively. The adjusted cost of equity securities was $551 million and $524 million as of September 30, 2015 and December 31, 2014, respectively.
The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2015 was as follows:
|
| | | |
| Fair Value of Fixed Income Securities |
| (in millions) |
Within 1 year | $ | 166 |
|
1 year – 5 years | 336 |
|
5 years – 10 years | 140 |
|
After 10 years | 174 |
|
Total | $ | 816 |
|
Fair Value Measurements of Financial Assets and Liabilities
The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in our valuation techniques.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2015
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Cash and Cash Equivalents (a) | | $ | 12 |
| | $ | 4 |
| | $ | — |
| | $ | 162 |
| | $ | 178 |
|
| | | | | | | | | | |
Other Temporary Investments | | | | | | | | | | |
Restricted Cash (a) | | 189 |
| | 6 |
| | — |
| | 6 |
| | 201 |
|
Fixed Income Securities - Mutual Funds | | 90 |
| | — |
| | — |
| | — |
| | 90 |
|
Equity Securities – Mutual Funds (b) | | 24 |
| | — |
| | — |
| | — |
| | 24 |
|
Total Other Temporary Investments | | 303 |
| | 6 |
| | — |
| | 6 |
| | 315 |
|
| | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (d) | | 17 |
| | 478 |
| | 248 |
| | (256 | ) | | 487 |
|
Cash Flow Hedges: | | |
| | |
| | |
| | |
| | |
|
Commodity Hedges (c) | | — |
| | 10 |
| | 1 |
| | (4 | ) | | 7 |
|
Fair Value Hedges | | — |
| | 1 |
| | — |
| | 1 |
| | 2 |
|
Total Risk Management Assets | | 17 |
| | 489 |
| | 249 |
| | (259 | ) | | 496 |
|
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | |
| | |
| | |
| | |
| | |
|
Cash and Cash Equivalents (e) | | 157 |
| | — |
| | — |
| | 7 |
| | 164 |
|
Fixed Income Securities: | | |
| | |
| | |
| | |
| | |
|
United States Government | | — |
| | 704 |
| | — |
| | — |
| | 704 |
|
Corporate Debt | | — |
| | 62 |
| | — |
| | — |
| | 62 |
|
State and Local Government | | — |
| | 50 |
| | — |
| | — |
| | 50 |
|
Subtotal Fixed Income Securities | | — |
| | 816 |
| | — |
| | — |
| | 816 |
|
Equity Securities – Domestic (b) | | 1,067 |
| | — |
| | — |
| | — |
| | 1,067 |
|
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,224 |
| | 816 |
| | — |
| | 7 |
| | 2,047 |
|
| | | | | | | | | | |
Total Assets | | $ | 1,556 |
| | $ | 1,315 |
| | $ | 249 |
| | $ | (84 | ) | | $ | 3,036 |
|
| | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | |
Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (d) | | $ | 33 |
| | $ | 440 |
| | $ | 76 |
| | $ | (299 | ) | | $ | 250 |
|
Cash Flow Hedges: | | |
| | |
| | |
| | |
| | |
|
Commodity Hedges (c) | | — |
| | 22 |
| | 6 |
| | (4 | ) | | 24 |
|
Interest Rate/Foreign Currency Hedges | | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Fair Value Hedges | | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Total Risk Management Liabilities | | $ | 33 |
| | $ | 463 |
| | $ | 82 |
| | $ | (302 | ) | | $ | 276 |
|
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2014
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Cash and Cash Equivalents (a) | | $ | 17 |
| | $ | 1 |
| | $ | — |
| | $ | 145 |
| | $ | 163 |
|
| | | | | | | | | | |
Other Temporary Investments | | | | | | | | | | |
Restricted Cash (a) | | 234 |
| | 9 |
| | — |
| | 37 |
| | 280 |
|
Fixed Income Securities - Mutual Funds | | 81 |
| | — |
| | — |
| | — |
| | 81 |
|
Equity Securities – Mutual Funds (b) | | 25 |
| | — |
| | — |
| | — |
| | 25 |
|
Total Other Temporary Investments | | 340 |
| | 9 |
| | — |
| | 37 |
| | 386 |
|
| | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (f) | | 37 |
| | 528 |
| | 190 |
| | (302 | ) | | 453 |
|
Cash Flow Hedges: | | |
| | |
| | |
| | |
| | |
|
Commodity Hedges (c) | | — |
| | 32 |
| | — |
| | (16 | ) | | 16 |
|
Fair Value Hedges | | — |
| | 1 |
| | — |
| | 2 |
| | 3 |
|
Total Risk Management Assets | | 37 |
| | 561 |
| | 190 |
| | (316 | ) | | 472 |
|
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | |
| | |
| | |
| | |
| | |
|
Cash and Cash Equivalents (e) | | 9 |
| | — |
| | — |
| | 11 |
| | 20 |
|
Fixed Income Securities: | | |
| | |
| | |
| | |
| | |
|
United States Government | | — |
| | 697 |
| | — |
| | — |
| | 697 |
|
Corporate Debt | | — |
| | 48 |
| | — |
| | — |
| | 48 |
|
State and Local Government | | — |
| | 208 |
| | — |
| | — |
| | 208 |
|
Subtotal Fixed Income Securities | | — |
| | 953 |
| | — |
| | — |
| | 953 |
|
Equity Securities – Domestic (b) | | 1,123 |
| | — |
| | — |
| | — |
| | 1,123 |
|
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,132 |
| | 953 |
| | — |
| | 11 |
| | 2,096 |
|
| | | | | | | | | | |
Total Assets | | $ | 1,526 |
| | $ | 1,524 |
| | $ | 190 |
| | $ | (123 | ) | | $ | 3,117 |
|
| | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | |
Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (f) | | $ | 65 |
| | $ | 432 |
| | $ | 36 |
| | $ | (334 | ) | | $ | 199 |
|
Cash Flow Hedges: | | |
| | |
| | |
| | |
| | |
|
Commodity Hedges (c) | | — |
| | 27 |
| | 3 |
| | (16 | ) | | 14 |
|
Interest Rate/Foreign Currency Hedges | | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Fair Value Hedges | | — |
| | 7 |
| | — |
| | 2 |
| | 9 |
|
Total Risk Management Liabilities | | $ | 65 |
| | $ | 467 |
| | $ | 39 |
| | $ | (348 | ) | | $ | 223 |
|
| |
(a) | Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. |
| |
(b) | Amounts represent publicly traded equity securities and equity-based mutual funds. |
| |
(c) | Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.'' |
| |
(d) | The September 30, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures ($4) million in 2015 and ($12) million in periods 2016-2018; Level 2 matures $5 million in 2015, $28 million in periods 2016-2018, $3 million in periods 2019-2020 and $2 million in periods 2021-2032; Level 3 matures $2 million in 2015, $63 million in periods 2016-2018, $25 million in periods 2019-2020 and $82 million in periods 2021-2032. Risk management commodity contracts are substantially comprised of power contracts. |
| |
(e) | Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. |
| |
(f) | The December 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and ($10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. |
There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2015 and 2014.
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as Level 3 in the fair value hierarchy:
|
| | | | |
Three Months Ended September 30, 2015 | | Net Risk Management Assets (Liabilities) |
| | (in millions) |
Balance as of June 30, 2015 | | $ | 203 |
|
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 11 |
|
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | 6 |
|
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | (2 | ) |
Purchases, Issuances and Settlements (c) | | (29 | ) |
Transfers into Level 3 (d) (e) | | 8 |
|
Transfers out of Level 3 (e) (f) | | (5 | ) |
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | | (25 | ) |
Balance as of September 30, 2015 | | $ | 167 |
|
|
| | | | |
Three Months Ended September 30, 2014 | | Net Risk Management Assets (Liabilities) |
| | (in millions) |
Balance as of June 30, 2014 | | $ | 132 |
|
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | (9 | ) |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | 10 |
|
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | (3 | ) |
Purchases, Issuances and Settlements (c) | | (5 | ) |
Transfers into Level 3 (d) (e) | | (9 | ) |
Transfers out of Level 3 (e) (f) | | (1 | ) |
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | | 14 |
|
Balance as of September 30, 2014 | | $ | 129 |
|
|
| | | | |
Nine Months Ended September 30, 2015 | | Net Risk Management Assets (Liabilities) |
| | (in millions) |
Balance as of December 31, 2014 | | $ | 151 |
|
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 14 |
|
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | 54 |
|
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | (4 | ) |
Purchases, Issuances and Settlements (c) | | (60 | ) |
Transfers into Level 3 (d) (e) | | 28 |
|
Transfers out of Level 3 (e) (f) | | (17 | ) |
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | | 1 |
|
Balance as of September 30, 2015 | | $ | 167 |
|
|
| | | | |
Nine Months Ended September 30, 2014 | | Net Risk Management Assets (Liabilities) |
| | (in millions) |
Balance as of December 31, 2013 | | $ | 117 |
|
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 91 |
|
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | (3 | ) |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | 12 |
|
Purchases, Issuances and Settlements (c) | | (103 | ) |
Transfers into Level 3 (d) (e) | | (9 | ) |
Transfers out of Level 3 (e) (f) | | (8 | ) |
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | | 32 |
|
Balance as of September 30, 2014 | | $ | 129 |
|
| |
(a) | Included in revenues on the condensed statements of income. |
| |
(b) | Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. |
| |
(c) | Represents the settlement of risk management commodity contracts for the reporting period. |
| |
(d) | Represents existing assets or liabilities that were previously categorized as Level 2. |
| |
(e) | Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. |
| |
(f) | Represents existing assets or liabilities that were previously categorized as Level 3. |
| |
(g) | Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. |
The following tables quantify the significant unobservable inputs used in developing the fair value of our Level 3 positions as of September 30, 2015 and December 31, 2014:
Significant Unobservable Inputs
September 30, 2015
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | Technique | | Input | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 226 |
| | $ | 79 |
| | Discounted Cash Flow | | Forward Market Price (a) | | $ | 13.03 |
| | $ | 165.93 |
| | $ | 36.37 |
|
| | | | | | | Counterparty Credit Risk (b) | | 481 |
FTRs | 23 |
| | 3 |
| | Discounted Cash Flow | | Forward Market Price (a) | | (10.67 | ) | | 11.60 |
| | 1.31 |
|
Total | $ | 249 |
| | $ | 82 |
| | | | | | |
| | |
| | |
Significant Unobservable Inputs
December 31, 2014
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | Technique | | Input | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 157 |
| | $ | 37 |
| | Discounted Cash Flow | | Forward Market Price (a) | | $ | 11.37 |
| | $ | 159.92 |
| | $ | 57.18 |
|
| | | | | | | Counterparty Credit Risk (b) | | 303 |
FTRs | 33 |
| | 2 |
| | Discounted Cash Flow | | Forward Market Price (a) | | (14.63 | ) | | 20.02 |
| | 0.96 |
|
Total | $ | 190 |
| | $ | 39 |
| | | | | | |
| | |
| | |
| |
(a) | Represents market prices in dollars per MWh. |
| |
(b) | Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. |
The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs as of September 30, 2015:
Sensitivity of Fair Value Measurements
September 30, 2015
|
| | | | | | |
Significant Unobservable Input | | Position | | Change in Input | | Impact on Fair Value
Measurement
|
Forward Market Price | | Buy | | Increase (Decrease) | | Higher (Lower) |
Forward Market Price | | Sell | | Increase (Decrease) | | Lower (Higher) |
Counterparty Credit Risk | | Loss | | Increase (Decrease) | | Higher (Lower) |
Counterparty Credit Risk | | Gain | | Increase (Decrease) | | Lower (Higher) |
11. INCOME TAXES
AEP System Tax Allocation Agreement
We, along with our subsidiaries, file a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to our subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Valuation Allowance
We assess the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to use existing deferred tax assets. On the basis of this evaluation, we recorded a valuation allowance of $165 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of our investment in the operations of AEPRO. The assets and liabilities of AEPRO have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on our condensed balance sheets as of September 30, 2015 and December 31, 2014. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information regarding the assets and liabilities classified as held for sale. As of September 30, 2015, valuation allowances totaling $221 million for unrealized capital losses have been recorded in order to recognize only the portion of the deferred tax assets that, more likely than not, will be realized.
Federal and State Income Tax Audit Status
We are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. Although the outcome of tax audits is uncertain, in our opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, we accrue interest on these uncertain tax positions. We are not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.
We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine our tax returns. We are currently under examination in several state and local jurisdictions. However, it is possible that we have filed tax returns with positions that may be challenged by these tax authorities. We believe that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. We are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.
State Tax Legislation
House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact net income, cash flows or financial condition.
12. FINANCING ACTIVITIES
Long-term Debt
The following table details long-term debt outstanding as of September 30, 2015 and December 31, 2014:
|
| | | | | | | | |
Type of Debt | | September 30, 2015 | | December 31, 2014 |
| | (in millions) |
Senior Unsecured Notes | | $ | 13,801 |
| | $ | 12,647 |
|
Pollution Control Bonds | | 1,874 |
| | 1,963 |
|
Notes Payable (a) | | 374 |
| | 357 |
|
Securitization Bonds | | 2,072 |
| | 2,380 |
|
Spent Nuclear Fuel Obligation (b) | | 266 |
| | 266 |
|
Other Long-term Debt | | 1,151 |
| | 1,101 |
|
Fair Value of Interest Rate Hedges | | — |
| | (6 | ) |
Unamortized Discount, Net | | (31 | ) | | (24 | ) |
Total Long-term Debt Outstanding (a) | | 19,507 |
| | 18,684 |
|
Long-term Debt Due Within One Year (a) | | 1,907 |
| | 2,503 |
|
Long-term Debt (a) | | $ | 17,600 |
| | $ | 16,181 |
|
| |
(a) | Amounts include debt related to AEPRO that have been classified as Liabilities Held for Sale on the condensed balance sheets. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. |
| |
(b) | Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of September 30, 2015 and December 31, 2014, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the condensed balance sheets. |
Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2015 are shown in the tables below:
|
| | | | | | | | | | |
Company | | Type of Debt | | Principal Amount | | Interest Rate | | Due Date |
Issuances: | | | | (in millions) | | (%) | | |
APCo | | Pollution Control Bonds | | $ | 86 |
| | 1.90 | | 2019 |
APCo | | Senior Unsecured Notes | | 350 |
| | 4.45 | | 2045 |
APCo | | Senior Unsecured Notes | | 300 |
| | 3.40 | | 2025 |
I&M | | Notes Payable | | 111 |
| | Variable | | 2019 |
I&M | | Other Long-term Debt | | 100 |
| | Variable | | 2018 |
PSO | | Senior Unsecured Notes | | 125 |
| | 3.17 | | 2025 |
PSO | | Senior Unsecured Notes | | 125 |
| | 4.09 | | 2045 |
SWEPCo | | Pollution Control Bonds | | 54 |
| | 1.60 | | 2019 |
SWEPCo | | Senior Unsecured Notes | | 400 |
| | 3.90 | | 2045 |
| | | | | | | | |
Non-Registrant: | | | | |
| | | | |
AEPTCo | | Senior Unsecured Notes | | 60 |
| | 4.01 | | 2030 |
AEPTCo | | Senior Unsecured Notes | | 50 |
| | 3.66 | | 2025 |
AEPTCo | | Senior Unsecured Notes | | 40 |
| | 3.76 | | 2025 |
AGR | | Other Long-term Debt | | 500 |
| | Variable | | 2017 |
KPCo | | Other Long-term Debt | | 25 |
| | Variable | | 2018 |
TCC | | Senior Unsecured Notes | | 250 |
| | 3.85 | | 2025 |
TNC | | Senior Unsecured Notes | | 50 |
| | 3.75 | | 2025 |
TNC | | Senior Unsecured Notes | | 25 |
| | 3.27 | | 2022 |
Transource Missouri | | Other Long-term Debt | | 20 |
| | Variable | | 2018 |
WPCo | | Senior Unsecured Notes | | 113 |
| | 3.36 | | 2022 |
WPCo | | Senior Unsecured Notes | | 122 |
| | 3.70 | | 2025 |
WPCo | | Senior Unsecured Notes | | 50 |
| | 4.20 | | 2035 |
Total Issuances | | | | $ | 2,956 |
| (a) | | | |
| |
(a) | Amount indicated on the statement of cash flows is net of issuance costs and premium or discount and will not tie to the issuance amount. |
|
| | | | | | | | | | |
Company | | Type of Debt | | Principal Amount Paid | | Interest Rate | | Due Date |
Total Retirements and Principal Payments: | | | | (in millions) | | (%) | | |
APCo | | Securitization Bonds | | $ | 23 |
| | 2.008 | | 2024 |
APCo | | Senior Unsecured Notes | | 350 |
| | 7.95 | | 2020 |
APCo | | Senior Unsecured Notes | | 300 |
| | 3.40 | | 2015 |
I&M | | Other Long-term Debt | | 94 |
| | Variable | | 2015 |
I&M | | Other Long-term Debt | | 1 |
| | 6.00 | | 2025 |
I&M | | Notes Payable | | 18 |
| | Variable | | 2016 |
I&M | | Notes Payable | | 21 |
| | Variable | | 2017 |
I&M | | Notes Payable | | 26 |
| | Variable | | 2019 |
I&M | | Notes Payable | | 16 |
| | Variable | | 2019 |
I&M | | Notes Payable | | 1 |
| | Variable | | 2016 |
I&M | | Notes Payable | | 1 |
| | 2.12 | | 2016 |
OPCo | | Pollution Control Bonds | | 86 |
| | 3.125 | | 2015 |
OPCo | | Securitization Bonds | | 45 |
| | 0.958 | | 2018 |
SWEPCo | | Notes Payable | | 3 |
| | 4.58 | | 2032 |
SWEPCo | | Pollution Control Bonds | | 54 |
| | 3.25 | | 2015 |
SWEPCo | | Senior Unsecured Notes | | 100 |
| | 5.375 | | 2015 |
SWEPCo | | Senior Unsecured Notes | | 150 |
| | 4.90 | | 2015 |
| | | | | | | | |
Non-Registrant: | | | | |
| | | | |
AEGCo | | Senior Unsecured Notes | | 7 |
| | 6.33 | | 2037 |
AEP Subsidiaries | | Notes Payable | | 5 |
| | Variable | | 2017 |
AEP Subsidiaries | | Notes Payable | | 1 |
| (a) | 7.59 | | 2026 |
AEP Subsidiaries | | Notes Payable | | 1 |
| (a) | 8.03 | | 2026 |
AGR | | Other Long-term Debt | | 500 |
| | Variable | | 2015 |
AGR | | Pollution Control Bonds | | 50 |
| | Variable | | 2015 |
AGR | | Pollution Control Bonds | | 39 |
| | Variable | | 2015 |
TCC | | Securitization Bonds | | 81 |
| | 5.09 | | 2015 |
TCC | | Securitization Bonds | | 76 |
| | 6.25 | | 2016 |
TCC | | Securitization Bonds | | 27 |
| | 0.88 | | 2017 |
TCC | | Securitization Bonds | | 57 |
| | 5.17 | | 2018 |
Total Retirements and Principal Payments | | | | $ | 2,133 |
| (a) | | | |
| |
(a) | Amount includes principal payments of debt related to AEPRO that has been classified as Discontinued Operations on the condensed statement of cash flows. |
In October 2015, KPCo drew the remaining $25 million on an existing $75 million variable rate credit facility due in 2018.
In October 2015, Transource Missouri drew $6 million on an existing $300 million variable rate credit facility due in 2018.
As of September 30, 2015, trustees held on our behalf, $475 million of our reacquired Pollution Control Bonds.
Dividend Restrictions
Parent Restrictions
The holders of our common stock are entitled to receive the dividends declared by our Board of Directors provided funds are legally available for such dividends. Our income primarily derives from our common stock equity in the earnings of our utility subsidiaries.
Pursuant to the leverage restrictions in our credit agreements, we must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. None of AEP’s retained earnings were restricted for the purpose of the payment of dividends.
Utility Subsidiaries’ Restrictions
Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends. Specifically, several of our public utility subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%.
The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings.
Short-term Debt
Our outstanding short-term debt was as follows:
|
| | | | | | | | | | | | | | |
| | September 30, 2015 | | December 31, 2014 |
Type of Debt | | Outstanding Amount | | Interest Rate (a) | | Outstanding Amount | | Interest Rate (a) |
| | (in millions) | | |
| | (in millions) | | |
|
Securitized Debt for Receivables (b) | | $ | 750 |
| | 0.28 | % | | $ | 744 |
| | 0.22 | % |
Commercial Paper | | 32 |
| | 0.44 | % | | 602 |
| | 0.59 | % |
Total Short-term Debt | | $ | 782 |
| | |
| | $ | 1,346 |
| | |
|
| |
(a) | Weighted average rate. |
| |
(b) | Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance. |
Credit Facilities
For an additional discussion of credit facilities, see “Letters of Credit” section of Note 5.
Securitized Accounts Receivable – AEP Credit
AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. AEP Credit continues to service the receivables. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables and accelerate AEP Credit’s cash collections.
Our receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2017.
Accounts receivable information for AEP Credit is as follows:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
| (dollars in millions) |
| |
| | |
| | |
| | |
|
Effective Interest Rates on Securitization of Accounts Receivable | 0.30 | % | | 0.21 | % | | 0.28 | % | | 0.22 | % |
Net Uncollectible Accounts Receivable Written Off | $ | 13 |
| | $ | 16 |
| | $ | 27 |
| | $ | 32 |
|
|
| | | | | | | |
| September 30, 2015 | | December 31, 2014 |
| (in millions) |
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts | $ | 970 |
| | $ | 975 |
|
Total Principal Outstanding | 750 |
| | 744 |
|
Delinquent Securitized Accounts Receivable | 50 |
| | 44 |
|
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable | 16 |
| | 13 |
|
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable | 277 |
| | 335 |
|
Customer accounts receivable retained and securitized for our operating companies are managed by AEP Credit. AEP Credit’s delinquent customer accounts receivable represents accounts greater than 30 days past due.
13. VARIABLE INTEREST ENTITIES
The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE’s variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. We believe that significant assumptions and judgments were applied consistently.
We are the primary beneficiary of Sabine, DCC Fuel, AEP Credit, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, a protected cell of EIS and Transource Energy. In addition, we have not provided material financial or other support to any of these entities that was not previously contractually required. We hold a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series).
Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended September 30, 2015 and 2014 were $41 million and $41 million, respectively, and for the nine months ended September 30, 2015 and 2014 were $124 million and $121 million, respectively. See the tables below for the classification of Sabine’s assets and liabilities on the condensed balance sheets.
I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended September 30, 2015 and 2014 were $29 million and $28 million, respectively, and for the nine months ended September 30, 2015 and 2014 were $86 million and $84 million, respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel’s assets and liabilities on the condensed balance sheets.
AEP Credit is a wholly-owned subsidiary of AEP. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings. Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on our control of AEP Credit, management concluded that we are the primary beneficiary and are required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the condensed balance sheets. See “Securitized Accounts Receivable – AEP Credit” section of Note 12.
Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The securitized bonds totaled $1.5 billion and $1.8 billion as of September 30, 2015 and December 31, 2014, respectively. Transition Funding has securitized transition assets of $1.4 billion and $1.6 billion as of September 30, 2015 and December 31, 2014, respectively. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to TCC or any other AEP entity. TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the condensed balance sheets.
Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $187 million and $232 million as of September 30, 2015 and December 31, 2014, respectively. Ohio Phase-in-Recovery Funding has securitized assets of $92 million and $110 million as of September 30, 2015 and December 31, 2014, respectively. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding's assets and liabilities on the condensed balance sheets.
Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $345 million and $368 million as of September 30, 2015 and December 31, 2014, respectively. Appalachian Consumer Rate Relief Funding has securitized assets of $333 million and $350 million as of September 30, 2015 and December 31, 2014, respectively. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Consumer Rate Relief Funding's assets and liabilities on the condensed balance sheets.
The securitized bonds of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets. The securitized assets of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in Securitized Assets on the condensed balance sheets.
Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on our control and the structure of the protected cell of EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate the protected cell of EIS. Our insurance premium expense to the protected cell for the three months ended September 30, 2015 and 2014 was $13 million and $16 million, respectively, and for the nine months ended September 30, 2015 and 2014 was $27 million and $33 million, respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the condensed balance sheets. The amount reported as equity is the protected cell’s policy holders’ surplus.
Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity. Therefore, AEP is required to consolidate Transource Energy. AEP’s equity interest could potentially be significant. In January 2014, Transource Missouri (a wholly-owned subsidiary of Transource Energy) acquired transmission assets from the non-controlling owner and issued debt and received a capital contribution to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, construction projects, debt issuance and capital contribution. AEP provided capital contributions to Transource Energy of $32 million and $23 million during the nine months ended September 30, 2015 and the year ended December 31, 2014, respectively. AEP and the other owner of Transource Energy are required to ensure a specific equity level in Transource Missouri upon completion of projects or if a project is abandoned by the RTO. See the tables below for the classification of Transource Energy’s assets and liabilities on the condensed balance sheets.
The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
September 30, 2015
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | SWEPCo Sabine | | I&M DCC Fuel | | AEP Credit | | TCC Transition Funding | | OPCo Ohio Phase-in- Recovery Funding | | | APCo Appalachian Consumer Rate Relief Funding | | Protected Cell of EIS | | Transource Energy |
ASSETS | | | | |
| | |
| | | | | | | | | |
| | |
Current Assets | | $ | 61 |
| | $ | 104 |
| | $ | 977 |
| | $ | 197 |
| | $ | 20 |
| | | $ | 11 |
| | $ | 163 |
| | $ | 12 |
|
Net Property, Plant and Equipment | | 144 |
| | 193 |
| | — |
| | — |
| | — |
| | | — |
| | — |
| | 184 |
|
Other Noncurrent Assets | | 60 |
| | 101 |
| | 1 |
| | 1,454 |
| (a) | 175 |
| (b) | | 341 |
| (c) | 3 |
| | 5 |
|
Total Assets | | $ | 265 |
| | $ | 398 |
| | $ | 978 |
| | $ | 1,651 |
| | $ | 195 |
| | | $ | 352 |
| | $ | 166 |
| | $ | 201 |
|
| | | | | | | | | | | | | | | | | |
LIABILITIES AND EQUITY | | |
| | |
| | |
| | |
| | |
| | | | | |
| | |
Current Liabilities | | $ | 40 |
| | $ | 98 |
| | $ | 875 |
| | $ | 283 |
| | $ | 47 |
| | | $ | 25 |
| | $ | 49 |
| | $ | 47 |
|
Noncurrent Liabilities | | 225 |
| | 300 |
| | 1 |
| | 1,350 |
| | 147 |
| | | 325 |
| | 76 |
| | 80 |
|
Equity | | — |
| | — |
| | 102 |
| | 18 |
| | 1 |
| | | 2 |
| | 41 |
| | 74 |
|
Total Liabilities and Equity | | $ | 265 |
| | $ | 398 |
| | $ | 978 |
| | $ | 1,651 |
| | $ | 195 |
| | | $ | 352 |
| | $ | 166 |
| | $ | 201 |
|
| |
(a) | Includes an intercompany item eliminated in consolidation of $70 million. |
| |
(b) | Includes an intercompany item eliminated in consolidation of $81 million. |
| |
(c) | Includes an intercompany item eliminated in consolidation of $4 million. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2014
(in millions)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | SWEPCo Sabine | | I&M DCC Fuel | | AEP Credit | | TCC Transition Funding | | OPCo Ohio Phase-in- Recovery Funding | | | APCo Appalachian Consumer Rate Relief Funding | | Protected Cell of EIS | | Transource Energy |
ASSETS | | | | |
| | |
| | | | | | | | | |
| | |
Current Assets | | $ | 68 |
| | $ | 97 |
| | $ | 980 |
| | $ | 239 |
| | $ | 33 |
| | | $ | 18 |
| | $ | 149 |
| | $ | 2 |
|
Net Property, Plant and Equipment | | 145 |
| | 158 |
| | — |
| | — |
| | — |
| | | — |
| | — |
| | 98 |
|
Other Noncurrent Assets | | 52 |
| | 80 |
| | — |
| | 1,654 |
| (a) | 210 |
| (b) | | 358 |
| (c) | 2 |
| | 4 |
|
Total Assets | | $ | 265 |
| | $ | 335 |
| | $ | 980 |
| | $ | 1,893 |
| | $ | 243 |
| | | $ | 376 |
| | $ | 151 |
| | $ | 104 |
|
| | | | | | | | | | | | | | | | | |
LIABILITIES AND EQUITY | | |
| | |
| | |
| | |
| | |
| | | | | |
| | |
Current Liabilities | | $ | 36 |
| | $ | 86 |
| | $ | 894 |
| | $ | 322 |
| | $ | 47 |
| | | $ | 27 |
| | $ | 44 |
| | $ | 21 |
|
Noncurrent Liabilities | | 228 |
| | 249 |
| | — |
| | 1,553 |
| | 195 |
| | | 347 |
| | 62 |
| | 55 |
|
Equity | | 1 |
| | — |
| | 86 |
| | 18 |
| | 1 |
| | | 2 |
| | 45 |
| | 28 |
|
Total Liabilities and Equity | | $ | 265 |
| | $ | 335 |
| | $ | 980 |
| | $ | 1,893 |
| | $ | 243 |
| | | $ | 376 |
| | $ | 151 |
| | $ | 104 |
|
| |
(a) | Includes an intercompany item eliminated in consolidation of $75 million. |
| |
(b) | Includes an intercompany item eliminated in consolidation of $97 million. |
| |
(c) | Includes an intercompany item eliminated in consolidation of $4 million. |
DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended September 30, 2015 and 2014 were $30 million and $24 million, respectively, and for the nine months ended September 30, 2015 and 2014 were $59 million and $31 million, respectively. We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC. Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets.
Our investment in DHLC was:
|
| | | | | | | | | | | | | | | |
| September 30, 2015 | | December 31, 2014 |
| As Reported on the Balance Sheet | | Maximum Exposure | | As Reported on the Balance Sheet | | Maximum Exposure |
| (in millions) |
Capital Contribution from SWEPCo | $ | 8 |
| | $ | 8 |
| | $ | 8 |
| | $ | 8 |
|
Retained Earnings | 6 |
| | 6 |
| | 4 |
| | 4 |
|
Advance Due to Parent | 40 |
| | 40 |
| | 56 |
| | 56 |
|
Guarantee of Debt | — |
| | 55 |
| | — |
| | 48 |
|
| | | | | | | |
Total Investment in DHLC | $ | 54 |
| | $ | 109 |
| | $ | 68 |
| | $ | 116 |
|
We and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH). PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region. PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned and controlled by a subsidiary of FirstEnergy. Provisions exist within the PATH-WV agreement that make it a VIE. We are not required to consolidate PATH-WV as we are not the primary beneficiary, although we hold a significant variable interest in PATH-WV. Our equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on our condensed balance sheets. We and FirstEnergy share the returns and losses equally in PATH-WV. Our subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements. The entities recover costs through regulated rates.
In August 2012, the PJM board cancelled the PATH Project, the transmission project that PATH was intended to develop, and removed it from the 2012 Regional Transmission Expansion Plan. In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project's abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case have been unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at FERC were held in March and April 2015. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, with recommendations on various issues in the case. The Initial Decision has no binding effect. Additional briefing is scheduled during the fourth quarter of 2015, after which the case will be pending before FERC.
Our investment in PATH-WV was:
|
| | | | | | | | | | | | | | | |
| September 30, 2015 | | December 31, 2014 |
| As Reported on the Balance Sheet | | Maximum Exposure | | As Reported on the Balance Sheet | | Maximum Exposure |
| (in millions) |
Capital Contribution from AEP | $ | 19 |
| | $ | 19 |
| | $ | 19 |
| | $ | 19 |
|
Retained Earnings | 2 |
| | 2 |
| | 2 |
| | 2 |
|
| | | | | | | |
Total Investment in PATH-WV | $ | 21 |
| | $ | 21 |
| | $ | 21 |
| | $ | 21 |
|
As of September 30, 2015, our $21 million investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheet. We believe the financial statements adequately address the impact of the Initial Decision. If we cannot ultimately recover our investment related to PATH-WV, it could reduce future net income and cash flows.
14. PROPERTY, PLANT AND EQUIPMENT
Asset Retirement Obligations (ARO)
We record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for our legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities, as well as for nuclear decommissioning of our Cook Plant. We have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which we have assets. Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property’s use. We do not estimate the retirement for such easements because we plan to use our facilities indefinitely. The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements, which is not expected.
We recorded an increase in our asset retirement obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the aggregate carrying amount of ARO, including a $95 million second quarter increase and other adjustments recorded in the third quarter:
|
| | | |
| Carrying Amount of ARO |
| (in millions) |
ARO as of December 31, 2014 | $ | 2,019 |
|
Accretion Expense | 76 |
|
Liabilities Incurred | 48 |
|
Liabilities Settled (a) | (126 | ) |
Revisions in Cash Flow Estimates (b) | 30 |
|
ARO as of September 30, 2015 | $ | 2,047 |
|
| |
(a) | Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the "Muskingum River Plant" section of Note 6. |
| |
(b) | Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. |
As of September 30, 2015 and December 31, 2014, our ARO liability included $1.31 billion and $1.27 billion, respectively, for nuclear decommissioning of the Cook Plant. As of September 30, 2015 and December 31, 2014, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $1.74 billion and $1.79 billion, respectively, and are recorded in Spent Nuclear Fuel and Decommissioning Trusts on the condensed balance sheets.
15. DISPOSITION PLANT SEVERANCE
AEP retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits.
The disposition plant severance activity for the nine months ended September 30, 2015 is described in the following table:
|
| | | | |
| | Disposition Plant Severance Activity |
| | (in millions) |
Balance as of December 31, 2014 | | $ | 29 |
|
Incurred | | 3 |
|
Settled | | (21 | ) |
Adjustments | | — |
|
Balance as of September 30, 2015 | | $ | 11 |
|
We recorded a charge of $29 million to Other Operation expense in 2014 primarily related to employees at the disposition plants. These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. Of the cumulative expense, approximately 32% was within the Generation & Marketing segment and 68% was within the Vertically Integrated Utilities segment. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. We incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. We do not expect additional severance costs to be incurred related to this initiative.
APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
EXECUTIVE OVERVIEW
Regulatory Activity
2015 Virginia Regulatory Asset Proceeding
In January 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets. In February and March 2015, briefs related to this proceeding were filed by various parties. As of September 30, 2015, APCo’s authorized regulatory assets under review in this proceeding were $11 million. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition.
New Virginia Legislation Affecting Biennial Reviews
In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA.
West Virginia Inquiry into Plant Closures
Subsequent to APCo’s retirement of the Kanawha River Plant in May 2015, the WVPSC issued an order in July 2015 that requested APCo to maintain, for at least four years, any infrastructure installed at the Kanawha River Plant that would be used if the plant were to be converted to burn natural gas. The WVPSC stated that it would not be reasonable and prudent to completely demolish facilities that might be available in the future for conversion to natural gas before further consideration is given to the future of APCo’s coal fired generation. The order indicated that the WVPSC would consider prudently incurred operating fees related to Kanawha River and Sporn Plants for recovery in a future case. In October 2015, APCo filed an application with the WVPSC to request that it be relieved of any obligation to study further the future viability of the Sporn Plant and Glen Lyn Plant units and of any obligation to maintain these units. Additionally, APCo plans to consider the Kanawha River Plant units in its preparation of an integrated resource plan to be filed with the WVPSC by December 31, 2015.
Litigation and Environmental Issues
In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in the 2014 Annual Report. Also, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 179. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.
See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 256 for additional discussion of relevant factors.
RESULTS OF OPERATIONS
KWh Sales/Degree Days
Summary of KWh Energy Sales
| | | Three Months Ended | | Nine Months Ended | Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, | September 30, | | September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in millions of KWhs) | (in millions of KWhs) |
Retail: | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
Residential | 2,599 |
| | 2,503 |
| | 9,039 |
| | 9,131 |
| 2,845 |
| | 2,599 |
| | 8,743 |
| | 9,039 |
|
Commercial | 1,744 |
| | 1,726 |
| | 5,161 |
| | 5,150 |
| 1,823 |
| | 1,744 |
| | 5,125 |
| | 5,161 |
|
Industrial | 2,493 |
| | 2,600 |
| | 7,520 |
| | 7,665 |
| 2,391 |
| | 2,493 |
| | 7,022 |
| | 7,520 |
|
Miscellaneous | 205 |
| | 205 |
| | 633 |
| | 636 |
| 217 |
| | 205 |
| | 637 |
| | 633 |
|
Total Retail | 7,041 |
| | 7,034 |
| | 22,353 |
| | 22,582 |
| 7,276 |
| | 7,041 |
| | 21,527 |
| | 22,353 |
|
| | | | | | | | | | | | | | |
Wholesale | 681 |
| | 563 |
| | 2,335 |
| | 2,507 |
| 1,029 |
| | 681 |
| | 2,413 |
| | 2,335 |
|
| | | | | | | | | | | | | | |
Total KWhs | 7,722 |
| | 7,597 |
| | 24,688 |
| | 25,089 |
| 8,305 |
| | 7,722 |
| | 23,940 |
| | 24,688 |
|
Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.
Summary of Heating and Cooling Degree Days
| | | Three Months Ended | | Nine Months Ended | Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, | September 30, | | September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in degree days) | (in degree days) |
Actual - Heating (a) | — |
| | — |
| | 1,735 |
| | 1,776 |
| — |
| | — |
| | 1,433 |
| | 1,735 |
|
Normal - Heating (b) | 3 |
| | 2 |
| | 1,415 |
| | 1,405 |
| 2 |
| | 3 |
| | 1,437 |
| | 1,415 |
|
| | | | | | | | | | | | | | |
Actual - Cooling (c) | 804 |
| | 639 |
| | 1,275 |
| | 1,041 |
| 1,049 |
| | 804 |
| | 1,437 |
| | 1,275 |
|
Normal - Cooling (b) | 809 |
| | 816 |
| | 1,175 |
| | 1,183 |
| 808 |
| | 809 |
| | 1,177 |
| | 1,175 |
|
| |
(a) | Eastern Region heatingHeating degree days are calculated on a 55 degree temperature base. |
| |
(b) | Normal Heating/Cooling represents the thirty-year average of degree days. |
| |
(c) | Eastern Region coolingCooling degree days are calculated on a 65 degree temperature base. |
Third Quarter of 20152016 Compared to Third Quarter of 20142015
| | Reconciliation of Third Quarter of 2014 to Third Quarter of 2015 | |
Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 | | Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 |
Net Income | (in millions) | | Third Quarter of 2014 | | $ | 49 |
| |
Third Quarter of 2015 | | | $ | 74.6 |
|
| | |
| | |
|
Changes in Gross Margin: | | |
| | |
|
Retail Margins | | 35 |
| | 54.4 |
|
Off-system Sales | | (1 | ) | | 1.5 |
|
Transmission Revenues | | (8 | ) | | 2.6 |
|
Other Revenues | | 2 |
| | 1.9 |
|
Total Change in Gross Margin | | 28 |
| | 60.4 |
|
| | |
| | |
|
Changes in Expenses and Other: | | |
| | |
|
Other Operation and Maintenance | | (4 | ) | | (12.1 | ) |
Depreciation and Amortization | | 4 |
| | (1.8 | ) |
Carrying Costs Income | | | (0.1 | ) |
Allowance for Equity Funds Used During Construction | | 1 |
| | 1.1 |
|
Interest Expense | | 6 |
| | 0.2 |
|
Total Change in Expenses and Other | | 7 |
| | (12.7 | ) |
| | |
| | |
|
Income Tax Expense | | (9 | ) | | (18.2 | ) |
| | |
| | |
|
Third Quarter of 2015 | | $ | 75 |
| |
Third Quarter of 2016 | | | $ | 104.1 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
Retail Margins increased $35$54 million primarily due to the following:
A $32$34 million increase primarily due to increases in rates in West Virginia offset by decreases in rates in Virginia and formula rates in both jurisdictions.Virginia. Of these changes, $4rate increases, $27 million relates to riders/trackers which have corresponding increases in other expense items below.
A $14$24 million increase in weather-related usage primarily due to a 26%30% increase in cooling degree days.
These increases were partially offset by:
A $12An $8 million decrease in weather-normalized margin primarily due to lower industrial usage.
Transmission Revenues decreased $8 million primarily due to lower Network Integrated Transmission Service (NITS) revenues. These NITS revenues are partially offset in Other Operation and Maintenance expenses below.
all retail classes.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $4$12 million primarily due to the following:
A $14$17 million increase in distribution expenses primarily related to implementation of a surcharge to recover West Virginia vegetation management expenses effective June 2015 and increasedassociated with amortization of West Virginia storm costs.
A $3 million increase in generation operation expenses primarily related to amortizations of West Virginia Carbon Capture storage and IGCC and decommissioning expenses at disposition plants. This increase was partially offset in Gross Margin above.
A $2 million increase in customer accounts expenses related to customer assistance and uncollectible accounts.
These increases were partially offset by:
A $7 million decrease in steam and electric plant maintenance expenses primarily at the Amos and Mountaineer Plants.
A $6 million decrease associated with the under recovery ofdeferred transmission costs in accordance with the Virginia Transmission Rate Adjustment Clause as allowed by the Virginia SCC.effective January 2016. This increase in expense is offset within Retail Margins above.
A $7 million increase in PJM transmission expenses. This increase in expense is offset within Retail Margins above.
These increases were partially offset by:
A $6 million decrease in employee-related expenses.
A $2 million decrease in PJMstorm-related expenses.
A $2 million decrease in distribution expenses primarily related to NITS. This decrease is partially offset by a corresponding decrease in Gross Margin above.
Depreciation and Amortization expenses decreased $4 million due to prior year amortization of Virginia environmental deferrals, which ended in the first quarter of 2015.
Interest Expense decreased $6 million primarily due to the following:
A $4 million decrease due to lower interest rates on long-term debt.vegetation pilot program.
Income Tax Expenseincreased $9$18 million primarily due to an increase in pretax book income, partially offset by the recording of federal and state income tax adjustments.income.
Nine Months Ended September 30, 20152016 Compared to Nine Months Ended September 30, 20142015
| | Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015 | |
Reconciliation of Nine Months Ended September 30, 2015 to Nine Months Ended September 30, 2016 | | Reconciliation of Nine Months Ended September 30, 2015 to Nine Months Ended September 30, 2016 |
Net Income
| Net Income
| Net Income |
(in millions)
| (in millions)
| (in millions) |
| Nine Months Ended September 30, 2014 | | $ | 187 |
| |
Nine Months Ended September 30, 2015 | | | $ | 275.4 |
|
| | |
| | |
|
Changes in Gross Margin: | | |
| | |
|
Retail Margins | | 116 |
| | 93.0 |
|
Off-system Sales | | (3 | ) | |
Transmission Revenues | | (6 | ) | | (14.1 | ) |
Other Revenues | | 2 |
| | 3.5 |
|
Total Change in Gross Margin | | 109 |
| | 82.4 |
|
| | |
| | |
|
Changes in Expenses and Other: | | |
| | |
|
Other Operation and Maintenance | | — |
| | (54.3 | ) |
Depreciation and Amortization | | 7 |
| | 2.7 |
|
Taxes Other Than Income Taxes | | (1 | ) | | (0.8 | ) |
Interest Income | | | (0.4 | ) |
Carrying Costs Income | | 2 |
| | (0.6 | ) |
Allowance for Equity Funds Used During Construction | | 6 |
| | (1.2 | ) |
Interest Expense | | 12 |
| | 4.9 |
|
Total Change in Expenses and Other | | 26 |
| | (49.7 | ) |
| | |
| | |
|
Income Tax Expense | | (47 | ) | | (4.3 | ) |
| | |
| | |
|
Nine Months Ended September 30, 2015 | | $ | 275 |
| |
Nine Months Ended September 30, 2016 | | | $ | 303.8 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
Retail Margins increased $116$93 million primarily due to the following:
A $93$111 million increase primarily due to increases in rates in West Virginia and Virginia, which includes recognition of deferred billing in West Virginia as well as anapproved by the WVPSC in June 2016. This increase is partially offset by a prior year adjustment due toaffected by the amended Virginia law impactingthat has an impact on biennial reviews. Of these rate increases, $13$81 million relate to riders/trackers which have corresponding increases in other expense items below.
An $18This increase was partially offset by:
A $20 million increasedecrease in weather-normalized margin primarily in the industrial class.
A $10 million decrease in weather-related usage primarily due to a 23%17% decrease in heating degree days offset with a 13% increase in cooling degree days.
A $10 million decrease in generation related PJM expenses due to the polar vortex in 2014 net of recovery or offsets.
A $7 million decrease in fuel expense from wholesale customers due to the timing of fuel recovery in 2014.
A $3 million decrease in consumables and allowances expense.
These increases were partially offset by:
A $32 million decrease in weather-normalized margin primarily due to lower usage.
Transmission Revenues decreased $6$14 million primarily due to lower NITSNetwork Integrated Transmission Service revenues.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses were approximately unchanged primarily due to the following:
A $21 million increase in PJM expenses primarily related to NITS.
This increase was partially offset by:
A $21 million decrease in plant maintenance expenses primarily at Amos Plant.
Depreciation and Amortization expenses decreased $7increased $54 million primarily due to the following:
A $9$41 million increase associated with amortization of deferred transmission costs in accordance with the Virginia Transmission Rate Adjustment Clause effective January 2016. This increase in expense is offset within Retail Margins above.
An $8 million increase in distribution expenses primarily due to vegetation management. This increase in expense is offset within Retail Margins above.
A $5 million increase in amortization of previously deferred West Virginia storm expenses as approved in the May 2015 West Virginia base case order. This increase in expense is offset within Retail Margins above.
A $4 million increase in storm-related expenses.
These increases were partially offset by:
A $6 million gain on the sale of property in the current year.
Depreciation and Amortization expenses decreased $3 million primarily due to the following:
A $7 million decrease in asset retirement obligations and plant amortizations due to prior year amortization of Virginia environmental deferrals, which endedplant retirements in the first quarter of 2015.
A $2 million decrease due to prior year amortization of West Virginia ENECenvironmental deferrals. This decrease in expense is offset within Retail Margins above.
These decreases were partially offset by:
A $4$6 million increase due to a higher depreciable base.
Carrying Cost Income increased $2 million related to West Virginia ENEC deferrals.
Allowance for Equity Funds Used During Construction increased $6 million primarily due to increased transmission projects.
Interest Expense decreased $12$5 million primarily due to the following:
A $5 million decrease due to lower interest rates on long-term debt.
A $3 million decrease due to higher debt component of AFUDC from increased transmission projects.
A $2 million decrease due to a 2014 amortization of loss on reacquired long-term debt.
Income Tax Expense increased $47$4 million primarily due to an increase in pretax book income.income and by the recording of federal income tax adjustments, partially offset by other book/tax differences which are accounted for on a flow-through basis and the regulatory accounting treatment of state income taxes.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2014 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.
See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 256 for a discussion of accounting pronouncements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
REVENUES | | | | | | | | |
| | | | | | | | |
|
Electric Generation, Transmission and Distribution | | $ | 685,312 |
| | $ | 672,459 |
| | $ | 2,184,943 |
| | $ | 2,202,967 |
| | $ | 739.0 |
| | $ | 685.3 |
| | $ | 2,153.3 |
| | $ | 2,184.9 |
|
Sales to AEP Affiliates | | 39,389 |
| | 35,455 |
| | 115,740 |
| | 108,439 |
| | 36.4 |
| | 39.3 |
| | 109.0 |
| | 115.7 |
|
Other Revenues | | 2,857 |
| | 1,970 |
| | 7,870 |
| | 6,537 |
| | 2.8 |
| | 2.9 |
| | 9.4 |
| | 7.9 |
|
TOTAL REVENUES | | 727,558 |
| | 709,884 |
| | 2,308,553 |
| | 2,317,943 |
| | 778.2 |
| | 727.5 |
| | 2,271.7 |
| | 2,308.5 |
|
| | | | | | | | | | | | | | | | |
EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Fuel and Other Consumables Used for Electric Generation | | 188,576 |
| | 194,303 |
| | 595,308 |
| | 627,943 |
| | 190.1 |
| | 188.5 |
| | 494.1 |
| | 595.3 |
|
Purchased Electricity for Resale | | 80,452 |
| | 85,656 |
| | 258,836 |
| | 340,680 |
| | 69.2 |
| | 80.5 |
| | 240.9 |
| | 258.9 |
|
Purchased Electricity from AEP Affiliates | | — |
| | — |
| | — |
| | 4,662 |
| |
Other Operation | | 101,841 |
| | 103,835 |
| | 311,631 |
| | 297,269 |
| | 117.6 |
| | 101.8 |
| | 349.4 |
| | 311.6 |
|
Maintenance | | 70,459 |
| | 64,333 |
| | 179,793 |
| | 193,907 |
| | 66.8 |
| | 70.5 |
| | 196.3 |
| | 179.8 |
|
Depreciation and Amortization | | 96,295 |
| | 99,889 |
| | 292,735 |
| | 300,125 |
| | 98.1 |
| | 96.3 |
| | 290.0 |
| | 292.7 |
|
Taxes Other Than Income Taxes | | 32,002 |
| | 31,632 |
| | 93,089 |
| | 92,434 |
| | 32.0 |
| | 32.0 |
| | 93.9 |
| | 93.1 |
|
TOTAL EXPENSES | | 569,625 |
| | 579,648 |
| | 1,731,392 |
| | 1,857,020 |
| | 573.8 |
| | 569.6 |
| | 1,664.6 |
| | 1,731.4 |
|
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | 157,933 |
| | 130,236 |
| | 577,161 |
| | 460,923 |
| | 204.4 |
| | 157.9 |
| | 607.1 |
| | 577.1 |
|
| | | | | | | | | | | | | | | | |
Other Income (Expense): | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Interest Income | | 290 |
| | 521 |
| | 1,128 |
| | 1,311 |
| | 0.3 |
| | 0.3 |
| | 0.8 |
| | 1.2 |
|
Carrying Costs Income (Expense) | | 73 |
| | 482 |
| | 783 |
| | (1,130 | ) | |
Carrying Costs Income | | | — |
| | 0.1 |
| | 0.2 |
| | 0.8 |
|
Allowance for Equity Funds Used During Construction | | 3,432 |
| | 1,665 |
| | 10,337 |
| | 4,525 |
| | 4.5 |
| | 3.4 |
| | 9.1 |
| | 10.3 |
|
Interest Expense | | (46,625 | ) | | (52,738 | ) | | (145,600 | ) | | (157,540 | ) | | (46.4 | ) | | (46.6 | ) | | (140.7 | ) | | (145.6 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | 115,103 |
| | 80,166 |
| | 443,809 |
| | 308,089 |
| | 162.8 |
| | 115.1 |
| | 476.5 |
| | 443.8 |
|
| | | | | | | | | | | | | | | | |
Income Tax Expense | | 40,507 |
| | 31,408 |
| | 168,368 |
| | 121,233 |
| | 58.7 |
| | 40.5 |
| | 172.7 |
| | 168.4 |
|
| | | | | | | | | | | | | | | | |
NET INCOME | | $ | 74,596 |
| | $ | 48,758 |
| | $ | 275,441 |
| | $ | 186,856 |
| | $ | 104.1 |
| | $ | 74.6 |
| | $ | 303.8 |
| | $ | 275.4 |
|
|
| | | | |
The common stock of APCo is wholly-owned by AEP.Parent. | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
Net Income | | $ | 74,596 |
| | $ | 48,758 |
| | $ | 275,441 |
| | $ | 186,856 |
| | $ | 104.1 |
| | $ | 74.6 |
| | $ | 303.8 |
| | $ | 275.4 |
|
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | |
| | |
| | |
| | |
| |
Cash Flow Hedges, Net of Tax of $120 and $92 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $49 and $314 for the Nine Months Ended September 30, 2015 and 2014, Respectively | | (222 | ) | | 170 |
| | (91 | ) | | 582 |
| |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $247 and $179 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $740 and $538 for the Nine Months Ended September 30, 2015 and 2014, Respectively | | (458 | ) | | (333 | ) | | (1,374 | ) | | (999 | ) | |
OTHER COMPREHENSIVE LOSS, NET OF TAXES | | | |
| | |
| | |
| | |
|
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2016 and 2015, Respectively, and $(0.3) and $0 for the Nine Months Ended September 30, 2016 and 2015, Respectively | | | (0.2 | ) | | (0.2 | ) | | (0.6 | ) | | (0.1 | ) |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.2) for the Three Months Ended September 30, 2016 and 2015, Respectively, and $(0.5) and $(0.7) for the Nine Months Ended September 30, 2016 and 2015, Respectively | | | (0.3 | ) | | (0.5 | ) | | (1.0 | ) | | (1.4 | ) |
| | | | | | | | | | | | | | | | |
TOTAL OTHER COMPREHENSIVE LOSS | | (680 | ) | | (163 | ) | | (1,465 | ) | | (417 | ) | | (0.5 | ) | | (0.7 | ) | | (1.6 | ) | | (1.5 | ) |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 73,916 |
| | $ | 48,595 |
| | $ | 273,976 |
| | $ | 186,439 |
| | $ | 103.6 |
| | $ | 73.9 |
| | $ | 302.2 |
| | $ | 273.9 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'SSHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2013 | | $ | 260,458 |
| | $ | 1,809,562 |
| | $ | 1,156,461 |
| | $ | 2,951 |
| | $ | 3,229,432 |
| |
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2014 | | | $ | 260.4 |
| | $ | 1,809.6 |
| | $ | 1,291.9 |
| | $ | 5.0 |
| | $ | 3,366.9 |
|
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | |
| | |
| | (60,000 | ) | | |
| | (60,000 | ) | | |
| | |
| | (181.3 | ) | | |
| | (181.3 | ) |
Net Income | | |
| | |
| | 186,856 |
| | |
| | 186,856 |
| | |
| | |
| | 275.4 |
| | |
| | 275.4 |
|
Other Comprehensive Loss | | |
| | |
| | |
| | (417 | ) | | (417 | ) | | |
| | |
| | |
| | (1.5 | ) | | (1.5 | ) |
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2014 | | $ | 260,458 |
| | $ | 1,809,562 |
| | $ | 1,283,317 |
| | $ | 2,534 |
| | $ | 3,355,871 |
| |
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2015 | | | $ | 260.4 |
| | $ | 1,809.6 |
| | $ | 1,386.0 |
| | $ | 3.5 |
| | $ | 3,459.5 |
|
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2014 | | $ | 260,458 |
| | $ | 1,809,562 |
| | $ | 1,291,876 |
| | $ | 5,032 |
| | $ | 3,366,928 |
| |
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2015 | | | $ | 260.4 |
| | $ | 1,828.7 |
| | $ | 1,388.7 |
| | $ | (2.8 | ) | | $ | 3,475.0 |
|
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | |
| | |
| | (181,250 | ) | | |
| | (181,250 | ) | | |
| | |
| | (225.0 | ) | | |
| | (225.0 | ) |
Net Income | | |
| | |
| | 275,441 |
| | |
| | 275,441 |
| | |
| | |
| | 303.8 |
| | |
| | 303.8 |
|
Other Comprehensive Loss | | |
| | |
| | |
| | (1,465 | ) | | (1,465 | ) | | |
| | |
| | |
| | (1.6 | ) | | (1.6 | ) |
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2015 | | $ | 260,458 |
| | $ | 1,809,562 |
| | $ | 1,386,067 |
| | $ | 3,567 |
| | $ | 3,459,654 |
| |
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2016 | | | $ | 260.4 |
| | $ | 1,828.7 |
| | $ | 1,467.5 |
| | $ | (4.4 | ) | | $ | 3,552.2 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20152016 and December 31, 20142015
(in thousands)millions)
(Unaudited)
| | | | September 30, | | December 31, | | September 30, | | December 31, |
| | 2015 | | 2014 | | 2016 | | 2015 |
CURRENT ASSETS | | | | | | | | |
Cash and Cash Equivalents | | $ | 2,411 |
| | $ | 2,613 |
| | $ | 3.3 |
| | $ | 2.8 |
|
Restricted Cash for Securitized Funding | | 7,436 |
| | 15,599 |
| | 7.8 |
| | 14.8 |
|
Advances to Affiliates | | 23,535 |
| | 48,519 |
| | 24.4 |
| | 25.6 |
|
Accounts Receivable: | | | | | | | | |
Customers | | 118,331 |
| | 114,711 |
| | 115.4 |
| | 120.9 |
|
Affiliated Companies | | 56,687 |
| | 67,294 |
| | 54.3 |
| | 51.2 |
|
Accrued Unbilled Revenues | | 36,629 |
| | 58,022 |
| | 42.3 |
| | 17.9 |
|
Miscellaneous | | 3,180 |
| | 1,956 |
| | 1.1 |
| | 2.2 |
|
Allowance for Uncollectible Accounts | | (3,961 | ) | | (2,364 | ) | | (4.7 | ) | | (4.3 | ) |
Total Accounts Receivable | | 210,866 |
| | 239,619 |
| | 208.4 |
| | 187.9 |
|
Fuel | | 77,785 |
| | 113,386 |
| | 124.8 |
| | 119.3 |
|
Materials and Supplies | | 126,941 |
| | 131,285 |
| | 100.0 |
| | 127.0 |
|
Risk Management Assets – Nonaffiliated | | 25,970 |
| | 23,792 |
| | 3.2 |
| | 14.7 |
|
Risk Management Assets – Affiliated | | 1,380 |
| | — |
| | — |
| | 0.9 |
|
Deferred Income Tax Benefits | | — |
| | 23,955 |
| |
Accrued Tax Benefits | | | 16.0 |
| | 30.6 |
|
Regulatory Asset for Under-Recovered Fuel Costs | | 69,013 |
| | 66,076 |
| | 71.6 |
| | 86.9 |
|
Prepayments and Other Current Assets | | 27,673 |
| | 13,660 |
| | 17.4 |
| | 17.4 |
|
TOTAL CURRENT ASSETS | | 573,010 |
| | 678,504 |
| | 576.9 |
| | 627.9 |
|
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | 6,174,000 |
| | 6,824,029 |
| | 6,319.5 |
| | 6,200.8 |
|
Transmission | | 2,271,351 |
| | 2,228,029 |
| | 2,555.3 |
| | 2,408.1 |
|
Distribution | | 3,351,264 |
| | 3,258,306 |
| | 3,519.2 |
| | 3,402.5 |
|
Other Property, Plant and Equipment | | 390,180 |
| | 373,520 |
| | 368.7 |
| | 345.5 |
|
Construction Work in Progress | | 535,112 |
| | 321,495 |
| | 481.9 |
| | 475.1 |
|
Total Property, Plant and Equipment | | 12,721,907 |
| | 13,005,379 |
| | 13,244.6 |
| | 12,832.0 |
|
Accumulated Depreciation and Amortization | | 3,426,961 |
| | 3,823,664 |
| | 3,598.1 |
| | 3,407.6 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 9,294,946 |
| | 9,181,715 |
| | 9,646.5 |
| | 9,424.4 |
|
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | 1,061,715 |
| | 857,872 |
| | 1,123.0 |
| | 1,154.2 |
|
Securitized Assets | | 333,491 |
| | 350,170 |
| | 311.0 |
| | 328.0 |
|
Long-term Risk Management Assets – Nonaffiliated | | 2,035 |
| | 4,891 |
| | 0.2 |
| | 0.1 |
|
Deferred Charges and Other Noncurrent Assets | | 141,012 |
| | 159,230 |
| | 110.7 |
| | 113.7 |
|
TOTAL OTHER NONCURRENT ASSETS | | 1,538,253 |
| | 1,372,163 |
| | 1,544.9 |
| | 1,596.0 |
|
| | | | | | | | |
TOTAL ASSETS | | $ | 11,406,209 |
| | $ | 11,232,382 |
| | $ | 11,768.3 |
| | $ | 11,648.3 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'SSHAREHOLDER’S EQUITY
September 30, 20152016 and December 31, 20142015
(Unaudited)
| | | | September 30, | | December 31, | | September 30, | | December 31, |
| | 2015 | | 2014 | | 2016 | | 2015 |
| | (in thousands) | | (in millions) |
CURRENT LIABILITIES | | | | | | | | |
Advances from Affiliates | | $ | 35,224 |
| | $ | — |
| | $ | 84.1 |
| | $ | 181.0 |
|
Accounts Payable: | | |
| | |
| | |
| | |
|
General | | 186,317 |
| | 166,821 |
| | 174.1 |
| | 196.5 |
|
Affiliated Companies | | 74,006 |
| | 80,602 |
| | 74.8 |
| | 67.7 |
|
Long-term Debt Due Within One Year – Nonaffiliated | | 318,020 |
| | 552,212 |
| | 503.1 |
| | 318.0 |
|
Long-term Debt Due Within One Year – Affiliated | | — |
| | 86,000 |
| |
Risk Management Liabilities – Nonaffiliated | | 6,902 |
| | 11,017 |
| | 10.7 |
| | 4.8 |
|
Customer Deposits | | 79,237 |
| | 71,766 |
| | 81.8 |
| | 83.9 |
|
Accrued Taxes | | 45,938 |
| | 109,482 |
| | 51.8 |
| | 79.5 |
|
Accrued Interest | | 63,837 |
| | 52,141 |
| | 63.3 |
| | 40.6 |
|
Other Current Liabilities | | 182,191 |
| | 145,017 |
| | 127.1 |
| | 153.4 |
|
TOTAL CURRENT LIABILITIES | | 991,672 |
| | 1,275,058 |
| | 1,170.8 |
| | 1,125.4 |
|
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | 3,637,275 |
| | 3,342,062 |
| | 3,530.0 |
| | 3,612.7 |
|
Long-term Risk Management Liabilities – Nonaffiliated | | 973 |
| | 2,057 |
| | 0.3 |
| | 0.1 |
|
Deferred Income Taxes | | 2,410,754 |
| | 2,288,842 |
| | 2,632.9 |
| | 2,527.0 |
|
Regulatory Liabilities and Deferred Investment Tax Credits | | 646,262 |
| | 652,867 |
| | 628.8 |
| | 637.1 |
|
Asset Retirement Obligations | | 110,474 |
| | 122,300 |
| | 91.2 |
| | 98.9 |
|
Employee Benefits and Pension Obligations | | 119,986 |
| | 127,980 |
| | 103.0 |
| | 114.4 |
|
Deferred Credits and Other Noncurrent Liabilities | | 29,159 |
| | 54,288 |
| | 59.1 |
| | 57.7 |
|
TOTAL NONCURRENT LIABILITIES | | 6,954,883 |
| | 6,590,396 |
| | 7,045.3 |
| | 7,047.9 |
|
| | | | | | | | |
TOTAL LIABILITIES | | 7,946,555 |
| | 7,865,454 |
| | 8,216.1 |
| | 8,173.3 |
|
| | | | | | | | |
Rate Matters (Note 4) | |
| |
| |
| |
|
Commitments and Contingencies (Note 5) | |
| |
| |
| |
|
| | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | |
Common Stock – No Par Value: | | | | | | | | |
Authorized – 30,000,000 Shares | | |
| | | | |
| | |
Outstanding – 13,499,500 Shares | | 260,458 |
| | 260,458 |
| | 260.4 |
| | 260.4 |
|
Paid-in Capital | | 1,809,562 |
| | 1,809,562 |
| | 1,828.7 |
| | 1,828.7 |
|
Retained Earnings | | 1,386,067 |
| | 1,291,876 |
| | 1,467.5 |
| | 1,388.7 |
|
Accumulated Other Comprehensive Income (Loss) | | 3,567 |
| | 5,032 |
| | (4.4 | ) | | (2.8 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | 3,459,654 |
| | 3,366,928 |
| | 3,552.2 |
| | 3,475.0 |
|
| | | | | | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY | | $ | 11,406,209 |
| | $ | 11,232,382 |
| |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | | $ | 11,768.3 |
| | $ | 11,648.3 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2016 | | 2015 |
OPERATING ACTIVITIES | | |
| | |
| | |
| | |
|
Net Income | | $ | 275,441 |
| | $ | 186,856 |
| | $ | 303.8 |
| | $ | 275.4 |
|
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
| | |
| | |
| | |
|
Depreciation and Amortization | | 292,735 |
| | 300,125 |
| | 290.0 |
| | 292.7 |
|
Deferred Income Taxes | | 179,143 |
| | 114,778 |
| | 100.9 |
| | 179.1 |
|
Carrying Costs Income (Expense) | | (783 | ) | | 1,130 |
| |
Carrying Costs Income | | | (0.2 | ) | | (0.8 | ) |
Allowance for Equity Funds Used During Construction | | (10,337 | ) | | (4,525 | ) | | (9.1 | ) | | (10.3 | ) |
Mark-to-Market of Risk Management Contracts | | (5,902 | ) | | 255 |
| | 18.4 |
| | (5.9 | ) |
Pension Contributions to Qualified Plan Trust | | (9,981 | ) | | (8,963 | ) | | (8.8 | ) | | (10.0 | ) |
Property Taxes | | 27,980 |
| | 25,856 |
| | 29.2 |
| | 28.0 |
|
Fuel Over/Under-Recovery, Net | | (1,729 | ) | | (114,022 | ) | |
Deferred Fuel Over/Under-Recovery, Net | | | 19.0 |
| | (1.7 | ) |
Change in Other Noncurrent Assets | | (32,481 | ) | | (19,178 | ) | | (5.1 | ) | | (33.2 | ) |
Change in Other Noncurrent Liabilities | | (27,399 | ) | | 29,312 |
| | (23.0 | ) | | (26.7 | ) |
Changes in Certain Components of Working Capital: | | |
| | |
| | |
| | |
|
Accounts Receivable, Net | | 28,753 |
| | 114,387 |
| | (20.5 | ) | | 28.8 |
|
Fuel, Materials and Supplies | | 31,352 |
| | 78,977 |
| | (1.2 | ) | | 31.4 |
|
Accounts Payable | | 2,678 |
| | (65,358 | ) | | 4.9 |
| | 2.7 |
|
Accrued Taxes, Net | | (75,290 | ) | | (43,092 | ) | | (13.9 | ) | | (75.3 | ) |
Other Current Assets | | (2,628 | ) | | (3,748 | ) | | (0.2 | ) | | (2.6 | ) |
Other Current Liabilities | | 15,411 |
| | 9,085 |
| | (4.1 | ) | | 15.4 |
|
Net Cash Flows from Operating Activities | | 686,963 |
| | 601,875 |
| | 680.1 |
| | 687.0 |
|
| | | | | | | | |
INVESTING ACTIVITIES | | |
| | |
| | |
| | |
|
Construction Expenditures | | (456,721 | ) | | (342,291 | ) | | (472.7 | ) | | (456.7 | ) |
Change in Restricted Cash for Securitized Funding | | | 7.0 |
| | 8.2 |
|
Change in Advances to Affiliates, Net | | 24,984 |
| | 22,395 |
| | 1.2 |
| | 25.0 |
|
Other Investing Activities | | 18,868 |
| | (1,114 | ) | | 10.6 |
| | 10.6 |
|
Net Cash Flows Used for Investing Activities | | (412,869 | ) | | (321,010 | ) | | (453.9 | ) | | (412.9 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | |
| | |
| | |
| | |
|
Issuance of Long-term Debt – Nonaffiliated | | 726,330 |
| | 295,039 |
| | 314.1 |
| | 726.3 |
|
Change in Advances from Affiliates, Net | | 35,224 |
| | — |
| | (96.9 | ) | | 35.2 |
|
Retirement of Long-term Debt – Nonaffiliated | | (672,552 | ) | | (512,702 | ) | | (213.6 | ) | | (672.5 | ) |
Retirement of Long-term Debt – Affiliated | | (86,000 | ) | | — |
| | — |
| | (86.0 | ) |
Make Whole Premium on Extinguishment of Long-term Debt – Nonaffiliated | | (92,658 | ) |
| — |
| | — |
| | (92.7 | ) |
Principal Payments for Capital Lease Obligations | | (3,843 | ) | | (4,255 | ) | | (4.7 | ) | | (3.8 | ) |
Dividends Paid on Common Stock | | (181,250 | ) | | (60,000 | ) | | (225.0 | ) | | (181.3 | ) |
Other Financing Activities | | 453 |
| | 1,009 |
| | 0.4 |
| | 0.5 |
|
Net Cash Flows Used for Financing Activities | | (274,296 | ) | | (280,909 | ) | | (225.7 | ) | | (274.3 | ) |
| | | | | | | | |
Net Decrease in Cash and Cash Equivalents | | (202 | ) | | (44 | ) | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 0.5 |
| | (0.2 | ) |
Cash and Cash Equivalents at Beginning of Period | | 2,613 |
| | 2,745 |
| | 2.8 |
| | 2.6 |
|
Cash and Cash Equivalents at End of Period | | $ | 2,411 |
| | $ | 2,701 |
| | $ | 3.3 |
| | $ | 2.4 |
|
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | |
| | |
| | |
| | |
|
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 128,435 |
| | $ | 136,919 |
| | $ | 113.2 |
| | $ | 128.4 |
|
Net Cash Paid for Income Taxes | | 33,712 |
| | 22,148 |
| | 55.8 |
| | 33.7 |
|
Noncash Acquisitions Under Capital Leases | | 2,257 |
| | 3,451 |
| | 2.1 |
| | 2.3 |
|
Construction Expenditures Included in Current Liabilities as of September 30, | | 80,990 |
| | 54,463 |
| | 66.8 |
| | 81.0 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES
The condensed notes to APCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to APCo.
|
| |
| Page
Number
|
| |
Significant Accounting Matters | |
New Accounting Pronouncements | |
Comprehensive Income | |
Rate Matters | |
Commitments, Guarantees and Contingencies | |
Benefit Plans | |
Business Segments | |
Derivatives and Hedging | |
Fair Value Measurements | |
Income Taxes | |
Financing Activities | |
Variable Interest Entities | |
Property, Plant and Equipment | |
Disposition Plant Severance | |
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
EXECUTIVE OVERVIEW
Regulatory Activity
Transmission, Distribution and Storage System Improvement Charge (TDSIC)
In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million. In April 2015, I&M filed a notice with the IURC to exclude $117 million related to certain projects. In September 2015, the IURC granted I&M's motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals.
Litigation and Environmental Issues
In the ordinary course of business, I&M is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in the 2014 Annual Report. Also, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 179. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.
Rockport Plant Litigation
In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. Plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. Management will continue to defend against the remaining claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.
See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 256 for additional discussion of relevant factors.
RESULTS OF OPERATIONS
KWh Sales/Degree Days
Summary of KWh Energy Sales
| | | Three Months Ended | | Nine Months Ended | Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, | September 30, | | September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in millions of KWhs) | (in millions of KWhs) |
Retail: | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
Residential | 1,441 |
| | 1,347 |
| | 4,311 |
| | 4,413 |
| 1,619 |
| | 1,441 |
| | 4,344 |
| | 4,311 |
|
Commercial | 1,342 |
| | 1,264 |
| | 3,744 |
| | 3,681 |
| 1,405 |
| | 1,342 |
| | 3,780 |
| | 3,744 |
|
Industrial | 1,972 |
| | 1,933 |
| | 5,712 |
| | 5,701 |
| 1,996 |
| | 1,972 |
| | 5,876 |
| | 5,712 |
|
Miscellaneous | 15 |
| | 15 |
| | 50 |
| | 50 |
| 15 |
| | 15 |
| | 50 |
| | 50 |
|
Total Retail | 4,770 |
| | 4,559 |
| | 13,817 |
| | 13,845 |
| 5,035 |
| | 4,770 |
| | 14,050 |
| | 13,817 |
|
| | | | | | | | | | | | | | |
Wholesale | 2,649 |
| | 3,985 |
| | 8,732 |
| | 13,151 |
| 2,613 |
| | 2,649 |
| | 7,038 |
| | 8,732 |
|
| | | | | | | | | | | | | | |
Total KWhs | 7,419 |
| | 8,544 |
| | 22,549 |
| | 26,996 |
| 7,648 |
| | 7,419 |
| | 21,088 |
| | 22,549 |
|
Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.
Summary of Heating and Cooling Degree Days
| | | Three Months Ended | | Nine Months Ended | Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, | September 30, | | September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in degree days) | (in degree days) |
Actual - Heating (a) | — |
| | 6 |
| | 2,931 |
| | 3,222 |
| — |
| | — |
| | 2,196 |
| | 2,931 |
|
Normal - Heating (b) | 10 |
| | 11 |
| | 2,413 |
| | 2,388 |
| 10 |
| | 10 |
| | 2,449 |
| | 2,413 |
|
| | | | | | | | | | | | | | |
Actual - Cooling (c) | 530 |
| | 410 |
| | 796 |
| | 712 |
| 741 |
| | 530 |
| | 1,011 |
| | 796 |
|
Normal - Cooling (b) | 574 |
| | 581 |
| | 836 |
| | 843 |
| 571 |
| | 574 |
| | 835 |
| | 836 |
|
| |
(a) | Eastern Region heatingHeating degree days are calculated on a 55 degree temperature base. |
| |
(b) | Normal Heating/Cooling represents the thirty-year average of degree days. |
| |
(c) | Eastern Region coolingCooling degree days are calculated on a 65 degree temperature base. |
Third Quarter of 20152016 Compared to Third Quarter of 20142015
| | Reconciliation of Third Quarter of 2014 to Third Quarter of 2015 | |
Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 | | Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 |
Net Income | (in millions) | | | | | |
Third Quarter of 2014 | | $ | 27 |
| |
Third Quarter of 2015 | | | $ | 56.6 |
|
| | |
| | |
|
Changes in Gross Margin: | | |
| | |
|
Retail Margins | | 27 |
| | 30.7 |
|
FERC Municipals and Cooperatives | | 7 |
| |
Off-system Sales | | (7 | ) | | (0.5 | ) |
Transmission Revenues | | (3 | ) | | 1.7 |
|
Other Revenues | | 6 |
| | (2.9 | ) |
Total Change in Gross Margin | | 30 |
| | 29.0 |
|
| | |
| | |
|
Changes in Expenses and Other: | | |
| | |
|
Other Operation and Maintenance | | 9 |
| | 10.2 |
|
Asset Impairments and Other Related Charges | | | (10.5 | ) |
Depreciation and Amortization | | 1 |
| | 0.2 |
|
Taxes Other Than Income Taxes | | 1 |
| | (0.9 | ) |
Other Income | | (3 | ) | | 1.8 |
|
Interest Expense | | (1 | ) | | (3.6 | ) |
Total Change in Expenses and Other | | 7 |
| | (2.8 | ) |
| | |
| | |
|
Income Tax Expense | | (7 | ) | | (7.4 | ) |
| | |
| | |
|
Third Quarter of 2015 | | $ | 57 |
| |
Third Quarter of 2016 | | | $ | 75.4 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
Retail Margins increased $27$31 million primarily due to the following:
A $15$17 million increase resulting from successful rate proceedings in the Indiana service territory. The increase in retail margins relating to riders has corresponding increases in other items below.
A $15 million increase in weather-related usage due to a 40% increase in cooling degree days.
An $8 million increase in weather-related usage primarily due to a 29% increase in cooling degree days.
A $5 million increase in weather-normalized usage.margins.
These increases were partially offset by:
A $4$6 million decrease in fuel recovery from wholesale customers due to the timing of fuel recovery in 2015 primarily as a result of an extended forced outage at Cook Plant, Unit 1.
A $2 million decrease due to increased costs for power acquired under the Unit Power Agreement between AEGCo and I&M.
Margins from FERC Municipal and Cooperatives increased $7 million primarily due to formulaPJM charges not currently recovered in rate changes.
Margins from Off-system Sales decreased $7 million due to lower market prices and decreased sales volumes.
recovery riders/trackers.Other Revenues increased $6decreased $3 million primarily due to a 2014 MPSC order disallowing $4 million of lostdecrease in barging deliveries to the Rockport Plant by River Transportation Division (RTD). The decrease in RTD revenue from 2012 through 2014 related to Demand Side Management.was offset by a corresponding decrease in Other Operation and Maintenance expenses for barging activities discussed below.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses decreased $9$10 million primarily due to the following:
An $8 million decrease due to a 2014 accrual for expected environmental remediation costs.
A $5$10 million decrease in boiler plant maintenancenuclear expenses primarily due to an extended forced outage at Cook Plant, Unit 1 related to the emergency diesel generator repair in 2015.
A $4 million decrease in general and administrative expenses.
A $4 million decrease in RTD expenses for barging activities. The decrease in RTD expenses was offset by a corresponding decrease in Other Revenues from barging activities discussed above.
A $3 million decrease in steam generation maintenance expenses at Rockport in addition to the retirement of the Tanners Creek Plant in May 2015.
These decreases were partially offset by:
A $4$5 million increase in nucleardistribution expenses primarily relateddue to Cook Plant, Unit 1 diesel generator repairs.increased forestry expenses.
A $2 million increase in transmission expenses primarily due to increased PJM expenses.
A $2 million increase in accretion due to the impact of a revision in the nuclear Asset Retirement Obligation (ARO) estimate on decommissioning expense. This increase has a corresponding offset in Depreciation and Amortization expenses.
Asset Impairments and Other IncomeRelated Charges decreased $3increased $11 million due to the impairment of I&M’s Price River coal reserves.
Interest Expense increased $4 million primarily due to a decrease in AFUDC Equity accrued on nuclear fuel for the reactors at Cook Plant.higher long-term debt balances.
Income Tax Expense increased $7$8 million primarily due to an increase in pretax book income, partially offset by the recording of federal and state income tax adjustments.income.
Nine Months Ended September 30, 20152016 Compared to Nine Months Ended September 30, 20142015
| | Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015 | |
Reconciliation of Nine Months Ended September 30, 2015 to Nine Months Ended September 30, 2016 | | Reconciliation of Nine Months Ended September 30, 2015 to Nine Months Ended September 30, 2016 |
Net Income | (in millions) | | | | | |
Nine Months Ended September 30, 2014 | | $ | 141 |
| |
Nine Months Ended September 30, 2015 | | | $ | 179.9 |
|
| | |
| | |
|
Changes in Gross Margin: | | |
| | |
|
Retail Margins | | 58 |
| | 32.0 |
|
FERC Municipals and Cooperatives | | 32 |
| |
Off-system Sales | | (58 | ) | | (9.8 | ) |
Transmission Revenues | | | (6.2 | ) |
Other Revenues | | (2 | ) | | (4.9 | ) |
Total Change in Gross Margin | | 30 |
| | 11.1 |
|
| | |
| | |
|
Changes in Expenses and Other: | | |
| | |
|
Other Operation and Maintenance | | 25 |
| | 19.7 |
|
Asset Impairments and Other Related Charges | | | (10.5 | ) |
Depreciation and Amortization | | | 7.0 |
|
Taxes Other Than Income Taxes | | (2 | ) | | (4.5 | ) |
Other Income | | (2 | ) | | 3.7 |
|
Interest Expense | | 3 |
| | (7.4 | ) |
Total Change in Expenses and Other | | 24 |
| | 8.0 |
|
| | |
| | |
|
Income Tax Expense | | (15 | ) | | 2.4 |
|
| | |
| | |
|
Nine Months Ended September 30, 2015 | | $ | 180 |
| |
Nine Months Ended September 30, 2016 | | | $ | 201.4 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
Retail Margins increased $58$32 million primarily due to the following:
A $42$29 million increase resulting from successful rate proceedings in the Indiana service territory. The increase in retail margins relating to riders has corresponding increases in other items below.
A $12$21 million decreaseincrease in PJM related expenses primarily related to the polar vortex in 2014.weather-normalized margins.
These increases were partially offset by:
A $4$12 million decrease in FERC municipal and cooperative revenues due to weather-normalized Residential sales.annual formula rate adjustments offset by increased formula rate changes.
MarginsA $3 million decrease in fuel recovery from FERC Municipal and Cooperatives increased $32 million primarilywholesale customers due to the annual true-up adjustmenttiming of formula rates to actual costs.
fuel recovery in 2015 primarily as a result of an extended forced outage at Cook Plant, Unit 1.Margins from Off-system Sales decreased $58$10 million primarily due to lower market prices and decreased sales volume.volumes.
Transmission Revenues decreased $6 million primarily due to a lower transmission formula rate true-up than in the prior year, partially offset by higher Network Integration Transmission Service revenues.
Other Revenues decreased $2$5 million primarily due to the following:
An $8 milliona decrease in barging deliveries to the Rockport Plant by River Transportation Division (RTD).RTD. The decrease in RTD revenue was offset by a corresponding decrease in Other Operation and Maintenance expenses for barging activities discussed below.
This decrease was partially offset by:
A $4 million increase relating to a 2014 MPSC order disallowing lost revenue from 2012 through 2014 related to Demand Side Management.
A $1 million increase relating to a net gain on coal procurement sales.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses decreased $25$20 million primarily due to the following:
A $14$26 million decrease in environmental costsnuclear expenses primarily due to an extended forced outage at Cook Plant, Unit 1 for the emergency diesel generator repair of $13 million, in addition to a 2014 accruallow pressure turbine inspection of $8$7 million for expected environmental remediation costs and a current year $6 million reduction of an environmental liability.at Cook Plant, Unit 2.
An $8 million decrease in general and administrative expenses.
An $8 million decrease in distribution expenses primarily due to lower storm restoration and forestry expense.the retirement of Tanners Creek Plant in May 2015.
A $6 million decrease in RTD expenses for barging activities. The decrease in RTD expenses was offset by a corresponding decrease in Other Revenues from barging activities discussed above.
A $5 million decrease primarily due to Rockport environmental compliance work performed in 2015.
These decreases were partially offset by:
An $11$8 million increase in nucleardistribution expenses primarily relateddue to Cook Plant, Unit 1 diesel generator repairs.increased forestry expenses.
A $7 million increase in transmission expenses primarily due to increased PJM expenses.
A $6 million increase due to the reduction of an environmental liability in 2015.
A $5 million increase in accretion due to the impact of a revision in the nuclear ARO estimate on decommissioning expense. This increase has a corresponding offset in Depreciation and Amortization expenses below.
Interest Expense Asset Impairments and Other Related Charges increased $11 million due to the impairment of I&M’s Price River coal reserves.
Depreciation and Amortization expensesdecreased $37 million primarily due to the retirement of Tanners Creek Plant in May 2015 and a revision in the nuclear ARO estimate, partially offset by higher depreciable base.
Taxes Other Than Income Taxes increased $5 million primarily due to property taxes.
Other Income increased $4 million primarily due to a lower interest rate$3 million increase in Life Cycle Management carrying charges and $1 million increase in AFUDC equity accrued on a remarketed pollution control bonds.nuclear fuel for the Cook Plant.
Income TaxInterest Expense increased $15$7 million primarily due to an increase in pretax book income, partially offset by the recording of federal and state income tax adjustments.higher long-term debt balances.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2014 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.
See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 256 for a discussion of accounting pronouncements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
REVENUES | | | | | | | | |
| | | | | | | | |
|
Electric Generation, Transmission and Distribution | | $ | 536,227 |
| | $ | 520,881 |
| | $ | 1,617,504 |
| | $ | 1,642,721 |
| | $ | 574.7 |
| | $ | 536.2 |
| | $ | 1,570.8 |
| | $ | 1,617.5 |
|
Sales to AEP Affiliates | | 9,677 |
| | 401 |
| | 16,634 |
| | 3,753 |
| | 3.9 |
| | 9.6 |
| | 22.4 |
| | 16.6 |
|
Other Revenues – Affiliated | | 21,672 |
| | 20,832 |
| | 62,183 |
| | 70,821 |
| | 15.6 |
| | 21.7 |
| | 46.3 |
| | 62.2 |
|
Other Revenues – Nonaffiliated | | 786 |
| | 749 |
| | 2,626 |
| | 1,298 |
| | 3.4 |
| | 0.8 |
| | 13.2 |
| | 2.6 |
|
TOTAL REVENUES | | 568,362 |
| | 542,863 |
| | 1,698,947 |
| | 1,718,593 |
| | 597.6 |
| | 568.3 |
| | 1,652.7 |
| | 1,698.9 |
|
| | | | | | | | | | | | | | | | |
EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Fuel and Other Consumables Used for Electric Generation | | 90,499 |
| | 117,414 |
| | 264,424 |
| | 387,757 |
| | 91.3 |
| | 90.5 |
| | 236.8 |
| | 264.4 |
|
Purchased Electricity for Resale | | 41,544 |
| | 20,019 |
| | 147,711 |
| | 52,467 |
| | 43.7 |
| | 41.5 |
| | 134.3 |
| | 147.7 |
|
Purchased Electricity from AEP Affiliates | | 67,281 |
| | 66,561 |
| | 182,239 |
| | 203,807 |
| | 64.5 |
| | 67.2 |
| | 165.9 |
| | 182.2 |
|
Other Operation | | 141,054 |
| | 144,331 |
| | 407,320 |
| | 431,953 |
| | 138.9 |
| | 141.0 |
| | 413.9 |
| | 407.3 |
|
Maintenance | | 53,727 |
| | 59,043 |
| | 160,907 |
| | 161,854 |
| | 45.7 |
| | 53.8 |
| | 134.6 |
| | 160.9 |
|
Asset Impairments and Other Related Charges | | | 10.5 |
| | — |
| | 10.5 |
| | — |
|
Depreciation and Amortization | | 49,215 |
| | 50,585 |
| | 150,162 |
| | 150,062 |
| | 49.1 |
| | 49.3 |
| | 143.2 |
| | 150.2 |
|
Taxes Other Than Income Taxes | | 21,608 |
| | 22,059 |
| | 66,992 |
| | 64,685 |
| | 22.5 |
| | 21.6 |
| | 71.5 |
| | 67.0 |
|
TOTAL EXPENSES | | 464,928 |
| | 480,012 |
| | 1,379,755 |
| | 1,452,585 |
| | 466.2 |
| | 464.9 |
| | 1,310.7 |
| | 1,379.7 |
|
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | 103,434 |
| | 62,851 |
| | 319,192 |
| | 266,008 |
| | 131.4 |
| | 103.4 |
| | 342.0 |
| | 319.2 |
|
| | | | | | | | | | | | | | | | |
Other Income (Expense): | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Interest Income | | 1,896 |
| | 1,450 |
| | 7,222 |
| | 4,228 |
| | 1.7 |
| | 1.9 |
| | 9.1 |
| | 7.2 |
|
Allowance for Equity Funds Used During Construction | | 2,157 |
| | 5,596 |
| | 9,107 |
| | 14,364 |
| | 4.1 |
| | 2.1 |
| | 10.9 |
| | 9.1 |
|
Interest Expense | | (23,144 | ) | | (22,617 | ) | | (68,889 | ) | | (71,955 | ) | | (26.7 | ) | | (23.1 | ) | | (76.3 | ) | | (68.9 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | 84,343 |
| | 47,280 |
| | 266,632 |
| | 212,645 |
| | 110.5 |
| | 84.3 |
| | 285.7 |
| | 266.6 |
|
| | | | | | | | | | | | | | | | |
Income Tax Expense | | 27,691 |
| | 20,654 |
| | 86,725 |
| | 71,596 |
| | 35.1 |
| | 27.7 |
| | 84.3 |
| | 86.7 |
|
| | | | | | | | | | | | | | | | |
NET INCOME | | $ | 56,652 |
| | $ | 26,626 |
| | $ | 179,907 |
| | $ | 141,049 |
| | $ | 75.4 |
| | $ | 56.6 |
| | $ | 201.4 |
| | $ | 179.9 |
|
|
|
The common stock of I&M is wholly-owned by AEP.Parent. |
|
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
Net Income | | $ | 56,652 |
| | $ | 26,626 |
| | $ | 179,907 |
| | $ | 141,049 |
| | $ | 75.4 |
| | $ | 56.6 |
| | $ | 201.4 |
| | $ | 179.9 |
|
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME, NET OF TAXES | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Cash Flow Hedges, Net of Tax of $144 and $220 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $432 and $638 for the Nine Months Ended September 30, 2015 and 2014, Respectively | | 267 |
| | 410 |
| | 802 |
| | 1,185 |
| |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $6 and $22 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $18 and $68 for the Nine Months Ended September 30, 2015 and 2014, Respectively | | 11 |
| | 42 |
| | 33 |
| | 128 |
| |
| | | | | | | | | |
TOTAL OTHER COMPREHENSIVE INCOME | | 278 |
| | 452 |
| | 835 |
| | 1,313 |
| |
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2016 and 2015, Respectively, and $0.5 and $0.4 for the Nine Months Ended September 30, 2016 and 2015, Respectively | | | 0.3 |
| | 0.3 |
| | 1.0 |
| | 0.8 |
|
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 56,930 |
| | $ | 27,078 |
| | $ | 180,742 |
| | $ | 142,362 |
| | $ | 75.7 |
| | $ | 56.9 |
| | $ | 202.4 |
| | $ | 180.7 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'SSHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2013 | $ | 56,584 |
| | $ | 980,896 |
| | $ | 900,182 |
| | $ | (15,509 | ) | | $ | 1,922,153 |
| |
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2014 | | $ | 56.6 |
| | $ | 980.9 |
| | $ | 930.8 |
| | $ | (14.3 | ) | | $ | 1,954.0 |
|
| | | | | | | | | | | | | | | | | | |
Common Stock Dividends | |
| | |
| | (100,000 | ) | | |
| | (100,000 | ) | |
| | |
| | (90.0 | ) | | |
| | (90.0 | ) |
Net Income | |
| | |
| | 141,049 |
| | |
| | 141,049 |
| |
| | |
| | 179.9 |
| | |
| | 179.9 |
|
Other Comprehensive Income | |
| | |
| | |
| | 1,313 |
| | 1,313 |
| |
| | |
| | |
| | 0.8 |
| | 0.8 |
|
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2014 | $ | 56,584 |
| | $ | 980,896 |
| | $ | 941,231 |
| | $ | (14,196 | ) | | $ | 1,964,515 |
| |
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2015 | | $ | 56.6 |
| | $ | 980.9 |
| | $ | 1,020.7 |
| | $ | (13.5 | ) | | $ | 2,044.7 |
|
| |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2014 | $ | 56,584 |
| | $ | 980,896 |
| | $ | 930,829 |
| | $ | (14,360 | ) | | $ | 1,953,949 |
| |
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2015 | | $ | 56.6 |
| | $ | 980.9 |
| | $ | 1,015.6 |
| | $ | (16.7 | ) | | $ | 2,036.4 |
|
| | | | | | | | | | | | | | | | | | |
Common Stock Dividends | |
| | |
| | (90,000 | ) | | |
| | (90,000 | ) | |
| | |
| | (93.8 | ) | | |
| | (93.8 | ) |
Net Income | |
| | |
| | 179,907 |
| | |
| | 179,907 |
| |
| | |
| | 201.4 |
| | |
| | 201.4 |
|
Other Comprehensive Income | |
| | |
| | |
| | 835 |
| | 835 |
| |
| | |
| | |
| | 1.0 |
| | 1.0 |
|
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2015 | $ | 56,584 |
| | $ | 980,896 |
| | $ | 1,020,736 |
| | $ | (13,525 | ) | | $ | 2,044,691 |
| |
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2016 | | $ | 56.6 |
| | $ | 980.9 |
| | $ | 1,123.2 |
| | $ | (15.7 | ) | | $ | 2,145.0 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20152016 and December 31, 20142015
(in thousands)millions)
(Unaudited)
| | | | September 30, | | December 31, | | September 30, | | December 31, |
| | 2015 | | 2014 | | 2016 | | 2015 |
CURRENT ASSETS | | | | | | | | |
Cash and Cash Equivalents | | $ | 1,264 |
| | $ | 1,020 |
| | $ | 1.6 |
| | $ | 1.1 |
|
Advances to Affiliates | | 13,508 |
| | 13,481 |
| | 12.4 |
| | 11.7 |
|
Accounts Receivable: | | | | | | | | |
Customers | | 58,950 |
| | 56,978 |
| | 46.3 |
| | 43.9 |
|
Affiliated Companies | | 63,135 |
| | 72,582 |
| | 47.6 |
| | 68.7 |
|
Accrued Unbilled Revenues | | 2,254 |
| | 503 |
| | 2.2 |
| | 0.1 |
|
Miscellaneous | | 1,409 |
| | 1,625 |
| | 0.9 |
| | 2.6 |
|
Allowance for Uncollectible Accounts | | (21 | ) | | (494 | ) | | (0.1 | ) | | (0.1 | ) |
Total Accounts Receivable | | 125,727 |
| | 131,194 |
| | 96.9 |
| | 115.2 |
|
Fuel | | 24,687 |
| | 54,623 |
| | 48.6 |
| | 46.5 |
|
Materials and Supplies | | 189,764 |
| | 201,089 |
| | 156.2 |
| | 185.9 |
|
Risk Management Assets – Nonaffiliated | | 8,574 |
| | 22,328 |
| | 5.2 |
| | 10.6 |
|
Risk Management Assets – Affiliated | | 2,053 |
| | — |
| | — |
| | 1.7 |
|
Accrued Tax Benefits | | 6,232 |
| | 24,788 |
| | 26.5 |
| | 40.5 |
|
Prepayments and Other Current Assets | | 27,549 |
| | 27,968 |
| | 50.1 |
| | 42.1 |
|
TOTAL CURRENT ASSETS | | 399,358 |
| | 476,491 |
| | 397.5 |
| | 455.3 |
|
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | 3,968,224 |
| | 3,741,831 |
| | 3,996.3 |
| | 3,841.7 |
|
Transmission | | 1,380,689 |
| | 1,358,419 |
| | 1,437.7 |
| | 1,406.9 |
|
Distribution | | 1,758,347 |
| | 1,698,409 |
| | 1,866.7 |
| | 1,790.8 |
|
Other Property, Plant and Equipment (September 30, 2015 and December 31, 2014 Amounts Include Coal Mining and Nuclear Fuel, December 31, 2014 Amount Includes 2015 Plant Retirement) | | 745,858 |
| | 1,490,820 |
| |
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | | | 623.8 |
| | 662.3 |
|
Construction Work in Progress | | 470,794 |
| | 537,237 |
| | 607.9 |
| | 519.8 |
|
Total Property, Plant and Equipment | | 8,323,912 |
| | 8,826,716 |
| | 8,532.4 |
| | 8,221.5 |
|
Accumulated Depreciation, Depletion and Amortization | | 3,084,188 |
| | 3,410,341 |
| | 3,063.9 |
| | 3,018.0 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 5,239,724 |
| | 5,416,375 |
| | 5,468.5 |
| | 5,203.5 |
|
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | 818,168 |
| | 536,152 |
| | 837.6 |
| | 804.3 |
|
Spent Nuclear Fuel and Decommissioning Trusts | | 2,047,260 |
| | 2,095,732 |
| | 2,230.8 |
| | 2,106.4 |
|
Long-term Risk Management Assets – Nonaffiliated | | 1,338 |
| | 3,317 |
| | 0.2 |
| | — |
|
Deferred Charges and Other Noncurrent Assets | | 123,676 |
| | 137,209 |
| | 136.6 |
| | 140.9 |
|
TOTAL OTHER NONCURRENT ASSETS | | 2,990,442 |
| | 2,772,410 |
| | 3,205.2 |
| | 3,051.6 |
|
| | | | | | | | |
TOTAL ASSETS | | $ | 8,629,524 |
| | $ | 8,665,276 |
| | $ | 9,071.2 |
| | $ | 8,710.4 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'SSHAREHOLDER’S EQUITY
September 30, 20152016 and December 31, 20142015
(dollars in thousands)millions)
(Unaudited)
| | | | September 30, | | December 31, | | September 30, | | December 31, |
| | 2015 | | 2014 | | 2016 | | 2015 |
CURRENT LIABILITIES | | | | | | | | |
Advances from Affiliates | | $ | 151,004 |
| | $ | 142,501 |
| | $ | 26.3 |
| | $ | 294.3 |
|
Accounts Payable: | | | | | | | | |
General | | 132,292 |
| | 168,294 |
| | 140.2 |
| | 201.0 |
|
Affiliated Companies | | 70,812 |
| | 76,010 |
| | 61.9 |
| | 61.8 |
|
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2015 and December 31, 2014 Amounts Include $97,953 and $85,657, Respectively, Related to DCC Fuel) | | 301,148 |
| | 382,187 |
| |
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2016 and December 31, 2015 Amounts Include $97.8 and $84.6, Respectively, Related to DCC Fuel) | | | 176.1 |
| | 162.9 |
|
Risk Management Liabilities – Nonaffiliated | | 4,615 |
| | 5,223 |
| | 1.3 |
| | 6.3 |
|
Customer Deposits | | 35,641 |
| | 35,206 |
| | 34.2 |
| | 35.7 |
|
Accrued Taxes | | 58,791 |
| | 72,742 |
| | 43.7 |
| | 74.2 |
|
Accrued Interest | | 13,263 |
| | 26,677 |
| | 11.8 |
| | 26.2 |
|
Obligations Under Capital Leases | | 40,375 |
| | 42,050 |
| | 8.7 |
| | 32.8 |
|
Other Current Liabilities | | 151,489 |
| | 150,566 |
| | 131.6 |
| | 142.1 |
|
TOTAL CURRENT LIABILITIES | | 959,430 |
| | 1,101,456 |
| | 635.8 |
| | 1,037.3 |
|
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | 1,759,503 |
| | 1,645,210 |
| | 2,231.3 |
| | 1,837.1 |
|
Long-term Risk Management Liabilities – Nonaffiliated | | 1,248 |
| | 1,395 |
| | 0.2 |
| | 1.6 |
|
Deferred Income Taxes | | 1,329,163 |
| | 1,264,167 |
| | 1,510.9 |
| | 1,361.5 |
|
Regulatory Liabilities and Deferred Investment Tax Credits | | 1,041,910 |
| | 1,199,694 |
| | 1,148.6 |
| | 1,076.2 |
|
Asset Retirement Obligations | | 1,379,004 |
| | 1,337,179 |
| | 1,291.1 |
| | 1,240.9 |
|
Deferred Credits and Other Noncurrent Liabilities | | 114,575 |
| | 162,226 |
| | 108.3 |
| | 119.4 |
|
TOTAL NONCURRENT LIABILITIES | | 5,625,403 |
| | 5,609,871 |
| | 6,290.4 |
| | 5,636.7 |
|
| | | | | | | | |
TOTAL LIABILITIES | | 6,584,833 |
| | 6,711,327 |
| | 6,926.2 |
| | 6,674.0 |
|
| | | | | | | | |
Rate Matters (Note 4) | |
| |
| |
| |
|
Commitments and Contingencies (Note 5) | |
| |
| |
| |
|
| | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | |
Common Stock – No Par Value: | | | | | | | | |
Authorized – 2,500,000 Shares | | | | | | | | |
Outstanding – 1,400,000 Shares | | 56,584 |
| | 56,584 |
| | 56.6 |
| | 56.6 |
|
Paid-in Capital | | 980,896 |
| | 980,896 |
| | 980.9 |
| | 980.9 |
|
Retained Earnings | | 1,020,736 |
| | 930,829 |
| | 1,123.2 |
| | 1,015.6 |
|
Accumulated Other Comprehensive Income (Loss) | | (13,525 | ) | | (14,360 | ) | | (15.7 | ) | | (16.7 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,044,691 |
| | 1,953,949 |
| | 2,145.0 |
| | 2,036.4 |
|
| | | | | | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY | | $ | 8,629,524 |
| | $ | 8,665,276 |
| |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | | $ | 9,071.2 |
| | $ | 8,710.4 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2016 | | 2015 |
OPERATING ACTIVITIES | | |
| | |
| | |
| | |
|
Net Income | | $ | 179,907 |
| | $ | 141,049 |
| | $ | 201.4 |
| | $ | 179.9 |
|
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
| | |
| | |
| | |
|
Depreciation and Amortization | | 150,162 |
| | 150,062 |
| | 143.2 |
| | 150.2 |
|
Deferred Income Taxes | | 38,338 |
| | 15,792 |
| | 116.2 |
| | 38.3 |
|
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net | | (148 | ) | | 23,951 |
| |
Asset Impairments and Other Related Charges | | | 10.5 |
| | — |
|
Deferral of Incremental Nuclear Refueling Outage Expenses, Net | | | (17.4 | ) | | (0.1 | ) |
Allowance for Equity Funds Used During Construction | | (9,107 | ) | | (14,364 | ) | | (10.9 | ) | | (9.1 | ) |
Mark-to-Market of Risk Management Contracts | | 12,926 |
| | (2,196 | ) | | 0.5 |
| | 12.9 |
|
Amortization of Nuclear Fuel | | 101,649 |
| | 114,238 |
| | 109.7 |
| | 101.6 |
|
Fuel Over/Under-Recovery, Net | | (16,055 | ) | | 18,931 |
| |
Pension Contribution to Qualified Plan Trust | | | (12.7 | ) | | (14.6 | ) |
Deferred Fuel Over/Under-Recovery, Net | | | 6.1 |
| | (16.1 | ) |
Change in Other Noncurrent Assets | | 27,286 |
| | (36,596 | ) | | — |
| | 26.4 |
|
Change in Other Noncurrent Liabilities | | (6,330 | ) | | 66,502 |
| | 30.0 |
| | 9.2 |
|
Changes in Certain Components of Working Capital: | | |
| | |
| | |
| | |
|
Accounts Receivable, Net | | 5,467 |
| | 59,646 |
| | 17.0 |
| | 5.5 |
|
Fuel, Materials and Supplies | | 29,609 |
| | 14,884 |
| | (1.1 | ) | | 29.6 |
|
Accounts Payable | | (14,001 | ) | | (12,052 | ) | | (17.9 | ) | | (14.0 | ) |
Accrued Taxes, Net | | 4,605 |
| | 30,719 |
| | (16.5 | ) | | 4.6 |
|
Other Current Assets | | 6,923 |
| | 11,741 |
| | 6.7 |
| | 7.0 |
|
Other Current Liabilities | | (9,276 | ) | | (8,201 | ) | | (27.8 | ) | | (9.3 | ) |
Net Cash Flows from Operating Activities | | 501,955 |
| | 574,106 |
| | 537.0 |
| | 502.0 |
|
| | | | | | | | |
INVESTING ACTIVITIES | | |
| | |
| | |
| | |
|
Construction Expenditures | | (337,021 | ) | | (345,369 | ) | | (405.1 | ) | | (337.0 | ) |
Change in Advances to Affiliates, Net | | (27 | ) | | 42,364 |
| | (0.7 | ) | | — |
|
Purchases of Investment Securities | | (1,479,149 | ) | | (789,461 | ) | | (2,452.9 | ) | | (1,479.1 | ) |
Sales of Investment Securities | | 1,437,336 |
| | 746,272 |
| | 2,427.0 |
| | 1,437.3 |
|
Acquisitions of Nuclear Fuel | | (53,262 | ) | | (109,224 | ) | | (127.6 | ) | | (53.3 | ) |
Other Investing Activities | | 9,000 |
| | 11,773 |
| | 7.8 |
| | 9.0 |
|
Net Cash Flows Used for Investing Activities | | (423,123 | ) | | (443,645 | ) | | (551.5 | ) | | (423.1 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | |
| | |
| | |
| | |
|
Issuance of Long-term Debt – Nonaffiliated | | 210,687 |
| | 99,323 |
| | 482.7 |
| | 210.7 |
|
Change in Advances from Affiliates, Net | | 8,503 |
| | 95,899 |
| | (268.0 | ) | | 8.5 |
|
Retirement of Long-term Debt – Nonaffiliated | | (178,471 | ) | | (190,550 | ) | | (76.8 | ) | | (178.5 | ) |
Principal Payments for Capital Lease Obligations | | (29,875 | ) | | (35,660 | ) | | (29.8 | ) | | (29.9 | ) |
Dividends Paid on Common Stock | | (90,000 | ) | | (100,000 | ) | | (93.8 | ) | | (90.0 | ) |
Other Financing Activities | | 568 |
| | 628 |
| | 0.7 |
| | 0.6 |
|
Net Cash Flows Used for Financing Activities | | (78,588 | ) | | (130,360 | ) | |
Net Cash Flows from (Used for) Financing Activities | | | 15.0 |
| | (78.6 | ) |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | 244 |
| | 101 |
| | 0.5 |
| | 0.3 |
|
Cash and Cash Equivalents at Beginning of Period | | 1,020 |
| | 1,317 |
| | 1.1 |
| | 1.0 |
|
Cash and Cash Equivalents at End of Period | | $ | 1,264 |
| | $ | 1,418 |
| | $ | 1.6 |
| | $ | 1.3 |
|
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | |
| | |
| | |
| | |
|
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 77,450 |
| | $ | 75,789 |
| | $ | 85.6 |
| | $ | 77.5 |
|
Net Cash Paid (Received) for Income Taxes | | 17,203 |
| | (1,475 | ) | | (36.0 | ) | | 17.2 |
|
Noncash Acquisitions Under Capital Leases | | 1,990 |
| | 5,015 |
| | 16.8 |
| | 2.0 |
|
Construction Expenditures Included in Current Liabilities as of September 30, | | 51,582 |
| | 69,241 |
| | 83.4 |
| | 51.6 |
|
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | | 31,140 |
| | 11 |
| | 0.3 |
| | 31.1 |
|
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage | | 2,136 |
| | 3,208 |
| | 0.1 |
| | 2.1 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES
The condensed notes to I&M’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to I&M.
|
| |
| Page
Number
|
| |
Significant Accounting Matters | |
New Accounting Pronouncements | |
Comprehensive Income | |
Rate Matters | |
Commitments, Guarantees and Contingencies | |
Benefit Plans | |
Business Segments | |
Derivatives and Hedging | |
Fair Value Measurements | |
Income Taxes | |
Financing Activities | |
Variable Interest Entities | |
Property, Plant and Equipment | |
Disposition Plant Severance | |
OHIO POWER COMPANY AND SUBSIDIARIES
OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
EXECUTIVE OVERVIEW
Regulatory Activity
Ohio Electric Security Plan Filings
2009 - 2011 ESP
In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. In June 2015, the Supreme Court of Ohio issued a decision that reversed, as requested by OPCo, the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. In September 2015, the Supreme Court of Ohio denied the IEU's request for reconsideration and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate.
June 2012 - May 2015 Ohio ESP Including Capacity Charge
In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in PUCO rehearing orders in January and March 2013.
In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and $150/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio, which has scheduled oral arguments for the fourth quarter of 2015.
As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50/MWh through May 2014 and at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR. In April 2015, the PUCO issued an order that approved, with modifications, OPCo's July 2014 application to collect the unrecovered portion of the deferred capacity costs. In May 2015, the PUCO granted intervenors requests for rehearing. As of September 30, 2015, OPCo’s net deferred capacity costs balance was $392 million, including debt carrying costs. Through September 30, 2015, OPCo has collected $183 million in deferred capacity costs, and related carrying charges.
In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.
In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating
a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report.
If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.
June 2015 - May 2018 ESP Including PPA Application
In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA.
In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the Distribution Investment Rider (DIR) with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo's and various intervenors' requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider.
In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. A hearing at the PUCO related to the PPA commenced in September 2015. In October 2015, the PUCO staff submitted testimony that opposed the PPA application as currently proposed but concluded that, with changes, a PPA could be in the public interest.
If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filings” section of OPCo Rate Matters in Note 4.
Litigation and Environmental Issues
In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in the 2014 Annual Report. Also, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 179. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.
See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 256 for additional discussion of relevant factors.
RESULTS OF OPERATIONS
KWh Sales/Degree Days
Summary of KWh Energy Sales
| | | Three Months Ended | | Nine Months Ended | Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, | September 30, | | September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in millions of KWhs) | (in millions of KWhs) |
Retail: | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
Residential | 3,788 |
| | 3,513 |
| | 11,249 |
| | 11,189 |
| 4,380 |
| | 3,788 |
| | 11,209 |
| | 11,249 |
|
Commercial | 3,929 |
| | 3,714 |
| | 11,074 |
| | 10,838 |
| 4,114 |
| | 3,929 |
| | 11,158 |
| | 11,074 |
|
Industrial | 3,711 |
| | 3,647 |
| | 11,081 |
| | 10,822 |
| 3,610 |
| | 3,711 |
| | 10,671 |
| | 11,081 |
|
Miscellaneous | 28 |
| | 26 |
| | 88 |
| | 88 |
| 27 |
| | 28 |
| | 89 |
| | 88 |
|
Total Retail (a) | 11,456 |
| | 10,900 |
| | 33,492 |
| | 32,937 |
| 12,131 |
| | 11,456 |
| | 33,127 |
| | 33,492 |
|
| | | | | | | | | | | | | | |
Wholesale (b) | 497 |
| | 575 |
| | 1,460 |
| | 1,727 |
| 654 |
| | 497 |
| | 1,389 |
| | 1,460 |
|
| | | | | | | | | | | | | | |
Total KWhs | 11,953 |
| | 11,475 |
| | 34,952 |
| | 34,664 |
| 12,785 |
| | 11,953 |
| | 34,516 |
| | 34,952 |
|
| |
(a) | Represents energy delivered to distribution customers. |
| |
(b) | Ohio'sPrimarily Ohio’s contractually obligated purchases of OVEC power sold into PJM. |
Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.
Summary of Heating and Cooling Degree Days
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
| | (in degree days) | | (in degree days) |
Actual - Heating (a) | | — |
| | 1 |
| | 2,575 |
| | 2,540 |
| | — |
| | — |
| | 1,929 |
| | 2,575 |
|
Normal - Heating (b) | | 6 |
| | 7 |
| | 2,073 |
| | 2,074 |
| | 7 |
| | 6 |
| | 2,110 |
| | 2,073 |
|
| | | | | | | | | | | | | | | | |
Actual - Cooling (c) | | 620 |
| | 581 |
| | 970 |
| | 943 |
| | 900 |
| | 620 |
| | 1,209 |
| | 970 |
|
Normal - Cooling (b) | | 666 |
| | 663 |
| | 956 |
| | 946 |
| | 664 |
| | 666 |
| | 956 |
| | 956 |
|
| |
(a) | Eastern Region heatingHeating degree days are calculated on a 55 degree temperature base. |
| |
(b) | Normal Heating/Cooling represents the thirty-year average of degree days. |
| |
(c) | Eastern Region coolingCooling degree days are calculated on a 65 degree temperature base. |
Third Quarter of 20152016 Compared to Third Quarter of 20142015
| | Reconciliation of Third Quarter of 2014 to Third Quarter of 2015 | |
Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 | | Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 |
Net Income | (in millions) | | | | | |
Third Quarter of 2014 | | $ | 54 |
| |
Third Quarter of 2015 | | | $ | 71.6 |
|
| | |
| | |
|
Changes in Gross Margin: | | |
| | |
|
Retail Margins | | 106 |
| | 41.7 |
|
Off-system Sales | | (10 | ) | | 9.4 |
|
Transmission Revenues | | (37 | ) | | 3.6 |
|
Other Revenues | | 1 |
| | 3.2 |
|
Total Change in Gross Margin | | 60 |
| | 57.9 |
|
| | |
| | |
|
Changes in Expenses and Other: | | |
| | |
|
Other Operation and Maintenance | | (11 | ) | | (13.4 | ) |
Depreciation and Amortization | | (9 | ) | | (5.7 | ) |
Taxes Other Than Income Taxes | | (4 | ) | | (8.1 | ) |
Interest Income | | | (0.5 | ) |
Carrying Costs Income | | (7 | ) | | 2.5 |
|
Allowance for Equity Funds Used During Construction | | | (1.9 | ) |
Interest Expense | | (1 | ) | | 5.4 |
|
Total Change in Expenses and Other | | (32 | ) | | (21.7 | ) |
| | |
| | |
|
Income Tax Expense | | (10 | ) | | (7.9 | ) |
| | |
| | |
|
Third Quarter of 2015 | | $ | 72 |
| |
Third Quarter of 2016 | | | $ | 99.9 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
Retail Margins increased $106$42 million primarily due to the following:
An $18 million increase in collections of the PIRR as a result of the June 2016 PUCO order.
A $10 million increase in transmission and PJM revenues, partially offset by a corresponding decrease in other expense items below.
A $9 million increase in the Universal Service Fund (USF) rider. This increase was offset by an increase in Other Operation and Maintenance expenses below.
A $4 million increase in revenues associated with the Distribution Investment Rider (DIR).
Margins from Off-system Sales increased $9 million primarily due to prior year losses from a power contract with OVEC.
Transmission Revenues increased $4 million primarily due to an increased investment in the transmission system.
Other Revenues increased $3 million primarily due to increased pole attachment revenue.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $13 million primarily due to the following:
| |
• | A $9 million increase in recoverable gridSMART® expenses. |
A $9 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins above.
A $3 million increase in recoverable PJM expenses.
These increases were partially offset by:
A $9 million decrease in employee-related expenses.
Depreciation and Amortization expensesincreased $6 million primarily due to the following:
A $65$6 million increase in DIR recoveries.
A $2 million increase in depreciation expense primarily due to an increase in depreciable base of transmission and distribution assets.
A $1 million increase due to recoveries of transmission cost rider carrying costs. The increase was offset by a corresponding increase in Retail Margins above.
These increases were partially offset by:
| |
• | A $5 million decrease in recoverable gridSMART® depreciation expenses. |
Taxes Other Than Income Taxes increased $8 million primarily due to the following:
A $5 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.
A $3 million increase in state excise taxes due to an increase in metered KWh.
| |
• | Carrying Costs Income increased $3 million primarily due to an unfavorable prior period adjustment related to gridSMART® capital carrying charges. |
InterestExpensedecreased $5 million primarily due to the maturity of a senior unsecured note in June 2016.
Income Tax Expense increased $8 million primarily due to an increase in pretax book income partially offset by the recording of federal income tax adjustments and by other book/tax differences which are accounted for on a flow-through basis.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2015 to Nine Months Ended September 30, 2016 |
Net Income |
(in millions) |
| | |
Nine Months Ended September 30, 2015 | | $ | 184.7 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins | | 207.2 |
|
Off-system Sales | | (6.2 | ) |
Transmission Revenues | | (36.8 | ) |
Other Revenues | | 0.9 |
|
Total Change in Gross Margin | | 165.1 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | (62.3 | ) |
Depreciation and Amortization | | (10.4 | ) |
Taxes Other Than Income Taxes | | (8.5 | ) |
Interest Income | | (1.3 | ) |
Carrying Costs Income | | (6.0 | ) |
Allowance for Equity Funds Used During Construction | | (3.3 | ) |
Interest Expense | | 8.6 |
|
Total Change in Expenses and Other | | (83.2 | ) |
| | |
|
Income Tax Expense | | (21.9 | ) |
| | |
|
Nine Months Ended September 30, 2016 | | $ | 244.7 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
Retail Margins increased $207 million primarily due to the following:
A $128 million increase in transmission and PJM revenues primarily due to the energy supplied as a result of the Ohio auction and a regulatory change which resulted in revenues collected through a non-bypassable transmission rider, partially offset by a corresponding decrease in Transmission Revenues below.
A $33 million regulatory provision recorded in 2014.
A $7 million increase in revenues associated with the Distribution Investment Rider.
| |
• | A $7$31 million increase in revenues associated with thevarious riders such as USF, Energy Efficiency/Peak Demand Reduction Cost Recovery and gridSMART®, Enhanced Service Reliability. This increase is primarily offset by an increase in Other Operation and Retail Stability Riders. These riders have corresponding increases in other expense itemsMaintenance expenses below. |
A $21 million increase due to a reversal of a regulatory provision resulting from a favorable court decision.
An $18 million increase in collections of the PIRR as a result of the June 2016 PUCO order.
A $16 million increase in revenues associated with the DIR.
A $10 million increase in carrying charges due to the collection of carrying costs on deferred capacity charges beginning June 2015.
These increases were partially offset by:
A $14 million decrease in base rates due to the discontinuance of seasonal rates.
A $14$16 million decrease in revenues associated with the recovery of 2012 storm costs under the Storm Damage Recovery Rider which ended in April 2015. This decrease in Retail Margins is primarily offset by a decrease in Other Operation and Maintenance expenses below.
Margins from Off-system Sales decreased $10$6 million primarily due to increased losses from a legacy power contract.contract with OVEC.
Transmission Revenues decreased $37 million primarily due to a decrease in Network Integrated Transmission Service (NITS) revenue due to OPCo assuming the responsibility for items determined to be cost-based transmission-related charges that were the responsibility of the CRES providers prior to June 2015, partially offset by a corresponding increase in Retail Margins above.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $11 million primarily due to the following:
A $19 million increase in recoverable PJM expenses.
A $4 million increase in employee-related expenses.
These increases were partially offset by:
A $14 million decrease due to the completion of the amortization of 2012 deferred storm expenses in April 2015. This decrease was offset by a corresponding decrease in Retail Margins above.
Depreciation and Amortization expensesincreased $9 million primarily due to the following:
A $4 million increase in amortization expenses for the collection of carrying costs on deferred capacity charges beginning June 2015. This increase was offset by a corresponding increase in Retail Margins above.
A $3 million increase in depreciation expense primarily due to an increase in depreciable base of transmission and distribution assets.
| |
• | A $3 million increase in gridSMART® capital carrying charges primarily due to a rider rate increase effective June 2015. This increase was offset by a corresponding increase in Retail Margins above.
|
Taxes Other Than Income Taxes increased $4 million primarily due to an increase in property taxes due to additional investment in transmission and distribution assets and higher tax rates.
Carrying Costs Income decreased $7 million primarily due to the collection of carrying costs on deferred capacity charges beginning June 2015.
Income Tax Expense increased $10 million primarily due to an increase in pretax book income.
Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
|
| | | | |
Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015 |
Net Income |
(In Millions) |
| | |
Nine Months Ended September 30, 2014 | | $ | 171 |
|
| | |
|
Changes in Gross Margin: | | |
|
Retail Margins | | 133 |
|
Off-system Sales | | (12 | ) |
Transmission Revenues | | (72 | ) |
Other Revenues | | 8 |
|
Total Change in Gross Margin | | 57 |
|
| | |
|
Changes in Expenses and Other: | | |
|
Other Operation and Maintenance | | (3 | ) |
Depreciation and Amortization | | (13 | ) |
Taxes Other Than Income Taxes | | (14 | ) |
Other Income | | (2 | ) |
Carrying Costs Income | | (10 | ) |
Interest Expense | | 1 |
|
Total Change in Expenses and Other | | (41 | ) |
| | |
|
Income Tax Expense | | (2 | ) |
| | |
|
Nine Months Ended September 30, 2015 | | $ | 185 |
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
Retail Margins increased $133 million primarily due to the following:
A $91 million increase in transmission and PJM revenues primarily due to the energy supplied as result of the Ohio auction and a regulatory change which resulted in revenues collected through a non-bypassable transmission rider, partially offset by a corresponding decrease in Transmission Revenues below.
A $33 million regulatory provision recorded in 2014.
A $22 million increase in revenues associated with the Distribution Investment Rider.
| |
• | A $14 million increase in revenues associated with the gridSMART®, Enhanced Service Reliability and Retail Stability Riders. These riders have corresponding increases in other expense items below.
|
These increases were partially offset by:
A $19 million decrease in the Energy Efficiency (EE), Peak Demand Reduction Cost Recovery Rider (PDR) revenues and associated deferrals. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
An $11 million decrease in revenues associated with the recovery of 2012 storm costs under the Storm Damage Recovery Rider which ended in April 2015. This decrease in Retail Margins is primarily offset by a decrease in Other Operation and Maintenance expenses below.
A $6 million decrease in revenues associated with the Universal Service Fund (USF) surcharge. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
A $4 million decrease in base rates due to the discontinuance of seasonal rates.
Margins from Off-system Sales decreased $12 million primarily due to losses from a legacy power contract.
Transmission Revenues decreased $72 million primarily due to the following:
A $44$55 million decrease in NITS revenue primarily due to OPCo assuming the responsibility for items determined to be cost-based transmission-related charges that were the responsibility of the CRES providers prior to June 2015, partially offset by a corresponding increase in Retail Margins above.
This decrease was partially offset by:
A $12$19 million increase due to a settlement recorded in 2015, a decrease in revenues related to a lower annual transmissionamortization of the formula rate true-up.
A $9 million transmission regulatory settlementtrue-up and the recording of the current year formula rate true-up in 2015.2016.
Other Revenues increased $8 million primarily due to increased pole attachment revenue.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $3$62 million primarily due to the following:
A $33$46 million increase in recoverable PJM expenses.
| |
• | A $25 million increase in recoverable gridSMART® expenses. |
A $6$15 million increase due to PUCO ordered contributionsin remitted USF surcharge payments to the Ohio Growth Fund.Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins above.
These increases were partially offset by:
A $19 million decrease in EE and PDR costs and associated deferrals. This decrease was offset by a corresponding decrease in Retail Margins above.
A $12$14 million decrease due to the completion of the amortization of 2012 deferred storm expenses in April 2015. This decrease was offset by a corresponding decrease in Retail Margins above.
A $6 million decrease in remitted USF surcharge paymentsdue to a PUCO ordered contribution to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset by a correspondingGrowth Fund recorded in 2015.
A $5 million decrease in Retail Margins above.employee-related expenses.
Depreciation and Amortization expenses increased $13$10 million primarily due to the following:
A $9An $8 million increase in depreciation expense primarily due to anrecoveries of transmission cost rider carrying costs. The increase was offset by a corresponding increase in depreciable base of transmission and distribution assets.Retail Margins above.
A $5$6 million increase in amortization expenses for the collection of carrying costs on deferred capacity charges beginning June 2015. This increase was offset by a corresponding increase in Retail Margins above.
Taxes Other Than Income Taxes increased $14A $6 million increase in depreciation expense primarily due to an increase in property taxesdepreciable base of transmission and distribution assets.
These increases were partially offset by:
| |
• | An $11 million decrease in recoverable gridSMART® depreciation expenses. |
Taxes Other Than Income Taxes increased $9 million primarily due to additional investmentinvestments in transmission and distribution assets and higher tax rates.
Carrying Costs Income decreased $10$6 million primarily due to the following:
A $10 million decrease due to the collection of carrying costs on deferred capacity charges beginning June 2015.
This decrease was partially offset by:
| |
• | A $4 million increase primarily due to an unfavorable prior period adjustment related to gridSMART® capital carrying charges. |
InterestExpensedecreased $9 million primarily due to the following:
A $7 million decrease due to the maturity of a senior unsecured note in June 2016.
| |
• | A $3 million decrease in recoverable gridSMART® interest expenses. |
Income Tax Expense increased $22 million primarily due to an increase in pretax book income partially offset by the recording of federal income tax adjustments and by other book/tax differences which are accounted for on a flow-through basis.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2014 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.
See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 256 for a discussion of accounting pronouncements.
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
REVENUES | | | | | | | | |
| | | | | | | | |
|
Electricity, Transmission and Distribution | | $ | 775,905 |
| | $ | 793,900 |
| | $ | 2,320,372 |
| | $ | 2,380,768 |
| | $ | 864.4 |
| | $ | 775.9 |
| | $ | 2,349.2 |
| | $ | 2,320.4 |
|
Sales to AEP Affiliates | | 4,426 |
| | 43,733 |
| | 79,690 |
| | 120,154 |
| | 5.5 |
| | 4.4 |
| | 11.7 |
| | 79.7 |
|
Other Revenues | | 1,953 |
| | 1,564 |
| | 6,416 |
| | 4,628 |
| | 1.4 |
| | 2.0 |
| | 4.8 |
| | 6.4 |
|
TOTAL REVENUES | | 782,284 |
| | 839,197 |
| | 2,406,478 |
| | 2,505,550 |
| | 871.3 |
| | 782.3 |
| | 2,365.7 |
| | 2,406.5 |
|
| | | | | | | | | | | | | | | | |
EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Purchased Electricity for Resale | | 173,094 |
| | 48,541 |
| | 431,608 |
| | 191,730 |
| | 203.4 |
| | 173.1 |
| | 516.1 |
| | 431.6 |
|
Purchased Electricity from AEP Affiliates | | 45,834 |
| | 315,903 |
| | 462,645 |
| | 897,658 |
| | 35.9 |
| | 45.8 |
| | 121.4 |
| | 462.6 |
|
Amortization of Generation Deferrals | | 55,466 |
| | 26,655 |
| | 122,221 |
| | 82,818 |
| | 66.1 |
| | 55.4 |
| | 173.0 |
| | 122.2 |
|
Other Operation | | 170,144 |
| | 145,163 |
| | 446,817 |
| | 428,074 |
| | 184.2 |
| | 170.2 |
| | 525.9 |
| | 446.8 |
|
Maintenance | | 39,437 |
| | 53,724 |
| | 121,224 |
| | 136,965 |
| | 38.8 |
| | 39.4 |
| | 104.4 |
| | 121.2 |
|
Depreciation and Amortization | | 63,757 |
| | 54,968 |
| | 178,609 |
| | 165,152 |
| | 69.4 |
| | 63.7 |
| | 189.0 |
| | 178.6 |
|
Taxes Other Than Income Taxes | | 93,666 |
| | 89,564 |
| | 283,092 |
| | 268,734 |
| | 101.9 |
| | 93.8 |
| | 291.7 |
| | 283.2 |
|
TOTAL EXPENSES | | 641,398 |
| | 734,518 |
| | 2,046,216 |
| | 2,171,131 |
| | 699.7 |
| | 641.4 |
| | 1,921.5 |
| | 2,046.2 |
|
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | 140,886 |
| | 104,679 |
| | 360,262 |
| | 334,419 |
| | 171.6 |
| | 140.9 |
| | 444.2 |
| | 360.3 |
|
| | | | | | | | | | | | | | | | |
Other Income (Expense): | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Interest Income | | 1,165 |
| | 1,986 |
| | 4,328 |
| | 8,159 |
| | 0.7 |
| | 1.2 |
| | 3.0 |
| | 4.3 |
|
Carrying Costs Income (Expense) | | (1,576 | ) | | 5,606 |
| | 10,037 |
| | 19,594 |
| | 0.9 |
| | (1.6 | ) | | 4.0 |
| | 10.0 |
|
Allowance for Equity Funds Used During Construction | | 2,228 |
| | 1,825 |
| | 7,015 |
| | 4,893 |
| | 0.3 |
| | 2.2 |
| | 3.7 |
| | 7.0 |
|
Interest Expense | | (32,593 | ) | | (31,171 | ) | | (96,313 | ) | | (96,937 | ) | | (27.2 | ) | | (32.6 | ) | | (87.7 | ) | | (96.3 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | 110,110 |
| | 82,925 |
| | 285,329 |
| | 270,128 |
| | 146.3 |
| | 110.1 |
| | 367.2 |
| | 285.3 |
|
| | | | | | | | | | | | | | | | |
Income Tax Expense | | 38,541 |
| | 28,865 |
| | 100,641 |
| | 98,759 |
| | 46.4 |
| | 38.5 |
| | 122.5 |
| | 100.6 |
|
| | | | | | | | | | | | | | | | |
NET INCOME | | $ | 71,569 |
| | $ | 54,060 |
| | $ | 184,688 |
| | $ | 171,369 |
| | $ | 99.9 |
| | $ | 71.6 |
| | $ | 244.7 |
| | $ | 184.7 |
|
|
| | | | |
The common stock of OPCo is wholly-owned by AEP.Parent. |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
Net Income | | $ | 71,569 |
| | $ | 54,060 |
| | $ | 184,688 |
| | $ | 171,369 |
| | $ | 99.9 |
| | $ | 71.6 |
| | $ | 244.7 |
| | $ | 184.7 |
|
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE LOSS, NET OF TAXES | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $185 and $185 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $555 and $611 for the Nine Months Ended September 30, 2015 and 2014, Respectively | | (344 | ) | | (343 | ) | | (1,030 | ) | | (1,134 | ) | |
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.2) for the Three Months Ended September 30, 2016 and 2015, Respectively, and $(0.5) and $(0.6) for the Nine Months Ended September 30, 2016 and 2015, Respectively | | | (0.2 | ) | | (0.3 | ) | | (1.0 | ) | | (1.0 | ) |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 71,225 |
| | $ | 53,717 |
| | $ | 183,658 |
| | $ | 170,235 |
| | $ | 99.7 |
| | $ | 71.3 |
| | $ | 243.7 |
| | $ | 183.7 |
|
| | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 113. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 113. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2016 and 2015
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2014 | $ | 321.2 |
| | $ | 838.8 |
| | $ | 814.6 |
| | $ | 5.6 |
| | $ | 1,980.2 |
|
| | | | | | | | | |
Common Stock Dividends | |
| | |
| | (156.3 | ) | | |
| | (156.3 | ) |
Net Income | |
| | |
| | 184.7 |
| | |
| | 184.7 |
|
Other Comprehensive Loss | |
| | |
| | |
| | (1.0 | ) | | (1.0 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2015 | $ | 321.2 |
| | $ | 838.8 |
| | $ | 843.0 |
| | $ | 4.6 |
| | $ | 2,007.6 |
|
| |
| | |
| | |
| | |
| | |
|
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2015 | $ | 321.2 |
| | $ | 838.8 |
| | $ | 822.3 |
| | $ | 4.3 |
| | $ | 1,986.6 |
|
| | | | | | | | | |
Common Stock Dividends | |
| | |
| | (150.0 | ) | | |
| | (150.0 | ) |
Net Income | |
| | |
| | 244.7 |
| | |
| | 244.7 |
|
Other Comprehensive Loss | |
| | |
| | |
| | (1.0 | ) | | (1.0 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2016 | $ | 321.2 |
| | $ | 838.8 |
| | $ | 917.0 |
| | $ | 3.3 |
| | $ | 2,080.3 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES INBALANCE SHEETS
COMMON SHAREHOLDER'S EQUITYASSETS
For the Nine Months Ended September 30, 20152016 and 2014December 31, 2015
(in thousands)millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2013 | $ | 321,201 |
| | $ | 663,782 |
| | $ | 633,203 |
| | $ | 7,079 |
| | $ | 1,625,265 |
|
| | | | | | | | | |
Common Stock Dividends | |
| | |
| | (35,000 | ) | | |
| | (35,000 | ) |
Net Income | |
| | |
| | 171,369 |
| | |
| | 171,369 |
|
Other Comprehensive Loss | |
| | |
| | |
| | (1,134 | ) | | (1,134 | ) |
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2014 | $ | 321,201 |
| | $ | 663,782 |
| | $ | 769,572 |
| | $ | 5,945 |
| | $ | 1,760,500 |
|
| |
| | |
| | |
| | |
| | |
|
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2014 | $ | 321,201 |
| | $ | 838,782 |
| | $ | 814,625 |
| | $ | 5,602 |
| | $ | 1,980,210 |
|
| | | | | | | | | |
Common Stock Dividends | |
| | |
| | (156,250 | ) | | |
| | (156,250 | ) |
Net Income | |
| | |
| | 184,688 |
| | |
| | 184,688 |
|
Other Comprehensive Loss | |
| | |
| | |
| | (1,030 | ) | | (1,030 | ) |
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2015 | $ | 321,201 |
| | $ | 838,782 |
| | $ | 843,063 |
| | $ | 4,572 |
| | $ | 2,007,618 |
|
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2016 | | 2015 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents | | $ | 4.0 |
| | $ | 3.1 |
|
Restricted Cash for Securitized Funding | | 16.1 |
| | 27.7 |
|
Advances to Affiliates | | 0.2 |
| | 331.1 |
|
Accounts Receivable: | | | | |
Customers | | 13.8 |
| | 46.4 |
|
Affiliated Companies | | 54.1 |
| | 64.3 |
|
Accrued Unbilled Revenues | | 35.1 |
| | 1.4 |
|
Miscellaneous | | 0.7 |
| | 0.4 |
|
Allowance for Uncollectible Accounts | | (0.2 | ) | | (0.2 | ) |
Total Accounts Receivable | | 103.5 |
| | 112.3 |
|
Materials and Supplies | | 48.8 |
| | 61.5 |
|
Emission Allowances | | 18.3 |
| | 24.6 |
|
Accrued Tax Benefits | | 11.5 |
| | 1.8 |
|
Prepayments and Other Current Assets | | 16.3 |
| | 11.1 |
|
TOTAL CURRENT ASSETS | | 218.7 |
| | 573.2 |
|
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Transmission | | 2,287.3 |
| | 2,235.6 |
|
Distribution | | 4,401.7 |
| | 4,287.7 |
|
Other Property, Plant and Equipment | | 436.7 |
| | 408.2 |
|
Construction Work in Progress | | 194.1 |
| | 171.9 |
|
Total Property, Plant and Equipment | | 7,319.8 |
| | 7,103.4 |
|
Accumulated Depreciation and Amortization | | 2,107.1 |
| | 2,048.7 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 5,212.7 |
| | 5,054.7 |
|
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Notes Receivable – Affiliated | | 32.3 |
| | 32.3 |
|
Regulatory Assets | | 1,016.4 |
| | 1,113.0 |
|
Securitized Assets | | 68.0 |
| | 85.9 |
|
Long-term Risk Management Assets | | — |
| | 19.2 |
|
Deferred Charges and Other Noncurrent Assets | | 116.0 |
| | 259.6 |
|
TOTAL OTHER NONCURRENT ASSETS | | 1,232.7 |
| | 1,510.0 |
|
| | | | |
TOTAL ASSETS | | $ | 6,664.1 |
| | $ | 7,137.9 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETSLIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20152016 and December 31, 20142015
(dollars in thousands)millions)
(Unaudited)
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2015 | | 2014 |
CURRENT ASSETS | | | | |
Cash and Cash Equivalents | | $ | 3,248 |
| | $ | 2,870 |
|
Restricted Cash for Securitized Funding | | 16,195 |
| | 28,687 |
|
Advances to Affiliates | | 279,129 |
| | 312,473 |
|
Accounts Receivable: | | | | |
Customers | | 35,711 |
| | 57,906 |
|
Affiliated Companies | | 57,240 |
| | 79,822 |
|
Accrued Unbilled Revenues | | 39,236 |
| | 35,755 |
|
Miscellaneous | | 1,246 |
| | 927 |
|
Allowance for Uncollectible Accounts | | (421 | ) | | (171 | ) |
Total Accounts Receivable | | 133,012 |
| | 174,239 |
|
Notes Receivable Due Within One Year – Affiliated | | — |
| | 86,000 |
|
Materials and Supplies | | 75,878 |
| | 60,909 |
|
Risk Management Assets | | — |
| | 7,242 |
|
Deferred Income Tax Benefits | | 20,568 |
| | 49,306 |
|
Accrued Tax Benefits | | 5,030 |
| | 6,100 |
|
Prepayments and Other Current Assets | | 11,141 |
| | 8,997 |
|
TOTAL CURRENT ASSETS | | 544,201 |
| | 736,823 |
|
| | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | | | | |
Transmission | | 2,181,389 |
| | 2,104,613 |
|
Distribution | | 4,231,051 |
| | 4,087,601 |
|
Other Property, Plant and Equipment | | 446,485 |
| | 390,848 |
|
Construction Work in Progress | | 212,093 |
| | 218,667 |
|
Total Property, Plant and Equipment | | 7,071,018 |
| | 6,801,729 |
|
Accumulated Depreciation and Amortization | | 2,086,931 |
| | 2,038,120 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 4,984,087 |
| | 4,763,609 |
|
| | | | |
OTHER NONCURRENT ASSETS | | | | |
Notes Receivable – Affiliated | | 32,245 |
| | 32,245 |
|
Regulatory Assets | | 1,150,864 |
| | 1,318,939 |
|
Securitized Assets | | 91,899 |
| | 109,999 |
|
Long-term Risk Management Assets | | 23,265 |
| | 45,102 |
|
Deferred Charges and Other Noncurrent Assets | | 118,942 |
| | 264,150 |
|
TOTAL OTHER NONCURRENT ASSETS | | 1,417,215 |
| | 1,770,435 |
|
| | | | |
TOTAL ASSETS | | $ | 6,945,503 |
| | $ | 7,270,867 |
|
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2016 | | 2015 |
CURRENT LIABILITIES | | | | |
Accounts Payable: | | |
| | |
|
General | | $ | 152.9 |
| | $ | 156.4 |
|
Affiliated Companies | | 90.9 |
| | 88.7 |
|
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2016 and December 31, 2015 Amounts Include $46.3 and $45.9, Respectively, Related to Ohio Phase-in-Recovery Funding) | | 46.4 |
| | 395.9 |
|
Risk Management Liabilities | | 5.6 |
| | 3.6 |
|
Customer Deposits | | 71.2 |
| | 65.4 |
|
Accrued Taxes | | 246.6 |
| | 528.3 |
|
Accrued Interest | | 38.4 |
| | 33.0 |
|
Other Current Liabilities | | 87.0 |
| | 154.3 |
|
TOTAL CURRENT LIABILITIES | | 739.0 |
| | 1,425.6 |
|
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated (September 30, 2016 and December 31, 2015 Amounts Include $93.7 and $139.4, Respectively, Related to Ohio Phase-in-Recovery Funding) | | 1,717.0 |
| | 1,761.8 |
|
Long-term Risk Management Liabilities | | 103.5 |
| | — |
|
Deferred Income Taxes | | 1,414.0 |
| | 1,383.2 |
|
Regulatory Liabilities and Deferred Investment Tax Credits | | 555.7 |
| | 514.2 |
|
Employee Benefits and Pension Obligations | | 27.7 |
| | 35.8 |
|
Deferred Credits and Other Noncurrent Liabilities | | 26.9 |
| | 30.7 |
|
TOTAL NONCURRENT LIABILITIES | | 3,844.8 |
| | 3,725.7 |
|
| | | | |
TOTAL LIABILITIES | | 4,583.8 |
| | 5,151.3 |
|
| | | | |
Rate Matters (Note 4) | |
| |
|
Commitments and Contingencies (Note 5) | |
| |
|
| | | | |
COMMON SHAREHOLDER’S EQUITY | | | | |
Common Stock – No Par Value: | | | | |
Authorized – 40,000,000 Shares | | |
| | |
Outstanding – 27,952,473 Shares | | 321.2 |
| | 321.2 |
|
Paid-in Capital | | 838.8 |
| | 838.8 |
|
Retained Earnings | | 917.0 |
| | 822.3 |
|
Accumulated Other Comprehensive Income (Loss) | | 3.3 |
| | 4.3 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,080.3 |
| | 1,986.6 |
|
| | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 6,664.1 |
| | $ | 7,137.9 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITYSTATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20152016 and December 31, 20142015
(dollars in thousands)millions)
(Unaudited)
|
| | | | | | | | |
| | September 30, | | December 31, |
| | 2015 | | 2014 |
CURRENT LIABILITIES | | | | |
Accounts Payable: | | |
| | |
|
General | | $ | 141,073 |
| | $ | 145,328 |
|
Affiliated Companies | | 88,324 |
| | 172,741 |
|
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2015 and December 31, 2014 Amounts Include $45,864 and $45,427, Respectively, Related to Ohio Phase-in-Recovery Funding) | | 395,938 |
| | 131,497 |
|
Risk Management Liabilities | | 2,823 |
| | 1,943 |
|
Customer Deposits | | 60,235 |
| | 53,922 |
|
Accrued Taxes | | 285,003 |
| | 420,772 |
|
Accrued Interest | | 45,452 |
| | 34,279 |
|
Other Current Liabilities | | 147,567 |
| | 179,093 |
|
TOTAL CURRENT LIABILITIES | | 1,166,415 |
| | 1,139,575 |
|
| | | | |
NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated (September 30, 2015 and December 31, 2014 Amounts Include $141,177 and $187,041, Respectively, Related to Ohio Phase-in-Recovery Funding) | | 1,770,112 |
| | 2,165,626 |
|
Long-term Risk Management Liabilities | | 4,871 |
| | 3,013 |
|
Deferred Income Taxes | | 1,402,369 |
| | 1,405,620 |
|
Regulatory Liabilities and Deferred Investment Tax Credits | | 535,458 |
| | 514,691 |
|
Employee Benefits and Pension Obligations | | 29,978 |
| | 36,662 |
|
Deferred Credits and Other Noncurrent Liabilities | | 28,682 |
| | 25,470 |
|
TOTAL NONCURRENT LIABILITIES | | 3,771,470 |
| | 4,151,082 |
|
| | | | |
TOTAL LIABILITIES | | 4,937,885 |
| | 5,290,657 |
|
| | | | |
Rate Matters (Note 4) | |
| |
|
Commitments and Contingencies (Note 5) | |
| |
|
| | | | |
COMMON SHAREHOLDER’S EQUITY | | | | |
Common Stock – No Par Value: | | | | |
Authorized – 40,000,000 Shares | | |
| | |
Outstanding – 27,952,473 Shares | | 321,201 |
| | 321,201 |
|
Paid-in Capital | | 838,782 |
| | 838,782 |
|
Retained Earnings | | 843,063 |
| | 814,625 |
|
Accumulated Other Comprehensive Income (Loss) | | 4,572 |
| | 5,602 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,007,618 |
| | 1,980,210 |
|
| | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY | | $ | 6,945,503 |
| | $ | 7,270,867 |
|
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2016 | | 2015 |
OPERATING ACTIVITIES | | |
| | |
|
Net Income | | $ | 244.7 |
| | $ | 184.7 |
|
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
| | |
|
Depreciation and Amortization | | 189.0 |
| | 178.6 |
|
Amortization of Generation Deferrals | | 173.0 |
| | 122.2 |
|
Deferred Income Taxes | | 28.6 |
| | 28.1 |
|
Carrying Costs Income | | (4.0 | ) | | (10.0 | ) |
Allowance for Equity Funds Used During Construction | | (3.7 | ) | | (7.0 | ) |
Mark-to-Market of Risk Management Contracts | | 124.7 |
| | 31.8 |
|
Pension Contributions to Qualified Plan Trust | | (7.1 | ) | | (7.7 | ) |
Property Taxes | | 169.1 |
| | 148.4 |
|
Purchased Electricity Over/Under-Recovery, Net | | (21.1 | ) | | (15.7 | ) |
Deferral of Ohio Capacity Costs, Net | | — |
| | (30.7 | ) |
Change in Other Noncurrent Assets | | (124.9 | ) | | 27.8 |
|
Change in Other Noncurrent Liabilities | | 17.2 |
| | 32.3 |
|
Changes in Certain Components of Working Capital: | | |
| | |
|
Accounts Receivable, Net | | 8.8 |
| | 41.2 |
|
Materials and Supplies | | 0.5 |
| | (15.0 | ) |
Accounts Payable | | 2.0 |
| | (78.8 | ) |
Accrued Taxes, Net | | (291.1 | ) | | (134.7 | ) |
Other Current Assets | | (4.5 | ) | | (3.2 | ) |
Other Current Liabilities | | (26.9 | ) | | 1.7 |
|
Net Cash Flows from Operating Activities | | 474.3 |
| | 494.0 |
|
| | | | |
INVESTING ACTIVITIES | | |
| | |
|
Construction Expenditures | | (276.4 | ) | | (346.8 | ) |
Change in Restricted Cash for Securitized Funding | | 11.6 |
| | 12.5 |
|
Change in Advances to Affiliates, Net | | 330.9 |
| | 33.3 |
|
Proceeds from Notes Receivable – Affiliated | | — |
| | 86.0 |
|
Other Investing Activities | | 9.0 |
| | 10.9 |
|
Net Cash Flows from (Used for) Investing Activities | | 75.1 |
| | (204.1 | ) |
| | | | |
FINANCING ACTIVITIES | | |
| | |
|
Retirement of Long-term Debt – Nonaffiliated | | (395.9 | ) | | (131.5 | ) |
Principal Payments for Capital Lease Obligations | | (3.1 | ) | | (2.9 | ) |
Dividends Paid on Common Stock | | (150.0 | ) | | (156.3 | ) |
Other Financing Activities | | 0.5 |
| | 1.2 |
|
Net Cash Flows Used for Financing Activities | | (548.5 | ) | | (289.5 | ) |
| | | | |
Net Increase in Cash and Cash Equivalents | | 0.9 |
| | 0.4 |
|
Cash and Cash Equivalents at Beginning of Period | | 3.1 |
| | 2.9 |
|
Cash and Cash Equivalents at End of Period | | $ | 4.0 |
| | $ | 3.3 |
|
| | | | |
SUPPLEMENTARY INFORMATION | | |
| | |
|
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 78.2 |
| | $ | 79.0 |
|
Net Cash Paid for Income Taxes | | 178.0 |
| | 24.1 |
|
Noncash Acquisitions Under Capital Leases | | 2.4 |
| | 2.1 |
|
Construction Expenditures Included in Current Liabilities as of September 30, | | 30.0 |
| | 30.2 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2015 and 2014
(in thousands)
(Unaudited)
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2015 | | 2014 |
OPERATING ACTIVITIES | | |
| | |
|
Net Income | | $ | 184,688 |
| | $ | 171,369 |
|
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
| | |
|
Depreciation and Amortization | | 178,609 |
| | 165,152 |
|
Amortization of Generation Deferrals | | 122,221 |
| | 82,818 |
|
Deferred Income Taxes | | 28,099 |
| | 27,990 |
|
Carrying Costs Income | | (10,037 | ) | | (19,594 | ) |
Allowance for Equity Funds Used During Construction | | (7,015 | ) | | (4,893 | ) |
Mark-to-Market of Risk Management Contracts | | 31,818 |
| | (5,003 | ) |
Pension Contributions to Qualified Plan Trust | | (7,671 | ) | | (6,547 | ) |
Property Taxes | | 148,407 |
| | 148,124 |
|
Fuel Over/Under-Recovery, Net | | (15,674 | ) | | 37,326 |
|
Deferral of Ohio Capacity Costs, Net | | (30,662 | ) | | (138,737 | ) |
Change in Other Noncurrent Assets | | 29,168 |
| | 35,962 |
|
Change in Other Noncurrent Liabilities | | 30,913 |
| | 59,081 |
|
Changes in Certain Components of Working Capital: | | |
| | |
|
Accounts Receivable, Net | | 41,227 |
| | (20,395 | ) |
Materials and Supplies | | (14,969 | ) | | (1,247 | ) |
Accounts Payable | | (78,831 | ) | | (83,029 | ) |
Customer Deposits | | 6,313 |
| | 2,973 |
|
Accrued Taxes, Net | | (134,699 | ) | | (173,470 | ) |
Other Current Assets | | (3,233 | ) | | (947 | ) |
Other Current Liabilities | | (4,707 | ) | | 26,039 |
|
Net Cash Flows from Operating Activities | | 493,965 |
| | 302,972 |
|
| | | | |
INVESTING ACTIVITIES | | |
| | |
|
Construction Expenditures | | (346,831 | ) | | (327,972 | ) |
Change in Restricted Cash for Securitized Funding | | 12,492 |
| | 1,653 |
|
Change in Advances to Affiliates, Net | | 33,344 |
| | 315,325 |
|
Proceeds from Notes Receivable – Affiliated | | 86,000 |
| | 178,580 |
|
Other Investing Activities | | 10,882 |
| | 6,807 |
|
Net Cash Flows from (Used for) Investing Activities | | (204,113 | ) | | 174,393 |
|
| | | | |
FINANCING ACTIVITIES | | |
| | |
|
Retirement of Long-term Debt – Nonaffiliated | | (131,484 | ) | | (438,583 | ) |
Principal Payments for Capital Lease Obligations | | (2,937 | ) | | (3,912 | ) |
Dividends Paid on Common Stock | | (156,250 | ) | | (35,000 | ) |
Other Financing Activities | | 1,197 |
| | 1,015 |
|
Net Cash Flows Used for Financing Activities | | (289,474 | ) | | (476,480 | ) |
| | | | |
Net Increase in Cash and Cash Equivalents | | 378 |
| | 885 |
|
Cash and Cash Equivalents at Beginning of Period | | 2,870 |
| | 3,004 |
|
Cash and Cash Equivalents at End of Period | | $ | 3,248 |
| | $ | 3,889 |
|
| | | | |
SUPPLEMENTARY INFORMATION | | |
| | |
|
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 79,019 |
| | $ | 90,188 |
|
Net Cash Paid for Income Taxes | | 24,060 |
| | 15,523 |
|
Noncash Acquisitions Under Capital Leases | | 2,115 |
| | 4,505 |
|
Construction Expenditures Included in Current Liabilities as of September 30, | | 30,209 |
| | 45,691 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 179. |
OHIO POWER COMPANY AND SUBSIDIARIES
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES
The condensed notes to OPCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to OPCo.
|
| |
| Page
Number
|
| |
Significant Accounting Matters | |
New Accounting Pronouncements | |
Comprehensive Income | |
Rate Matters | |
Commitments, Guarantees and Contingencies | |
Benefit Plans | |
Business Segments | |
Derivatives and Hedging | |
Fair Value Measurements | |
Income Taxes | |
Financing Activities | |
Variable Interest Entities | |
Property, Plant and Equipment | |
Disposition Plant Severance | |
PUBLIC SERVICE COMPANY OF OKLAHOMA
PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
EXECUTIVE OVERVIEW
Regulatory Activity
2015 Oklahoma Base Rate Case
In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million, which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service.
In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million, will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC.
In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million, based upon returns on common equity ranging from 8.75% to 9.3%, and increases to depreciation expense ranging from $23 million to $46 million. Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certain intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC are scheduled for December 2015. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2015 Oklahoma Base Rate Case” section of PSO Rate Matters in Note 4.
Litigation and Environmental Issues
In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in the 2014 Annual Report. Also, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 179. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.
See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 256 for additional discussion of relevant factors.
RESULTS OF OPERATIONS
KWh Sales/Degree Days
Summary of KWh Energy Sales
| | | Three Months Ended | | Nine Months Ended | Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, | September 30, | | September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in millions of KWhs) | (in millions of KWhs) |
Retail: | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
Residential | 2,126 |
| | 1,981 |
| | 4,966 |
| | 4,978 |
| 2,184 |
| | 2,126 |
| | 4,925 |
| | 4,966 |
|
Commercial | 1,568 |
| | 1,455 |
| | 4,028 |
| | 3,905 |
| 1,529 |
| | 1,568 |
| | 4,001 |
| | 4,028 |
|
Industrial | 1,408 |
| | 1,407 |
| | 4,039 |
| | 3,939 |
| 1,494 |
| | 1,408 |
| | 4,162 |
| | 4,039 |
|
Miscellaneous | 365 |
| | 356 |
| | 958 |
| | 956 |
| 369 |
| | 365 |
| | 955 |
| | 958 |
|
Total Retail | 5,467 |
| | 5,199 |
| | 13,991 |
| | 13,778 |
| 5,576 |
| | 5,467 |
| | 14,043 |
| | 13,991 |
|
| | | | | | | | | | | | | | |
Wholesale | 28 |
| | 42 |
| | 166 |
| | 318 |
| 113 |
| | 28 |
| | 226 |
| | 166 |
|
| | | | | | | | | | | | | | |
Total KWhs | 5,495 |
| | 5,241 |
| | 14,157 |
| | 14,096 |
| 5,689 |
| | 5,495 |
| | 14,269 |
| | 14,157 |
|
Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.
Summary of Heating and Cooling Degree Days
| | | Three Months Ended | | Nine Months Ended | Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, | September 30, | | September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in degree days) | (in degree days) |
Actual - Heating (a) | — |
| | — |
| | 1,176 |
| | 1,417 |
| — |
| | — |
| | 782 |
| | 1,176 |
|
Normal - Heating (b) | 1 |
| | 1 |
| | 1,089 |
| | 1,086 |
| 1 |
| | 1 |
| | 1,105 |
| | 1,089 |
|
| | | | | | | | | | | | | | |
Actual - Cooling (c) | 1,444 |
| | 1,259 |
| | 2,103 |
| | 1,935 |
| 1,535 |
| | 1,444 |
| | 2,247 |
| | 2,103 |
|
Normal - Cooling (b) | 1,387 |
| | 1,394 |
| | 2,053 |
| | 2,058 |
| 1,390 |
| | 1,387 |
| | 2,055 |
| | 2,053 |
|
| |
(a) | Western Region heatingHeating degree days are calculated on a 55 degree temperature base. |
| |
(b) | Normal Heating/Cooling represents the thirty-year average of degree days. |
| |
(c) | Western Region coolingCooling degree days are calculated on a 65 degree temperature base. |
Third Quarter of 20152016 Compared to Third Quarter of 20142015
| | Reconciliation of Third Quarter of 2014 to Third Quarter of 2015 | |
Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 | | Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 |
Net Income | (in millions) | | | | | |
Third Quarter of 2014 | | $ | 45 |
| |
Third Quarter of 2015 | | | $ | 44.7 |
|
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins (a) | | 13 |
| | 24.6 |
|
Off-system Sales | | | 0.3 |
|
Transmission Revenues | | 1 |
| | (3.4 | ) |
Other Revenues | | 1 |
| | 0.4 |
|
Total Change in Gross Margin | | 15 |
| | 21.9 |
|
| | | | |
Changes in Expenses and Other: | | |
| | |
|
Other Operation and Maintenance | | (11 | ) | | (1.9 | ) |
Depreciation and Amortization | | (6 | ) | | (6.3 | ) |
Taxes Other Than Income Taxes | | | 0.2 |
|
Allowance for Equity Funds Used During Construction | | 2 |
| | (1.3 | ) |
Interest Expense | | (1 | ) | | 0.1 |
|
Total Change in Expenses and Other | | (16 | ) | | (9.2 | ) |
| | |
| | |
|
Income Tax Expense | | 1 |
| | (4.6 | ) |
| | |
| | |
|
Third Quarter of 2015 | | $ | 45 |
| |
Third Quarter of 2016 | | | $ | 52.8 |
|
| |
(a) | Includes firm wholesale sales to municipals and cooperatives. |
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
Retail Margins increased $13$25 million primarily due to the following:
An $11A $21 million increase primarily duerelated to revenueinterim base rate increases from rate riders.implemented in January 2016. This increase in retail margins has corresponding increases to riders/trackers recognized in other expense items below.
A $9$4 million increase in weather-related usage primarily due to a 15%6% increase in cooling degree days.
These increases were partially offset by:
An $8Transmission Revenues decreased $3 million decrease primarily due to lower weather-normalized residential sales.an accrual for SPP sponsor-funded transmission upgrades.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $11$2 million primarily due to the following:
A $5 million increase in distribution expenses primarily due to increased vegetation management expenses and amortization of 2013 storm restoration expenses beginning in the second quarter of 2015.
A $2 million increase in generation plant maintenance expenses.
A $2 million increase in transmission expenses primarily due to increased SPP transmission services.
A $2 million increase in distribution expenses primarily due an increase in energy efficiency programs.
These increases were partially offset by:
A $4 million decrease in general and administrative expenses.
A $2 million decrease in generation plant maintenance expenses.
Depreciation and Amortizationexpenses increased $6 million primarily due to the following:
A $4$9 million increase in depreciation primarily related to interim rate increases.
This increase was partially offset by:
A $3 million decrease in amortization related to an advanced metering rider implemented in November 2014.infrastructure projects.
A $2Income Tax Expense increased $5 million increaseprimarily due to a higher depreciable base.
155an increase in pretax book income.
Nine Months Ended September 30, 20152016 Compared to Nine Months Ended September 30, 20142015
| | Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015 | |
Reconciliation of Nine Months Ended September 30, 2015 to Nine Months Ended September 30, 2016 | | Reconciliation of Nine Months Ended September 30, 2015 to Nine Months Ended September 30, 2016 |
Net Income | (in millions) | | | | | |
Nine Months Ended September 30, 2014 | | $ | 76 |
| |
Nine Months Ended September 30, 2015 | | | $ | 85.5 |
|
| | |
| | |
|
Changes in Gross Margin: | | |
| | |
|
Retail Margins (a) | | 32 |
| | 49.6 |
|
Off-system Sales | | | 0.2 |
|
Transmission Revenues | | 2 |
| | (3.4 | ) |
Other Revenues | | 1 |
| | 1.4 |
|
Total Change in Gross Margin | | 35 |
| | 47.8 |
|
| | |
| | |
|
Changes in Expenses and Other: | | |
| | |
|
Other Operation and Maintenance | | (5 | ) | | (9.8 | ) |
Depreciation and Amortization | | (17 | ) | | (19.7 | ) |
Interest Income | | | 0.2 |
|
Allowance for Equity Funds Used During Construction | | 4 |
| | (1.1 | ) |
Interest Expense | | (3 | ) | | (0.2 | ) |
Total Change in Expenses and Other | | (21 | ) | | (30.6 | ) |
| | |
| | |
|
Income Tax Expense | | (4 | ) | | (5.3 | ) |
| | |
| | |
|
Nine Months Ended September 30, 2015 | | $ | 86 |
| |
Nine Months Ended September 30, 2016 | | | $ | 97.4 |
|
| |
(a) | Includes firm wholesale sales to municipals and cooperatives. |
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
Retail Margins increased $32$50 million primarily duerelated to the following:
A $27 million increase primarily due to revenueinterim base rate increases from rate riders.implemented in January 2016. This increase in retail margins has corresponding increases to riders/trackers recognized in other expense items below.
A $7Transmission Revenues decreased $3 million net increase in weather-related usage primarily due to a 9% increase in cooling degree days, partially offset by a decrease in heating degree days.an accrual for SPP sponsor-funded transmission upgrades.
These increases were partially offset by:
A $3 million decrease primarily due to lower weather-normalized residential sales.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $5$10 million primarily due to the following:
A $3$12 million increase in transmission expenses primarily due to increased SPP transmission services.
A $4 million increase in distribution expenses primarily due to amortization of 2013 storm restoration expenses beginning in the second quarter of 2015.
A $3 million increase in transmission expenses primarily due to increased SPP transmission services.
A $2 millionMay 2015 and an increase in energy efficiency program expenses.programs.
These increases were partially offset by:
A $3$5 million decrease in generation plant maintenance expenses.
A $2 million decrease in general and administrative expenses.
Depreciation and Amortizationexpenses increased $17$20 million primarily due to the following:
A $10$25 million increase in depreciation primarily related to interim rate increases.
This increase was partially offset by:
A $6 million decrease in amortization related to an advanced metering rider implemented in November 2014.
A $6 million increase due to a higher depreciable base.
Allowance for Equity Funds Used During Construction increased $4 million primarily due to increased environmentalinfrastructure projects.
Interest Expense increased $3 million primarily due to increased long-term debt outstanding.
Income Tax Expense increased $4$5 million primarily due to an increase in pretax book income.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2014 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.
See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 256 for a discussion of accounting pronouncements.
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
REVENUES | | | | | | | | |
| | | | | | | | |
|
Electric Generation, Transmission and Distribution | | $ | 418,592 |
| | $ | 415,193 |
| | $ | 1,040,876 |
| | $ | 1,028,427 |
| | $ | 400.9 |
| | $ | 418.6 |
| | $ | 971.3 |
| | $ | 1,040.9 |
|
Sales to AEP Affiliates | | 1,062 |
| | 789 |
| | 3,505 |
| | 6,240 |
| | 0.1 |
| | 1.1 |
| | 2.0 |
| | 3.5 |
|
Other Revenues | | 709 |
| | 1,009 |
| | 2,258 |
| | 2,524 |
| | 0.7 |
| | 0.6 |
| | 2.9 |
| | 2.2 |
|
TOTAL REVENUES | | 420,363 |
| | 416,991 |
| | 1,046,639 |
| | 1,037,191 |
| | 401.7 |
| | 420.3 |
| | 976.2 |
| | 1,046.6 |
|
| | | | | | | | | | | | | | | | |
EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Fuel and Other Consumables Used for Electric Generation | | 87,680 |
| | 85,018 |
| | 226,260 |
| | 192,567 |
| | 16.4 |
| | 87.7 |
| | 43.0 |
| | 226.3 |
|
Purchased Electricity for Resale | | 103,226 |
| | 117,521 |
| | 253,785 |
| | 301,816 |
| | 130.8 |
| | 103.2 |
| | 315.3 |
| | 253.8 |
|
Purchased Electricity from AEP Affiliates | | — |
| | — |
| | — |
| | 11,024 |
| | 3.2 |
| | — |
| | 3.6 |
| | — |
|
Other Operation | | 77,541 |
| | 71,605 |
| | 199,334 |
| | 193,101 |
| | 81.0 |
| | 77.5 |
| | 211.8 |
| | 199.3 |
|
Maintenance | | 27,239 |
| | 21,800 |
| | 74,322 |
| | 76,223 |
| | 25.6 |
| | 27.2 |
| | 71.6 |
| | 74.3 |
|
Depreciation and Amortization | | 30,832 |
| | 24,496 |
| | 90,148 |
| | 73,085 |
| | 37.2 |
| | 30.9 |
| | 109.9 |
| | 90.2 |
|
Taxes Other Than Income Taxes | | 9,327 |
| | 9,137 |
| | 27,843 |
| | 27,757 |
| | 9.1 |
| | 9.3 |
| | 27.8 |
| | 27.8 |
|
TOTAL EXPENSES | | 335,845 |
| | 329,577 |
| | 871,692 |
| | 875,573 |
| | 303.3 |
| | 335.8 |
| | 783.0 |
| | 871.7 |
|
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | 84,518 |
| | 87,414 |
| | 174,947 |
| | 161,618 |
| | 98.4 |
| | 84.5 |
| | 193.2 |
| | 174.9 |
|
| | | | | | | | | | | | | | | | |
Other Income (Expense): | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Interest Income | | 127 |
| | 137 |
| | 255 |
| | 138 |
| | 0.2 |
| | 0.2 |
| | 0.5 |
| | 0.3 |
|
Allowance for Equity Funds Used During Construction | | 2,342 |
| | 194 |
| | 5,952 |
| | 2,215 |
| | 1.1 |
| | 2.4 |
| | 4.9 |
| | 6.0 |
|
Interest Expense | | (14,950 | ) | | (13,913 | ) | | (44,372 | ) | | (41,009 | ) | | (14.9 | ) | | (15.0 | ) | | (44.6 | ) | | (44.4 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | 72,037 |
| | 73,832 |
| | 136,782 |
| | 122,962 |
| | 84.8 |
| | 72.1 |
| | 154.0 |
| | 136.8 |
|
| | | | | | | | | | | | | | | | |
Income Tax Expense | | 27,298 |
| | 28,746 |
| | 51,260 |
| | 46,979 |
| | 32.0 |
| | 27.4 |
| | 56.6 |
| | 51.3 |
|
| | | | | | | | | | | | | | | | |
NET INCOME | | $ | 44,739 |
| | $ | 45,086 |
| | $ | 85,522 |
| | $ | 75,983 |
| | $ | 52.8 |
| | $ | 44.7 |
| | $ | 97.4 |
| | $ | 85.5 |
|
|
| | | | |
The common stock of PSO is wholly-owned by AEP.Parent. |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
Net Income | | $ | 44,739 |
| | $ | 45,086 |
| | $ | 85,522 |
| | $ | 75,983 |
| | $ | 52.8 |
| | $ | 44.7 |
| | $ | 97.4 |
| | $ | 85.5 |
|
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE LOSS, NET OF TAXES | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Cash Flow Hedges, Net of Tax of $101 and $102 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $306 and $337 for the Nine Months Ended September 30, 2015 and 2014, Respectively | | (189 | ) | | (190 | ) | | (569 | ) | | (626 | ) | |
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2016 and 2015, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2016 and 2015, Respectively | | | (0.2 | ) | | (0.1 | ) | | (0.6 | ) | | (0.5 | ) |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
TOTAL COMPREHENSIVE INCOME | | $ | 44,550 |
| | $ | 44,896 |
| | $ | 84,953 |
| | $ | 75,357 |
| | $ | 52.6 |
| | $ | 44.6 |
| | $ | 96.8 |
| | $ | 85.0 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'SSHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2013 | $ | 157,230 |
| | $ | 364,037 |
| | $ | 415,076 |
| | $ | 5,758 |
| | $ | 942,101 |
| |
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2014 | | $ | 157.2 |
| | $ | 364.0 |
| | $ | 502.0 |
| | $ | 5.0 |
| | $ | 1,028.2 |
|
| | | | | | | | | | | | | | | | | | |
Net Income | |
| | |
| | 75,983 |
| | |
| | 75,983 |
| |
| | |
| | 85.5 |
| | |
| | 85.5 |
|
Other Comprehensive Loss | |
| | |
| | |
| | (626 | ) | | (626 | ) | |
| | |
| | |
| | (0.5 | ) | | (0.5 | ) |
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2014 | $ | 157,230 |
| | $ | 364,037 |
| | $ | 491,059 |
| | $ | 5,132 |
| | $ | 1,017,458 |
| |
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2015 | | $ | 157.2 |
| | $ | 364.0 |
| | $ | 587.5 |
| | $ | 4.5 |
| | $ | 1,113.2 |
|
| |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2014 | $ | 157,230 |
| | $ | 364,037 |
| | $ | 502,005 |
| | $ | 4,943 |
| | $ | 1,028,215 |
| |
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2015 | | $ | 157.2 |
| | $ | 364.0 |
| | $ | 594.5 |
| | $ | 4.2 |
| | $ | 1,119.9 |
|
| | | | | | | | | | | | | | | | | | |
Net Income | |
| | |
| | 85,522 |
| | |
| | 85,522 |
| |
| | |
| | 97.4 |
| | |
| | 97.4 |
|
Other Comprehensive Loss | |
| | |
| | |
| | (569 | ) | | (569 | ) | |
| | |
| | |
| | (0.6 | ) | | (0.6 | ) |
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2015 | $ | 157,230 |
| | $ | 364,037 |
| | $ | 587,527 |
| | $ | 4,374 |
| | $ | 1,113,168 |
| |
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2016 | | $ | 157.2 |
| | $ | 364.0 |
| | $ | 691.9 |
| | $ | 3.6 |
| | $ | 1,216.7 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 20152016 and December 31, 20142015
(in thousands)millions)
(Unaudited)
| | | | September 30, | | December 31, | | September 30, | | December 31, |
| | 2015 | | 2014 | | 2016 | | 2015 |
CURRENT ASSETS | | | | | | | | |
Cash and Cash Equivalents | | $ | 1,663 |
| | $ | 1,352 |
| | $ | 2.0 |
| | $ | 1.4 |
|
Advances to Affiliates | | 116,345 |
| | — |
| | 51.1 |
| | 80.6 |
|
Accounts Receivable: | | | | | | | | |
Customers | | 24,770 |
| | 28,448 |
| | 17.8 |
| | 26.0 |
|
Affiliated Companies | | 25,117 |
| | 22,114 |
| | 23.5 |
| | 20.8 |
|
Miscellaneous | | 9,559 |
| | 6,026 |
| | 4.4 |
| | 3.3 |
|
Allowance for Uncollectible Accounts | | (359 | ) | | (147 | ) | | (0.6 | ) | | (0.6 | ) |
Total Accounts Receivable | | 59,087 |
| | 56,441 |
| | 45.1 |
| | 49.5 |
|
Fuel | | 15,864 |
| | 16,436 |
| | 21.8 |
| | 17.6 |
|
Materials and Supplies | | 52,519 |
| | 50,880 |
| | 50.1 |
| | 51.9 |
|
Risk Management Assets | | 1,035 |
| | — |
| | 1.1 |
| | 0.6 |
|
Deferred Income Tax Benefits | | 8,975 |
| | — |
| |
Accrued Tax Benefits | | 19,093 |
| | 24,369 |
| | 7.6 |
| | 37.3 |
|
Regulatory Asset for Under-Recovered Fuel Costs | | — |
| | 35,699 |
| | 4.1 |
| | — |
|
Prepayments and Other Current Assets | | 7,280 |
| | 6,524 |
| | 10.8 |
| | 6.5 |
|
TOTAL CURRENT ASSETS | | 281,861 |
| | 191,701 |
| | 193.7 |
| | 245.4 |
|
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | 1,296,921 |
| | 1,264,724 |
| | 1,552.1 |
| | 1,302.6 |
|
Transmission | | 805,505 |
| | 788,911 |
| | 832.1 |
| | 815.4 |
|
Distribution | | 2,185,778 |
| | 2,080,221 |
| | 2,284.4 |
| | 2,206.7 |
|
Other Property, Plant and Equipment (Including Plant to be Retired) | | 435,807 |
| | 421,568 |
| |
Other Property, Plant and Equipment (December 31, 2015 Amount Includes 2016 Plant Retirement) | | | 243.0 |
| | 405.7 |
|
Construction Work in Progress | | 274,470 |
| | 204,753 |
| | 127.9 |
| | 315.3 |
|
Total Property, Plant and Equipment | | 4,998,481 |
| | 4,760,177 |
| | 5,039.5 |
| | 5,045.7 |
|
Accumulated Depreciation and Amortization | | 1,383,116 |
| | 1,319,554 |
| | 1,297.4 |
| | 1,352.5 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 3,615,365 |
| | 3,440,623 |
| | 3,742.1 |
| | 3,693.2 |
|
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | 180,605 |
| | 154,327 |
| | 322.2 |
| | 214.8 |
|
Employee Benefits and Pension Assets | | 21,231 |
| | 19,335 |
| | 15.7 |
| | 10.6 |
|
Deferred Charges and Other Noncurrent Assets | | 15,664 |
| | 7,557 |
| | 18.1 |
| | 6.4 |
|
TOTAL OTHER NONCURRENT ASSETS | | 217,500 |
| | 181,219 |
| | 356.0 |
| | 231.8 |
|
| | | | | | | | |
TOTAL ASSETS | | $ | 4,114,726 |
| | $ | 3,813,543 |
| | $ | 4,291.8 |
| | $ | 4,170.4 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'SSHAREHOLDER’S EQUITY
September 30, 20152016 and December 31, 20142015
(Unaudited)
| | | | September 30, | | December 31, | | September 30, | | December 31, |
| | 2015 | | 2014 | | 2016 | | 2015 |
| | (in thousands) | | (in millions) |
CURRENT LIABILITIES | | | | | | | | |
Advances from Affiliates | | $ | — |
| | $ | 154,249 |
| |
Accounts Payable: | | |
| | |
| | |
| | |
|
General | | 98,777 |
| | 92,672 |
| | $ | 116.7 |
| | $ | 108.2 |
|
Affiliated Companies | | 37,267 |
| | 51,744 |
| | 40.3 |
| | 51.5 |
|
Long-term Debt Due Within One Year – Nonaffiliated | | 150,437 |
| | 427 |
| | 125.5 |
| | 275.4 |
|
Risk Management Liabilities | | 70 |
| | 918 |
| | — |
| | 0.2 |
|
Customer Deposits | | 50,147 |
| | 48,700 |
| | 50.2 |
| | 50.3 |
|
Accrued Taxes | | 36,637 |
| | 20,887 |
| | 39.3 |
| | 23.6 |
|
Accrued Interest | | 15,499 |
| | 12,699 |
| | 14.5 |
| | 15.1 |
|
Regulatory Liability for Over-Recovered Fuel Costs | | 41,175 |
| | — |
| | — |
| | 76.1 |
|
Other Current Liabilities | | 56,255 |
| | 58,878 |
| | 55.0 |
| | 64.4 |
|
TOTAL CURRENT LIABILITIES | | 486,264 |
| | 441,174 |
| | 441.5 |
| | 664.8 |
|
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | 1,140,536 |
| | 1,040,609 |
| | 1,160.7 |
| | 1,010.7 |
|
Long-term Risk Management Liabilities | | 8 |
| | — |
| |
Deferred Income Taxes | | 958,168 |
| | 898,352 |
| | 1,055.0 |
| | 971.8 |
|
Regulatory Liabilities and Deferred Investment Tax Credits | | 339,161 |
| | 334,479 |
| | 340.0 |
| | 335.1 |
|
Asset Retirement Obligations | | 42,680 |
| | 37,030 |
| | 52.5 |
| | 39.9 |
|
Employee Benefits and Pension Obligations | | 16,456 |
| | 20,095 |
| | 13.8 |
| | 14.5 |
|
Deferred Credits and Other Noncurrent Liabilities | | 18,285 |
| | 13,589 |
| | 11.6 |
| | 13.7 |
|
TOTAL NONCURRENT LIABILITIES | | 2,515,294 |
| | 2,344,154 |
| | 2,633.6 |
| | 2,385.7 |
|
| | | | | | | | |
TOTAL LIABILITIES | | 3,001,558 |
| | 2,785,328 |
| | 3,075.1 |
| | 3,050.5 |
|
| | | | | | | | |
Rate Matters (Note 4) | |
| |
| |
| |
|
Commitments and Contingencies (Note 5) | |
| |
| |
| |
|
| | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | |
Common Stock – Par Value – $15 Per Share: | | | | | | | | |
Authorized – 11,000,000 Shares | | |
| | | | |
| | |
Issued – 10,482,000 Shares | | |
| | | | |
| | |
Outstanding – 9,013,000 Shares | | 157,230 |
| | 157,230 |
| | 157.2 |
| | 157.2 |
|
Paid-in Capital | | 364,037 |
| | 364,037 |
| | 364.0 |
| | 364.0 |
|
Retained Earnings | | 587,527 |
| | 502,005 |
| | 691.9 |
| | 594.5 |
|
Accumulated Other Comprehensive Income (Loss) | | 4,374 |
| | 4,943 |
| | 3.6 |
| | 4.2 |
|
TOTAL COMMON SHAREHOLDER’S EQUITY | | 1,113,168 |
| | 1,028,215 |
| | 1,216.7 |
| | 1,119.9 |
|
| | | | | | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY | | $ | 4,114,726 |
| | $ | 3,813,543 |
| |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | | $ | 4,291.8 |
| | $ | 4,170.4 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2016 | | 2015 |
OPERATING ACTIVITIES | | |
| | |
| | |
| | |
|
Net Income | | $ | 85,522 |
| | $ | 75,983 |
| | $ | 97.4 |
| | $ | 85.5 |
|
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
| | |
| | |
| | |
|
Depreciation and Amortization | | 90,148 |
| | 73,085 |
| | 109.9 |
| | 90.2 |
|
Deferred Income Taxes | | 40,052 |
| | 27,327 |
| | 79.5 |
| | 40.1 |
|
Allowance for Equity Funds Used During Construction | | (5,952 | ) | | (2,215 | ) | | (4.9 | ) | | (6.0 | ) |
Mark-to-Market of Risk Management Contracts | | (1,875 | ) | | 432 |
| | (0.7 | ) | | (1.9 | ) |
Pension Contributions to Qualified Plan Trust | | (5,795 | ) | | (4,439 | ) | | (5.6 | ) | | (5.8 | ) |
Property Taxes | | (8,049 | ) | | (7,970 | ) | | (8.0 | ) | | (8.0 | ) |
Fuel Over/Under-Recovery, Net | | 76,874 |
| | (33,246 | ) | |
Deferred Fuel Over/Under-Recovery, Net | | | (80.2 | ) | | 76.9 |
|
Change in Other Noncurrent Assets | | (13,066 | ) | | 2,035 |
| | (18.8 | ) | | (13.6 | ) |
Change in Other Noncurrent Liabilities | | 7,733 |
| | (2,015 | ) | | (3.7 | ) | | 8.2 |
|
Changes in Certain Components of Working Capital: | | |
| | |
| | |
| | |
|
Accounts Receivable, Net | | (2,646 | ) | | 333 |
| | 4.4 |
| | (2.6 | ) |
Fuel, Materials and Supplies | | (1,067 | ) | | 5,755 |
| | (2.4 | ) | | (1.1 | ) |
Accounts Payable | | (9,339 | ) | | (28,643 | ) | | 23.1 |
| | (9.3 | ) |
Accrued Taxes, Net | | 21,026 |
| | 32,131 |
| | 45.4 |
| | 21.0 |
|
Other Current Assets | | (1,866 | ) | | (4,034 | ) | | (2.2 | ) | | (1.9 | ) |
Other Current Liabilities | | 7,977 |
| | 17,024 |
| | (1.1 | ) | | 8.0 |
|
Net Cash Flows from Operating Activities | | 279,677 |
| | 151,543 |
| | 232.1 |
| | 279.7 |
|
| | | | | | | | |
INVESTING ACTIVITIES | | |
| | |
| | |
| | |
|
Construction Expenditures | | (262,887 | ) | | (256,741 | ) | | (266.8 | ) | | (262.9 | ) |
Change in Advances to Affiliates, Net | | (116,345 | ) | | — |
| | 29.5 |
| | (116.3 | ) |
Other Investing Activities | | 7,679 |
| | 2,881 |
| | 8.7 |
| | 7.6 |
|
Net Cash Flows Used for Investing Activities | | (371,553 | ) | | (253,860 | ) | | (228.6 | ) | | (371.6 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | |
| | |
| | |
| | |
|
Issuance of Long-term Debt – Nonaffiliated | | 248,785 |
| | 74,973 |
| | 150.0 |
| | 248.8 |
|
Change in Advances from Affiliates, Net | | (154,249 | ) | | 64,095 |
| | — |
| | (154.2 | ) |
Retirement of Long-term Debt – Nonaffiliated | | (319 | ) | | (34,010 | ) | | (150.3 | ) | | (0.3 | ) |
Principal Payments for Capital Lease Obligations | | (2,765 | ) | | (2,785 | ) | | (3.0 | ) | | (2.8 | ) |
Other Financing Activities | | 735 |
| | 595 |
| | 0.4 |
| | 0.7 |
|
Net Cash Flows from Financing Activities | | 92,187 |
| | 102,868 |
| |
Net Cash Flows from (Used for) Financing Activities | | | (2.9 | ) | | 92.2 |
|
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | 311 |
| | 551 |
| | 0.6 |
| | 0.3 |
|
Cash and Cash Equivalents at Beginning of Period | | 1,352 |
| | 1,277 |
| | 1.4 |
| | 1.4 |
|
Cash and Cash Equivalents at End of Period | | $ | 1,663 |
| | $ | 1,828 |
| | $ | 2.0 |
| | $ | 1.7 |
|
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | |
| | |
| | |
| | |
|
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 40,562 |
| | $ | 37,458 |
| | $ | 45.0 |
| | $ | 40.6 |
|
Net Cash Paid (Received) for Income Taxes | | 12,772 |
| | (416 | ) | | (50.3 | ) | | 12.8 |
|
Noncash Acquisitions Under Capital Leases | | 1,546 |
| | 2,098 |
| | 2.2 |
| | 1.5 |
|
Construction Expenditures Included in Current Liabilities as of September 30, | | 37,328 |
| | 33,527 |
| | 20.2 |
| | 37.3 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES
The condensed notes to PSO’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to PSO.
|
| |
| Page
Number
|
| |
Significant Accounting Matters | |
New Accounting Pronouncements | |
Comprehensive Income | |
Rate Matters | |
Commitments, Guarantees and Contingencies | |
Benefit Plans | |
Business Segments | |
Derivatives and Hedging | |
Fair Value Measurements | |
Income Taxes | |
Financing Activities | |
Variable Interest Entities | |
Property, Plant and Equipment | |
Disposition Plant Severance | |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
EXECUTIVE OVERVIEW
Regulatory Activity
2012 Texas Base Rate Case
Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million. In May 2014, intervenors filed appeals of the order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned it could reduce future net income and cash flows and impact financial condition. See the “2012 Texas Base Rate Case” section of SWEPCo Rate Matters in Note 4.
2012 Louisiana Formula Rate Filing
In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant. In February 2013, a settlement was approved by the LPSC that increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013. The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million, primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. See the “2012 Louisiana Formula Rate Filing” section of SWEPCo Rate Matters in Note 4.
2014 Louisiana Formula Rate Filing
In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase, which was effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2015 Louisiana Formula Rate Filing
In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Welsh Plant, Units 1 and 3 - Environmental Projects
To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2024 for Welsh Plant, Units 1 and 3 will cost approximately $700 million, excluding AFUDC. As of September 30, 2015, SWEPCo has incurred costs of $303 million, including AFUDC, and has remaining contractual construction obligations of $62 millionrelated to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. See "Mercury and Other Hazardous Air Pollutants (HAPs) Regulation" and "Climate Change, CO2 Regulation and Energy Policy" sections of “Environmental Issues” within “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries”. As of September 30, 2015, the net book value of Welsh Plant, Units 1 and 3 was $529 million, before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Merchant Portion of Turk Plant
SWEPCo constructed the Turk Plant, a base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012 and is included in the Vertically Integrated Utilities segment. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.
The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This share of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under cost-based rate recovery in Texas, Louisiana, and through SWEPCo’s wholesale customers under FERC-based rates.
If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.
Litigation and Environmental Issues
In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in the 2014 Annual Report. Also, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 179. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.
See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 256 for additional discussion of relevant factors.
RESULTS OF OPERATIONS
KWh Sales/Degree Days
Summary of KWh Energy Sales
| | | Three Months Ended | | Nine Months Ended | Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, | September 30, | | September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in millions of KWhs) | (in millions of KWhs) |
Retail: | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
Residential | 2,087 |
| | 1,949 |
| | 5,135 |
| | 4,974 |
| 2,105 |
| | 2,087 |
| | 4,879 |
| | 5,135 |
|
Commercial | 1,782 |
| | 1,744 |
| | 4,705 |
| | 4,583 |
| 1,793 |
| | 1,782 |
| | 4,652 |
| | 4,705 |
|
Industrial | 1,419 |
| | 1,511 |
| | 4,079 |
| | 4,453 |
| 1,254 |
| | 1,419 |
| | 3,830 |
| | 4,079 |
|
Miscellaneous | 19 |
| | 20 |
| | 60 |
| | 60 |
| 20 |
| | 19 |
| | 61 |
| | 60 |
|
Total Retail | 5,307 |
| | 5,224 |
| | 13,979 |
| | 14,070 |
| 5,172 |
| | 5,307 |
| | 13,422 |
| | 13,979 |
|
| | | | | | | | | | | | | | |
Wholesale | 2,460 |
| | 2,458 |
| | 7,092 |
| | 7,022 |
| 2,326 |
| | 2,460 |
| | 6,056 |
| | 7,092 |
|
| | | | | | | | | | | | | | |
Total KWhs | 7,767 |
| | 7,682 |
| | 21,071 |
| | 21,092 |
| 7,498 |
| | 7,767 |
| | 19,478 |
| | 21,071 |
|
Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.
Summary of Heating and Cooling Degree Days
| | | Three Months Ended | | Nine Months Ended | Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, | September 30, | | September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in degree days) | (in degree days) |
Actual - Heating (a) | — |
| | — |
| | 920 |
| | 1,039 |
| — |
| | — |
| | 586 |
| | 920 |
|
Normal - Heating (b) | 1 |
| | 1 |
| | 733 |
| | 748 |
| 1 |
| | 1 |
| | 747 |
| | 733 |
|
| | | | | | | | | | | | | | |
Actual - Cooling (c) | 1,500 |
| | 1,232 |
| | 2,278 |
| | 1,917 |
| 1,502 |
| | 1,500 |
| | 2,277 |
| | 2,278 |
|
Normal - Cooling (b) | 1,408 |
| | 1,404 |
| | 2,175 |
| | 2,162 |
| 1,410 |
| | 1,408 |
| | 2,177 |
| | 2,175 |
|
| |
(a) | Western Region heatingHeating degree days are calculated on a 55 degree temperature base. |
| |
(b) | Normal Heating/Cooling represents the thirty-year average of degree days. |
| |
(c) | Western Region coolingCooling degree days are calculated on a 65 degree temperature base. |
Third Quarter of 20152016 Compared to Third Quarter of 20142015
| | Reconciliation of Third Quarter of 2014 to Third Quarter of 2015 | |
Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 | | Reconciliation of Third Quarter of 2015 to Third Quarter of 2016 |
Earnings Attributable to SWEPCo Common Shareholder | (in millions) | | | | | |
Third Quarter of 2014 | | $ | 73 |
| |
Third Quarter of 2015 | | | $ | 81.1 |
|
| | |
| | |
|
Changes in Gross Margin: | | |
| | |
|
Retail Margins (a) | | 28 |
| | 4.9 |
|
Off-system Sales | | (3 | ) | | 0.1 |
|
Transmission Revenues | | 4 |
| | 11.7 |
|
Other Revenues | | (1 | ) | | (0.6 | ) |
Total Change in Gross Margin | | 28 |
| | 16.1 |
|
| | |
| | |
|
Changes in Expenses and Other: | | |
| | |
|
Other Operation and Maintenance | | (17 | ) | | (7.2 | ) |
Depreciation and Amortization | | (2 | ) | | (2.3 | ) |
Taxes Other Than Income Taxes | | (1 | ) | | (0.4 | ) |
Allowance for Equity Funds Used During Construction | | 4 |
| | (7.0 | ) |
Interest Expense | | 2 |
| | (3.4 | ) |
Total Change in Expenses and Other | | (14 | ) | | (20.3 | ) |
| | |
| | |
|
Income Tax Expense | | (6 | ) | | 4.2 |
|
Equity Earnings of Unconsolidated Subsidiary | | | 2.3 |
|
Net Income Attributable to Noncontrolling Interest | | | (0.1 | ) |
| | |
| | |
|
Third Quarter of 2015 | | $ | 81 |
| |
Third Quarter of 2016 | | | $ | 83.3 |
|
| |
(a) | Includes firm wholesale sales to municipals and cooperatives. |
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
Retail Margins increased $28$5 million primarily due to the following:
A $25$6 million increase primarily due to revenue increases from rate riders primarily in LouisianaTexas and Texas.Arkansas.
A $16$3 million increase in weather-related usage primarilymunicipal and cooperative revenues due to an 18% increase in cooling degree days.formula rate adjustments.
These increases were partially offset by:
An $11A $3 million decrease primarily due to lower weather-normalized retail sales.margins.
Margins from Off-system SalesTransmission Revenues decreased $3increased $12 million primarily due to lower market pricesan $8 million accrual for SPP sponsor-funded transmission upgrades and decreased sales volumes.an additional $4 million due to increased transmission investments in SPP. This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.
Transmission Revenues increased $4 million primarily due to higher SPP margins.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $17$7 million primarily due to the following:
A $7$15 million increase in SPP transmission expensesservices primarily due to increaseda $12 million accrual for SPP sponsor-funded transmission services.upgrades. This increase was partially offset by a corresponding increase in Transmission Revenues above.
This increase was partially offset by:
A $3$4 million increasedecrease in general and administrative expenses.
A $3 million increase in generation plant expenses.
A $2 million increasedecrease in energy efficiency program expenses.
A $2 million increase in distribution expenses primarily due to increased vegetation managementcustomer related expenses.
Allowance for Equity Funds Used During Construction increased $4decreased $7 million primarily due to the completion of environmental projects.
Interest Expenseincreased $3 million due to a decrease in the debt component of AFUDC as a result of decreased environmental and transmission projects.
Income Tax Expenseincreased $6 decreased $4 million primarily due to an increasea decrease in pretax book income and by the recording of federal and state income tax adjustments, partially offset by the regulatory accounting treatment of state income taxes and by other book/tax differences which are accounted for on a flow-through basis.
Nine Months Ended September 30, 20152016 Compared to Nine Months Ended September 30, 20142015
| | Reconciliation of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2015 | |
Reconciliation of Nine Months Ended September 30, 2015 to Nine Months Ended September 30, 2016 | | Reconciliation of Nine Months Ended September 30, 2015 to Nine Months Ended September 30, 2016 |
Earnings Attributable to SWEPCo Common Shareholder | (in millions) | | | | | |
Nine Months Ended September 30, 2014 | | $ | 127 |
| |
Nine Months Ended September 30, 2015 | | | $ | 185.3 |
|
| | |
| | |
|
Changes in Gross Margin: | | |
| | |
|
Retail Margins (a) | | 96 |
| | (40.7 | ) |
Off-system Sales | | (8 | ) | | (1.0 | ) |
Transmission Revenues | | 4 |
| | 19.3 |
|
Other Revenues | | (2 | ) | | (1.1 | ) |
Total Change in Gross Margin | | 90 |
| | (23.5 | ) |
| | |
| | |
|
Changes in Expenses and Other: | | |
| | |
|
Other Operation and Maintenance | | (15 | ) | | (30.4 | ) |
Depreciation and Amortization | | (5 | ) | | (4.3 | ) |
Taxes Other Than Income Taxes | | (3 | ) | | (0.7 | ) |
Interest Income | | 1 |
| | (1.2 | ) |
Allowance For Equity Funds Used During Construction | | 11 |
| | (8.7 | ) |
Interest Expense | | 4 |
| | (0.6 | ) |
Total Change in Expenses and Other | | (7 | ) | | (45.9 | ) |
| | |
| | |
|
Income Tax Expense | | (25 | ) | | 31.5 |
|
Equity Earnings of Unconsolidated Subsidiary | | | 2.8 |
|
Net Income Attributable to Noncontrolling Interest | | | (0.3 | ) |
| | |
| | |
|
Nine Months Ended September 30, 2015 | | $ | 185 |
| |
Nine Months Ended September 30, 2016 | | | $ | 149.9 |
|
| |
(a) | Includes firm wholesale sales to municipals and cooperatives. |
The major components of the increasedecrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
Retail Margins increased $96decreased $41 million primarily due to the following:
A $45$23 million decrease due to fuel cost recovery adjustments in 2015.
A $22 million decrease in municipal and cooperative revenues due to a true-up of formula rates in 2015.
An $18 million decrease in weather-related usage due to a 36% decrease in heating degree days.
These decreases were partially offset by:
A $16 million increase primarily due to revenue increases from rate riders primarily in LouisianaArkansas and Texas.
A $26$6 million increase in municipal and cooperative revenues primarily due to formula rate adjustments.
A $22 million net increase in weather-related usage primarily due to a 16% increase in cooling degree days, partially offset by a decrease in heating degree days.
A $16 million increase primarily due to higher fuel cost recovery.
These increases were partially offset by:
A $13 million decrease primarily due to lower weather-normalized retail sales.margins.
Margins from Off-system SalesTransmission Revenues decreased $8increased $19 million primarily due to lower market prices.an additional $9 million in increased transmission investments in SPP and an $8 million accrual for SPP sponsor-funded transmission upgrades. This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.
Transmission Revenues increased $4 million primarily due to higher SPP margins.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $15$30 million primarily due to the following:
An $8A $21 million increase in SPP transmission services.services primarily due to a $12 million accrual for SPP sponsor-funded transmission upgrades and an additional $7 million in increased transmission investments in SPP. This increase was partially offset by a corresponding increase in Transmission Revenues above.
A $7 million increase in distributiongeneration plant expenses primarily due to increased vegetation managementplanned maintenance.
A $6 million increase in general and administrative expenses.
Depreciation and Amortizationexpenses increased $5$4 million primarily due to a higher depreciable base.
Allowance for Equity Funds Used During Construction increased $11 million primarily due to increased environmental and transmission projects.
Interest Expensedecreased $4$9 million primarily due to the following:completion of environmental projects.
A $6 million increase in the debt component of AFUDC due to increased environmental and transmission projects.
This decrease was partially offset by:
A $4 million increase due to increased long-term debt outstanding.
Income Tax Expense increased $25decreased $32 million primarily due to an increasea decrease in pretax book income.income and the recording of state income tax adjustments, partially offset by other book/tax differences which are accounted for on a flow-through basis.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2014 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.
See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 256 for a discussion of accounting pronouncements.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
REVENUES | | | | | | | | |
| | | | | | | | |
|
Electric Generation, Transmission and Distribution | | $ | 525,922 |
| | $ | 526,047 |
| | $ | 1,387,644 |
| | $ | 1,397,326 |
| | $ | 530.5 |
| | $ | 526.0 |
| | $ | 1,324.1 |
| | $ | 1,387.7 |
|
Sales to AEP Affiliates | | 5,959 |
| | 5,203 |
| | 13,115 |
| | 22,748 |
| | 8.6 |
| | 5.9 |
| | 20.0 |
| | 13.1 |
|
Other Revenues | | 618 |
| | 521 |
| | 1,486 |
| | 1,570 |
| | 0.6 |
| | 0.6 |
| | 1.6 |
| | 1.5 |
|
TOTAL REVENUES | | 532,499 |
| | 531,771 |
| | 1,402,245 |
| | 1,421,644 |
| | 539.7 |
| | 532.5 |
| | 1,345.7 |
| | 1,402.3 |
|
| | | | | | | | | | | | | | | | |
EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Fuel and Other Consumables Used for Electric Generation | | 179,995 |
| | 194,175 |
| | 463,092 |
| | 500,878 |
| | 158.8 |
| | 180.0 |
| | 403.3 |
| | 463.1 |
|
Purchased Electricity for Resale | | 23,597 |
| | 36,960 |
| | 70,799 |
| | 138,380 |
| | 35.9 |
| | 23.6 |
| | 97.5 |
| | 70.8 |
|
Purchased Electricity from AEP Affiliates | | — |
| | — |
| | — |
| | 3,766 |
| |
Other Operation | | 81,391 |
| | 68,601 |
| | 214,835 |
| | 206,442 |
| | 89.2 |
| | 81.4 |
| | 243.3 |
| | 214.8 |
|
Maintenance | | 34,425 |
| | 29,867 |
| | 100,076 |
| | 93,946 |
| | 33.8 |
| | 34.4 |
| | 102.0 |
| | 100.1 |
|
Depreciation and Amortization | | 48,862 |
| | 46,791 |
| | 143,780 |
| | 138,316 |
| | 51.2 |
| | 48.9 |
| | 148.1 |
| | 143.8 |
|
Taxes Other Than Income Taxes | | 23,014 |
| | 22,246 |
| | 66,062 |
| | 63,272 |
| | 23.4 |
| | 23.0 |
| | 66.8 |
| | 66.1 |
|
TOTAL EXPENSES | | 391,284 |
| | 398,640 |
| | 1,058,644 |
| | 1,145,000 |
| | 392.3 |
| | 391.3 |
| | 1,061.0 |
| | 1,058.7 |
|
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | 141,215 |
| | 133,131 |
| | 343,601 |
| | 276,644 |
| | 147.4 |
| | 141.2 |
| | 284.7 |
| | 343.6 |
|
| | | | | | | | | | | | | | | | |
Other Income (Expense): | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Interest Income | | 69 |
| | 230 |
| | 1,233 |
| | 322 |
| | — |
| | — |
| | — |
| | 1.2 |
|
Allowance for Equity Funds Used During Construction | | 7,053 |
| | 3,137 |
| | 18,164 |
| | 7,415 |
| | 0.1 |
| | 7.1 |
| | 9.5 |
| | 18.2 |
|
Interest Expense | | (29,263 | ) | | (31,644 | ) | | (91,423 | ) | | (95,258 | ) | | (32.6 | ) | | (29.2 | ) | | (92.0 | ) | | (91.4 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS | | 119,074 |
| | 104,854 |
| | 271,575 |
| | 189,123 |
| | 114.9 |
| | 119.1 |
| | 202.2 |
| | 271.6 |
|
| | | | | | | | | | | | | | | | |
Income Tax Expense | | 37,358 |
| | 31,042 |
| | 85,417 |
| | 60,252 |
| | 33.2 |
| | 37.4 |
| | 53.9 |
| | 85.4 |
|
Equity Earnings of Unconsolidated Subsidiary | | 410 |
| | 735 |
| | 2,131 |
| | 1,461 |
| | 2.7 |
| | 0.4 |
| | 4.9 |
| | 2.1 |
|
| | | | | | | | | | | | | | | | |
NET INCOME | | 82,126 |
| | 74,547 |
| | 188,289 |
| | 130,332 |
| | 84.4 |
| | 82.1 |
| | 153.2 |
| | 188.3 |
|
| | | | | | | | | | | | | | | | |
Net Income Attributable to Noncontrolling Interest | | 1,013 |
| | 1,109 |
| | 3,002 |
| | 3,337 |
| | 1.1 |
| | 1.0 |
| | 3.3 |
| | 3.0 |
|
| | | | | | | | | | | | | | | | |
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | $ | 81,113 |
| | $ | 73,438 |
| | $ | 185,287 |
| | $ | 126,995 |
| | $ | 83.3 |
| | $ | 81.1 |
| | $ | 149.9 |
| | $ | 185.3 |
|
|
| | | | |
The common stock of SWEPCo is wholly-owned by AEP.Parent. |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | Three Months Ended | | Nine Months Ended | Three Months Ended | | Nine Months Ended |
| September 30, | | September 30, | September 30, | | September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
Net Income | $ | 82,126 |
| | $ | 74,547 |
| | $ | 188,289 |
| | $ | 130,332 |
| $ | 84.4 |
| | $ | 82.1 |
| | $ | 153.2 |
| | $ | 188.3 |
|
| | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
Cash Flow Hedges, Net of Tax of $232 and $305 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $843 and $881 for the Nine Months Ended September 30, 2015 and 2014, Respectively | 432 |
| | 567 |
| | 1,566 |
| | 1,636 |
| |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $129 and $126 for the Three Months Ended September 30, 2015 and 2014, Respectively, and $387 and $379 for the Nine Months Ended September 30, 2015 and 2014, Respectively | (240 | ) | | (235 | ) | | (719 | ) | | (704 | ) | |
Cash Flow Hedges, Net of Tax of $0.2 and $0.2 for the Three Months Ended September 30, 2016 and 2015, Respectively, and $0.7 and $0.8 for the Nine Months Ended September 30, 2016 and 2015, Respectively | | 0.4 |
| | 0.4 |
| | 1.3 |
| | 1.5 |
|
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2016 and 2015, Respectively, and $(0.3) and $(0.4) for the Nine Months Ended September 30, 2016 and 2015, Respectively | | (0.1 | ) | | (0.2 | ) | | (0.5 | ) | | (0.7 | ) |
| | | | | | | | | | | | | | |
TOTAL OTHER COMPREHENSIVE INCOME | 192 |
| | 332 |
| | 847 |
| | 932 |
| 0.3 |
| | 0.2 |
| | 0.8 |
| | 0.8 |
|
| | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | 82,318 |
| | 74,879 |
| | 189,136 |
| | 131,264 |
| 84.7 |
| | 82.3 |
| | 154.0 |
| | 189.1 |
|
| | | | | | | | | | | | | | |
Total Comprehensive Income Attributable to Noncontrolling Interest | 1,013 |
| | 1,109 |
| | 3,002 |
| | 3,337 |
| 1.1 |
| | 1.0 |
| | 3.3 |
| | 3.0 |
|
| |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | $ | 81,305 |
| | $ | 73,770 |
| | $ | 186,134 |
| | $ | 127,927 |
| $ | 83.6 |
| | $ | 81.3 |
| | $ | 150.7 |
| | $ | 186.1 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | SWEPCo Common Shareholder | | | | | SWEPCo Common Shareholder | | | | |
| Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interest | | Total | |
TOTAL EQUITY - DECEMBER 31, 2013 | $ | 135,660 |
| | $ | 674,606 |
| | $ | 1,253,617 |
| | $ | (8,444 | ) | | $ | 478 |
| | $ | 2,055,917 |
| |
| | | | | | | | | | | | |
Common Stock Dividends | | | | | (75,000 | ) | | | | | | (75,000 | ) | |
Common Stock Dividends – Nonaffiliated | |
| | |
| | |
| | |
| | (3,483 | ) | | (3,483 | ) | |
Net Income | |
| | |
| | 126,995 |
| | |
| | 3,337 |
| | 130,332 |
| |
Other Comprehensive Income | |
| | |
| | |
| | 932 |
| | |
| | 932 |
| |
TOTAL EQUITY - SEPTEMBER 30, 2014 | $ | 135,660 |
| | $ | 674,606 |
| | $ | 1,305,612 |
| | $ | (7,512 | ) | | $ | 332 |
| | $ | 2,108,698 |
| |
| | | | | | | | | | | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interest | | Total |
TOTAL EQUITY - DECEMBER 31, 2014 | $ | 135,660 |
| | $ | 674,606 |
| | $ | 1,293,986 |
| | $ | (7,466 | ) | | $ | 415 |
| | $ | 2,097,201 |
| $ | 135.7 |
| | $ | 674.6 |
| | $ | 1,294.0 |
| | $ | (7.5 | ) | | $ | 0.4 |
| | $ | 2,097.2 |
|
| | | | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | |
| | |
| | (90,000 | ) | | |
| | |
| | (90,000 | ) | | | | | (90.0 | ) | | | | | | (90.0 | ) |
Common Stock Dividends – Nonaffiliated | |
| | |
| | |
| | |
| | (3,099 | ) | | (3,099 | ) | |
| | |
| | |
| | |
| | (3.1 | ) | | (3.1 | ) |
Net Income | |
| | |
| | 185,287 |
| | |
| | 3,002 |
| | 188,289 |
| |
| | |
| | 185.3 |
| | |
| | 3.0 |
| | 188.3 |
|
Other Comprehensive Income | |
| | |
| | |
| | 847 |
| | |
| | 847 |
| |
| | |
| | |
| | 0.8 |
| | |
| | 0.8 |
|
Contribution of Mutual Energy SWEPCo, LLC from Parent | | | 1,945 |
| |
|
| | | | | | 1,945 |
| | | 2.0 |
| | | | | | | | 2.0 |
|
TOTAL EQUITY - SEPTEMBER 30, 2015 | $ | 135,660 |
| | $ | 676,551 |
| | $ | 1,389,273 |
| | $ | (6,619 | ) | | $ | 318 |
| | $ | 2,195,183 |
| $ | 135.7 |
| | $ | 676.6 |
| | $ | 1,389.3 |
| | $ | (6.7 | ) | | $ | 0.3 |
| | $ | 2,195.2 |
|
| | | | | | | | | | | | |
TOTAL EQUITY - DECEMBER 31, 2015 | | $ | 135.7 |
| | $ | 676.6 |
| | $ | 1,366.3 |
| | $ | (9.4 | ) | | $ | 0.5 |
| | $ | 2,169.7 |
|
| | | | | | | | | | | | |
Common Stock Dividends | | |
| | |
| | (90.0 | ) | | |
| | |
| | (90.0 | ) |
Common Stock Dividends – Nonaffiliated | | |
| | |
| | |
| | |
| | (3.5 | ) | | (3.5 | ) |
Net Income | | |
| | |
| | 149.9 |
| | |
| | 3.3 |
| | 153.2 |
|
Other Comprehensive Income | | |
| | |
| | |
| | 0.8 |
| | |
| | 0.8 |
|
TOTAL EQUITY - SEPTEMBER 30, 2016 | | $ | 135.7 |
| | $ | 676.6 |
| | $ | 1,426.2 |
| | $ | (8.6 | ) | | $ | 0.3 |
| | $ | 2,230.2 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20152016 and December 31, 20142015
(in thousands)millions)
(Unaudited)
| | | | September 30, | | December 31, | | September 30, | | December 31, |
| | 2015 | | 2014 | | 2016 | | 2015 |
CURRENT ASSETS | | | | | | | | |
Cash and Cash Equivalents (September 30, 2015 and December 31, 2014 Amounts Include $11,693 and $12,695, Respectively, Related to Sabine) | | $ | 14,258 |
| | $ | 14,356 |
| |
Cash and Cash Equivalents (September 30, 2016 and December 31, 2015 Amounts Include $12.8 and $3.7, Respectively, Related to Sabine) | | | $ | 15.2 |
| | $ | 5.2 |
|
Advances to Affiliates | | 45,019 |
| | 41,033 |
| | 299.4 |
| | 2.0 |
|
Accounts Receivable: | | | | | | | | |
Customers | | 41,086 |
| | 46,738 |
| | 25.0 |
| | 40.2 |
|
Affiliated Companies | | 33,937 |
| | 37,114 |
| | 30.4 |
| | 22.0 |
|
Miscellaneous | | 31,322 |
| | 25,625 |
| | 22.4 |
| | 27.1 |
|
Allowance for Uncollectible Accounts | | (148 | ) | | (516 | ) | | (1.6 | ) | | (0.9 | ) |
Total Accounts Receivable | | 106,197 |
| | 108,961 |
| | 76.2 |
| | 88.4 |
|
Fuel (September 30, 2015 and December 31, 2014 Amounts Include $27,194 and $38,920, Respectively, Related to Sabine) | | 93,125 |
| | 116,955 |
| |
Fuel (September 30, 2016 and December 31, 2015 Amounts Include $33.4 and $40.4, Respectively, Related to Sabine) | | | 109.4 |
| | 142.1 |
|
Materials and Supplies | | 72,735 |
| | 73,666 |
| | 70.8 |
| | 71.5 |
|
Risk Management Assets | | 1,280 |
| | 31 |
| | 1.4 |
| | 0.8 |
|
Deferred Income Tax Benefits | | 7,406 |
| | 9,041 |
| |
Accrued Tax Benefits | | 1,413 |
| | 15,408 |
| |
Regulatory Asset for Under-Recovered Fuel Costs | | 14,352 |
| | 24,024 |
| | 0.8 |
| | 4.1 |
|
Prepayments and Other Current Assets | | 20,083 |
| | 25,779 |
| | 21.0 |
| | 21.2 |
|
TOTAL CURRENT ASSETS | | 375,868 |
| | 429,254 |
| | 594.2 |
| | 335.3 |
|
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | 3,928,939 |
| | 3,864,543 |
| | 4,581.9 |
| | 3,943.5 |
|
Transmission | | 1,362,543 |
| | 1,300,729 |
| | 1,487.6 |
| | 1,387.8 |
|
Distribution | | 1,945,074 |
| | 1,894,572 |
| | 1,994.5 |
| | 1,957.3 |
|
Other Property, Plant and Equipment (Including Plant to be Retired) (September 30, 2015 and December 31, 2014 Amounts Include $291,896 and $288,183, Respectively, Related to Sabine) | | 895,958 |
| | 878,753 |
| |
Other Property, Plant and Equipment (December 31, 2015 Amount Includes 2016 Plant Retirement) (September 30, 2016 and December 31, 2015 Amounts Include $282.4 and $297.7, Respectively, Related to Sabine) | | | 707.1 |
| | 883.5 |
|
Construction Work in Progress | | 681,991 |
| | 471,980 |
| | 188.5 |
| | 751.3 |
|
Total Property, Plant and Equipment | | 8,814,505 |
| | 8,410,577 |
| | 8,959.6 |
| | 8,923.4 |
|
Accumulated Depreciation and Amortization (September 30, 2015 and December 31, 2014 Amounts Include $153,400 and $142,983, Respectively, Related to Sabine) | | 2,611,129 |
| | 2,503,290 |
| |
Accumulated Depreciation and Amortization (September 30, 2016 and December 31, 2015 Amounts Include $160.2 and $157.3, Respectively, Related to Sabine) | | | 2,572.4 |
| | 2,602.3 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 6,203,376 |
| | 5,907,287 |
| | 6,387.2 |
| | 6,321.1 |
|
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | 413,434 |
| | 393,602 |
| | 500.7 |
| | 415.8 |
|
Employee Benefits and Pension Assets | | 23,437 |
| | 21,427 |
| |
Deferred Charges and Other Noncurrent Assets | | 85,491 |
| | 65,323 |
| | 116.2 |
| | 75.8 |
|
TOTAL OTHER NONCURRENT ASSETS | | 522,362 |
| | 480,352 |
| | 616.9 |
| | 491.6 |
|
| | | | | | | | |
TOTAL ASSETS | | $ | 7,101,606 |
| | $ | 6,816,893 |
| | $ | 7,598.3 |
| | $ | 7,148.0 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 20152016 and December 31, 20142015
(Unaudited)
| | | | September 30, | | December 31, | | September 30, | | December 31, |
| | 2015 | | 2014 | | 2016 | | 2015 |
| | (in thousands) | | (in millions) |
CURRENT LIABILITIES | | | | | | | | |
Advances from Affiliates | | | $ | — |
| | $ | 58.3 |
|
Accounts Payable: | | | | | | | | |
General | | $ | 160,885 |
| | $ | 175,109 |
| | 129.3 |
| | 150.4 |
|
Affiliated Companies | | 58,866 |
| | 67,410 |
| | 51.6 |
| | 78.8 |
|
Long-term Debt Due Within One Year – Nonaffiliated | | 3,250 |
| | 306,750 |
| | 354.0 |
| | 3.3 |
|
Risk Management Liabilities | | 1,302 |
| | 1,082 |
| | — |
| | 3.1 |
|
Customer Deposits | | 60,594 |
| | 59,903 |
| | 61.8 |
| | 61.4 |
|
Accrued Taxes | | 83,125 |
| | 43,965 |
| | 74.0 |
| | 58.3 |
|
Accrued Interest | | 23,097 |
| | 44,328 |
| | 23.0 |
| | 43.0 |
|
Obligations Under Capital Leases | | 22,081 |
| | 17,557 |
| | 16.8 |
| | 21.9 |
|
Other Current Liabilities | | 81,965 |
| | 104,553 |
| | 81.0 |
| | 110.7 |
|
TOTAL CURRENT LIABILITIES | | 495,165 |
| | 820,657 |
| | 791.5 |
| | 589.2 |
|
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | 2,280,716 |
| | 1,833,687 |
| | 2,320.0 |
| | 2,270.2 |
|
Long-term Risk Management Liabilities | | 757 |
| | — |
| | — |
| | 2.1 |
|
Deferred Income Taxes | | 1,415,833 |
| | 1,351,111 |
| | 1,562.1 |
| | 1,399.8 |
|
Regulatory Liabilities and Deferred Investment Tax Credits | | 457,438 |
| | 458,530 |
| | 446.9 |
| | 448.8 |
|
Asset Retirement Obligations | | 108,093 |
| | 92,015 |
| | 127.4 |
| | 117.5 |
|
Employee Benefits and Pension Obligations | | 26,224 |
| | 25,374 |
| | 26.6 |
| | 25.8 |
|
Obligations Under Capital Leases | | 74,533 |
| | 91,044 |
| | 68.5 |
| | 75.6 |
|
Deferred Credits and Other Noncurrent Liabilities | | 47,664 |
| | 47,274 |
| | 25.1 |
| | 49.3 |
|
TOTAL NONCURRENT LIABILITIES | | 4,411,258 |
| | 3,899,035 |
| | 4,576.6 |
| | 4,389.1 |
|
| | | | | | | | |
TOTAL LIABILITIES | | 4,906,423 |
| | 4,719,692 |
| | 5,368.1 |
| | 4,978.3 |
|
| | | | | | | | |
Rate Matters (Note 4) | |
| |
| |
| |
|
Commitments and Contingencies (Note 5) | |
| |
| |
| |
|
| | | | | | | | |
EQUITY | | | | | | | | |
Common Stock – Par Value – $18 Per Share: | | | | | | | | |
Authorized – 7,600,000 Shares | | | | | | | | |
Outstanding – 7,536,640 Shares | | 135,660 |
| | 135,660 |
| | 135.7 |
| | 135.7 |
|
Paid-in Capital | | 676,551 |
| | 674,606 |
| | 676.6 |
| | 676.6 |
|
Retained Earnings | | 1,389,273 |
| | 1,293,986 |
| | 1,426.2 |
| | 1,366.3 |
|
Accumulated Other Comprehensive Income (Loss) | | (6,619 | ) | | (7,466 | ) | | (8.6 | ) | | (9.4 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,194,865 |
| | 2,096,786 |
| | 2,229.9 |
| | 2,169.2 |
|
| | | | | | | | |
Noncontrolling Interest | | 318 |
| | 415 |
| | 0.3 |
| | 0.5 |
|
| | | | | | | | |
TOTAL EQUITY | | 2,195,183 |
| | 2,097,201 |
| | 2,230.2 |
| | 2,169.7 |
|
| | | | | | | | |
TOTAL LIABILITIES AND EQUITY | | $ | 7,101,606 |
| | $ | 6,816,893 |
| | $ | 7,598.3 |
| | $ | 7,148.0 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20152016 and 20142015
(in thousands)millions)
(Unaudited)
| | | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2016 | | 2015 |
OPERATING ACTIVITIES | | |
| | |
| | |
| | |
|
Net Income | | $ | 188,289 |
| | $ | 130,332 |
| | $ | 153.2 |
| | $ | 188.3 |
|
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | 143,780 |
| | 138,316 |
| | 148.1 |
| | 143.8 |
|
Deferred Income Taxes | | 45,672 |
| | 181,482 |
| | 141.9 |
| | 45.7 |
|
Allowance for Equity Funds Used During Construction | | (18,164 | ) | | (7,415 | ) | | (9.5 | ) | | (18.2 | ) |
Mark-to-Market of Risk Management Contracts | | (272 | ) | | 802 |
| | (5.8 | ) | | (0.3 | ) |
Pension Contributions to Qualified Plan Trust | | (8,052 | ) | | (3,832 | ) | | (8.3 | ) | | (8.1 | ) |
Property Taxes | | (13,024 | ) | | (12,503 | ) | | (13.7 | ) | | (13.0 | ) |
Fuel Over/Under-Recovery, Net | | 11,705 |
| | (19,547 | ) | |
Deferred Fuel Over/Under-Recovery, Net | | | 1.2 |
| | 11.7 |
|
Change in Other Noncurrent Assets | | 2,756 |
| | 11,926 |
| | 18.4 |
| | 2.0 |
|
Change in Other Noncurrent Liabilities | | (1,820 | ) | | 39 |
| | (25.8 | ) | | (1.1 | ) |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | 2,764 |
| | 36,622 |
| | 12.2 |
| | 2.8 |
|
Fuel, Materials and Supplies | | 24,761 |
| | 22,500 |
| | 33.4 |
| | 24.8 |
|
Accounts Payable | | (17,120 | ) | | (15,046 | ) | | (17.2 | ) | | (17.1 | ) |
Accrued Taxes, Net | | 53,155 |
| | (76,982 | ) | | 14.1 |
| | 53.1 |
|
Accrued Interest | | (21,231 | ) | | (24,406 | ) | | (20.0 | ) | | (21.2 | ) |
Other Current Assets | | 2,794 |
| | (7,448 | ) | | (2.4 | ) | | 2.8 |
|
Other Current Liabilities | | (23,678 | ) | | (2,983 | ) | | (24.8 | ) | | (23.7 | ) |
Net Cash Flows from Operating Activities | | 372,315 |
| | 351,857 |
| | 395.0 |
| | 372.3 |
|
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | (408,293 | ) | | (351,666 | ) | | (315.3 | ) | | (408.3 | ) |
Change in Advances to Affiliates, Net | | (2,038 | ) | | — |
| | (297.4 | ) | | (2.0 | ) |
Other Investing Activities | | 4,427 |
| | 4,334 |
| | (1.9 | ) | | 4.4 |
|
Net Cash Flows Used for Investing Activities | | (405,904 | ) | | (347,332 | ) | | (614.6 | ) | | (405.9 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt – Nonaffiliated | | 445,949 |
| | 99,633 |
| | 402.2 |
| | 446.0 |
|
Change in Advances from Affiliates, Net | | — |
| | (2,851 | ) | | (58.3 | ) | | — |
|
Retirement of Long-term Debt – Nonaffiliated | | (306,750 | ) | | (3,250 | ) | | (3.3 | ) | | (306.8 | ) |
Principal Payments for Capital Lease Obligations | | (13,398 | ) | | (13,673 | ) | | (18.6 | ) | | (13.4 | ) |
Dividends Paid on Common Stock | | (90,000 | ) | | (75,000 | ) | | (90.0 | ) | | (90.0 | ) |
Dividends Paid on Common Stock – Nonaffiliated | | (3,099 | ) | | (3,483 | ) | | (3.5 | ) | | (3.1 | ) |
Other Financing Activities | | 789 |
| | 844 |
| | 1.1 |
| | 0.8 |
|
Net Cash Flows from Financing Activities | | 33,491 |
| | 2,220 |
| | 229.6 |
| | 33.5 |
|
| | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | (98 | ) | | 6,745 |
| | 10.0 |
| | (0.1 | ) |
Cash and Cash Equivalents at Beginning of Period | | 14,356 |
| | 17,241 |
| | 5.2 |
| | 14.4 |
|
Cash and Cash Equivalents at End of Period | | $ | 14,258 |
| | $ | 23,986 |
| | $ | 15.2 |
| | $ | 14.3 |
|
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 106,078 |
| | $ | 113,137 |
| | $ | 107.6 |
| | $ | 106.1 |
|
Net Cash Paid (Received) for Income Taxes | | 12,320 |
| | (13,820 | ) | | (66.6 | ) | | 12.3 |
|
Noncash Acquisitions Under Capital Leases | | 1,493 |
| | 3,923 |
| | 5.5 |
| | 1.5 |
|
Construction Expenditures Included in Current Liabilities as of September 30, | | 85,268 |
| | 88,291 |
| | 54.3 |
| | 85.3 |
|
Noncash Contribution of Mutual Energy SWEPCo, LLC from Parent | | (1,945 | ) | | — |
| | — |
| | (2.0 | ) |
Noncash Increase in Advances to Affiliates, Net due to Contribution of Mutual Energy SWEPCo, LLC | | 1,948 |
| | — |
| | — |
| | 2.0 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant SubsidiariesRegistrants beginning on page 179113. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES
The condensed notes to SWEPCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to SWEPCo.
|
| |
| Page
Number
|
| |
Significant Accounting Matters | |
New Accounting Pronouncements | |
Comprehensive Income | |
Rate Matters | |
Commitments, Guarantees and Contingencies | |
Benefit Plans | |
Business Segments | |
Derivatives and Hedging | |
Fair Value Measurements | |
Income Taxes | |
Financing Activities | |
Variable Interest Entities | |
Property, Plant and Equipment | |
Disposition Plant Severance | |
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES REGISTRANTS
The condensed notes to condensed financial statements that follow are a combined presentation for the Registrant Subsidiaries.Registrants. The following list indicates the registrantsRegistrants to which the footnotes apply:notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise:
|
| | | | |
Note | | Registrant | | Page Number |
| | | | |
Significant Accounting Matters | | AEP, APCo, I&M, OPCo, PSO, SWEPCo | | |
New Accounting Pronouncements | | AEP, APCo, I&M, OPCo, PSO, SWEPCo | | |
Comprehensive Income | | AEP, APCo, I&M, OPCo, PSO, SWEPCo | | |
Rate Matters | | AEP, APCo, I&M, OPCo, PSO, SWEPCo | | |
Commitments, Guarantees and Contingencies | | AEP, APCo, I&M, OPCo, PSO, SWEPCo | | |
Dispositions, Assets and Liabilities Held for Sale and Impairments | | AEP, I&M | | |
Benefit Plans | | AEP, APCo, I&M, OPCo, PSO, SWEPCo | | |
Business Segments | | AEP, APCo, I&M, OPCo, PSO, SWEPCo | | |
Derivatives and Hedging | | AEP, APCo, I&M, OPCo, PSO, SWEPCo | | |
Fair Value Measurements | | AEP, APCo, I&M, OPCo, PSO, SWEPCo | | |
Income Taxes | | AEP, APCo, I&M, OPCo, PSO, SWEPCo | | |
Financing Activities | | AEP, APCo, I&M, OPCo, PSO, SWEPCo | | |
Variable Interest Entities | | AEP, APCo, I&M, OPCo, PSO, SWEPCo | |
Property, Plant and Equipment | APCo, I&M, OPCo, PSO, SWEPCo | |
Disposition Plant Severance | APCo, I&M, OPCo, PSO, SWEPCo | |
1. SIGNIFICANT ACCOUNTING MATTERS
The disclosures in this note apply to all Registrants unless indicated otherwise.
General
The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.
In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary.Registrant. Net income for the three and nine months ended September 30, 20152016 is not necessarily indicative of results that may be expected for the year ending December 31, 2015.2016. The condensed financial statements are unaudited and should be read in conjunction with the audited 20142015 financial statements and notes thereto, which are included in the Registrant Subsidiaries’Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 20, 2015.23, 2016.
Investment Tax Credits
Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial.
Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized.
Earnings Per Share (EPS) (Applies to AEP)
Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.
The following tables present AEP’s basic and diluted EPS calculations included on the statements of operations:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, |
| 2016 | | 2015 |
| (in millions, except per share data) |
| |
| | $/share | | | | $/share |
Income (Loss) from Continuing Operations | $ | (764.2 | ) | | | | $ | 511.8 |
| | |
Less: Net Income Attributable to Noncontrolling Interests | 1.6 |
| | | | 1.3 |
| | |
Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations | $ | (765.8 | ) | | |
| | $ | 510.5 |
| | |
|
| | | | | | | |
Weighted Average Number of Basic Shares Outstanding | 491.7 |
| | $ | (1.56 | ) | | 490.6 |
| | $ | 1.04 |
|
Weighted Average Dilutive Effect of Restricted Stock Units | 0.1 |
| | — |
| | 0.2 |
| | — |
|
Weighted Average Number of Diluted Shares Outstanding | 491.8 |
| | $ | (1.56 | ) | | 490.8 |
| | $ | 1.04 |
|
|
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2016 | | 2015 |
| (in millions, except per share data) |
| |
| | $/share | | | | $/share |
Income from Continuing Operations | $ | 245.3 |
| | | | $ | 1,563.4 |
| | |
Less: Net Income Attributable to Noncontrolling Interests | 5.3 |
| | | | 4.1 |
| | |
Earnings Attributable to AEP Common Shareholders from Continuing Operations | $ | 240.0 |
| | | | $ | 1,559.3 |
| | |
| | | | | | | |
Weighted Average Number of Basic Shares Outstanding | 491.4 |
| | $ | 0.49 |
| | 490.2 |
| | $ | 3.18 |
|
Weighted Average Dilutive Effect of Restricted Stock Units | 0.2 |
| | — |
| | 0.2 |
| | — |
|
Weighted Average Number of Diluted Shares Outstanding | 491.6 |
| | $ | 0.49 |
| | 490.4 |
| | $ | 3.18 |
|
There were no antidilutive shares outstanding as of September 30, 2016 and 2015.
2. NEW ACCOUNTING PRONOUNCEMENTS
The disclosures in this note apply to all Registrants unless indicated otherwise.
Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’Registrants’ business. The following final pronouncements will impact the financial statements.
ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08)
In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date.
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. There were no events requiring the application of this new accounting guidance.
ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09)
In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts.
The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized inon the statements of income statements in each reporting period. Management is analyzing the impact of this new standard and atthe related ASUs that clarify guidance in the standard. At this time, management cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018.
ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01)
In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements.
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. Management plans to adopt ASU 2015-01 effective January 1, 2016.
ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03)
In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The Registrant Subsidiaries include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt.
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management intends to early adopt ASU 2015-03 for the 2015 Form 10-K.
ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05)
In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-05 effective January 1, 2016.
ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11)
In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management does not expect the new standard to impact the Registrants’ results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017.
ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01)
In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets.
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-112016-01 effective January 1, 2017.2018.
ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets”2016-02 “Accounting for Leases” (ASU 2015-13)2016-02)
In August 2015,February 2016, the FASB issued ASU 2015-13 clarifying whether a contract for2016-02 increasing the purchase or sale of electricitytransparency and comparability among organizations by recognizing lease assets and lease liabilities on a forward basis should be eligible to meet the physical delivery criterion of the normal purchasesbalance sheet and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator.disclosing key information about leasing arrangements. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contractmust recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a normal purchasefinance lease going forward. Leases with lease terms of 12 months or normal sale.longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard.
The new accounting guidance is effective upon issuancefor annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and applied prospectively.lessors to recognize and measure leases at the beginning of the earliest period presented as well as a number of optional practical expedients that entities may elect to apply. Management has analyzedis analyzing the impact of this new standard and, determined that it will have noat this time, cannot estimate the impact of adoption. Management expects the new standard to impact the Registrants’ financial position, but not the Registrants’ results of operations or cash flows. Management plans to adopt ASU 2016-02 effective January 1, 2019.
ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09)
In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income.
The new accounting guidance is effective for annual periods beginning after December 15, 2016. Early adoption is permitted in any interim or annual period. Certain provisions require retrospective/modified retrospective transition while others are to be applied prospectively. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management plans to adopt ASU 2016-09 effective January 1, 2017.
ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13)
In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination.
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the Registrant Subsidiaries' contracts. Additionally,beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption has no impact on net income. Management adoptedplans to adopt ASU 2015-13 upon its issuance date.2016-13 effective January 1, 2020.
3. COMPREHENSIVE INCOME
The disclosures in this note apply to all Registrants unless indicated otherwise.
Presentation of Comprehensive Income
The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 20152016 and 2014. All amounts2015. The amortization of pension and OPEB AOCI components are included in the following tables are presentedcomputation of net of related income taxes.periodic pension and OPEB costs. See Note 7 for additional details.
AEP
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016
|
| | | | | | | | | | | | | | | | | | | |
| Cash Flow Hedges | | | | | | |
| Commodity | | Interest Rate and Foreign Currency | | Securities Available for Sale | | Pension and OPEB | | Total |
| (in millions) |
Balance in AOCI as of June 30, 2016 | $ | 1.9 |
| | $ | (16.5 | ) | | $ | 8.3 |
| | $ | (111.6 | ) | | $ | (117.9 | ) |
Change in Fair Value Recognized in AOCI | (26.7 | ) | | — |
| | 0.5 |
| | — |
| | (26.2 | ) |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | | |
Generation & Marketing Revenues | (5.4 | ) | | — |
| | — |
| | — |
| | (5.4 | ) |
Purchased Electricity for Resale | 1.8 |
| | — |
| | — |
| | — |
| | 1.8 |
|
Interest Expense | — |
| | 0.6 |
| | — |
| | — |
| | 0.6 |
|
Amortization of Prior Service Cost (Credit) | — |
| | — |
| | — |
| | (4.8 | ) | | (4.8 | ) |
Amortization of Actuarial (Gains)/Losses | — |
| | — |
| | — |
| | 5.0 |
| | 5.0 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | (3.6 | ) | | 0.6 |
| | — |
| | 0.2 |
| | (2.8 | ) |
Income Tax (Expense) Credit | (1.3 | ) | | 0.2 |
| | — |
| | — |
| | (1.1 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (2.3 | ) | | 0.4 |
| | — |
| | 0.2 |
| | (1.7 | ) |
Net Current Period Other Comprehensive Income (Loss) | (29.0 | ) | | 0.4 |
| | 0.5 |
| | 0.2 |
| | (27.9 | ) |
Balance in AOCI as of September 30, 2016 | $ | (27.1 | ) | | $ | (16.1 | ) | | $ | 8.8 |
| | $ | (111.4 | ) | | $ | (145.8 | ) |
AEP
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2015
|
| | | | | | | | | | | | | | | | | | | |
| Cash Flow Hedges | | | | | | |
| Commodity | | Interest Rate and Foreign Currency | | Securities Available for Sale | | Pension and OPEB | | Total |
| (in millions) |
Balance in AOCI as of June 30, 2015 | $ | (5.2 | ) | | $ | (17.7 | ) | | $ | 8.0 |
| | $ | (87.6 | ) | | $ | (102.5 | ) |
Change in Fair Value Recognized in AOCI | (3.3 | ) | | 0.3 |
| | (1.3 | ) | | — |
| | (4.3 | ) |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | | |
Generation & Marketing Revenues | (19.5 | ) | | — |
| | — |
| | — |
| | (19.5 | ) |
Purchased Electricity for Resale | 14.3 |
| | — |
| | — |
| | — |
| | 14.3 |
|
Interest Expense | — |
| | (0.2 | ) | | — |
| | — |
| | (0.2 | ) |
Amortization of Prior Service Cost (Credit) | — |
| | — |
| | — |
| | (4.8 | ) | | (4.8 | ) |
Amortization of Actuarial (Gains)/Losses | — |
| | — |
| | — |
| | 5.3 |
| | 5.3 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | (5.2 | ) | | (0.2 | ) | | — |
| | 0.5 |
| | (4.9 | ) |
Income Tax (Expense) Credit | (3.0 | ) | | (0.1 | ) | | — |
| | 0.2 |
| | (2.9 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (2.2 | ) | | (0.1 | ) | | — |
| | 0.3 |
| | (2.0 | ) |
Net Current Period Other Comprehensive Income (Loss) | (5.5 | ) | | 0.2 |
| | (1.3 | ) | | 0.3 |
| | (6.3 | ) |
Balance in AOCI as of September 30, 2015 | $ | (10.7 | ) | | $ | (17.5 | ) | | $ | 6.7 |
| | $ | (87.3 | ) | | $ | (108.8 | ) |
AEP
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016
|
| | | | | | | | | | | | | | | | | | | |
| Cash Flow Hedges | | | | | | |
| Commodity | | Interest Rate and Foreign Currency | | Securities Available for Sale | | Pension and OPEB | | Total |
| (in millions) |
Balance in AOCI as of December 31, 2015 | $ | (5.2 | ) | | $ | (17.2 | ) | | $ | 7.1 |
| | $ | (111.8 | ) | | $ | (127.1 | ) |
Change in Fair Value Recognized in AOCI | (17.7 | ) | | — |
| | 1.7 |
| | — |
| | (16.0 | ) |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | | |
Generation & Marketing Revenues | (20.7 | ) | | — |
| | — |
| | — |
| | (20.7 | ) |
Purchased Electricity for Resale | 14.2 |
| | — |
| | — |
| | — |
| | 14.2 |
|
Interest Expense | — |
| | 1.7 |
| | — |
| | — |
| | 1.7 |
|
Amortization of Prior Service Cost (Credit) | — |
| | — |
| | — |
| | (14.6 | ) | | (14.6 | ) |
Amortization of Actuarial (Gains)/Losses | — |
| | — |
| | — |
| | 15.2 |
| | 15.2 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | (6.5 | ) | | 1.7 |
| | — |
| | 0.6 |
| | (4.2 | ) |
Income Tax (Expense) Credit | (2.3 | ) | | 0.6 |
| | — |
| | 0.2 |
| | (1.5 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (4.2 | ) | | 1.1 |
| | — |
| | 0.4 |
| | (2.7 | ) |
Net Current Period Other Comprehensive Income (Loss) | (21.9 | ) | | 1.1 |
| | 1.7 |
| | 0.4 |
| | (18.7 | ) |
Balance in AOCI as of September 30, 2016 | $ | (27.1 | ) | | $ | (16.1 | ) | | $ | 8.8 |
| | $ | (111.4 | ) | | $ | (145.8 | ) |
AEP
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2015
|
| | | | | | | | | | | | | | | | | | | |
| Cash Flow Hedges | | | | | | |
| Commodity | | Interest Rate and Foreign Currency | | Securities Available for Sale | | Pension and OPEB | | Total |
| (in millions) |
Balance in AOCI as of December 31, 2014 | $ | 1.6 |
| | $ | (19.1 | ) | | $ | 7.7 |
| | $ | (93.3 | ) | | $ | (103.1 | ) |
Change in Fair Value Recognized in AOCI | (2.0 | ) | | 0.9 |
| | (1.0 | ) | | — |
| | (2.1 | ) |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | | |
Generation & Marketing Revenues | (36.3 | ) | | — |
| | — |
| | — |
| | (36.3 | ) |
Purchased Electricity for Resale | 20.4 |
| | — |
| | — |
| | — |
| | 20.4 |
|
Interest Expense | — |
| | 1.0 |
| | — |
| | — |
| | 1.0 |
|
Amortization of Prior Service Cost (Credit) | — |
| | — |
| | — |
| | (14.6 | ) | | (14.6 | ) |
Amortization of Actuarial (Gains)/Losses | — |
| | — |
| | — |
| | 16.0 |
| | 16.0 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | (15.9 | ) | | 1.0 |
| | — |
| | 1.4 |
| | (13.5 | ) |
Income Tax (Expense) Credit | (5.6 | ) | | 0.3 |
| | — |
| | 0.5 |
| | (4.8 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (10.3 | ) | | 0.7 |
| | — |
| | 0.9 |
| | (8.7 | ) |
Net Current Period Other Comprehensive Income (Loss) | (12.3 | ) | | 1.6 |
| | (1.0 | ) | | 0.9 |
| | (10.8 | ) |
Pension and OPEB Adjustment Related to Mitchell Plant | — |
| | — |
| | — |
| | 5.1 |
| | 5.1 |
|
Balance in AOCI as of September 30, 2015 | $ | (10.7 | ) | | $ | (17.5 | ) | | $ | 6.7 |
| | $ | (87.3 | ) | | $ | (108.8 | ) |
APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016
|
| | | | | | | | | | | | |
| | Cash Flow Hedges | | | | |
| | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of June 30, 2016 | | $ | 3.2 |
| | $ | (7.1 | ) | | $ | (3.9 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
Interest Expense | | (0.2 | ) | | — |
| | (0.2 | ) |
Amortization of Prior Service Cost (Credit) | | — |
| | (1.2 | ) | | (1.2 | ) |
Amortization of Actuarial (Gains)/Losses | | — |
| | 0.7 |
| | 0.7 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (0.2 | ) | | (0.5 | ) | | (0.7 | ) |
Income Tax (Expense) Credit | | — |
| | (0.2 | ) | | (0.2 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.2 | ) | | (0.3 | ) | | (0.5 | ) |
Net Current Period Other Comprehensive Loss | | (0.2 | ) | | (0.3 | ) | | (0.5 | ) |
Balance in AOCI as of September 30, 2016 | | $ | 3.0 |
| | $ | (7.4 | ) | | $ | (4.4 | ) |
APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2015
| | | | Cash Flow Hedges | | | | | | Cash Flow Hedges | | | | |
| | Commodity | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in thousands) | | (in millions) |
Balance in AOCI as of June 30, 2015 | | $ | — |
| | $ | 4,027 |
| | $ | 220 |
| | $ | 4,247 |
| | $ | 4.0 |
| | $ | 0.2 |
| | $ | 4.2 |
|
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | (222 | ) | | (458 | ) | | (680 | ) | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | |
Interest Expense | | | (0.3 | ) | | — |
| | (0.3 | ) |
Amortization of Prior Service Cost (Credit) | | | — |
| | (1.2 | ) | | (1.2 | ) |
Amortization of Actuarial (Gains)/Losses | | | — |
| | 0.5 |
| | 0.5 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | | (0.3 | ) | | (0.7 | ) | | (1.0 | ) |
Income Tax (Expense) Credit | | | (0.1 | ) | | (0.2 | ) | | (0.3 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | | (0.2 | ) | | (0.5 | ) | | (0.7 | ) |
Net Current Period Other Comprehensive Loss | | — |
| | (222 | ) | | (458 | ) | | (680 | ) | | (0.2 | ) | | (0.5 | ) | | (0.7 | ) |
Balance in AOCI as of September 30, 2015 | | $ | — |
| | $ | 3,805 |
| | $ | (238 | ) | | $ | 3,567 |
| | $ | 3.8 |
| | $ | (0.3 | ) | | $ | 3.5 |
|
APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the ThreeNine Months Ended September 30, 20142016
|
| | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | | | |
| | Commodity | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in thousands) |
Balance in AOCI as of June 30, 2014 | | $ | — |
| | $ | 3,596 |
| | $ | (899 | ) | | $ | 2,697 |
|
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | 170 |
| | (333 | ) | | (163 | ) |
Net Current Period Other Comprehensive Income (Loss) | | — |
| | 170 |
| | (333 | ) | | (163 | ) |
Balance in AOCI as of September 30, 2014 | | $ | — |
| | $ | 3,766 |
| | $ | (1,232 | ) | | $ | 2,534 |
|
|
| | | | | | | | | | | | |
| | Cash Flow Hedges | | | | |
| | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of December 31, 2015 | | $ | 3.6 |
| | $ | (6.4 | ) | | $ | (2.8 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
Interest Expense | | (0.8 | ) | | — |
| | (0.8 | ) |
Amortization of Prior Service Cost (Credit) | | — |
| | (3.8 | ) | | (3.8 | ) |
Amortization of Actuarial (Gains)/Losses | | — |
| | 2.2 |
| | 2.2 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (0.8 | ) | | (1.6 | ) | | (2.4 | ) |
Income Tax (Expense) Credit | | (0.2 | ) | | (0.6 | ) | | (0.8 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.6 | ) | | (1.0 | ) | | (1.6 | ) |
Net Current Period Other Comprehensive Loss | | (0.6 | ) | | (1.0 | ) | | (1.6 | ) |
Balance in AOCI as of September 30, 2016 | | $ | 3.0 |
| | $ | (7.4 | ) | | $ | (4.4 | ) |
APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2015
| | | | Cash Flow Hedges | | | | | | Cash Flow Hedges | | | | |
| | Commodity | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in thousands) | | (in millions) |
Balance in AOCI as of December 31, 2014 | | $ | — |
| | $ | 3,896 |
| | $ | 1,136 |
| | $ | 5,032 |
| | $ | 3.9 |
| | $ | 1.1 |
| | $ | 5.0 |
|
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | (91 | ) | | (1,374 | ) | | (1,465 | ) | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | |
Interest Expense | | | (0.1 | ) | | — |
| | (0.1 | ) |
Amortization of Prior Service Cost (Credit) | | | — |
| | (3.8 | ) | | (3.8 | ) |
Amortization of Actuarial (Gains)/Losses | | | — |
| | 1.7 |
| | 1.7 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | | (0.1 | ) | | (2.1 | ) | | (2.2 | ) |
Income Tax (Expense) Credit | | | — |
| | (0.7 | ) | | (0.7 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | | (0.1 | ) | | (1.4 | ) | | (1.5 | ) |
Net Current Period Other Comprehensive Loss | | — |
| | (91 | ) | | (1,374 | ) | | (1,465 | ) | | (0.1 | ) | | (1.4 | ) | | (1.5 | ) |
Balance in AOCI as of September 30, 2015 | | $ | — |
| | $ | 3,805 |
| | $ | (238 | ) | | $ | 3,567 |
| | $ | 3.8 |
| | $ | (0.3 | ) | | $ | 3.5 |
|
APCo
I&M
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the NineThree Months Ended September 30, 20142016
|
| | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | | | |
| | Commodity | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in thousands) |
Balance in AOCI as of December 31, 2013 | | $ | 94 |
| | $ | 3,090 |
| | $ | (233 | ) | | $ | 2,951 |
|
Change in Fair Value Recognized in AOCI | | 1,686 |
| | — |
| | — |
| | 1,686 |
|
Amounts Reclassified from AOCI | | (1,780 | ) | | 676 |
| | (999 | ) | | (2,103 | ) |
Net Current Period Other Comprehensive Income (Loss) | | (94 | ) | | 676 |
| | (999 | ) | | (417 | ) |
Balance in AOCI as of September 30, 2014 | | $ | — |
| | $ | 3,766 |
| | $ | (1,232 | ) | | $ | 2,534 |
|
|
| | | | | | | | | | | | |
| | Cash Flow Hedges | | | | |
| | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of June 30, 2016 | | $ | (12.6 | ) | | $ | (3.4 | ) | | $ | (16.0 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
Interest Expense | | 0.5 |
| | — |
| | 0.5 |
|
Amortization of Prior Service Cost (Credit) | | — |
| | (0.2 | ) | | (0.2 | ) |
Amortization of Actuarial (Gains)/Losses | | — |
| | 0.2 |
| | 0.2 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | 0.5 |
| | — |
| | 0.5 |
|
Income Tax (Expense) Credit | | 0.2 |
| | — |
| | 0.2 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 0.3 |
| | — |
| | 0.3 |
|
Net Current Period Other Comprehensive Income | | 0.3 |
| | — |
| | 0.3 |
|
Balance in AOCI as of September 30, 2016 | | $ | (12.3 | ) | | $ | (3.4 | ) | | $ | (15.7 | ) |
I&M
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2015
| | | | Cash Flow Hedges | | | | | | Cash Flow Hedges | | | | |
| | Commodity | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in thousands) | | (in millions) |
Balance in AOCI as of June 30, 2015 | | $ | — |
| | $ | (13,871 | ) | | $ | 68 |
| | $ | (13,803 | ) | | $ | (13.9 | ) | | $ | 0.1 |
| | $ | (13.8 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | 267 |
| | 11 |
| | 278 |
| |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | |
Interest Expense | | | 0.4 |
| | — |
| | 0.4 |
|
Amortization of Prior Service Cost (Credit) | | | — |
| | (0.2 | ) | | (0.2 | ) |
Amortization of Actuarial (Gains)/Losses | | | — |
| | 0.2 |
| | 0.2 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | | 0.4 |
| | — |
| | 0.4 |
|
Income Tax (Expense) Credit | | | 0.1 |
| | — |
| | 0.1 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | | 0.3 |
| | — |
| | 0.3 |
|
Net Current Period Other Comprehensive Income | | — |
| | 267 |
| | 11 |
| | 278 |
| | 0.3 |
| | — |
| | 0.3 |
|
Balance in AOCI as of September 30, 2015 | | $ | — |
| | $ | (13,604 | ) | | $ | 79 |
| | $ | (13,525 | ) | | $ | (13.6 | ) | | $ | 0.1 |
| | $ | (13.5 | ) |
I&M
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the ThreeNine Months Ended September 30, 20142016
|
| | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | | | |
| | Commodity | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in thousands) |
Balance in AOCI as of June 30, 2014 | | $ | — |
| | $ | (15,155 | ) | | $ | 507 |
| | $ | (14,648 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | 410 |
| | 42 |
| | 452 |
|
Net Current Period Other Comprehensive Income | | — |
| | 410 |
| | 42 |
| | 452 |
|
Balance in AOCI as of September 30, 2014 | | $ | — |
| | $ | (14,745 | ) | | $ | 549 |
| | $ | (14,196 | ) |
|
| | | | | | | | | | | | |
| | Cash Flow Hedges | | | | |
| | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of December 31, 2015 | | $ | (13.3 | ) | | $ | (3.4 | ) | | $ | (16.7 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
Interest Expense | | 1.5 |
| | — |
| | 1.5 |
|
Amortization of Prior Service Cost (Credit) | | — |
| | (0.6 | ) | | (0.6 | ) |
Amortization of Actuarial (Gains)/Losses | | — |
| | 0.6 |
| | 0.6 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | 1.5 |
| | — |
| | 1.5 |
|
Income Tax (Expense) Credit | | 0.5 |
| | — |
| | 0.5 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 1.0 |
| | — |
| | 1.0 |
|
Net Current Period Other Comprehensive Income | | 1.0 |
| | — |
| | 1.0 |
|
Balance in AOCI as of September 30, 2016 | | $ | (12.3 | ) | | $ | (3.4 | ) | | $ | (15.7 | ) |
I&M
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2015
| | | | Cash Flow Hedges | | | | | | Cash Flow Hedges | | | | |
| | Commodity | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in thousands) | | (in millions) |
Balance in AOCI as of December 31, 2014 | | $ | — |
| | $ | (14,406 | ) | | $ | 46 |
| | $ | (14,360 | ) | | $ | (14.4 | ) | | $ | 0.1 |
| | $ | (14.3 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | 802 |
| | 33 |
| | 835 |
| |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | |
Interest Expense | | | 1.2 |
| | — |
| | 1.2 |
|
Amortization of Prior Service Cost (Credit) | | | — |
| | (0.6 | ) | | (0.6 | ) |
Amortization of Actuarial (Gains)/Losses | | | — |
| | 0.6 |
| | 0.6 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | | 1.2 |
| | — |
| | 1.2 |
|
Income Tax (Expense) Credit | | | 0.4 |
| | — |
| | 0.4 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | | 0.8 |
| | — |
| | 0.8 |
|
Net Current Period Other Comprehensive Income | | — |
| | 802 |
| | 33 |
| | 835 |
| | 0.8 |
| | — |
| | 0.8 |
|
Balance in AOCI as of September 30, 2015 | | $ | — |
| | $ | (13,604 | ) | | $ | 79 |
| | $ | (13,525 | ) | | $ | (13.6 | ) | | $ | 0.1 |
| | $ | (13.5 | ) |
I&M
OPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the NineThree Months Ended September 30, 20142016
|
| | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | | | |
| | Commodity | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in thousands) |
Balance in AOCI as of December 31, 2013 | | $ | 46 |
| | $ | (15,976 | ) | | $ | 421 |
| | $ | (15,509 | ) |
Change in Fair Value Recognized in AOCI | | 1,130 |
| | — |
| | — |
| | 1,130 |
|
Amounts Reclassified from AOCI | | (1,176 | ) | | 1,231 |
| | 128 |
| | 183 |
|
Net Current Period Other Comprehensive Income (Loss) | | (46 | ) | | 1,231 |
| | 128 |
| | 1,313 |
|
Balance in AOCI as of September 30, 2014 | | $ | — |
| | $ | (14,745 | ) | | $ | 549 |
| | $ | (14,196 | ) |
|
| | | | |
| | Cash Flow Hedges |
| | Interest Rate and Foreign Currency |
| | (in millions) |
Balance in AOCI as of June 30, 2016 | | $ | 3.5 |
|
Change in Fair Value Recognized in AOCI | | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense | �� | (0.3 | ) |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (0.3 | ) |
Income Tax (Expense) Credit | | (0.1 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.2 | ) |
Net Current Period Other Comprehensive Loss | | (0.2 | ) |
Balance in AOCI as of September 30, 2016 | | $ | 3.3 |
|
OPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2015
| | | | Cash Flow Hedges | | | | Cash Flow Hedges |
| | Commodity | | Interest Rate and Foreign Currency | | Total | | Interest Rate and Foreign Currency |
| | (in thousands) | | (in millions) |
Balance in AOCI as of June 30, 2015 | | $ | — |
| | $ | 4,916 |
| | $ | 4,916 |
| | $ | 4.9 |
|
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | (344 | ) | | (344 | ) | |
Amount of (Gain) Loss Reclassified from AOCI | | | |
Interest Expense | | | (0.5 | ) |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | | (0.5 | ) |
Income Tax (Expense) Credit | | | (0.2 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | | (0.3 | ) |
Net Current Period Other Comprehensive Loss | | — |
| | (344 | ) | | (344 | ) | | (0.3 | ) |
Balance in AOCI as of September 30, 2015 | | $ | — |
| | $ | 4,572 |
| | $ | 4,572 |
| | $ | 4.6 |
|
OPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the ThreeNine Months Ended September 30, 20142016
|
| | | | | | | | | | | | |
| | Cash Flow Hedges | | |
| | Commodity | | Interest Rate and Foreign Currency | | Total |
| | (in thousands) |
Balance in AOCI as of June 30, 2014 | | $ | — |
| | $ | 6,288 |
| | $ | 6,288 |
|
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | (343 | ) | | (343 | ) |
Net Current Period Other Comprehensive Loss | | — |
| | (343 | ) | | (343 | ) |
Balance in AOCI as of September 30, 2014 | | $ | — |
| | $ | 5,945 |
| | $ | 5,945 |
|
|
| | | | |
| | Cash Flow Hedges |
| | Interest Rate and Foreign Currency |
| | (in millions) |
Balance in AOCI as of December 31, 2015 | | $ | 4.3 |
|
Change in Fair Value Recognized in AOCI | | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense | | (1.4 | ) |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (1.4 | ) |
Income Tax (Expense) Credit | | (0.4 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (1.0 | ) |
Net Current Period Other Comprehensive Loss | | (1.0 | ) |
Balance in AOCI as of September 30, 2016 | | $ | 3.3 |
|
OPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2015
| | | | Cash Flow Hedges | | | | Cash Flow Hedges |
| | Commodity | | Interest Rate and Foreign Currency | | Total | | Interest Rate and Foreign Currency |
| | (in thousands) | | (in millions) |
Balance in AOCI as of December 31, 2014 | | $ | — |
| | $ | 5,602 |
| | $ | 5,602 |
| | $ | 5.6 |
|
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | (1,030 | ) | | (1,030 | ) | |
Amount of (Gain) Loss Reclassified from AOCI | | | |
Interest Expense | | | (1.6 | ) |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | | (1.6 | ) |
Income Tax (Expense) Credit | | | (0.6 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | | (1.0 | ) |
Net Current Period Other Comprehensive Loss | | — |
| | (1,030 | ) | | (1,030 | ) | | (1.0 | ) |
Balance in AOCI as of September 30, 2015 | | $ | — |
| | $ | 4,572 |
| | $ | 4,572 |
| | $ | 4.6 |
|
OPCo
PSO
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the NineThree Months Ended September 30, 20142016
|
| | | | | | | | | | | | |
| | Cash Flow Hedges | | |
| | Commodity | | Interest Rate and Foreign Currency | | Total |
| | (in thousands) |
Balance in AOCI as of December 31, 2013 | | $ | 105 |
| | $ | 6,974 |
| | $ | 7,079 |
|
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | (105 | ) | | (1,029 | ) | | (1,134 | ) |
Net Current Period Other Comprehensive Loss | | (105 | ) | | (1,029 | ) | | (1,134 | ) |
Balance in AOCI as of September 30, 2014 | | $ | — |
| | $ | 5,945 |
| | $ | 5,945 |
|
|
| | | | |
| | Cash Flow Hedges |
| | Interest Rate and Foreign Currency |
| | (in millions) |
Balance in AOCI as of June 30, 2016 | | $ | 3.8 |
|
Change in Fair Value Recognized in AOCI | | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense | | (0.3 | ) |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (0.3 | ) |
Income Tax (Expense) Credit | | (0.1 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.2 | ) |
Net Current Period Other Comprehensive Loss | | (0.2 | ) |
Balance in AOCI as of September 30, 2016 | | $ | 3.6 |
|
PSO
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2015
| | | | Cash Flow Hedges | | | | Cash Flow Hedges |
| | Commodity | | Interest Rate and Foreign Currency | | Total | | Interest Rate and Foreign Currency |
| | (in thousands) | | (in millions) |
Balance in AOCI as of June 30, 2015 | | $ | — |
| | $ | 4,563 |
| | $ | 4,563 |
| | $ | 4.6 |
|
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | (189 | ) | | (189 | ) | |
Amount of (Gain) Loss Reclassified from AOCI | | | |
Interest Expense | | | (0.2 | ) |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | | (0.2 | ) |
Income Tax (Expense) Credit | | | (0.1 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | | (0.1 | ) |
Net Current Period Other Comprehensive Loss | | — |
| | (189 | ) | | (189 | ) | | (0.1 | ) |
Balance in AOCI as of September 30, 2015 | | $ | — |
| | $ | 4,374 |
| | $ | 4,374 |
| | $ | 4.5 |
|
PSO
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the ThreeNine Months Ended September 30, 20142016
|
| | | | | | | | | | | | |
| | Cash Flow Hedges | | |
| | Commodity | | Interest Rate and Foreign Currency | | Total |
| | (in thousands) |
Balance in AOCI as of June 30, 2014 | | $ | — |
| | $ | 5,322 |
| | $ | 5,322 |
|
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | (190 | ) | | (190 | ) |
Net Current Period Other Comprehensive Loss | | — |
| | (190 | ) | | (190 | ) |
Balance in AOCI as of September 30, 2014 | | $ | — |
| | $ | 5,132 |
| | $ | 5,132 |
|
|
| | | | |
| | Cash Flow Hedges |
| | Interest Rate and Foreign Currency |
| | (in millions) |
Balance in AOCI as of December 31, 2015 | | $ | 4.2 |
|
Change in Fair Value Recognized in AOCI | | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | |
Interest Expense | | (0.9 | ) |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (0.9 | ) |
Income Tax (Expense) Credit | | (0.3 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.6 | ) |
Net Current Period Other Comprehensive Loss | | (0.6 | ) |
Balance in AOCI as of September 30, 2016 | | $ | 3.6 |
|
PSO
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2015
| | | | Cash Flow Hedges | | | | Cash Flow Hedges |
| | Commodity | | Interest Rate and Foreign Currency | | Total | | Interest Rate and Foreign Currency |
| | (in thousands) | | (in millions) |
Balance in AOCI as of December 31, 2014 | | $ | — |
| | $ | 4,943 |
| | $ | 4,943 |
| | $ | 5.0 |
|
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | (569 | ) | | (569 | ) | |
Amount of (Gain) Loss Reclassified from AOCI | | | |
Interest Expense | | | (0.8 | ) |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | | (0.8 | ) |
Income Tax (Expense) Credit | | | (0.3 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | | (0.5 | ) |
Net Current Period Other Comprehensive Loss | | — |
| | (569 | ) | | (569 | ) | | (0.5 | ) |
Balance in AOCI as of September 30, 2015 | | $ | — |
| | $ | 4,374 |
| | $ | 4,374 |
| | $ | 4.5 |
|
PSO
SWEPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the NineThree Months Ended September 30, 20142016
|
| | | | | | | | | | | | |
| | Cash Flow Hedges | | |
| | Commodity | | Interest Rate and Foreign Currency | | Total |
| | (in thousands) |
Balance in AOCI as of December 31, 2013 | | $ | 57 |
| | $ | 5,701 |
| | $ | 5,758 |
|
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | (57 | ) | | (569 | ) | | (626 | ) |
Net Current Period Other Comprehensive Loss | | (57 | ) | | (569 | ) | | (626 | ) |
Balance in AOCI as of September 30, 2014 | | $ | — |
| | $ | 5,132 |
| | $ | 5,132 |
|
|
| | | | | | | | | | | | |
| | Cash Flow Hedges | | | | |
| | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of June 30, 2016 | | $ | (8.2 | ) | | $ | (0.7 | ) | | $ | (8.9 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
Interest Expense | | 0.7 |
| | — |
| | 0.7 |
|
Amortization of Prior Service Cost (Credit) | | — |
| | (0.4 | ) | | (0.4 | ) |
Amortization of Actuarial (Gains)/Losses | | — |
| | 0.2 |
| | 0.2 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | 0.7 |
| | (0.2 | ) | | 0.5 |
|
Income Tax (Expense) Credit | | 0.3 |
| | (0.1 | ) | | 0.2 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 0.4 |
| | (0.1 | ) | | 0.3 |
|
Net Current Period Other Comprehensive Income (Loss) | | 0.4 |
| | (0.1 | ) | | 0.3 |
|
Balance in AOCI as of September 30, 2016 | | $ | (7.8 | ) | | $ | (0.8 | ) | | $ | (8.6 | ) |
SWEPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2015
| | | | Cash Flow Hedges | | | | | | Cash Flow Hedges | | | | |
| | Commodity | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in thousands) | | (in millions) |
Balance in AOCI as of June 30, 2015 | | $ | — |
| | $ | (9,902 | ) | | $ | 3,091 |
| | $ | (6,811 | ) | | $ | (10.0 | ) | | $ | 3.1 |
| | $ | (6.9 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | 432 |
| | (240 | ) | | 192 |
| |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | |
Interest Expense | | | 0.7 |
| | — |
| | 0.7 |
|
Amortization of Prior Service Cost (Credit) | | | — |
| | (0.5 | ) | | (0.5 | ) |
Amortization of Actuarial (Gains)/Losses | | | — |
| | 0.1 |
| | 0.1 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | | 0.7 |
| | (0.4 | ) | | 0.3 |
|
Income Tax (Expense) Credit | | | 0.3 |
| | (0.2 | ) | | 0.1 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | | 0.4 |
| | (0.2 | ) | | 0.2 |
|
Net Current Period Other Comprehensive Income (Loss) | | — |
| | 432 |
| | (240 | ) | | 192 |
| | 0.4 |
| | (0.2 | ) | | 0.2 |
|
Balance in AOCI as of September 30, 2015 | | $ | — |
| | $ | (9,470 | ) | | $ | 2,851 |
| | $ | (6,619 | ) | | $ | (9.6 | ) | | $ | 2.9 |
| | $ | (6.7 | ) |
SWEPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the ThreeNine Months Ended September 30, 20142016
|
| | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | | | |
| | Commodity | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in thousands) |
Balance in AOCI as of June 30, 2014 | | $ | — |
| | $ | (12,169 | ) | | $ | 4,325 |
| | $ | (7,844 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | 567 |
| | (235 | ) | | 332 |
|
Net Current Period Other Comprehensive Income (Loss) | | — |
| | 567 |
| | (235 | ) | | 332 |
|
Balance in AOCI as of September 30, 2014 | | $ | — |
| | $ | (11,602 | ) | | $ | 4,090 |
| | $ | (7,512 | ) |
|
| | | | | | | | | | | | |
| | Cash Flow Hedges | | | | |
| | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of December 31, 2015 | | $ | (9.1 | ) | | $ | (0.3 | ) | | $ | (9.4 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
Interest Expense | | 2.0 |
| | — |
| | 2.0 |
|
Amortization of Prior Service Cost (Credit) | | — |
| | (1.4 | ) | | (1.4 | ) |
Amortization of Actuarial (Gains)/Losses | | — |
| | 0.6 |
| | 0.6 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | 2.0 |
| | (0.8 | ) | | 1.2 |
|
Income Tax (Expense) Credit | | 0.7 |
| | (0.3 | ) | | 0.4 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 1.3 |
| | (0.5 | ) | | 0.8 |
|
Net Current Period Other Comprehensive Income (Loss) | | 1.3 |
| | (0.5 | ) | | 0.8 |
|
Balance in AOCI as of September 30, 2016 | | $ | (7.8 | ) | | $ | (0.8 | ) | | $ | (8.6 | ) |
SWEPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2015
| | | | Cash Flow Hedges | | | | | | Cash Flow Hedges | | | | |
| | Commodity | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in thousands) | | (in millions) |
Balance in AOCI as of December 31, 2014 | | $ | — |
| | $ | (11,036 | ) | | $ | 3,570 |
| | $ | (7,466 | ) | | $ | (11.1 | ) | | $ | 3.6 |
| | $ | (7.5 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | — |
| | 1,566 |
| | (719 | ) | | 847 |
| |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | |
Interest Expense | | | 2.4 |
| | — |
| | 2.4 |
|
Amortization of Prior Service Cost (Credit) | | | — |
| | (1.4 | ) | | (1.4 | ) |
Amortization of Actuarial (Gains)/Losses | | | — |
| | 0.3 |
| | 0.3 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | | 2.4 |
| | (1.1 | ) | | 1.3 |
|
Income Tax (Expense) Credit | | | 0.9 |
| | (0.4 | ) | | 0.5 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | | 1.5 |
| | (0.7 | ) | | 0.8 |
|
Net Current Period Other Comprehensive Income (Loss) | | — |
| | 1,566 |
| | (719 | ) | | 847 |
| | 1.5 |
| | (0.7 | ) | | 0.8 |
|
Balance in AOCI as of September 30, 2015 | | $ | — |
| | $ | (9,470 | ) | | $ | 2,851 |
| | $ | (6,619 | ) | | $ | (9.6 | ) | | $ | 2.9 |
| | $ | (6.7 | ) |
SWEPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2014
|
| | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | | | |
| | Commodity | | Interest Rate and Foreign Currency | | Pension and OPEB | | Total |
| | (in thousands) |
Balance in AOCI as of December 31, 2013 | | $ | 66 |
| | $ | (13,304 | ) | | $ | 4,794 |
| | $ | (8,444 | ) |
Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
| | — |
|
Amounts Reclassified from AOCI | | (66 | ) | | 1,702 |
| | (704 | ) | | 932 |
|
Net Current Period Other Comprehensive Income (Loss) | | (66 | ) | | 1,702 |
| | (704 | ) | | 932 |
|
Balance in AOCI as of September 30, 2014 | | $ | — |
| | $ | (11,602 | ) | | $ | 4,090 |
| | $ | (7,512 | ) |
Reclassifications from Accumulated Other Comprehensive Income
The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2015 and 2014. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details.
APCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2015 and 2014
|
| | | | | | | | |
| | Amount of (Gain) Loss Reclassified from AOCI |
| | Three Months Ended September 30, |
| | 2015 | | 2014 |
Gains and Losses on Cash Flow Hedges | | (in thousands) |
Commodity: | | |
| | |
Purchased Electricity for Resale | | $ | — |
| | $ | — |
|
Regulatory Assets/(Liabilities), Net (a) | | — |
| | — |
|
Subtotal – Commodity | | — |
| | — |
|
| | |
| | |
Interest Rate and Foreign Currency: | | |
| | |
Interest Expense | | (342 | ) | | 262 |
|
Subtotal – Interest Rate and Foreign Currency | | (342 | ) | | 262 |
|
| | | | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (342 | ) | | 262 |
|
Income Tax (Expense) Credit | | (120 | ) | | 92 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (222 | ) | | 170 |
|
| | | | |
Pension and OPEB | | |
| | |
Amortization of Prior Service Cost (Credit) | | (1,282 | ) | | (1,281 | ) |
Amortization of Actuarial (Gains)/Losses | | 577 |
| | 769 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (705 | ) | | (512 | ) |
Income Tax (Expense) Credit | | (247 | ) | | (179 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (458 | ) | | (333 | ) |
| | |
| | |
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | $ | (680 | ) | | $ | (163 | ) |
APCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2015 and 2014
|
| | | | | | | | |
| | Amount of (Gain) Loss Reclassified from AOCI |
| | Nine Months Ended September 30, |
| | 2015 | | 2014 |
Gains and Losses on Cash Flow Hedges | | (in thousands) |
Commodity: | | |
| | |
Purchased Electricity for Resale | | $ | — |
| | $ | (526 | ) |
Other Operation Expense | | — |
| | (10 | ) |
Maintenance Expense | | — |
| | (20 | ) |
Property, Plant and Equipment | | — |
| | (17 | ) |
Regulatory Assets/(Liabilities), Net (a) | | — |
| | (2,165 | ) |
Subtotal – Commodity | | — |
| | (2,738 | ) |
| | |
| | |
Interest Rate and Foreign Currency: | | |
| | |
Interest Expense | | (140 | ) | | 1,042 |
|
Subtotal – Interest Rate and Foreign Currency | | (140 | ) | | 1,042 |
|
| | | | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (140 | ) | | (1,696 | ) |
Income Tax (Expense) Credit | | (49 | ) | | (592 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (91 | ) | | (1,104 | ) |
| | | | |
Pension and OPEB | | |
| | |
Amortization of Prior Service Cost (Credit) | | (3,847 | ) | | (3,846 | ) |
Amortization of Actuarial (Gains)/Losses | | 1,733 |
| | 2,309 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (2,114 | ) | | (1,537 | ) |
Income Tax (Expense) Credit | | (740 | ) | | (538 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (1,374 | ) | | (999 | ) |
| | |
| | |
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | $ | (1,465 | ) | | $ | (2,103 | ) |
I&M
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2015 and 2014
|
| | | | | | | | |
| | Amount of (Gain) Loss Reclassified from AOCI |
| | Three Months Ended September 30, |
| | 2015 | | 2014 |
Gains and Losses on Cash Flow Hedges | | (in thousands) |
Commodity: | | |
| | |
Purchased Electricity for Resale | | $ | — |
| | $ | — |
|
Regulatory Assets/(Liabilities), Net (a) | | — |
| | — |
|
Subtotal – Commodity | | — |
| | — |
|
| | |
| | |
Interest Rate and Foreign Currency: | | |
| | |
Interest Expense | | 412 |
| | 631 |
|
Subtotal – Interest Rate and Foreign Currency | | 412 |
| | 631 |
|
| | | | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | 412 |
| | 631 |
|
Income Tax (Expense) Credit | | 145 |
| | 221 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 267 |
| | 410 |
|
| | | | |
Pension and OPEB | | |
| | |
Amortization of Prior Service Cost (Credit) | | (198 | ) | | (200 | ) |
Amortization of Actuarial (Gains)/Losses | | 215 |
| | 264 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | 17 |
| | 64 |
|
Income Tax (Expense) Credit | | 6 |
| | 22 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 11 |
| | 42 |
|
| | |
| | |
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | $ | 278 |
| | $ | 452 |
|
I&M
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2015 and 2014
|
| | | | | | | | |
| | Amount of (Gain) Loss Reclassified from AOCI |
| | Nine Months Ended September 30, |
| | 2015 | | 2014 |
Gains and Losses on Cash Flow Hedges | | (in thousands) |
Commodity: | | |
| | |
Purchased Electricity for Resale | | $ | — |
| | $ | (812 | ) |
Other Operation Expense | | — |
| | (7 | ) |
Maintenance Expense | | — |
| | (7 | ) |
Property, Plant and Equipment | | — |
| | (10 | ) |
Regulatory Assets/(Liabilities), Net (a) | | — |
| | (973 | ) |
Subtotal – Commodity | | — |
| | (1,809 | ) |
| | |
| | |
Interest Rate and Foreign Currency: | | |
| | |
Interest Expense | | 1,234 |
| | 1,893 |
|
Subtotal – Interest Rate and Foreign Currency | | 1,234 |
| | 1,893 |
|
| | | | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | 1,234 |
| | 84 |
|
Income Tax (Expense) Credit | | 432 |
| | 29 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 802 |
| | 55 |
|
| | | | |
Pension and OPEB | | |
| | |
Amortization of Prior Service Cost (Credit) | | (596 | ) | | (597 | ) |
Amortization of Actuarial (Gains)/Losses | | 647 |
| | 791 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | 51 |
| | 194 |
|
Income Tax (Expense) Credit | | 18 |
| | 66 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 33 |
| | 128 |
|
| | |
| | |
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | $ | 835 |
| | $ | 183 |
|
OPCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2015 and 2014
|
| | | | | | | | |
| | Amount of (Gain) Loss Reclassified from AOCI |
| | Three Months Ended September 30, |
| | 2015 | | 2014 |
Gains and Losses on Cash Flow Hedges | | (in thousands) |
Commodity: | | |
| | |
Other Operation Expense | | $ | — |
| | $ | — |
|
Maintenance Expense | | — |
| | — |
|
Property, Plant and Equipment | | — |
| | — |
|
Regulatory Assets/(Liabilities), Net (a) | | — |
| | — |
|
Subtotal – Commodity | | — |
| | — |
|
| | | | |
Interest Rate and Foreign Currency: | | |
| | |
Depreciation and Amortization Expense | | (4 | ) | | (3 | ) |
Interest Expense | | (526 | ) | | (524 | ) |
Subtotal – Interest Rate and Foreign Currency | | (530 | ) | | (527 | ) |
| | | | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (530 | ) | | (527 | ) |
Income Tax (Expense) Credit | | (186 | ) | | (184 | ) |
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | $ | (344 | ) | | $ | (343 | ) |
OPCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2015 and 2014
|
| | | | | | | | |
| | Amount of (Gain) Loss Reclassified from AOCI |
| | Nine Months Ended September 30, |
| | 2015 | | 2014 |
Gains and Losses on Cash Flow Hedges | | (in thousands) |
Commodity: | | |
| | |
Other Operation Expense | | $ | — |
| | $ | (11 | ) |
Maintenance Expense | | — |
| | (11 | ) |
Property, Plant and Equipment | | — |
| | (18 | ) |
Regulatory Assets/(Liabilities), Net (a) | | — |
| | (122 | ) |
Subtotal – Commodity | | — |
| | (162 | ) |
| | |
| | |
Interest Rate and Foreign Currency: | | |
| | |
Depreciation and Amortization Expense | | (10 | ) | | (9 | ) |
Interest Expense | | (1,574 | ) | | (1,572 | ) |
Subtotal – Interest Rate and Foreign Currency | | (1,584 | ) | | (1,581 | ) |
| | | | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (1,584 | ) | | (1,743 | ) |
Income Tax (Expense) Credit | | (554 | ) | | (609 | ) |
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | $ | (1,030 | ) | | $ | (1,134 | ) |
PSO
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2015 and 2014
|
| | | | | | | | |
| | Amount of (Gain) Loss Reclassified from AOCI |
| | Three Months Ended September 30, |
| | 2015 | | 2014 |
Gains and Losses on Cash Flow Hedges | | (in thousands) |
Commodity: | | | | |
Other Operation Expense | | $ | — |
| | $ | — |
|
Maintenance Expense | | — |
| | — |
|
Property, Plant and Equipment | | — |
| | — |
|
Regulatory Assets/(Liabilities), Net (a) | | — |
| | — |
|
Subtotal – Commodity | | — |
| | — |
|
| | | | |
Interest Rate and Foreign Currency: | | |
| | |
Interest Expense | | (291 | ) | | (292 | ) |
Subtotal – Interest Rate and Foreign Currency | | (291 | ) | | (292 | ) |
| | | | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (291 | ) | | (292 | ) |
Income Tax (Expense) Credit | | (102 | ) | | (102 | ) |
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | $ | (189 | ) | | $ | (190 | ) |
PSO
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2015 and 2014
|
| | | | | | | | |
| | Amount of (Gain) Loss Reclassified from AOCI |
| | Nine Months Ended September 30, |
| | 2015 | | 2014 |
Gains and Losses on Cash Flow Hedges | | (in thousands) |
Commodity: | | |
| | |
Other Operation Expense | | $ | — |
| | $ | (8 | ) |
Maintenance Expense | | — |
| | (9 | ) |
Property, Plant and Equipment | | — |
| | (13 | ) |
Regulatory Assets/(Liabilities), Net (a) | | — |
| | (58 | ) |
Subtotal – Commodity | | — |
| | (88 | ) |
| | |
| | |
Interest Rate and Foreign Currency: | | |
| | |
Interest Expense | | (875 | ) | | (876 | ) |
Subtotal – Interest Rate and Foreign Currency | | (875 | ) | | (876 | ) |
| | | | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (875 | ) | | (964 | ) |
Income Tax (Expense) Credit | | (306 | ) | | (338 | ) |
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | $ | (569 | ) | | $ | (626 | ) |
SWEPCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended September 30, 2015 and 2014
|
| | | | | | | | |
| | Amount of (Gain) Loss Reclassified from AOCI |
| | Three Months Ended September 30, |
| | 2015 | | 2014 |
Gains and Losses on Cash Flow Hedges | | (in thousands) |
Commodity: | | |
| | |
Other Operation Expense | | $ | — |
| | $ | — |
|
Maintenance Expense | | — |
| | — |
|
Property, Plant and Equipment | | — |
| | — |
|
Regulatory Assets/(Liabilities), Net (a) | | — |
| | — |
|
Subtotal – Commodity | | — |
| | — |
|
| | | | |
Interest Rate and Foreign Currency: | | |
| | |
Interest Expense | | 665 |
| | 872 |
|
Subtotal – Interest Rate and Foreign Currency | | 665 |
| | 872 |
|
| | | | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | 665 |
| | 872 |
|
Income Tax (Expense) Credit | | 233 |
| | 305 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 432 |
| | 567 |
|
| | | | |
Pension and OPEB | | |
| | |
Amortization of Prior Service Cost (Credit) | | (468 | ) | | (478 | ) |
Amortization of Actuarial (Gains)/Losses | | 99 |
| | 118 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (369 | ) | | (360 | ) |
Income Tax (Expense) Credit | | (129 | ) | | (125 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (240 | ) | | (235 | ) |
| | |
| | |
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | $ | 192 |
| | $ | 332 |
|
SWEPCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Nine Months Ended September 30, 2015 and 2014
|
| | | | | | | | |
| | Amount of (Gain) Loss Reclassified from AOCI |
| | Nine Months Ended September 30, |
| | 2015 | | 2014 |
Gains and Losses on Cash Flow Hedges | | (in thousands) |
Commodity: | | |
| | |
Other Operation Expense | | $ | — |
| | $ | (13 | ) |
Maintenance Expense | | — |
| | (10 | ) |
Property, Plant and Equipment | | — |
| | (11 | ) |
Regulatory Assets/(Liabilities), Net (a) | | — |
| | (67 | ) |
Subtotal – Commodity | | — |
| | (101 | ) |
| | |
| | |
Interest Rate and Foreign Currency: | | |
| | |
Interest Expense | | 2,409 |
| | 2,616 |
|
Subtotal – Interest Rate and Foreign Currency | | 2,409 |
| | 2,616 |
|
| | | | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | | 2,409 |
| | 2,515 |
|
Income Tax (Expense) Credit | | 843 |
| | 879 |
|
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 1,566 |
| | 1,636 |
|
| | | | |
Pension and OPEB | | |
| | |
Amortization of Prior Service Cost (Credit) | | (1,402 | ) | | (1,433 | ) |
Amortization of Actuarial (Gains)/Losses | | 296 |
| | 351 |
|
Reclassifications from AOCI, before Income Tax (Expense) Credit | | (1,106 | ) | | (1,082 | ) |
Income Tax (Expense) Credit | | (387 | ) | | (378 | ) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (719 | ) | | (704 | ) |
| | |
| | |
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | $ | 847 |
| | $ | 932 |
|
| |
(a) | Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
4. RATE MATTERS
The disclosures in this note apply to all Registrants unless indicated otherwise.
As discussed in the 20142015 Annual Report, the Registrant SubsidiariesRegistrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 20142015 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 20152016 and updates the 20142015 Annual Report.
Regulatory Assets Pending Final Regulatory Approval
|
| | | | | | | | |
| | APCo |
| | September 30, | | December 31, |
| | 2015 | | 2014 |
Noncurrent Regulatory Assets | | (in thousands) |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Materials and Supplies Related to Retired Plants | | $ | 8,592 |
| | $ | — |
|
Vegetation Management Program – West Virginia | | — |
| | 19,089 |
|
Regulatory Assets Currently Not Earning a Return | | | | |
Asset Retirement Obligation Costs Related to Retired Plants | | 32,128 |
| | — |
|
Peak Demand Reduction/Energy Efficiency – Virginia | | 11,650 |
| | 8,791 |
|
Amos Plant Transfer Costs – West Virginia | | 1,950 |
| | 1,377 |
|
Deferred Permit Fees Related to Retired Plants – West Virginia | | 617 |
| | — |
|
Storm Related Costs – West Virginia | | — |
| | 65,206 |
|
Carbon Capture and Storage Product Validation Facility – West Virginia, FERC | | — |
| | 13,264 |
|
IGCC Pre-Construction Costs – West Virginia, FERC | | — |
| | 10,838 |
|
Expanded Net Energy Charge – Coal Inventory – West Virginia | | — |
| | 3,421 |
|
Expanded Net Energy Charge – Construction Surcharge – West Virginia | | — |
| | 2,307 |
|
Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC | | — |
| | 1,287 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | — |
| | 168 |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 54,937 |
| | $ | 125,748 |
|
|
| | | | | | | | |
| | AEP |
| | September 30, | | December 31, |
| | 2016 | | 2015 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Plant Retirement Costs - Unrecovered Plant | | $ | 161.3 |
| | $ | — |
|
Storm-Related Costs | | 25.4 |
| | 24.2 |
|
Plant Retirement Costs - Materials and Supplies | | 20.8 |
| | 20.9 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | 1.2 |
| | — |
|
Regulatory Assets Currently Not Earning a Return | | |
| | |
|
Plant Retirement Costs - Asset Retirement Obligation Costs | | 56.7 |
| | 59.8 |
|
Storm-Related Costs | | 26.7 |
| | 18.2 |
|
Cook Plant Turbine | | 12.0 |
| | 9.7 |
|
Peak Demand Reduction/Energy Efficiency | | 0.2 |
| | 13.1 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | 39.0 |
| | 22.0 |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 343.3 |
| | $ | 167.9 |
|
|
| | | | | | | | |
| | I&M |
| | September 30, | | December 31, |
| | 2015 | | 2014 |
Noncurrent Regulatory Assets | | (in thousands) |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Materials and Supplies Related to Retired Plants | | $ | 11,652 |
| | $ | — |
|
Regulatory Assets Currently Not Earning a Return | | | | |
Asset Retirement Obligation Costs Related to Retired Plants | | 27,079 |
| | — |
|
Cook Plant Turbine | | 8,955 |
| | 6,596 |
|
Stranded Costs on Abandoned Plants | | 3,897 |
| | 3,897 |
|
Deferred Cook Plant Life Cycle Management Project Costs – Michigan | | 3,445 |
| | 1,222 |
|
Rockport Dry Sorbent Injection System | | 1,865 |
| | 148 |
|
Storm Related Costs – Indiana | | — |
| | 1,074 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | 11 |
| | 712 |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 56,904 |
| | $ | 13,649 |
|
|
| | | | | | | | |
| | APCo |
| | September 30, | | December 31, |
| | 2016 | | 2015 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Plant Retirement Costs - Materials and Supplies | | $ | 9.2 |
| | $ | 9.3 |
|
Regulatory Assets Currently Not Earning a Return | | | | |
Plant Retirement Costs - Asset Retirement Obligation Costs | | 29.6 |
| | 32.7 |
|
Peak Demand Reduction/Energy Efficiency - Virginia | | — |
| | 12.7 |
|
Amos Plant Transfer Costs - West Virginia | | — |
| | 2.0 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | 0.6 |
| | 0.6 |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 39.4 |
| | $ | 57.3 |
|
|
| | | | | | | | |
| | OPCo |
| | September 30, | | December 31, |
| | 2015 | | 2014 |
Noncurrent Regulatory Assets | | (in thousands) |
| | | | |
Regulatory Assets Currently Not Earning a Return | | |
| | |
|
Ormet Special Rate Recovery Mechanism | | $ | 10,483 |
| | $ | 10,483 |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 10,483 |
| | $ | 10,483 |
|
| | | | PSO | | I&M |
| | September 30, | | December 31, | | September 30, | | December 31, |
| | 2015 | | 2014 | | 2016 | | 2015 |
Noncurrent Regulatory Assets | | (in thousands) | | (in millions) |
| | | | | | | | |
Regulatory Assets Currently Earning a Return | | | | | |
Plant Retirement Costs - Materials and Supplies | | | $ | 11.6 |
| | $ | 11.6 |
|
Regulatory Assets Currently Not Earning a Return | | |
| | |
| | | | |
Storm Related Costs | | $ | — |
| | $ | 16,614 |
| |
Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana | | | 27.1 |
| | 27.1 |
|
Cook Plant Turbine | | | 12.0 |
| | 9.7 |
|
Deferred Cook Plant Life Cycle Management Project Costs - Michigan | | | 7.1 |
| | 4.2 |
|
Rockport Dry Sorbent Injection System - Indiana | | | 5.5 |
| | 2.8 |
|
Stranded Costs on Retired Plant | | | 3.9 |
| | 3.9 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | — |
| | 1,079 |
| | 0.6 |
| | — |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | — |
| | $ | 17,693 |
| | $ | 67.8 |
| | $ | 59.3 |
|
|
| | | | | | | | |
| | SWEPCo |
| | September 30, | | December 31, |
| | 2015 | | 2014 |
Noncurrent Regulatory Assets | | (in thousands) |
| | | | |
Regulatory Assets Currently Not Earning a Return | | | | |
Shipe Road Transmission Project | | $ | 3,031 |
| | $ | 2,287 |
|
Asset Retirement Obligation | | 1,516 |
| | 1,144 |
|
Rate Case Expenses | | — |
| | 8,126 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | 695 |
| | 558 |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 5,242 |
| | $ | 12,115 |
|
|
| | | | | | | | |
| | OPCo |
| | September 30, | | December 31, |
| | 2016 | | 2015 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Not Earning a Return | | |
| | |
|
OVEC Purchased Power | | 9.1 |
| | — |
|
gridSMART® Costs | | 3.2 |
| | 1.3 |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 12.3 |
| | $ | 1.3 |
|
|
| | | | | | | | |
| | PSO |
| | September 30, | | December 31, |
| | 2016 | | 2015 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Plant Retirement Costs - Unrecovered Plant | | $ | 85.9 |
| | $ | — |
|
Plant Retirement Costs - Asset Retirement Obligation Costs | | 0.5 |
| | — |
|
Regulatory Assets Currently Not Earning a Return | | |
| | |
|
Storm-Related Costs | | 20.5 |
| | 12.3 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | 1.3 |
| | 1.1 |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 108.2 |
| | $ | 13.4 |
|
|
| | | | | | | | |
| | SWEPCo |
| | September 30, | | December 31, |
| | 2016 | | 2015 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Plant Retirement Costs - Unrecovered Plant | | $ | 75.4 |
| | $ | — |
|
Plant Retirement Costs - Asset Retirement Obligation Costs | | 0.5 |
| | — |
|
Other Regulatory Assets Pending Final Regulatory Approval | | 0.1 |
| | — |
|
Regulatory Assets Currently Not Earning a Return | | | | |
Shipe Road Transmission Project - FERC | | 3.1 |
| | 3.1 |
|
Asset Retirement Obligation - Arkansas, Louisiana | | 2.5 |
| | 1.7 |
|
Other Regulatory Assets Pending Final Regulatory Approval | | 2.2 |
| | 1.1 |
|
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 83.8 |
| | $ | 5.9 |
|
If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.
APCo and WPCo Rate Matters (Applies to AEP and APCo)
2016 West Virginia Expanded Net Energy Cost Filing
In June 2016, the WVPSC approved a settlement agreement related to APCo and WPCo’s combined annual ENEC filing. The settlement agreement included $38 million ($30 million related to APCo) of additional ENEC revenues and $17 million ($14 million related to APCo) in construction surcharges annually for two years, effective July 2016. Additionally, APCo and WPCo agreed that a general rate case will not be filed before April 2018.
West Virginia Deferred Base Rate Increase
In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. The order included a delayed billing of $25 million ($22 million related to APCo) of the annual base rate increase to residential customers until July 2016. In June 2016, the WVPSC issued an order that approved recovery of the total deferred billing, including carrying charges through June 2018, totaling $29 million ($27 million related to APCo). Recovery was approved over two years, effective July 2016. Additionally, at the end of the two-year amortization, any over/under-recovery of the delayed billing will be included in the annual ENEC filing. The WVPSC also approved implementation of the prospective $25 million base rate increase effective July 2016.
2015 Virginia Regulatory Asset Proceeding
In 2015, the Virginia SCC initiated a proceeding to address the treatment of APCo’s authorized regulatory assets. In September 2016, the Virginia SCC issued an order that approved the continued recovery through amortization of certain regulatory assets established prior to the period of frozen rates pursuant to the amended Virginia law (see “Virginia Legislation Affecting Biennial Reviews” below).
Virginia Legislation Affecting Biennial Reviews
In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA.
In February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning in 2016. In July 2016, the Virginia SCC issued an order that denied the petition. In July 2016, intervenors, including certain APCo industrial customers, filed an appeal of the order with the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition.
ETT Rate Matters (Applies to AEP)
ETT Interim Transmission Rates
Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of September 30, 2016, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $545 million based upon interim rate increases received from 2009 through 2016.During a November 2015 open meeting at the PUCT, ETT committed to file a base rate case by February 2017. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition.
I&M Rate Matters (Applies to AEP and I&M)
Indiana Amended PJM Settlement Agreement
In September 2016, I&M and certain intervenors filed an amended settlement agreement with the IURC. This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017.
The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018. Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018. A hearing at the IURC was held in October 2016.
Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR)
In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NOx from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs, depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates.
KGPCo Rate Matters (Applies to AEP)
Kingsport Base Rate Case
In January 2016, KGPCo filed a request with the TRA to increase base rates by $12 million annually based upon a proposed return on common equity of 10.66%. In August 2016, the TRA approved a settlement agreement that included an $8 million annual increase in base rates with a 9.85% return on common equity effective September 2016.
OPCo Rate Matters (Applies to AEP and OPCo)
Ohio Electric Security Plan Filings
2009 – 2011 ESP
The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018.
In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissedremanded the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. In September 2015, the Supreme Court of Ohio denied the IEU's request for reconsideration and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. In June 2016, the PUCO approved OPCo’s proposed increase to the PIRR rates, in accordance with the Supreme Court of Ohio ruling. The increase to PIRR rates included $146 million in additional carrying charges and the recovery of $40 million in additional under-recovered fuel costs resulting from a decrease in customer demand. The increase is effective July 2016 through December 2018. In July 2016, intervenors filed requests for rehearing with the PUCO, which the PUCO granted in August 2016.
202If the PUCO determines after rehearing that the additional PIRR carrying charges are not recoverable, it could reduce future net income and cash flows and impact financial condition.
June 2012 – May 2015 ESP Including Capacity Charge
In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. ThisIn 2013, this ruling was generally upheld in PUCO rehearing orders in January and March 2013.orders.
In July 2012, the PUCO issued an order in a separate capacity proceeding which stated thatrequiring OPCo mustto charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The OPCo RPM price collected from CRES providers, which includesincluded reserve margins, was approximately $34/MW day through May 2014 and $150/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision withApril 2016, the Supreme Court of Ohio which has scheduled oralissued two opinions related to the deferral of OPCo’s capacity charges. In one of the opinions, the Supreme Court of Ohio ruled that the PUCO must reconsider an energy credit that was used to determine OPCo’s authorized capacity deferral threshold of $188.88/MW day during the August 2012 through May 2015 period. The PUCO reduced OPCo’s authorized capacity deferral threshold to $188.88/MW day largely due to an offset for an energy credit of $147.41/MW day. The Supreme Court of Ohio directed the PUCO to substantively address OPCo’s arguments forthat the fourth quarter of 2015.$147.41/MW day credit was overstated by approximately $100/MW day due to various inaccuracies affecting input data and assumptions.
As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50/MWh through May 2014 and at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that modified and approved with modifications, OPCo'sOPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00/MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million. In May 2015, the PUCO granted intervenors requests for rehearing.balance. As of September 30, 2015, OPCo's2016, OPCo’s net deferred capacity costs balance of $392was $239 million, including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. ThroughIn April 2016, the second Supreme Court of Ohio opinion rejected a portion of OPCo’s RSR revenues collected during the period September 30,2012 through May 2015 OPCo hasand directed the PUCO to reduce OPCo’s deferred capacity costs by these previously collected $183 million inRSR revenues. The Supreme Court of
Ohio was not able to determine the amount of the reduction to OPCo’s deferred capacity costs and related carrying charges.remanded the issue to the PUCO to determine the appropriate reduction. As directed by the PUCO, in May 2016, OPCo submitted revised RSR tariffs that reflect the RSR being collected subject to refund.
In April 2016, the Supreme Court of Ohio also ruled favorably on OPCo’s cross-appeal regarding a previously PUCO-imposed SEET threshold under the ESP and remanded this issue to the PUCO. See “Significantly Excessive Earnings Test Filings” section below.
In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015.
In November 2013, the PUCO issued an order approving OPCo’s CBPcompetitive bid process with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.
In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report with the PUCO for the period August 2012 through May 2015 with the PUCO.2015. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo'sOPCo’s $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report.
In June 2016, OPCo filed a request with the PUCO that requested a consolidated procedural schedule to resolve interrelated proceedings including (a) OPCo’s deferral of capacity costs for the period August 2012 through May 2015, (b) the implementation of OPCo’s RSR and (c) the concerns related to the recovery of fixed fuel costs through both the FAC and the approved capacity charges. As part of the filing, OPCo requested that its net deferred capacity costs balance as of May 31, 2015 increase by $157 million, including carrying charges through September 2016. This net increase consists of a $327 million decrease due to the non-deferral portion of the RSR collections and an increase of $484 million for the correction of the energy credit. Recovery of the $157 million was requested to be effective October 2016 through December 2018. Additionally, OPCo filed testimony supporting the position that double recovery of fixed fuel costs could not have occurred because OPCo was unable to fully recover its capacity costs, which included fixed fuel costs, even with a corrected energy credit.
Due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, management believes that the PUCO will rule upon these issues together. Further, management believes that the net impact of these issues will not result in a material future reduction of OPCo’s net income. The recovery of fixed fuel costs will be addressed in a separate hearing scheduled for January 2017. See “2012 and 2013 Fuel Adjustment Clause Audits” section below.
If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.
June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024
In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA)PPA rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets.
In February 2015, the PUCO issued an order approving OPCo'sOPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo'sOPCo’s proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo'sOPCo’s and various intervenors'intervenors’ requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider.
In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo'sOPCo’s OVEC contractual entitlement (OVEC PPA), (b) addressed the PPA requirements set forth in the PUCO'sPUCO’s February 2015 order (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d)(c) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. A hearingunits (Affiliate PPA).
In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is effective April 2016 through May 2024, subject to audit and review by the PUCO. The stipulation agreement, as approved, included (a) an Affiliate PPA between OPCo and AGR to be included in the PPA rider, (b) OPCo’s OVEC PPA to be included in the PPA rider, (c) potential additional contingent customer credits of up to $100 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions.
In March 2016, a group of merchant generation owners filed a complaint at the FERC against PJM seeking revisions to the Minimum Offer Price Rule (MOPR) in PJM’s tariff. Although the complaint requested the FERC act in advance of the May 2016 Base Residual Auction for the 2019/2020 delivery year, the complaint is still pending without a decision from the FERC. If approved as proposed, the revised MOPR could affect future bidding behavior for units with cost recovery mechanisms.
In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and OPCo. The FERC order rescinded the waivers of the FERC’s affiliate rules as to the affiliate PPA between AGR and OPCo. As a result, AGR and OPCo cannot implement the affiliate PPA without the FERC review, in accordance with FERC’s rules governing affiliate transactions. As a result of the April 2016 FERC order, management does not intend to pursue the affiliate PPA.
In May 2016, OPCo filed an application for rehearing with the PUCO related to certain aspects of the March 2016 PUCO order. The application included a proposed OVEC-only PPA Rider that included an option for the rider to be bypassable. The proposed OVEC-only PPA Rider included (a) the elimination of the PUCO-imposed customer-specific rate impact cap of 5% through May 2018, (b) modifications to proportionately decrease the amount of the potential customer credits and (c) the inclusion of PJM capacity performance penalties within the PPA commencedrider. Also in September 2015. In October 2015,May 2016, intervenors filed applications for rehearing with the PUCO staff submitted testimony that opposedopposing the modified and approved stipulation agreement.
OPCo has the option to exercise its right to withdraw from the PPA application as currentlystipulation if the PUCO does not accept the requested modifications.
Consistent with the terms of the modified and approved stipulation agreement, in May 2016, OPCo filed an amended ESP that proposed but concluded that, with changes,to extend the ESP through May 2024. The amended ESP included (a) an extension of the PPA rider, which includes only OPCo’s entitlements to its ownership percentage of OVEC, (b) a PPA could beproposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the public interest.June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Generation Resource Rider. Based upon a September 2016 PUCO order, OPCo will refile its ESP extension application and supporting testimony in November 2016.
If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.
Significantly Excessive Earnings Test Filings
Background
Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric distribution utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk.
2009 SEET Filing
In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project.
In September 2013, a proposed second phase of OPCo’s gridSMART® (gridSMART® Phase II) program was filed with the PUCO which included a proposed project to satisfy thisthe PUCO 2009 SEET directive. In April 2016, a stipulation agreement related to the gridSMART® Phase II program was filed with the PUCO. As part of the stipulation agreement, OPCo will invest at least $20 million over a six-year period for the installation of Volt VAR Optimization (VVO) technology on selected circuits throughout OPCo’s service territory. All parties to the stipulation agree that OPCo’s proposed VVO investment resolves OPCo’s outstanding obligation for renewable or similar investment associated with the PUCO’s 2009 SEET directive. A hearing at the PUCO on the stipulation was held in August 2016. A decision from the PUCO is pending.
2014 and 2015 SEET Filing
The PUCO established an annual SEET earnings threshold of 12% during the June 2012 - May 2015 ESP period. In May 2013, OPCo filed a cross appeal with the Supreme Court of Ohio, asserting that the SEET threshold would not be based on the earnings of comparable publicly traded companies as originally required by the SEET statute.
In April 2016, the Supreme Court of Ohio agreed with OPCo’s cross-appeal assertion that a 12% SEET threshold was not based on the applicable Ohio SEET statute. The Supreme Court of Ohio reversed the 12% threshold and remanded this issue to the PUCO. A decision from the PUCO is pending.
In June 2015 and May 2016, OPCo submitted its SEET filings for 2014 SEET filingand 2015, respectively, with the PUCO. In August 2016, intervenors filed testimony recommending a revenue refund of approximately $20 million for 2014 and no refund for 2015 based upon a new approach to determine significantly excessive earnings that has not been previously approved by the PUCO. In September 2016, OPCo and the PUCO staff filed a stipulation agreement with the PUCO stating that no significantly excessive earnings occurred for 2014 or 2015. In September 2016, intervenors filed testimony opposing the stipulation agreement. Management believes its financial statements adequately address the impact of 2014 and 2015 SEET requirements.
Corporate Separation
In October 2012, the PUCO issued an order which approved the corporate separation and transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo’s generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition.
2009 Fuel Adjustment Clause Audit
In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.
In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.
2012 and 2013 Fuel Adjustment Clause Audits
In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June“June 2012 - May 2015 ESP Including Capacity Charge"Charge” section above.
A hearing at the PUCO is scheduled for January 2017 to jointly review the recovery of fixed fuel costs as well as the open FAC audits discussed above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition.
Ormet
Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018.OPCo. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of September 30, 2015, is recorded in Regulatory Assets on the condensed balance sheet. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement was held in May 2014.
In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future.revenues. Through September 2009, the last month of the interim arrangement, OPCo had approximately $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. Of the $64 million in deferred FAC costs, approximately 50% was related to Columbus Southern Power Company (CSPCo) and 50% related to OPCo, prior to the merger of CSPCo into OPCo in December 2011. CSPCo’s portion of these deferred fuel costs has been recovered as a result of the previous collections of CSPCo fuel costs from ratepayers and the PUCO’s 2013 order to apply CSPCo’s 2010 excessive earnings to offset CSPCo’s final deferred fuel balance. OPCo’s share of Ormet deferred fuel costs continues to be recovered through OPCo’s PIRR.
To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition.
SWEPCo Rate Matters
2012 Texas Base Rate Case
In 2012, SWEPCo filed a request with the PUCTrefunded to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of September 30, 2015, the net book value of Welsh Plant, Unit 2 was $83 million, before cost of removal, including materials and supplies inventory and CWIP.
Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million. In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses.
If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.
2012 Louisiana Formula Rate Filing
In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit. The rates are subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC review base rates in 2014 and 2015 and that SWEPCo recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million, primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition.
2014 Louisiana Formula Rate Filing
In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase, which was effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers, in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2015 Louisiana Formula Rate Filing
In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Welsh Plant, Units 1 and 3 – Environmental Projects
To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2024 for Welsh Plant, Units 1 and 3 will cost approximately $700 million, excluding AFUDC. As of September 30, 2015, SWEPCo has incurred costs of $303 million, including AFUDC, and has remaining contractual construction obligations of $62 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of September 30, 2015, the net book value of Welsh Plant, Units 1 and 3 was $529 million, before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
APCo Rate Matters
2014 West Virginia Base Rate Case
In May 2015, the WVPSC issued an order on APCo's base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $85 million based upon a 9.75% return on common equity. The order included a delayed billing of $22 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $22 million delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $38 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $77 million in previously recorded regulatory assets, which will predominantly be recovered over five years.
2015 Virginia Regulatory Asset Proceeding
In January 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets. In February and March 2015, briefs related to this proceeding were filed by various parties. As of September 30, 2015, APCo’s authorized regulatory assets under review in this proceeding were $11 million. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition.
New Virginia Legislation Affecting Biennial Reviews
In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA.
PSO Rate Matters (Applies to AEP and PSO)
2015 Oklahoma Base Rate Case
In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million, which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the2016. The proposed $44 million forincrease related to environmental investments which iswas effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls gowere placed in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million, excluding AFUDC. As of September 30, 2015,2016, PSO hashad incurred costs of $162$180 million related to these projects,and $43 million, including AFUDC.AFUDC, for Northeastern Plant, Unit 3 and Comanche Plant, respectively.
In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million, will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4, in April 2016, which would be recovered through the FAC. As of September 30, 2015,In April 2016, Northeastern Plant, Unit 4 was retired. Upon retirement, $87 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Northeastern Plant, Unit 4 was $94 million, before cost of removal, including materials and supplies inventory and CWIP.4. These regulatory assets are pending regulatory approval.
In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million, based upon returns on common equity ranging from 8.75% to 9.3%, and increases to depreciation expense ranging from $23 million to $46 million. Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certainsome intervenors did not supportrecommended no change in depreciation lives for Northeastern Plant, Units 3 and 4. These units are currently being depreciated through 2040. Hearings at the OCC were held in December 2015. In January 2016, PSO implemented an interim annual base rate increase of $75 million. These interim rates are subject to refund pending a final order from the OCC related to the initial $137 million request.
In June 2016, an Administrative Law Judge (ALJ) issued a report related to PSO’s base rate case filing and subsequently provided an additional supplemental report in August 2016. The ALJ recommended a 9.25% return on common equity. The ALJ found that PSO’s environmental compliance plan is prudent and provided for cost recovery of the investment in this case with a recommended investment cap of $210 million on environmental controls installed at Northeastern Plant, Unit 3. Additionally, the ALJ recommendations included (a) a $14 million increase in depreciation expense, for the(b) continued depreciation of Northeastern Plant, Units 3 and 4 through 2040 (no accelerated depreciation), (c) return of, but no return on, the remaining net book value of Northeastern Plant, Unit 4, (d) elimination of the rider to permitrecover advanced metering starting in December 2016, without inclusion in base rates and (e) elimination of the system reliability rider through consolidation in base rates, without addressing a transition for recovery of rider costs, including deferred costs. The estimated annual revenue increase resulting from the ALJ recommendations is approximately $47 million.
In June and September 2016, PSO, the OCC staff, the Attorney General and intervenors filed exceptions to the ALJ reports. PSO’s response included numerous exceptions related to the ALJ recommendations including the lack of a return on the net book value of Northeastern Plant, Unit 4. The OCC staff filed exceptions that supported the full recovery of Northeastern Plant, Unit 4, including a return, and recommended a $32 million increase in annual revenues. An order from the OCC is anticipated in the fourth quarter of 2016.
If any of these costs, including a return on Northeastern Plant, Unit 4, are not recoverable, it could reduce future net income and cash flows and impact financial condition.
SWEPCo Rate Matters (Applies to AEP and SWEPCo)
2012 Texas Base Rate Case
In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.
Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals. A hearing at the Texas District Court is scheduled for March 2017.
If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition.
2012 Louisiana Formula Rate Filing
In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was approved by the LPSC. The settlement increased SWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit. The rates are subject to refund based on the prudence review of the Turk Plant. The settlement also provided that the LPSC would review base rates in 2014 and 2015 and that SWEPCo would recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by Unit 3’s 2026 retirement date as$3 million, primarily due to the proposals calledtiming of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for no change in existing cost recovery by 2040. Hearingscertain previously expensed costs. A hearing at the OCC areLPSC related to the Turk Plant prudence review is scheduled for December 2015.March 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition.
2014 Louisiana Formula Rate Filing
In 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase, which was effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015, subject to staff review of the cost of service and prudence review of the Turk Plant. In July 2016, the LPSC approved a settlement agreement related to the staff review of the cost of service. A portion of the rates remain subject to refund based on the prudence review of the Turk Plant, see “2012 Louisiana Formula Rate Filing” above. Management believes its financial statements adequately address the impact of this settlement agreement. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition.
2015 Louisiana Formula Rate Filing
In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2014 Oklahoma Base Rate Case
Welsh Plant - Environmental Impact
Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost approximately $850 million, excluding AFUDC. As of September 30, 2016, SWEPCo had incurred costs of $395 million, including AFUDC, and had remaining contractual construction obligations of $14 million related to these projects. As part of this investment, in 2016 SWEPCo completed construction of environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $370 million, excluding AFUDC. Management continues to evaluate the impact of environmental rules and related project cost estimates. In April 2015,March 2016, SWEPCo filed a request with the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall changeAPSC to recover $69 million in environmental costs related to the transmission rider orArkansas retail jurisdictional share of Welsh Plant, Units 1 and 3, which was approved by the APSC in August 2016. SWEPCo began recovering the Arkansas jurisdictional share of these costs in March 2016, subject to annual revenues, other thanreview in the next filed base rate proceeding. In September 2016, SWEPCo filed an additional revenues through a separate rider relatedrequest to advanced metering costs, and thatincrease the termsArkansas retail jurisdictional share of the stipulation be effective November 2014. The advanced metering rider provides $24environmental investment by $10 million, for a total of revenues over 14 months beginning$79 million. SWEPCo implemented the increase in November 2014 and increases to $27 million inSeptember 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c)SWEPCo will seek recovery of regulatory assets for 2013 stormsthe remaining project costs from customers at the state commissions and regulatory case expenses. The advanced metering cost rider was implemented in November 2014.
I&M Rate Mattersthe FERC.
Tanners Creek Plant
In October 2014, I&M filed an application with the IURC seeking approvalAs of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates,September 30, 2016, the net book value of the Tanners CreekWelsh Plant, be recovered over the remaining lifeUnits 1 and 3 was $632 million, before cost of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider.removal, including materials and supplies inventory and CWIP. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates.
In May 2015, Tanners CreekApril 2016, Welsh Plant, Unit 2 was retired. Upon retirement, $265$76 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners CreekWelsh Plant, Unit 2 and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pendingobligation costs. Management will seek recovery of the remaining regulatory approval.assets in future rate proceedings.
If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.
TCC Rate Matters (Applies to AEP)
TCC Distribution Cost Recovery Factor (DCRF)
In July 2016, the PUCT approved a settlement agreement between TCC and intervenors related to TCC’s request for a DCRF rider to allow recovery of eligible net distribution investments. The settlement agreement included an annual revenue requirement of $45 million, effective September 2016. Amounts approved are subject to refund based upon a prudence review of the investments in TCC’s next base rate case.
TNC Rate Matters (Applies to AEP)
TNC Distribution Cost Recovery Factor (DCRF)
In July 2016, the PUCT approved a settlement agreement between TNC and intervenors related to TNC’s request for a DCRF rider to allow recovery of eligible net distribution investments. The settlement agreement included an annual revenue requirement of $11 million, effective September 2016. Amounts approved are subject to refund based upon a prudence review of the investments in TNC’s next base rate case.
FERC Rate Matters (Applies to AEP, APCo, I&M and OPCo)
PJM Transmission DistributionRates
In June 2016, PJM transmission owners, including the AEP East Companies, and Storage System Improvement Charge (TDSIC)various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms.
FERC Transmission Complaint
In October 2014, I&M2016, several parties filed petitionsa joint complaint with the IURC for approvalFERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM Open Access Transmission Tariff (OATT) is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. Management is reviewing the filing and evaluating a TDSIC Riderresponse to the complaint. If the FERC orders revenue reductions, including refunds from the date of filing, it could reduce future net income and approvalcash flows and impact financial condition.
Other Rate Matters (Applies to AEP, PSO and SWEPCo)
SPP Open Access Transmission Tariff (OATT) Upgrade Costs
Under the SPP OATT, costs of I&M’s seven-year TDSIC Plan for eligiblesponsor-funded transmission distributionupgrades may be recovered, in part, from SPP customers whose transmission service is dependent upon capacity enabled by the upgrades. SPP has not charged its customers any amounts attributable to these upgrades. Based upon preliminary information provided by SPP, in the third quarter of 2016, PSO and storage system improvements totaling $787 million. In April 2015, I&M filedSWEPCo recognized a notice with the IURC to exclude $117net unfavorable impact of $3 million and $4 million, respectively, related to certain projects. In September 2015, the IURC granted I&M's motionOATT upgrade costs. SPP expects to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal withfinalize the Indiana Courtamounts due in the fourth quarter of Appeals.2016.
5. COMMITMENTS, GUARANTEES AND CONTINGENCIES
The Registrant Subsidiariesdisclosures in this note apply to all Registrants unless indicated otherwise.
The Registrants are subject to certain claims and legal actions arising in theirthe ordinary course of business. In addition, theirthe Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. ContingentManagement accrues contingent liabilities are accrued only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When determinedmanagement determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss are disclosed if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.
For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 20142015 Annual Report should be read in conjunction with this report.
GUARANTEES
Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees.guarantees unless specified below. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.
Letters of Credit – Affecting(Applies to AEP, APCo, I&M and OPCoOPCo)
Certain Registrant Subsidiaries enter into standbyStandby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.
AEP has two revolving credit facilities totaling $3.5 billion. In June 2016, the $1.75 billion credit facility due in June 2017 was amended to $3 billion due in June 2021, under which up to $1.2 billion may be issued as letters of credit.credit on behalf of subsidiaries. Also in June 2016, the $1.75 billion credit facility due in July 2018 was amended to $500 million due in June 2018. As of September 30, 2015, the maximum future payment for2016, no letters of credit were issued under the $3 billion revolving credit facilities was as follows:
|
| | | | | | |
Company | | Amount | | Maturity |
| | (in thousands) | | |
I&M | | $ | 35 |
| | March 2016 |
facility.
AEP issues letters of credit under two uncommitted facilities totaling $150 million. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $300 million. As of September 30, 2015,2016, the Registrants’ maximum future paymentpayments for letters of credit issued under the uncommitted facilities waswere as follows:
| | Company | | Amount | | Maturity | | Amount | | Maturity |
| | (in thousands) | | | | (in millions) | | |
AEP | | | $ | 147.2 |
| | October 2016 to September 2017 |
OPCo | | $ | 4,200 |
| | September 2016 | | 4.2 |
| | September 2017 |
The Registrant SubsidiariesRegistrants have $307$291 million of variable rate Pollution Control Bonds supported by $295 million of bilateral letters of credit for $310 million as follows:
| | Company | | Pollution Control Bonds | | Bilateral Letters of Credit | | Maturity of Bilateral Letters of Credit | | Pollution Control Bonds | | Bilateral Letters of Credit | | Maturity of Bilateral Letters of Credit |
| | (in thousands) | | | | (in millions) | | |
AEP | | | $ | 291.4 |
| | $ | 294.7 |
| | March 2017 to July 2017 |
APCo | | $ | 229,650 |
| | $ | 232,293 |
| | March 2016 to March 2017 | | 104.4 |
| | 105.6 |
| | March 2017 |
I&M | | 77,000 |
| | 77,886 |
| | March 2017 | | 77.0 |
| | 77.9 |
| | March 2017 |
Guarantees of Third-Party Obligations – Affecting SWEPCo(Applies to AEP and SWEPCo)
As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $58 million. Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2015,2016, SWEPCo has collected $65$68 million through a rider for final mine closure and reclamation costs, of which $16$15 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $49$53 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed balance sheets.
Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause.
Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo
Contracts
The Registrant SubsidiariesRegistrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of September 30, 2015,2016, there were no material liabilities recorded for any indemnifications.
APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity.
Master Lease Agreements
The Registrant SubsidiariesRegistrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant SubsidiariesRegistrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2015,2016, the maximum potential loss by Registrant SubsidiaryRegistrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term wasis as follows:
| | Company | | Maximum Potential Loss | | Maximum Potential Loss |
| | (in thousands) | | (in millions) |
AEP | | | $ | 36.8 |
|
APCo | | $ | 5,396 |
| | 5.5 |
|
I&M | | 3,448 |
| | 3.4 |
|
OPCo | | 6,075 |
| | 5.8 |
|
PSO | | 2,785 |
| | 3.0 |
|
SWEPCo | | 3,086 |
| | 3.5 |
|
Railcar Lease (Applies to AEP, I&M and SWEPCo)
In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $11$9 million and $12$11 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2015.2016.
Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five yearfive-year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment.term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $9 million and $10 million for I&M and SWEPCo, respectively, as of September 30, 2016, assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss.
AEPRO Boat and Barge Leases (Applies to AEP)
In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. See “AEPRO (Corporate and Other Segment)” section of Note 6. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of September 30, 2016, the maximum potential amount of future payments required under the guaranteed leases was $87 million. In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of September 30, 2016, AEP’s boat and barge lease guarantee liability was $14 million, of which $3 million was recorded in Other Current Liabilities and $11 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets.
ENVIRONMENTAL CONTINGENCIES
The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M
By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrant SubsidiariesRegistrants currently incur costs to dispose of these substances safely.
In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M's&M’s accrual was reduced. As of September 30, 2016, I&M’s accrual for all of these sites was reduced. As of September 30, 2015, I&M's accrual for all of these sites is approximately $8 million. As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any.
NUCLEAR CONTINGENCIES – AFFECTING(APPLIES TO AEP AND I&M&M)
I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission.Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.
OPERATIONAL CONTINGENCIES
Rockport Plant Litigation – Affecting(Applies to AEP and I&M&M)
In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’plaintiff’s claims. Several claims remain,remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. PlaintiffsThe plaintiff subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. Management will continueIn November 2015, AEGCo and I&M filed a motion to defend againststrike the plaintiff’s motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims.claims with prejudice and the court subsequently entered a final judgment. In May 2016, Plaintiffs filed a notice of appeal on whether AEGCo and I&M are in breach of certain contract provisions that Plaintiffs allege operate to protect the Plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing Plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. This matter is currently pending before the U.S. Court of Appeals for the Sixth Circuit. Management is unable to determine a range of potential losses that are reasonably possible of occurring.
Natural Gas Markets Lawsuits (Applies to AEP)
In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court’s orders in these cases. The appellate court reversed the district court’s holding that the state antitrust claims were preempted by the Natural Gas
Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases. Defendants in these cases, including AEP, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue. AEP also subsequently filed a separate petition with the U.S. Supreme Court seeking review of the personal jurisdiction issue. In July 2014, the U.S. Supreme Court granted the defendants’ previously filed petition for further review with the U.S. Supreme Court on the preemption issue. Oral argument occurred in January 2015. In April 2015, the U.S. Supreme Court affirmed the judgment of the U.S. Court of Appeals for the Ninth Circuit on the preemption issue, holding that the plaintiffs’ state antitrust claims were not preempted by the Natural Gas Act. The U.S. Supreme Court denied AEP’s petition for review of the personal jurisdiction issue shortly thereafter. The cases were remanded to the district court for further proceedings. There are four pending cases, of which three are class actions and one is a single plaintiff case. A tentative settlement has been reached in the three class actions. This settlement, once finalized, will be subject to court approval. In May 2016, the district court dismissed the remaining case. Management will continue to defend any appeal of that matter. Management is unable to determine the amount of potential additional loss that is reasonably possible of occurring.
Wage and Hours Lawsuit – Affecting PSO(Applies to AEP and PSO)
In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have beenwere denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount.
In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. Management will continue to defendIn February 2016, PSO filed a motion for summary judgment. In April 2016, by opinion and order, the court granted PSO’s motion for summary judgment and dismissed the case. Management doesPlaintiffs did not believe a lossappeal the dismissal and the court’s order is probable. If there is an unfavorable outcome contrary to expectations, management estimates possible losses of up to $30 million.final.
Gavin Landfill Litigation – Affecting OPCo(Applies to AEP and OPCo)
In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Management appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel, which typically handles multi-plaintiff cases, rather than back to the Mason County, West Virginia Circuit Court. Defendants’ petition for rehearing was denied by the West Virginia Supreme Court. Management will continue to defend against the claims. Management believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
6.DISPOSITIONS, ASSETS AND LIABILITIES HELD FOR SALE AND IMPAIRMENTS
The disclosures in this note apply to AEP only unless indicated otherwise.
DISPOSITIONS
2016
Tanners Creek Plant (Vertically Integrated Utilities Segment) (Applies to AEP and I&M)
In October 2016, I&M sold its retired Tanners Creek plant site including its associated asset retirement obligations (AROs) to a nonaffiliated party. I&M paid $92 million and the nonaffiliated party took ownership of the Tanners Creek plant site assets and assumed responsibility for environmental liabilities and AROs, including ash pond closure, asbestos abatement and decommissioning and demolition. I&M does not expect to record a gain or loss related to this sale and will address recovery of Tanner’s Creek deferred costs in future rate proceedings. If any of the costs associated with Tanner’s Creek are not recoverable, it could reduce future net income and impact financial condition.
2015
Muskingum River Plant (Generation & Marketing Segment)
In August 2015, AGR sold its retired Muskingum River Plant site including its associated asset retirement obligations to a nonaffiliated party. AGR paid $48 million and the nonaffiliated party took ownership of the Muskingum River Plant site assets and assumed responsibility for environmental liabilities and AROs, including ash pond closure, asbestos abatement and decommissioning and demolition. As a result of the sale, a net gain of $32 million was recognized and recorded in Other Operation on the statements of operations. The cash paid was recorded in Operating Activities on the statements of cash flows.
AEPRO (Corporate and Other Segment)
In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. The nonaffiliated party acquired AEPRO by purchasing all of the common stock of AEP Resources, Inc., the parent company of AEPRO. The nonaffiliated party assumed certain assets and liabilities of AEPRO, excluding the equity method investment in International Marine Terminals, LLC, pension and benefit assets and liabilities and debt obligations. Prior to the closing of the sale, AEP retired the debt obligations of AEPRO. AEP retained ownership of its captive barge fleet that delivers coal to the company’s regulated coal-fueled power plant units owned or leased by AEGCo, APCo, I&M, KPCo and WPCo. AEP signed a contract with the nonaffiliated party to dispatch and schedule its captive barge fleet for the company’s regulated coal-fueled power plant units. AEP also has a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2016.
Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of operations for the three and nine months ended September 30, 2015, as shown in the following table:
|
| | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | |
| | 2015 | | 2015 |
| | (in millions) |
Other Revenues | | $ | 129.1 |
| | $ | 372.2 |
|
| | | | |
Other Operation Expense | | 96.7 |
| | 273.1 |
|
Maintenance Expense | | 4.2 |
| | 19.9 |
|
Depreciation and Amortization Expense | | 8.8 |
| | 26.9 |
|
Taxes Other Than Income Taxes | | 2.7 |
| | 9.9 |
|
Total Expenses | | 112.4 |
| | 329.8 |
|
| | | | |
Other Income (Expense) | | (5.4 | ) | | (14.5 | ) |
| | | | |
Pretax Income of Discontinued Operations | | 11.3 |
|
| 27.9 |
|
Income Tax Expense | | 3.6 |
| | 9.7 |
|
Equity Earnings of Unconsolidated Subsidiaries | | 0.1 |
| | — |
|
Total Income on Discontinued Operations as Presented on the Statements of Operations | | $ | 7.8 |
|
| $ | 18.2 |
|
In the second quarter of 2016, AEP recorded a $3 million loss related to the final accounting for the sale of AEPRO, which was recorded in Income (Loss) from Discontinued Operations, Net of Tax, on AEP’s statements of operations.
ASSETS AND LIABILITIES HELD FOR SALE
2016
Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)
During the third quarter of 2016, AEP received bids and selected a buyer, received approval from AEP’s Board of Directors and signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby plants as well as AEGCo’s Lawrenceburg plant totaling 5,326 MW of competitive generation assets for approximately $2.2 billion to a nonaffiliated party. The sale is subject to regulatory approvals from the FERC, the IURC and federal clearance pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR). In October 2016, the Federal Trade Commission granted the sale early termination of the HSR waiting period thereby satisfying the HSR conditions to close the transaction. The sale is expected to close in the first quarter of 2017.
Upon evaluation, management concluded that the disposal group met the classification as held for sale in the third quarter of 2016. Accordingly, the four plants’ assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale on AEP’s balance sheet as of September 30, 2016 and as shown in the table below. The Income from Continuing Operations before Income Tax Expense and Equity Earnings of the four plants was approximately $116 million and $118 million for the three months ended September 30, 2016 and 2015, respectively, and $312 million and $404 million for the nine months ended September 30, 2016 and 2015, respectively.
|
| | | | |
| | September 30, |
| | 2016 |
Assets: | | (in millions) |
Fuel | | $ | 139.7 |
|
Materials and Supplies | | 48.7 |
|
Property, Plant and Equipment - Net | | 1,726.5 |
|
Other Class of Assets That Are Not Major | | 0.4 |
|
Total Assets Classified as Held for Sale on the Balance Sheets | | $ | 1,915.3 |
|
| | |
Liabilities: | | |
Long-term Debt | | $ | 134.8 |
|
Waterford Plant Upgrade Liability | | 53.1 |
|
Asset Retirement Obligations | | 36.3 |
|
Other Classes of Liabilities That Are Not Major | | 6.8 |
|
Total Liabilities Classified as Held for Sale on the Balance Sheets | | $ | 231.0 |
|
IMPAIRMENTS
2016
Merchant Generating Assets (Generation & Marketing Segment)
In September 2016, due to AEP’s ongoing evaluation of strategic alternatives for its merchant generation assets, declining forecasts of future energy and capacity prices, and a decreasing likelihood of cost recovery through regulatory proceedings or legislation in the state of Ohio providing for the recovery of AEP’s existing Ohio merchant generation assets, AEP performed an impairment analysis at the unit level on the remaining merchant generation assets in accordance with accounting guidance for impairments of long-lived assets. Cardinal Unit 1, a 43.5% interest in Conesville Unit 4, Conesville Units 5-6, a 26% interest in Stuart Units 1-4, a 25.4% interest in Zimmer Unit 1, and a 54.7% interest in Oklaunion (collectively the “Merchant Coal-Fired Generation Assets”) were subject to this analysis. Additionally, Racine Hydroelectric Plant (“Racine”), Putnam and I&M’s Price River coal reserves (“Coal Reserves”) and Desert Sky and Trent Wind Farms (“Wind Farms”) were also included in this analysis. For the Merchant Coal-Fired Generation Assets, Racine and the Wind Farms, AEP performed step one of the impairment analysis using undiscounted cash flows for the estimated useful lives of the assets based upon energy and capacity price curves, as applicable, which were developed internally with both observable Level 2 third party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. The step one analysis concluded the book value of Racine would be recovered and the book value of the remaining assets would not be recovered.
AEP performed step two of the impairment analysis on the Merchant Coal-Fired Generation Assets using a ten-year discounted cash flow model based upon forecasted energy and capacity price curves, which were developed internally using both observable Level 2 third party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. The step two analysis resulted in projected negative cash flows. Based on this result, coupled with the significant capital investments necessary to comply with environmental rules to allow the Merchant Coal-Fired Generation Assets to operate to the end of their currently estimated depreciable lives and the joint-ownership structure of these facilities, management determined the fair value of these assets was $0. AEP performed step two of the impairment analysis on the Wind Farms using a ten-year discounted cash flow model utilizing forecasted energy price curves, which were developed internally using both observable Level 2 third party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. The results concluded the Wind Farms were also impaired.
For the Coal Reserves, AEP performed step one of the impairment analysis and concluded the book value of the assets would not be recovered. Step two of the impairment analysis on the Coal Reserves was performed using a market approach with Level 3 unobservable inputs. The results concluded the Coal Reserves were also impaired.
Based on the impairment analysis performed, in the third quarter of 2016, AEP recorded a pretax impairment of $2.3 billion in Asset Impairments and Other Related Charges on the statement of operations. See the table below for additional information.
|
| | | | | | | | | | | | |
Impaired Assets | | Book Value | | Fair Value | | Impairment |
| | (in millions) |
Merchant Coal-Fired Generation Assets | | $ | 2,139.4 |
| | $ | — |
| | $ | 2,139.4 |
|
Trent and Desert Sky Wind Farms | | 118.7 |
| | 46.0 |
| | 72.7 |
|
Coal Reserves (a) | | 56.6 |
| | 3.8 |
| | 52.8 |
|
Total | | $ | 2,314.7 |
| | $ | 49.8 |
| | $ | 2,264.9 |
|
| |
(a) | Includes the $11 million book value of I&M’s Price River Coal Reserves which were fully impaired. This $11 million impairment is reflected in the Vertically Integrated Utilities Segment. |
7. BENEFIT PLANS
The Registrant Subsidiaries participatedisclosures in an this note apply to all Registrants unless indicated otherwise.
AEP sponsoredsponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. The Registrant SubsidiariesAEP also participate insponsors OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.
Components of Net Periodic Benefit Cost
The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and nine months ended September 30, 20152016 and 2014:2015:
AEP
|
| | | | | | | | | | | | | | | |
| Pension Plans | | Other Postretirement Benefit Plans |
| Three Months Ended September 30, | | Three Months Ended September 30, |
| 2016 | | 2015 | | 2016 | | 2015 |
| (in millions) |
Service Cost | $ | 21.4 |
| | $ | 23.4 |
| | $ | 2.6 |
| | $ | 3.1 |
|
Interest Cost | 52.9 |
| | 51.3 |
| | 15.3 |
| | 14.2 |
|
Expected Return on Plan Assets | (70.1 | ) | | (68.6 | ) | | (26.8 | ) | | (27.7 | ) |
Amortization of Prior Service Cost (Credit) | 0.6 |
| | 0.5 |
| | (17.3 | ) | | (17.3 | ) |
Amortization of Net Actuarial Loss | 21.0 |
| | 26.7 |
| | 7.8 |
| | 4.7 |
|
Net Periodic Benefit Cost (Credit) | $ | 25.8 |
| | $ | 33.3 |
| | $ | (18.4 | ) | | $ | (23.0 | ) |
|
| | | | | | | | | | | | | | | |
| Pension Plans | | Other Postretirement Benefit Plans |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2016 | | 2015 | | 2016 | | 2015 |
| (in millions) |
Service Cost | $ | 64.3 |
| | $ | 70.1 |
| | $ | 7.7 |
| | $ | 9.2 |
|
Interest Cost | 158.7 |
| | 153.9 |
| | 45.7 |
| | 42.6 |
|
Expected Return on Plan Assets | (210.2 | ) | | (206.0 | ) | | (80.3 | ) | | (83.3 | ) |
Amortization of Prior Service Cost (Credit) | 1.7 |
| | 1.7 |
| | (51.8 | ) | | (51.8 | ) |
Amortization of Net Actuarial Loss | 62.9 |
| | 80.3 |
| | 23.5 |
| | 14.1 |
|
Net Periodic Benefit Cost (Credit) | $ | 77.4 |
| | $ | 100.0 |
| | $ | (55.2 | ) | | $ | (69.2 | ) |
APCo
| | | Pension Plans | | Other Postretirement Benefit Plans | Pension Plans | | Other Postretirement Benefit Plans |
| Three Months Ended September 30, | | Three Months Ended September 30, | Three Months Ended September 30, | | Three Months Ended September 30, |
| 2015 |
| 2014 | | 2015 | | 2014 | 2016 |
| 2015 | | 2016 | | 2015 |
| (in thousands) | (in millions) |
Service Cost | $ | 2,175 |
| | $ | 1,759 |
| | $ | 286 |
| | $ | 362 |
| $ | 2.1 |
| | $ | 2.1 |
| | $ | 0.2 |
| | $ | 0.3 |
|
Interest Cost | 6,679 |
| | 7,406 |
| | 2,584 |
| | 3,197 |
| 6.8 |
| | 6.7 |
| | 2.7 |
| | 2.5 |
|
Expected Return on Plan Assets | (8,745 | ) | | (8,482 | ) | | (4,529 | ) | | (4,634 | ) | (8.8 | ) | | (8.7 | ) | | (4.3 | ) | | (4.5 | ) |
Amortization of Prior Service Cost (Credit) | 45 |
| | 49 |
| | (2,513 | ) | | (2,512 | ) | |
Amortization of Prior Service Credit | | — |
| | — |
| | (2.5 | ) | | (2.5 | ) |
Amortization of Net Actuarial Loss | 3,474 |
| | 4,149 |
| | 900 |
| | 1,145 |
| 2.6 |
| | 3.5 |
| | 1.4 |
| | 0.9 |
|
Net Periodic Benefit Cost (Credit) | $ | 3,628 |
| | $ | 4,881 |
| | $ | (3,272 | ) | | $ | (2,442 | ) | $ | 2.7 |
| | $ | 3.6 |
| | $ | (2.5 | ) | | $ | (3.3 | ) |
| | | Pension Plans | | Other Postretirement Benefit Plans | Pension Plans | | Other Postretirement Benefit Plans |
| Nine Months Ended September 30, | | Nine Months Ended September 30, | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) | (in millions) |
Service Cost | $ | 6,525 |
| | $ | 5,277 |
| | $ | 857 |
| | $ | 1,086 |
| $ | 6.1 |
| | $ | 6.5 |
| | $ | 0.7 |
| | $ | 0.9 |
|
Interest Cost | 20,037 |
| | 22,218 |
| | 7,753 |
| | 9,591 |
| 20.4 |
| | 20.1 |
| | 8.1 |
| | 7.7 |
|
Expected Return on Plan Assets | (26,236 | ) | | (25,445 | ) | | (13,587 | ) | | (13,900 | ) | (26.5 | ) | | (26.2 | ) | | (13.0 | ) | | (13.6 | ) |
Amortization of Prior Service Cost (Credit) | 135 |
| | 148 |
| | (7,538 | ) | | (7,537 | ) | 0.1 |
| | 0.1 |
| | (7.5 | ) | | (7.5 | ) |
Amortization of Net Actuarial Loss | 10,421 |
| | 12,445 |
| | 2,699 |
| | 3,436 |
| 8.0 |
| | 10.4 |
| | 4.1 |
| | 2.7 |
|
Net Periodic Benefit Cost (Credit) | $ | 10,882 |
| | $ | 14,643 |
| | $ | (9,816 | ) | | $ | (7,324 | ) | $ | 8.1 |
| | $ | 10.9 |
| | $ | (7.6 | ) | | $ | (9.8 | ) |
I&M
| | | Pension Plans | | Other Postretirement Benefit Plans | Pension Plans | | Other Postretirement Benefit Plans |
| Three Months Ended September 30, | | Three Months Ended September 30, | Three Months Ended September 30, | | Three Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) | (in millions) |
Service Cost | $ | 3,217 |
| | $ | 2,517 |
| | $ | 406 |
| | $ | 486 |
| $ | 3.1 |
| | $ | 3.3 |
| | $ | 0.4 |
| | $ | 0.4 |
|
Interest Cost | 6,114 |
| | 6,573 |
| | 1,592 |
| | 1,909 |
| 6.3 |
| | 6.1 |
| | 1.7 |
| | 1.6 |
|
Expected Return on Plan Assets | (8,115 | ) | | (7,749 | ) | | (3,304 | ) | | (3,363 | ) | (8.4 | ) | | (8.1 | ) | | (3.2 | ) | | (3.3 | ) |
Amortization of Prior Service Cost (Credit) | 45 |
| | 49 |
| | (2,355 | ) | | (2,355 | ) | |
Amortization of Prior Service Credit | | — |
| | — |
| | (2.4 | ) | | (2.4 | ) |
Amortization of Net Actuarial Loss | 3,145 |
| | 3,647 |
| | 506 |
| | 592 |
| 2.5 |
| | 3.1 |
| | 0.9 |
| | 0.5 |
|
Net Periodic Benefit Cost (Credit) | $ | 4,406 |
| | $ | 5,037 |
| | $ | (3,155 | ) | | $ | (2,731 | ) | $ | 3.5 |
| | $ | 4.4 |
| | $ | (2.6 | ) | | $ | (3.2 | ) |
| | | Pension Plans | | Other Postretirement Benefit Plans | Pension Plans | | Other Postretirement Benefit Plans |
| Nine Months Ended September 30, | | Nine Months Ended September 30, | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) | (in millions) |
Service Cost | $ | 9,651 |
| | $ | 7,551 |
| | $ | 1,219 |
| | $ | 1,460 |
| $ | 9.2 |
| | $ | 9.7 |
| | $ | 1.1 |
| | $ | 1.2 |
|
Interest Cost | 18,344 |
| | 19,720 |
| | 4,776 |
| | 5,728 |
| 19.0 |
| | 18.3 |
| | 5.2 |
| | 4.8 |
|
Expected Return on Plan Assets | (24,347 | ) | | (23,245 | ) | | (9,912 | ) | | (10,090 | ) | (25.2 | ) | | (24.3 | ) | | (9.6 | ) | | (9.9 | ) |
Amortization of Prior Service Cost (Credit) | 136 |
| | 146 |
| | (7,066 | ) | | (7,066 | ) | 0.1 |
| | 0.1 |
| | (7.1 | ) | | (7.1 | ) |
Amortization of Net Actuarial Loss | 9,434 |
| | 10,939 |
| | 1,519 |
| | 1,776 |
| 7.4 |
| | 9.4 |
| | 2.8 |
| | 1.5 |
|
Net Periodic Benefit Cost (Credit) | $ | 13,218 |
| | $ | 15,111 |
| | $ | (9,464 | ) | | $ | (8,192 | ) | $ | 10.5 |
| | $ | 13.2 |
| | $ | (7.6 | ) | | $ | (9.5 | ) |
OPCo
| | | Pension Plans | | Other Postretirement Benefit Plans | Pension Plans | | Other Postretirement Benefit Plans |
| Three Months Ended September 30, | | Three Months Ended September 30, | Three Months Ended September 30, | | Three Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) | (in millions) |
Service Cost | $ | 1,671 |
| | $ | 1,285 |
| | $ | 216 |
| | $ | 256 |
| $ | 1.6 |
| | $ | 1.6 |
| | $ | 0.2 |
| | $ | 0.2 |
|
Interest Cost | 5,071 |
| | 5,527 |
| | 1,615 |
| | 1,900 |
| 5.1 |
| | 5.1 |
| | 1.8 |
| | 1.6 |
|
Expected Return on Plan Assets | (6,878 | ) | | (6,607 | ) | | (3,376 | ) | | (3,379 | ) | (6.9 | ) | | (6.8 | ) | | (3.3 | ) | | (3.4 | ) |
Amortization of Prior Service Cost (Credit) | 35 |
| | 40 |
| | (1,731 | ) | | (1,731 | ) | |
Amortization of Prior Service Credit | | — |
| | — |
| | (1.7 | ) | | (1.8 | ) |
Amortization of Net Actuarial Loss | 2,644 |
| | 3,105 |
| | 517 |
| | 595 |
| 2.1 |
| | 2.6 |
| | 0.9 |
| | 0.6 |
|
Net Periodic Benefit Cost (Credit) | $ | 2,543 |
| | $ | 3,350 |
| | $ | (2,759 | ) | | $ | (2,359 | ) | $ | 1.9 |
| | $ | 2.5 |
| | $ | (2.1 | ) | | $ | (2.8 | ) |
| | | Pension Plans | | Other Postretirement Benefit Plans | Pension Plans | | Other Postretirement Benefit Plans |
| Nine Months Ended September 30, | | Nine Months Ended September 30, | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) | (in millions) |
Service Cost | $ | 5,015 |
| | $ | 3,855 |
| | $ | 647 |
| | $ | 769 |
| $ | 4.9 |
| | $ | 5.0 |
| | $ | 0.6 |
| | $ | 0.6 |
|
Interest Cost | 15,211 |
| | 16,579 |
| | 4,845 |
| | 5,701 |
| 15.4 |
| | 15.2 |
| | 5.3 |
| | 4.8 |
|
Expected Return on Plan Assets | (20,634 | ) | | (19,820 | ) | | (10,130 | ) | | (10,139 | ) | (20.8 | ) | | (20.6 | ) | | (9.7 | ) | | (10.1 | ) |
Amortization of Prior Service Cost (Credit) | 105 |
| | 118 |
| | (5,192 | ) | | (5,192 | ) | 0.1 |
| | 0.1 |
| | (5.2 | ) | | (5.2 | ) |
Amortization of Net Actuarial Loss | 7,932 |
| | 9,316 |
| | 1,552 |
| | 1,785 |
| 6.1 |
| | 7.9 |
| | 2.8 |
| | 1.6 |
|
Net Periodic Benefit Cost (Credit) | $ | 7,629 |
| | $ | 10,048 |
| | $ | (8,278 | ) | | $ | (7,076 | ) | $ | 5.7 |
| | $ | 7.6 |
| | $ | (6.2 | ) | | $ | (8.3 | ) |
PSO
| | | Pension Plans | | Other Postretirement Benefit Plans | Pension Plans | | Other Postretirement Benefit Plans |
| Three Months Ended September 30, | | Three Months Ended September 30, | Three Months Ended September 30, | | Three Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) | (in millions) |
Service Cost | $ | 1,598 |
| | $ | 1,301 |
| | $ | 170 |
| | $ | 209 |
| $ | 1.5 |
| | $ | 1.6 |
| | $ | 0.2 |
| | $ | 0.2 |
|
Interest Cost | 2,731 |
| | 3,015 |
| | 759 |
| | 893 |
| 2.8 |
| | 2.7 |
| | 0.8 |
| | 0.8 |
|
Expected Return on Plan Assets | (3,786 | ) | | (3,651 | ) | | (1,578 | ) | | (1,575 | ) | (3.9 | ) | | (3.8 | ) | | (1.5 | ) | | (1.5 | ) |
Amortization of Prior Service Cost (Credit) | 63 |
| | 74 |
| | (1,072 | ) | | (1,072 | ) | 0.1 |
| | 0.1 |
| | (1.1 | ) | | (1.1 | ) |
Amortization of Net Actuarial Loss | 1,418 |
| | 1,689 |
| | 242 |
| | 278 |
| 1.1 |
| | 1.5 |
| | 0.4 |
| | 0.2 |
|
Net Periodic Benefit Cost (Credit) | $ | 2,024 |
| | $ | 2,428 |
| | $ | (1,479 | ) | | $ | (1,267 | ) | $ | 1.6 |
| | $ | 2.1 |
| | $ | (1.2 | ) | | $ | (1.4 | ) |
| | | Pension Plans | | Other Postretirement Benefit Plans | Pension Plans | | Other Postretirement Benefit Plans |
| Nine Months Ended September 30, | | Nine Months Ended September 30, | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) | (in millions) |
Service Cost | $ | 4,796 |
| | $ | 3,905 |
| | $ | 509 |
| | $ | 629 |
| $ | 4.6 |
| | $ | 4.8 |
| | $ | 0.5 |
| | $ | 0.5 |
|
Interest Cost | 8,194 |
| | 9,043 |
| | 2,277 |
| | 2,680 |
| 8.4 |
| | 8.2 |
| | 2.4 |
| | 2.3 |
|
Expected Return on Plan Assets | (11,358 | ) | | (10,953 | ) | | (4,732 | ) | | (4,725 | ) | (11.6 | ) | | (11.4 | ) | | (4.5 | ) | | (4.7 | ) |
Amortization of Prior Service Cost (Credit) | 189 |
| | 222 |
| | (3,217 | ) | | (3,217 | ) | 0.2 |
| | 0.2 |
| | (3.2 | ) | | (3.2 | ) |
Amortization of Net Actuarial Loss | 4,252 |
| | 5,065 |
| | 725 |
| | 832 |
| 3.3 |
| | 4.3 |
| | 1.3 |
| | 0.7 |
|
Net Periodic Benefit Cost (Credit) | $ | 6,073 |
| | $ | 7,282 |
| | $ | (4,438 | ) | | $ | (3,801 | ) | $ | 4.9 |
| | $ | 6.1 |
| | $ | (3.5 | ) | | $ | (4.4 | ) |
SWEPCo
| | | Pension Plans | | Other Postretirement Benefit Plans | Pension Plans | | Other Postretirement Benefit Plans |
| Three Months Ended September 30, | | Three Months Ended September 30, | Three Months Ended September 30, | | Three Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) | (in millions) |
Service Cost | $ | 2,081 |
| | $ | 1,655 |
| | $ | 211 |
| | $ | 253 |
| $ | 2.0 |
| | $ | 2.2 |
| | $ | 0.2 |
| | $ | 0.2 |
|
Interest Cost | 2,932 |
| | 3,163 |
| | 837 |
| | 998 |
| 3.1 |
| | 2.9 |
| | 0.9 |
| | 0.8 |
|
Expected Return on Plan Assets | (4,008 | ) | | (3,857 | ) | | (1,735 | ) | | (1,754 | ) | (4.0 | ) | | (4.0 | ) | | (1.7 | ) | | (1.7 | ) |
Amortization of Prior Service Cost (Credit) | 78 |
| | 87 |
| | (1,289 | ) | | (1,289 | ) | |
Amortization of Prior Service Credit | | — |
| | — |
| | (1.3 | ) | | (1.3 | ) |
Amortization of Net Actuarial Loss | 1,506 |
| | 1,762 |
| | 266 |
| | 309 |
| 1.2 |
| | 1.5 |
| | 0.5 |
| | 0.3 |
|
Net Periodic Benefit Cost (Credit) | $ | 2,589 |
| | $ | 2,810 |
| | $ | (1,710 | ) | | $ | (1,483 | ) | $ | 2.3 |
| | $ | 2.6 |
| | $ | (1.4 | ) | | $ | (1.7 | ) |
| | | Pension Plans | | Other Postretirement Benefit Plans | Pension Plans | | Other Postretirement Benefit Plans |
| Nine Months Ended September 30, | | Nine Months Ended September 30, | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) | (in millions) |
Service Cost | $ | 6,244 |
| | $ | 4,964 |
| | $ | 632 |
| | $ | 759 |
| $ | 6.1 |
| | $ | 6.3 |
| | $ | 0.6 |
| | $ | 0.6 |
|
Interest Cost | 8,796 |
| | 9,488 |
| | 2,512 |
| | 2,994 |
| 9.3 |
| | 8.8 |
| | 2.7 |
| | 2.5 |
|
Expected Return on Plan Assets | (12,024 | ) | | (11,571 | ) | | (5,206 | ) | | (5,262 | ) | (12.3 | ) | | (12.0 | ) | | (5.0 | ) | | (5.2 | ) |
Amortization of Prior Service Cost (Credit) | 232 |
| | 262 |
| | (3,867 | ) | | (3,867 | ) | 0.2 |
| | 0.2 |
| | (3.9 | ) | | (3.8 | ) |
Amortization of Net Actuarial Loss | 4,520 |
| | 5,285 |
| | 798 |
| | 926 |
| 3.6 |
| | 4.5 |
| | 1.5 |
| | 0.8 |
|
Net Periodic Benefit Cost (Credit) | $ | 7,768 |
| | $ | 8,428 |
| | $ | (5,131 | ) | | $ | (4,450 | ) | $ | 6.9 |
| | $ | 7.8 |
| | $ | (4.1 | ) | | $ | (5.1 | ) |
7.8. BUSINESS SEGMENTS
The disclosures in this note apply to all Registrants unless indicated otherwise.
AEP’s Reportable Segments
AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.
AEP’s reportable segments and their related business activities are outlined below:
Vertically Integrated Utilities
Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.
Transmission and Distribution Utilities
Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load.
AEP Transmission Holdco
Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission-only subsidiaries and transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.
Generation & Marketing
Competitive generation in ERCOT and PJM.
Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO.
The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 6 for additional information.
The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2016 and 2015 and reportable segment balance sheet information as of September 30, 2016 and December 31, 2015. These amounts include certain estimates and allocations where necessary.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| (in millions) |
Three Months Ended September 30, 2016 | |
| | |
| | |
| | |
| | |
| | | | |
|
Revenues from: | |
| | |
| | |
| | |
| | |
| | | | |
|
External Customers | $ | 2,538.3 |
| | $ | 1,245.4 |
| | $ | 39.5 |
| | $ | 823.3 |
| | $ | 5.7 |
| | $ | — |
| | $ | 4,652.2 |
|
Other Operating Segments | 18.0 |
| | 30.2 |
| | 92.9 |
| | 36.1 |
| | 19.1 |
| | (196.3 | ) | | — |
|
Total Revenues | $ | 2,556.3 |
| | $ | 1,275.6 |
| | $ | 132.4 |
| | $ | 859.4 |
| | $ | 24.8 |
| | $ | (196.3 | ) | | $ | 4,652.2 |
|
| | | | | | | | | | | | | |
Income (Loss) from Continuing Operations | $ | 343.4 |
| | $ | 155.5 |
| | $ | 69.5 |
| | $ | (1,369.2 | ) | | $ | 36.6 |
| | $ | — |
| | $ | (764.2 | ) |
Income from Discontinued Operations, Net of Tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net Income (Loss) | $ | 343.4 |
| | $ | 155.5 |
| | $ | 69.5 |
| | $ | (1,369.2 | ) | | $ | 36.6 |
| | $ | — |
| | $ | (764.2 | ) |
| | | | | | | | | | | | | |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| (in millions) |
Three Months Ended September 30, 2015 | |
| | |
| | |
| | |
| | |
| | | | |
|
Revenues from: | |
| | |
| | |
| | |
| | |
| | | | |
|
External Customers | $ | 2,435.8 |
| | $ | 1,163.6 |
| | $ | 26.9 |
| | $ | 801.8 |
| | $ | 3.3 |
| | $ | — |
| | $ | 4,431.4 |
|
Other Operating Segments | 35.7 |
| | 25.0 |
| | 60.6 |
| | 34.2 |
| | 20.5 |
| | (176.0 | ) | | — |
|
Total Revenues | $ | 2,471.5 |
| | $ | 1,188.6 |
| | $ | 87.5 |
| | $ | 836.0 |
| | $ | 23.8 |
| | $ | (176.0 | ) | | $ | 4,431.4 |
|
| | | | | | | | | | | | | |
Income (Loss) from Continuing Operations | $ | 274.5 |
| | $ | 113.0 |
| | $ | 45.9 |
| | $ | 91.6 |
| | $ | (13.2 | ) | | $ | — |
| | $ | 511.8 |
|
Income from Discontinued Operations, Net of Tax | — |
| | — |
| | — |
| | — |
| | 7.8 |
| | — |
| | 7.8 |
|
Net Income (Loss) | $ | 274.5 |
| | $ | 113.0 |
| | $ | 45.9 |
| | $ | 91.6 |
| | $ | (5.4 | ) | | $ | — |
| | $ | 519.6 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| (in millions) |
Nine Months Ended September 30, 2016 | |
| | |
| | |
| | |
| | |
| | | | |
|
Revenues from: | |
| | |
| | |
| | |
| | |
| | | | |
|
External Customers | $ | 6,864.6 |
| | $ | 3,398.9 |
| | $ | 110.1 |
| | $ | 2,192.5 |
| | $ | 23.9 |
| | $ | — |
| | $ | 12,590.0 |
|
Other Operating Segments | 63.2 |
| | 69.6 |
| | 272.6 |
| | 98.7 |
| | 55.2 |
| | (559.3 | ) | | — |
|
Total Revenues | $ | 6,927.8 |
| | $ | 3,468.5 |
| | $ | 382.7 |
| | $ | 2,291.2 |
| | $ | 79.1 |
| | $ | (559.3 | ) | | $ | 12,590.0 |
|
| | | | | | | | | | | | | |
Income (Loss) from Continuing Operations | $ | 832.6 |
| | $ | 388.1 |
| | $ | 209.5 |
| | $ | (1,248.8 | ) | | $ | 63.9 |
| | $ | — |
| | $ | 245.3 |
|
Loss from Discontinued Operations, Net of Tax | — |
| | — |
| | — |
| | — |
| | (2.5 | ) | | — |
| | (2.5 | ) |
Net Income (Loss) | $ | 832.6 |
| | $ | 388.1 |
| | $ | 209.5 |
| | $ | (1,248.8 | ) | | $ | 61.4 |
| | $ | — |
| | $ | 242.8 |
|
| | | | | | | | | | | | | |
| Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| (in millions) |
Nine Months Ended September 30, 2015 | |
| | |
| | |
| | |
| | |
| | | | |
|
Revenues from: | |
| | |
| | |
| | |
| | |
| | | | |
|
External Customers | $ | 7,081.8 |
| | $ | 3,377.9 |
| | $ | 74.1 |
| | $ | 2,288.6 |
| | $ | 16.1 |
| | $ | — |
| | $ | 12,838.5 |
|
Other Operating Segments | 77.3 |
| | 141.5 |
| | 170.8 |
| | 518.1 |
| | 57.8 |
| | (965.5 | ) | | — |
|
Total Revenues | $ | 7,159.1 |
| | $ | 3,519.4 |
| | $ | 244.9 |
| | $ | 2,806.7 |
| | $ | 73.9 |
| | $ | (965.5 | ) | | $ | 12,838.5 |
|
| | | | | | | | | | | | | |
Income (Loss) from Continuing Operations | $ | 782.7 |
| | $ | 287.8 |
| | $ | 147.7 |
| | $ | 360.3 |
| | $ | (15.1 | ) | | $ | — |
| | $ | 1,563.4 |
|
Income from Discontinued Operations, Net of Tax | — |
| | — |
| | — |
| | — |
| | 18.2 |
| | — |
| | 18.2 |
|
Net Income | $ | 782.7 |
| | $ | 287.8 |
| | $ | 147.7 |
| | $ | 360.3 |
| | $ | 3.1 |
| | $ | — |
| | $ | 1,581.6 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| | (in millions) |
September 30, 2016 | | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Total Property, Plant and Equipment | | $ | 41,015.6 |
| | $ | 14,438.4 |
| | $ | 4,896.4 |
| | $ | 234.3 |
| | $ | 368.6 |
| | $ | (353.5 | ) | (b) | $ | 60,599.8 |
|
Accumulated Depreciation and Amortization | | 12,549.8 |
| | 3,647.4 |
| | 88.2 |
| | 44.2 |
| | 192.1 |
| | (184.1 | ) | (b) | 16,337.6 |
|
Total Property Plant and Equipment - Net | | $ | 28,465.8 |
| | $ | 10,791.0 |
| | $ | 4,808.2 |
| | $ | 190.1 |
| | $ | 176.5 |
| | $ | (169.4 | ) | (b) | $ | 44,262.2 |
|
| | | | | | | | | | | | | | |
Assets Held for Sale | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,915.3 |
| | $ | — |
| | $ | — |
| | $ | 1,915.3 |
|
| | | | | | | | | | | | | | |
Total Assets | | $ | 36,924.3 |
| | $ | 14,155.7 |
| | $ | 5,780.5 |
| | $ | 3,176.6 |
| | $ | 21,772.4 |
| | $ | (20,367.5 | ) | (b) (c) | $ | 61,442.0 |
|
| | | | | | | | | | | | | | |
Long-term Debt Due Within One Year: | | | | | | | | | | | | | | |
Non-Affiliated | | $ | 1,611.0 |
| | $ | 268.3 |
| | $ | — |
| | $ | 505.2 |
| | $ | 0.3 |
| | $ | — |
| | $ | 2,384.8 |
|
| | | | | | | | | | | | | | |
Long-term Debt: | | | | | | | | | | | | | | |
Affiliated | | 20.0 |
| | — |
| | — |
| | 32.2 |
| | — |
| | (52.2 | ) | | — |
|
Non-Affiliated | | 10,067.3 |
| | 4,745.3 |
| | 1,660.4 |
| | — |
| | 846.9 |
| | — |
| | 17,319.9 |
|
| | | | | | | | | | | | | | |
Total Long-term Debt | | $ | 11,698.3 |
| | $ | 5,013.6 |
| | $ | 1,660.4 |
| | $ | 537.4 |
| | $ | 847.2 |
| | $ | (52.2 | ) | | $ | 19,704.7 |
|
| | | | | | | | | | | | | | |
Liabilities Held for Sale | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 231.0 |
| | $ | — |
| | $ | — |
| | $ | 231.0 |
|
| | | | | | | | | | | | | | |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| | (in millions) |
December 31, 2015 | | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Total Property, Plant and Equipment | | $ | 40,130.3 |
| | $ | 13,840.5 |
| | $ | 3,977.6 |
| | $ | 7,461.3 |
| | $ | 350.9 |
| | $ | (279.2 | ) | (b) | $ | 65,481.4 |
|
Accumulated Depreciation and Amortization | | 12,335.0 |
| | 3,529.2 |
| | 52.3 |
| | 3,367.0 |
| | 176.9 |
| | (112.2 | ) | (b) | 19,348.2 |
|
Total Property Plant and Equipment - Net | | $ | 27,795.3 |
| | $ | 10,311.3 |
| | $ | 3,925.3 |
| | $ | 4,094.3 |
| | $ | 174.0 |
| | $ | (167.0 | ) | (b) | $ | 46,133.2 |
|
| | | | | | | | | | | | | | |
Total Assets | | $ | 35,792.3 |
| | $ | 14,640.2 |
| | $ | 5,012.1 |
| | $ | 5,414.5 |
| | $ | 21,907.4 |
| | $ | (21,083.4 | ) | (b) (c) | $ | 61,683.1 |
|
| | | | | | | | | | | | | | |
Long-term Debt Due Within One Year: | | | | | | | | | | | | | | |
Non-Affiliated | | $ | 935.4 |
| | $ | 824.7 |
| | $ | — |
| | $ | 71.6 |
| | $ | 0.1 |
| | $ | — |
| | $ | 1,831.8 |
|
| | | | | | | | | | | | | | |
Long-term Debt: | | | | | | | | | | | | | | |
Affiliated | | 20.0 |
| | — |
| | — |
| | 32.2 |
| | — |
| | (52.2 | ) | | — |
|
Non-Affiliated | | 9,833.0 |
| | 4,776.8 |
| | 1,648.4 |
| | 639.5 |
| | 843.2 |
| | — |
| | 17,740.9 |
|
| | | | | | | | | | | | | | |
Total Long-term Debt | | $ | 10,788.4 |
| | $ | 5,601.5 |
| | $ | 1,648.4 |
| | $ | 743.3 |
| | $ | 843.3 |
| | $ | (52.2 | ) | | $ | 19,572.7 |
|
| |
(a) | Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. |
| |
(b) | Includes eliminations due to an intercompany capital lease. |
| |
(c) | Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. |
Registrant Subsidiaries’ Reportable Segments
The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, which has an electricity transmission and distribution business that started in 2014.business. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
8.9. DERIVATIVES AND HEDGING
The disclosures in this note apply to all Registrants unless indicated otherwise.
OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS
AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries.
The Registrant SubsidiariesRegistrants are exposed to certain market risks as major power producers and participants in the wholesale electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant SubsidiariesRegistrants due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, managesManagement utilizes derivative instruments to manage these risks using derivative instruments.risks.
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES
Risk Management Strategies
The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes focusingwhich focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries.commodities. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries,Registrants primarily employsemploy risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.
AEPSC, on behalf of the Registrant Subsidiaries, enters intoThe Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters intoThe Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries,The Registrants also engages in risk management ofutilize derivative contracts to manage interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’sthe Board of Directors.
The following tables represent the gross notional volume of the Registrant Subsidiaries’Registrants’ outstanding derivative contracts as of September 30, 20152016 and December 31, 2014:2015:
Notional Volume of Derivative Instruments
September 30, 20152016
| | Primary Risk Exposure | | Unit of Measure | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | | Unit of Measure | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) | | (in millions) |
Commodity: | | | | | | |
| | |
| | |
| | |
| | | | | | | | |
| | |
| | |
| | |
|
Power | | MWhs | | 62,306 |
| | 30,345 |
| | 13,470 |
| | 17,580 |
| | 21,736 |
| | MWhs | | 398.7 |
| | 66.4 |
| | 22.4 |
| | 11.3 |
| | 18.3 |
| | 21.8 |
|
Coal | | Tons | | 116 |
| | 1,468 |
| | — |
| | — |
| | 2,125 |
| | Tons | | 2.1 |
| | — |
| | 0.7 |
| | — |
| | — |
| | 1.4 |
|
Natural Gas | | MMBtus | | 256 |
| | 174 |
| | — |
| | — |
| | — |
| | MMBtus | | 37.3 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Heating Oil and Gasoline | | Gallons | | 1,763 |
| | 836 |
| | 1,858 |
| | 1,019 |
| | 1,166 |
| | Gallons | | 6.9 |
| | 1.3 |
| | 0.6 |
| | 1.5 |
| | 0.8 |
| | 0.9 |
|
Interest Rate | | USD | | $ | 2,645 |
| | $ | 1,794 |
| | $ | — |
| | $ | — |
| | $ | — |
| | USD | | $ | 82.2 |
| | $ | 0.1 |
| | $ | 0.1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | |
Interest Rate and Foreign Currency | | | USD | | $ | 505.2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Notional Volume of Derivative Instruments
December 31, 20142015
| | Primary Risk Exposure | | Unit of Measure | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | | Unit of Measure | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) | | (in millions) |
Commodity: | | | | | | |
| | |
| | |
| | |
| | | | | | | | |
| | |
| | |
| | |
|
Power | | MWhs | | 32,479 |
| | 23,774 |
| | 20,334 |
| | 16,765 |
| | 20,469 |
| | MWhs | | 317.8 |
| | 40.9 |
| | 22.8 |
| | 13.3 |
| | 11.3 |
| | 14.0 |
|
Coal | | Tons | | 279 |
| | 500 |
| | — |
| | — |
| | 1,500 |
| | Tons | | 4.4 |
| | — |
| | 1.6 |
| | — |
| | — |
| | 2.8 |
|
Natural Gas | | MMBtus | | 421 |
| | 286 |
| | — |
| | — |
| | — |
| | MMBtus | | 38.2 |
| | 0.3 |
| | 0.2 |
| | — |
| | 0.2 |
| | 0.2 |
|
Heating Oil and Gasoline | | Gallons | | 1,089 |
| | 521 |
| | 1,108 |
| | 614 |
| | 699 |
| | Gallons | | 7.4 |
| | 1.4 |
| | 0.7 |
| | 1.6 |
| | 0.8 |
| | 0.9 |
|
Interest Rate | | USD | | $ | 5,094 |
| | $ | 3,455 |
| | $ | — |
| | $ | — |
| | $ | — |
| | USD | | $ | 113.5 |
| | $ | 2.4 |
| | $ | 1.6 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | |
Interest Rate and Foreign Currency | | | USD | | $ | 560.3 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Fair Value Hedging Strategies (Applies to AEP)
Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges.
Cash Flow Hedging Strategies
AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates asThe Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrant SubsidiariesRegistrants do not hedge all commodity price risk.
The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.
AEPSC, on behalf of the Registrant Subsidiaries, enters intoRegistrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. AEPSC, on behalf of the Registrant Subsidiaries,The Registrants also enters intoutilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrant SubsidiariesRegistrants do not hedge all interest rate exposure.
At times, the Registrant SubsidiariesRegistrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries,Registrants may enter intoutilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant SubsidiariesRegistrants do not hedge all foreign currency exposure.
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS
The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheetsheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries alsoRegistrants apply valuation adjustments for discounting, liquidity and credit quality.
Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract'scontract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.
According to the accounting guidance for “Derivatives and Hedging,” the Registrant SubsidiariesRegistrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant SubsidiariesRegistrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 20152016 and December 31, 2014 condensed2015 balance sheets, the Registrant SubsidiariesRegistrants netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:
| | | | | September 30, 2016 | | December 31, 2015 |
| | | Cash Collateral | | Cash Collateral | | Cash Collateral | | Cash Collateral |
| | | Received | | Paid | | Received | | Paid |
| | | | | | | | | | | Netted Against | | Netted Against | | Netted Against | | Netted Against |
| | September 30, 2015 | | December 31, 2014 | | Risk Management | | Risk Management | | Risk Management | | Risk Management |
Company | | Cash Collateral Received Netted Against Risk Management Assets | | Cash Collateral Paid Netted Against Risk Management Liabilities | | Cash Collateral Received Netted Against Risk Management Assets | | Cash Collateral Paid Netted Against Risk Management Liabilities | | Assets | | Liabilities | | Assets | | Liabilities |
| | (in thousands) | | (in millions) |
AEP | | | $ | 7.1 |
| | $ | 36.0 |
| | $ | 5.8 |
| | $ | 44.4 |
|
APCo | | $ | — |
| | $ | 1,688 |
| | $ | 68 |
| | $ | 98 |
| | 0.1 |
| | 0.1 |
| | — |
| | 3.1 |
|
I&M | | — |
| | 333 |
| | 163 |
| | 47 |
| | — |
| | 0.3 |
| | — |
| | 0.6 |
|
OPCo | | — |
| | 500 |
| | — |
| | 102 |
| | — |
| | — |
| | — |
| | 0.5 |
|
PSO | | — |
| | 280 |
| | — |
| | 54 |
| | — |
| | — |
| | — |
| | 0.3 |
|
SWEPCo | | — |
| | 319 |
| | — |
| | 62 |
| | — |
| | — |
| | — |
| | 0.3 |
|
The following tables represent the gross fair value of the Registrant Subsidiaries’Registrants’ derivative activity on the condensed balance sheets as of September 30, 20152016 and December 31, 2014:2015:
APCoAEP
Fair Value of Derivative Instruments
September 30, 20152016
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency (a) | | | |
| | (in thousands) |
Current Risk Management Assets - Nonaffiliated and Affiliated | | $ | 34,278 |
| | $ | — |
| | $ | — |
| | $ | 34,278 |
| | $ | (6,928 | ) | | $ | 27,350 |
|
Long-term Risk Management Assets - Nonaffiliated | | 2,485 |
| | — |
| | — |
| | 2,485 |
| | (450 | ) | | 2,035 |
|
Total Assets | | 36,763 |
| | — |
| | — |
| | 36,763 |
| | (7,378 | ) | | 29,385 |
|
| | | | | | | | | | | | |
Current Risk Management Liabilities - Nonaffiliated | | 15,345 |
| | — |
| | — |
| | 15,345 |
| | (8,443 | ) | | 6,902 |
|
Long-term Risk Management Liabilities - Nonaffiliated | | 1,596 |
| | — |
| | — |
| | 1,596 |
| | (623 | ) | | 973 |
|
Total Liabilities | | 16,941 |
| | — |
| | — |
| | 16,941 |
| | (9,066 | ) | | 7,875 |
|
| | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 19,822 |
| | $ | — |
| | $ | — |
| | $ | 19,822 |
| | $ | 1,688 |
| | $ | 21,510 |
|
APCo
Fair Value of Derivative Instruments
December 31, 2014
| | | | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) | | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency (a) | | | Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency (a) | |
| | (in thousands) | | (in millions) |
Current Risk Management Assets - Nonaffiliated | | $ | 32,903 |
| | $ | — |
| | $ | — |
| | $ | 32,903 |
| | $ | (9,111 | ) | | $ | 23,792 |
| |
Long-term Risk Management Assets - Nonaffiliated | | 5,159 |
| | — |
| | — |
| | 5,159 |
| | (268 | ) | | 4,891 |
| |
Current Risk Management Assets | | | $ | 267.0 |
| | $ | 8.0 |
| | $ | 0.3 |
| | $ | 275.3 |
| | $ | (164.5 | ) | | $ | 110.8 |
|
Long-term Risk Management Assets | | | 364.2 |
| | 5.4 |
| | — |
| | 369.6 |
| | (57.9 | ) | | 311.7 |
|
Total Assets | | 38,062 |
| | — |
| | — |
| | 38,062 |
| | (9,379 | ) | | 28,683 |
| | 631.2 |
| | 13.4 |
| | 0.3 |
| | 644.9 |
| | (222.4 | ) | | 422.5 |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities - Non Affiliated | | 20,161 |
| | — |
| | — |
| | 20,161 |
| | (9,144 | ) | | 11,017 |
| |
Long-term Risk Management Liabilities - Nonaffiliated | | 2,322 |
| | — |
| | — |
| | 2,322 |
| | (265 | ) | | 2,057 |
| |
Current Risk Management Liabilities | | | 241.5 |
| | 6.6 |
| | 0.2 |
| | 248.3 |
| | (169.0 | ) | | 79.3 |
|
Long-term Risk Management Liabilities | | | 273.3 |
| | 48.7 |
| | 0.3 |
| | 322.3 |
| | (82.3 | ) | | 240.0 |
|
Total Liabilities | | 22,483 |
| | — |
| | — |
| | 22,483 |
| | (9,409 | ) | | 13,074 |
| | 514.8 |
| | 55.3 |
| | 0.5 |
| | 570.6 |
| | (251.3 | ) | | 319.3 |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 15,579 |
| | $ | — |
| | $ | — |
| | $ | 15,579 |
| | $ | 30 |
| | $ | 15,609 |
| | $ | 116.4 |
| | $ | (41.9 | ) | | $ | (0.2 | ) | | $ | 74.3 |
| | $ | 28.9 |
| | $ | 103.2 |
|
| | | | | | | | | | | | | |
AEP | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Fair Value of Derivative Instruments | | Fair Value of Derivative Instruments |
December 31, 2015 | | December 31, 2015 |
| | | | | | | | | | | | | |
| | | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) |
Balance Sheet Location | | | Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency (a) | |
| | | (in millions) |
Current Risk Management Assets | | | $ | 368.8 |
| | $ | 8.2 |
| | $ | 0.1 |
| | $ | 377.1 |
| | $ | (242.7 | ) | | $ | 134.4 |
|
Long-term Risk Management Assets | | | 364.8 |
| | 11.7 |
| | — |
| | 376.5 |
| | (54.7 | ) | | 321.8 |
|
Total Assets | | | 733.6 |
| | 19.9 |
| | 0.1 |
| | 753.6 |
| | (297.4 | ) | | 456.2 |
|
| | | | | | | | | | | | | |
Current Risk Management Liabilities | | | 347.0 |
| | 9.1 |
| | 0.3 |
| | 356.4 |
| | (269.3 | ) | | 87.1 |
|
Long-term Risk Management Liabilities | | | 223.3 |
| | 19.3 |
| | 3.2 |
| | 245.8 |
| | (66.7 | ) | | 179.1 |
|
Total Liabilities | | | 570.3 |
| | 28.4 |
| | 3.5 |
| | 602.2 |
| | (336.0 | ) | | 266.2 |
|
| | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | | $ | 163.3 |
| | $ | (8.5 | ) | | $ | (3.4 | ) | | $ | 151.4 |
| | $ | 38.6 |
| | $ | 190.0 |
|
| |
(a) | Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives“Derivatives and Hedging."” |
| |
(b) | Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives“Derivatives and Hedging."” |
| |
(c) | There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. |
I&MAPCo
Fair Value of Derivative Instruments
September 30, 20152016
| | | | | | | Gross | | Net Amounts of |
| | | | | Amounts | | Assets/Liabilities |
| | | Risk | | Offset in the | | Presented in the |
| | | | | | | | | | | | | | | Management | | Statement of | | Statement of |
| | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) | | Contracts - | | Financial | | Financial |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency (a) | | | Commodity (a) | | Position (b) | | Position (c) |
| | (in thousands) | | (in millions) |
Current Risk Management Assets - Nonaffiliated and Affiliated | | $ | 16,675 |
| | $ | — |
| | $ | — |
| | $ | 16,675 |
| | $ | (6,048 | ) | | $ | 10,627 |
| |
Current Risk Management Assets - Nonaffiliated | | | $ | 11.0 |
| | $ | (7.8 | ) | | $ | 3.2 |
|
Long-term Risk Management Assets - Nonaffiliated | | 1,619 |
| | — |
| | — |
| | 1,619 |
| | (281 | ) | | 1,338 |
| | 1.0 |
| | (0.8 | ) | | 0.2 |
|
Total Assets | | 18,294 |
| | — |
| | — |
| | 18,294 |
| | (6,329 | ) | | 11,965 |
| | 12.0 |
| | (8.6 | ) | | 3.4 |
|
| | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities - Nonaffiliated | | 10,901 |
| | — |
| | — |
| | 10,901 |
| | (6,286 | ) | | 4,615 |
| | 18.5 |
| | (7.8 | ) | | 10.7 |
|
Long-term Risk Management Liabilities - Nonaffiliated | | 1,624 |
| | — |
| | — |
| | 1,624 |
| | (376 | ) | | 1,248 |
| | 1.1 |
| | (0.8 | ) | | 0.3 |
|
Total Liabilities | | 12,525 |
| | — |
| | — |
| | 12,525 |
| | (6,662 | ) | | 5,863 |
| | 19.6 |
| | (8.6 | ) | | 11.0 |
|
| | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 5,769 |
| | $ | — |
| | $ | — |
| | $ | 5,769 |
| | $ | 333 |
| | $ | 6,102 |
| |
Total MTM Derivative Contract Net Liabilities | | | $ | (7.6 | ) | | $ | — |
| | $ | (7.6 | ) |
I&MAPCo
Fair Value of Derivative Instruments
December 31, 20142015
| | | | | | | Gross | | Net Amounts of |
| | | | | Amounts | | Assets/Liabilities |
| | | Risk | | Offset in the | | Presented in the |
| | | | | | | | | | | | | | | Management | | Statement of | | Statement of |
| | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) | | Contracts - | | Financial | | Financial |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency (a) | | | Commodity (a) | | Position (b) | | Position (c) |
| | (in thousands) | | (in millions) |
Current Risk Management Assets - Nonaffiliated | | $ | 28,545 |
| | $ | — |
| | $ | — |
| | $ | 28,545 |
| | $ | (6,217 | ) | | $ | 22,328 |
| |
Current Risk Management Assets - Nonaffiliated and Affiliated | | | $ | 25.9 |
| | $ | (10.3 | ) | | $ | 15.6 |
|
Long-term Risk Management Assets - Nonaffiliated | | 3,499 |
| | — |
| | — |
| | 3,499 |
| | (182 | ) | | 3,317 |
| | 0.3 |
| | (0.2 | ) | | 0.1 |
|
Total Assets | | 32,044 |
| | — |
| | — |
| | 32,044 |
| | (6,399 | ) | | 25,645 |
| | 26.2 |
| | (10.5 | ) | | 15.7 |
|
| | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities - Nonaffiliated | | 11,326 |
| | — |
| | — |
| | 11,326 |
| | (6,103 | ) | | 5,223 |
| | 18.1 |
| | (13.3 | ) | | 4.8 |
|
Long-term Risk Management Liabilities - Nonaffiliated | | 1,575 |
| | — |
| | — |
| | 1,575 |
| | (180 | ) | | 1,395 |
| | 0.3 |
| | (0.2 | ) | | 0.1 |
|
Total Liabilities | | 12,901 |
| | — |
| | — |
| | 12,901 |
| | (6,283 | ) | | 6,618 |
| | 18.4 |
| | (13.5 | ) | | 4.9 |
|
| | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 19,143 |
| | $ | — |
| | $ | — |
| | $ | 19,143 |
| | $ | (116 | ) | | $ | 19,027 |
| |
Total MTM Derivative Contract Net Assets | | | $ | 7.8 |
| | $ | 3.0 |
| | $ | 10.8 |
|
| |
(a) | Derivative instruments within these categoriesthis category are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives“Derivatives and Hedging."” |
| |
(b) | Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives“Derivatives and Hedging."” |
| |
(c) | There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. |
OPCoI&M
Fair Value of Derivative Instruments
September 30, 20152016
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency (a) | | | |
| | (in thousands) |
Current Risk Management Assets | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Long-term Risk Management Assets | | 23,265 |
| | — |
| | — |
| | 23,265 |
| | — |
| | 23,265 |
|
Total Assets | | 23,265 |
| | — |
| | — |
| | 23,265 |
| | — |
| | 23,265 |
|
| | | | | | | | | | | | |
Current Risk Management Liabilities | | 3,271 |
| | — |
| | — |
| | 3,271 |
| | (448 | ) | | 2,823 |
|
Long-term Risk Management Liabilities | | 4,923 |
| | — |
| | — |
| | 4,923 |
| | (52 | ) | | 4,871 |
|
Total Liabilities | | 8,194 |
| | — |
| | — |
| | 8,194 |
| | (500 | ) | | 7,694 |
|
| | | | �� | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 15,071 |
| | $ | — |
| | $ | — |
| | $ | 15,071 |
| | $ | 500 |
| | $ | 15,571 |
|
|
| | | | | | | | | | | | |
| | | | Gross | | Net Amounts of |
| | | | Amounts | | Assets/Liabilities |
| | Risk | | Offset in the | | Presented in the |
| | Management | | Statement of | | Statement of |
| | Contracts - | | Financial | | Financial |
Balance Sheet Location | | Commodity (a) | | Position (b) | | Position (c) |
| | (in millions) |
Current Risk Management Assets - Nonaffiliated | | $ | 10.8 |
| | $ | (5.6 | ) | | $ | 5.2 |
|
Long-term Risk Management Assets - Nonaffiliated | | 0.6 |
| | (0.4 | ) | | 0.2 |
|
Total Assets | | 11.4 |
| | (6.0 | ) | | 5.4 |
|
| | | | | | |
Current Risk Management Liabilities - Nonaffiliated | | 7.2 |
| | (5.9 | ) | | 1.3 |
|
Long-term Risk Management Liabilities - Nonaffiliated | | 0.6 |
| | (0.4 | ) | | 0.2 |
|
Total Liabilities | | 7.8 |
| | (6.3 | ) | | 1.5 |
|
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 3.6 |
| | $ | 0.3 |
| | $ | 3.9 |
|
OPCoI&M
Fair Value of Derivative Instruments
December 31, 20142015
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency (a) | | | |
| | (in thousands) |
Current Risk Management Assets | | $ | 7,242 |
| | $ | — |
| | $ | — |
| | $ | 7,242 |
| | $ | — |
| | $ | 7,242 |
|
Long-term Risk Management Assets | | 45,102 |
| | — |
| | — |
| | 45,102 |
| | — |
| | 45,102 |
|
Total Assets | | 52,344 |
| | — |
| | — |
| | 52,344 |
| | — |
| | 52,344 |
|
| | | | | | | | | | | | |
Current Risk Management Liabilities | | 2,045 |
| | — |
| | — |
| | 2,045 |
| | (102 | ) | | 1,943 |
|
Long-term Risk Management Liabilities | | 3,013 |
| | — |
| | — |
| | 3,013 |
| | — |
| | 3,013 |
|
Total Liabilities | | 5,058 |
| | — |
| | — |
| | 5,058 |
| | (102 | ) | | 4,956 |
|
| | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 47,286 |
| | $ | — |
| | $ | — |
| | $ | 47,286 |
| | $ | 102 |
| | $ | 47,388 |
|
|
| | | | | | | | | | | | |
| | | | Gross | | Net Amounts of |
| | | | Amounts | | Assets/Liabilities |
| | Risk | | Offset in the | | Presented in the |
| | Management | | Statement of | | Statement of |
| | Contracts - | | Financial | | Financial |
Balance Sheet Location | | Commodity (a) | | Position (b) | | Position (c) |
| | (in millions) |
Current Risk Management Assets - Nonaffiliated and Affiliated | | $ | 22.8 |
| | $ | (10.5 | ) | | $ | 12.3 |
|
Long-term Risk Management Assets - Nonaffiliated | | 0.6 |
| | (0.6 | ) | | — |
|
Total Assets | | 23.4 |
| | (11.1 | ) | | 12.3 |
|
| | | | | | |
Current Risk Management Liabilities - Nonaffiliated | | 17.0 |
| | (10.7 | ) | | 6.3 |
|
Long-term Risk Management Liabilities - Nonaffiliated | | 2.6 |
| | (1.0 | ) | | 1.6 |
|
Total Liabilities | | 19.6 |
| | (11.7 | ) | | 7.9 |
|
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 3.8 |
| | $ | 0.6 |
| | $ | 4.4 |
|
| |
(a) | Derivative instruments within these categoriesthis category are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives“Derivatives and Hedging."” |
| |
(b) | Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives“Derivatives and Hedging."” |
| |
(c) | There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. |
PSOOPCo
Fair Value of Derivative Instruments
September 30, 20152016
| | | | | | | Gross | | Net Amounts of |
| | | | | Amounts | | Assets/Liabilities |
| | | Risk | | Offset in the | | Presented in the |
| | | | | | | | | | | | | | | Management | | Statement of | | Statement of |
| | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) | | Contracts - | | Financial | | Financial |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency (a) | | | Commodity (a) | | Position (b) | | Position (c) |
| | (in thousands) | | (in millions) |
Current Risk Management Assets | | $ | 1,166 |
| | $ | — |
| | $ | — |
| | $ | 1,166 |
| | $ | (131 | ) | | $ | 1,035 |
| | $ | 0.1 |
| | $ | (0.1 | ) | | $ | — |
|
Long-term Risk Management Assets | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total Assets | | 1,166 |
| | — |
| | — |
| | 1,166 |
| | (131 | ) | | 1,035 |
| | 0.1 |
| | (0.1 | ) | | — |
|
| | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | 454 |
| | — |
| | — |
| | 454 |
| | (384 | ) | | 70 |
| | 5.7 |
| | (0.1 | ) | | 5.6 |
|
Long-term Risk Management Liabilities | | 35 |
| | — |
| | — |
| | 35 |
| | (27 | ) | | 8 |
| | 103.5 |
| | — |
| | 103.5 |
|
Total Liabilities | | 489 |
| | — |
| | — |
| | 489 |
| | (411 | ) | | 78 |
| | 109.2 |
| | (0.1 | ) | | 109.1 |
|
| | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 677 |
| | $ | — |
| | $ | — |
| | $ | 677 |
| | $ | 280 |
| | $ | 957 |
| |
Total MTM Derivative Contract Net Liabilities | | | $ | (109.1 | ) | | $ | — |
| | $ | (109.1 | ) |
PSOOPCo
Fair Value of Derivative Instruments
December 31, 20142015
| | | | | | | Gross | | Net Amounts of |
| | | | | Amounts | | Assets/Liabilities |
| | | Risk | | Offset in the | | Presented in the |
| | | | | | | | | | | | | | | Management | | Statement of | | Statement of |
| | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) | | Contracts - | | Financial | | Financial |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency (a) | | | Commodity (a) | | Position (b) | | Position (c) |
| | (in thousands) | | (in millions) |
Current Risk Management Assets | | $ | 360 |
| | $ | — |
| | $ | — |
| | $ | 360 |
| | $ | (360 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Long-term Risk Management Assets | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 19.2 |
| | — |
| | 19.2 |
|
Total Assets | | 360 |
| | — |
| | — |
| | 360 |
| | (360 | ) | | — |
| | 19.2 |
| | — |
| | 19.2 |
|
| | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | 1,332 |
| | — |
| | — |
| | 1,332 |
| | (414 | ) | | 918 |
| | 4.1 |
| | (0.5 | ) | | 3.6 |
|
Long-term Risk Management Liabilities | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total Liabilities | | 1,332 |
| | — |
| | — |
| | 1,332 |
| | (414 | ) | | 918 |
| | 4.1 |
| | (0.5 | ) | | 3.6 |
|
| | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | (972 | ) | | $ | — |
| | $ | — |
| | $ | (972 | ) | | $ | 54 |
| | $ | (918 | ) | |
Total MTM Derivative Contract Net Assets | | | $ | 15.1 |
| | $ | 0.5 |
| | $ | 15.6 |
|
| |
(a) | Derivative instruments within these categoriesthis category are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives“Derivatives and Hedging."” |
| |
(b) | Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives“Derivatives and Hedging."” |
| |
(c) | There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. |
SWEPCoPSO
Fair Value of Derivative Instruments
September 30, 20152016
| | | | | | | Gross | | Net Amounts of |
| | | | | Amounts | | Assets/Liabilities |
| | | Risk | | Offset in the | | Presented in the |
| | | | | | | | | | | | | | | Management | | Statement of | | Statement of |
| | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) | | Contracts - | | Financial | | Financial |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency (a) | | | Commodity (a) | | Position (b) | | Position (c) |
| | (in thousands) | | (in millions) |
Current Risk Management Assets | | $ | 1,442 |
| | $ | — |
| | $ | — |
| | $ | 1,442 |
| | $ | (162 | ) | | $ | 1,280 |
| | $ | 1.2 |
| | $ | (0.1 | ) | | $ | 1.1 |
|
Long-term Risk Management Assets | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total Assets | | 1,442 |
| | — |
| | — |
| | 1,442 |
| | (162 | ) | | 1,280 |
| | 1.2 |
| | (0.1 | ) | | 1.1 |
|
| | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | 1,752 |
| | — |
| | — |
| | 1,752 |
| | (450 | ) | | 1,302 |
| | 0.1 |
| | (0.1 | ) | | — |
|
Long-term Risk Management Liabilities | | 788 |
| | — |
| | — |
| | 788 |
| | (31 | ) | | 757 |
| | — |
| | — |
| | — |
|
Total Liabilities | | 2,540 |
| | — |
| | — |
| | 2,540 |
| | (481 | ) | | 2,059 |
| | 0.1 |
| | (0.1 | ) | | — |
|
| | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | (1,098 | ) | | $ | — |
| | $ | — |
| | $ | (1,098 | ) | | $ | 319 |
| | $ | (779 | ) | |
Total MTM Derivative Contract Net Assets | | | $ | 1.1 |
| | $ | — |
| | $ | 1.1 |
|
SWEPCoPSO
Fair Value of Derivative Instruments
December 31, 20142015
| | | | | | | Gross | | Net Amounts of |
| | | | | Amounts | | Assets/Liabilities |
| | | Risk | | Offset in the | | Presented in the |
| | | | | | | | | | | | | | | Management | | Statement of | | Statement of |
| | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) | | Contracts - | | Financial | | Financial |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency (a) | | | Commodity (a) | | Position (b) | | Position (c) |
| | (in thousands) | | (in millions) |
Current Risk Management Assets | | $ | 471 |
| | $ | — |
| | $ | — |
| | $ | 471 |
| | $ | (440 | ) | | $ | 31 |
| | $ | 0.6 |
| | $ | — |
| | $ | 0.6 |
|
Long-term Risk Management Assets | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total Assets | | 471 |
| | — |
| | — |
| | 471 |
| | (440 | ) | | 31 |
| | 0.6 |
| | — |
| | 0.6 |
|
| | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | 1,584 |
| | — |
| | — |
| | 1,584 |
| | (502 | ) | | 1,082 |
| | 0.5 |
| | (0.3 | ) | | 0.2 |
|
Long-term Risk Management Liabilities | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total Liabilities | | 1,584 |
| | — |
| | — |
| | 1,584 |
| | (502 | ) | | 1,082 |
| | 0.5 |
| | (0.3 | ) | | 0.2 |
|
| | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | (1,113 | ) | | $ | — |
| | $ | — |
| | $ | (1,113 | ) | | $ | 62 |
| | $ | (1,051 | ) | |
Total MTM Derivative Contract Net Assets | | | $ | 0.1 |
| | $ | 0.3 |
| | $ | 0.4 |
|
| |
(a) | Derivative instruments within these categoriesthis category are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives“Derivatives and Hedging."” |
| |
(b) | Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives“Derivatives and Hedging."” |
| |
(c) | There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. |
SWEPCo
Fair Value of Derivative Instruments
September 30, 2016
|
| | | | | | | | | | | | |
| | | | Gross | | Net Amounts of |
| | | | Amounts | | Assets/Liabilities |
| | Risk | | Offset in the | | Presented in the |
| | Management | | Statement of | | Statement of |
| | Contracts - | | Financial | | Financial |
Balance Sheet Location | | Commodity (a) | | Position (b) | | Position (c) |
| | (in millions) |
Current Risk Management Assets | | $ | 1.5 |
| | $ | (0.1 | ) | | $ | 1.4 |
|
Long-term Risk Management Assets | | — |
| | — |
| | — |
|
Total Assets | | 1.5 |
| | (0.1 | ) | | 1.4 |
|
| | | | | | |
Current Risk Management Liabilities | | 0.1 |
| | (0.1 | ) | | — |
|
Long-term Risk Management Liabilities | | — |
| | — |
| | — |
|
Total Liabilities | | 0.1 |
| | (0.1 | ) | | — |
|
| | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 1.4 |
| | $ | — |
| | $ | 1.4 |
|
SWEPCo
Fair Value of Derivative Instruments
December 31, 2015
|
| | | | | | | | | | | | |
| | | | Gross | | Net Amounts of |
| | | | Amounts | | Assets/Liabilities |
| | Risk | | Offset in the | | Presented in the |
| | Management | | Statement of | | Statement of |
| | Contracts - | | Financial | | Financial |
Balance Sheet Location | | Commodity (a) | | Position (b) | | Position (c) |
| | (in millions) |
Current Risk Management Assets | | $ | 0.8 |
| | $ | — |
| | $ | 0.8 |
|
Long-term Risk Management Assets | | — |
| | — |
| | — |
|
Total Assets | | 0.8 |
| | — |
| | 0.8 |
|
| | | | | | |
Current Risk Management Liabilities | | 3.4 |
| | (0.3 | ) | | 3.1 |
|
Long-term Risk Management Liabilities | | 2.1 |
| | — |
| | 2.1 |
|
Total Liabilities | | 5.5 |
| | (0.3 | ) | | 5.2 |
|
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | (4.7 | ) | | $ | 0.3 |
| | $ | (4.4 | ) |
| |
(a) | Derivative instruments within this category are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” |
| |
(b) | Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” |
| |
(c) | There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. |
The tables below present the Registrant Subsidiaries’Registrants’ activity of derivative risk management contracts for the three and nine months ended September 30, 20152016 and 2014:2015:
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 2016
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Location of Gain (Loss) | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Vertically Integrated Utility Revenues | | $ | 2.4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Transmission and Distribution Utilities Revenues | | 0.1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Generation & Marketing Revenues | | 9.2 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric Generation, Transmission and Distribution Revenues | | — |
| | 1.0 |
| | 1.2 |
| | 0.1 |
| | — |
| | (0.1 | ) |
Purchased Electricity for Resale | | 1.5 |
| | 0.8 |
| | 0.1 |
| | — |
| | — |
| | — |
|
Other Operation Expense | | (0.4 | ) | | — |
| | — |
| | (0.1 | ) | | — |
| | — |
|
Maintenance Expense | | (0.4 | ) | | (0.1 | ) | | — |
| | (0.1 | ) | | (0.1 | ) | | (0.1 | ) |
Regulatory Assets (a) | | (22.5 | ) | | 5.2 |
| | 1.6 |
| | (95.4 | ) | | 0.1 |
| | 2.8 |
|
Regulatory Liabilities (a) | | 28.6 |
| | 16.9 |
| | 5.5 |
| | — |
| | 0.8 |
| | 3.7 |
|
Total Gain (Loss) on Risk Management Contracts | | $ | 18.5 |
| | $ | 23.8 |
| | $ | 8.4 |
| | $ | (95.5 | ) | | $ | 0.8 |
| | $ | 6.3 |
|
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 2015
| | Location of Gain (Loss) | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) | | (in millions) |
Transmission and Distribution Utilities Revenues | | | $ | (0.9 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Generation & Marketing Revenues | | | 1.0 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric Generation, Transmission and Distribution Revenues | | $ | (369 | ) | | $ | 350 |
| | $ | (917 | ) | | $ | (9 | ) | | $ | (7 | ) | | — |
| | (0.4 | ) | | 0.4 |
| | (0.9 | ) | | — |
| | — |
|
Sales to AEP Affiliates | | 1,156 |
| | 3,336 |
| | — |
| | — |
| | — |
| | — |
| | 1.2 |
| | 3.3 |
| | — |
| | — |
| | — |
|
Purchased Electricity for Resale | | | 1.6 |
| | 0.8 |
| | — |
| | — |
| | — |
| | — |
|
Other Operation Expense | | (88 | ) | | (63 | ) | | (128 | ) | | (109 | ) | | (127 | ) | | (0.7 | ) | | (0.1 | ) | | (0.1 | ) | | (0.1 | ) | | (0.1 | ) | | (0.1 | ) |
Maintenance Expense | | (164 | ) | | (86 | ) | | (140 | ) | | (88 | ) | | (88 | ) | | (0.8 | ) | | (0.2 | ) | | (0.1 | ) | | (0.1 | ) | | (0.1 | ) | | (0.1 | ) |
Purchased Electricity for Resale | | 831 |
| | 15 |
| | 30 |
| | — |
| | — |
| |
Regulatory Assets (a) | | 861 |
| | (981 | ) | | — |
| | (190 | ) | | 188 |
| | 0.1 |
| | 0.9 |
| | (1.0 | ) | | — |
| | (0.2 | ) | | 0.2 |
|
Regulatory Liabilities (a) | | 3,197 |
| | (1,718 | ) | | (22,281 | ) | | (498 | ) | | 1,137 |
| | (20.3 | ) | | 3.2 |
| | (1.7 | ) | | (22.3 | ) | | (0.5 | ) | | 1.1 |
|
Total Gain (Loss) on Risk Management Contracts | | $ | 5,424 |
| | $ | 853 |
| | $ | (23,436 | ) | | $ | (894 | ) | | $ | 1,103 |
| | $ | (20.0 | ) | | $ | 5.4 |
| | $ | 0.8 |
| | $ | (23.4 | ) | | $ | (0.9 | ) | | $ | 1.1 |
|
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the ThreeNine Months Ended September 30, 20142016
| | Location of Gain (Loss) | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) | | (in millions) |
Vertically Integrated Utility Revenues | | | $ | 3.1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Transmission and Distribution Utilities Revenues | | | 0.1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Generation & Marketing Revenues | | | 50.1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric Generation, Transmission and Distribution Revenues | | $ | 1,231 |
| | $ | 2,988 |
| | $ | 41 |
| | $ | 45 |
| | $ | 74 |
| | — |
| | (0.8 | ) | | 3.7 |
| | 0.1 |
| | — |
| | (0.1 | ) |
Sales to AEP Affiliates | | — |
| | (196 | ) | | — |
| | 196 |
| | — |
| | — |
| | 2.1 |
| | 5.8 |
| | — |
| | — |
| | — |
|
Purchased Electricity for Resale | | | 4.9 |
| | 2.7 |
| | 0.2 |
| | — |
| | — |
| | — |
|
Other Operation Expense | | | (1.3 | ) | | (0.1 | ) | | (0.1 | ) | | (0.3 | ) | | (0.1 | ) | | (0.2 | ) |
Maintenance Expense | | | (1.6 | ) | | (0.3 | ) | | (0.1 | ) | | (0.3 | ) | | (0.2 | ) | | (0.2 | ) |
Regulatory Assets (a) | | (2,571 | ) | | (471 | ) | | (852 | ) | | (109 | ) | | (284 | ) | | (51.0 | ) | | (7.2 | ) | | 3.0 |
| | (115.9 | ) | | 0.4 |
| | 5.5 |
|
Regulatory Liabilities (a) | | (3,606 | ) | | (176 | ) | | (1,555 | ) | | 120 |
| | (180 | ) | | 58.0 |
| | 39.2 |
| | 11.2 |
| | (15.2 | ) | | 3.2 |
| | 14.7 |
|
Total Gain (Loss) on Risk Management Contracts | | $ | (4,946 | ) | | $ | 2,145 |
| | $ | (2,366 | ) | | $ | 252 |
| | $ | (390 | ) | | $ | 62.3 |
| | $ | 35.6 |
| | $ | 23.7 |
| | $ | (131.6 | ) | | $ | 3.3 |
| | $ | 19.7 |
|
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 2015
|
| | | | | | | | | | | | | | | | | | | | |
Location of Gain (Loss) | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) |
Electric Generation, Transmission and Distribution Revenues | | $ | 790 |
| | $ | 3,591 |
| | $ | (882 | ) | | $ | 16 |
| | $ | 19 |
|
Sales to AEP Affiliates | | 1,511 |
| | 4,341 |
| | — |
| | — |
| | — |
|
Other Operation Expense | | (287 | ) | | (221 | ) | | (389 | ) | | (307 | ) | | (373 | ) |
Maintenance Expense | | (503 | ) | | (221 | ) | | (396 | ) | | (248 | ) | | (265 | ) |
Purchased Electricity for Resale | | 1,571 |
| | 347 |
| | 30 |
| | — |
| | — |
|
Regulatory Assets (a) | | 2,136 |
| | (1,213 | ) | | — |
| | 615 |
| | (1,234 | ) |
Regulatory Liabilities (a) | | 31,797 |
| | 4,121 |
| | (24,880 | ) | | 5,076 |
| | 14,446 |
|
Total Gain (Loss) on Risk Management Contracts | | $ | 37,015 |
| | $ | 10,745 |
| | $ | (26,517 | ) | | $ | 5,152 |
| | $ | 12,593 |
|
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 2014
| | Location of Gain (Loss) | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) | | (in millions) |
Vertically Integrated Utilities Revenues | | | $ | 6.7 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Transmission and Distribution Utilities Revenues | | | (0.9 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Generation & Marketing Revenues | | | 59.9 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric Generation, Transmission and Distribution Revenues | | $ | 7,262 |
| | $ | 10,467 |
| | $ | 97 |
| | $ | 172 |
| | $ | 18 |
| | — |
| | 0.8 |
| | 3.6 |
| | (0.9 | ) | | — |
| | — |
|
Sales to AEP Affiliates | | — |
| | (717 | ) | | — |
| | 717 |
| | — |
| | — |
| | 1.5 |
| | 4.3 |
| | — |
| | — |
| | — |
|
Purchased Electricity for Resale | | | 5.3 |
| | 1.6 |
| | 0.3 |
| | — |
| | — |
| | — |
|
Other Operation Expense | | | (2.3 | ) | | (0.3 | ) | | (0.2 | ) | | (0.4 | ) | | (0.3 | ) | | (0.4 | ) |
Maintenance Expense | | | (2.2 | ) | | (0.5 | ) | | (0.2 | ) | | (0.4 | ) | | (0.2 | ) | | (0.3 | ) |
Regulatory Assets (a) | | (2,567 | ) | | (471 | ) | | (215 | ) | | (119 | ) | | (285 | ) | | 0.2 |
| | 2.1 |
| | (1.2 | ) | | — |
| | 0.6 |
| | (1.2 | ) |
Regulatory Liabilities (a) | | 42,444 |
| | 26,934 |
| | 39,311 |
| | (69 | ) | | 119 |
| | 33.3 |
| | 31.8 |
| | 4.1 |
| | (24.8 | ) | | 5.1 |
| | 14.5 |
|
Total Gain (Loss) on Risk Management Contracts | | $ | 47,139 |
| | $ | 36,213 |
| | $ | 39,193 |
| | $ | 701 |
| | $ | (148 | ) | | $ | 100.0 |
| | $ | 37.0 |
| | $ | 10.7 |
| | $ | (26.5 | ) | | $ | 5.2 |
| | $ | 12.6 |
|
| |
(a) | Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis.
The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.
For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that
economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale.
Accounting for Fair Value Hedging Strategies (Applies to AEP)
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change.
AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of operations. The following table shows the results of hedging gains (losses) during the three and nine months ended September 30, 2016 and 2015:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2016 | | 2015 | | 2016 | | 2015 |
| (in millions) |
Gain (Loss) on Fair Value Hedging Instruments | $ | (1.1 | ) | | $ | 3.7 |
| | $ | 3.0 |
| | $ | 6.8 |
|
Gain (Loss) on Fair Value Portion of Long-term Debt | 1.1 |
| | (3.7 | ) | | (3.0 | ) | | (6.8 | ) |
During the three and nine months ended September 30, 2016 and 2015, hedge ineffectiveness was immaterial.
Accounting for Cash Flow Hedging Strategies
For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant SubsidiariesRegistrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant SubsidiariesRegistrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness iswould be recorded as a regulatory asset (for losses) or a regulatory liability (for gains). if applicable.
Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the condensed statements of income or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2016 and 2015, the Registrant Subsidiaries did not designate power derivatives asAEP applied cash flow hedges.hedging to outstanding power derivatives. During the three and nine months ended September 30, 2014, APCo2016 and I&M designated power derivatives as2015, the Registrant Subsidiaries did not apply cash flow hedges.hedging to outstanding power derivatives.
The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. The impact of cash flow hedge accounting for these derivative contracts was immaterial and was discontinued effective March 31, 2014.
The Registrant SubsidiariesRegistrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2016 and 2015, AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and 2014,nine months ended September 30, 2016 and 2015, the Registrant Subsidiaries did not designateapply cash flow hedging to outstanding interest rate derivatives as cash flow hedges.derivatives.
The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2016 and 2015, and 2014, the Registrant SubsidiariesRegistrants did not designateapply cash flow hedging to any outstanding foreign currency derivatives as cash flow hedges.derivatives.
During the three and nine months ended September 30, 20152016 and 2014,2015, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.
For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges, for the three and nine months ended September 30, 2015 and 2014, see Note 3.
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 20152016 and December 31, 20142015 were:
Impact of Cash Flow Hedges on the Registrant Subsidiaries’
CondensedAEP’s Balance Sheets
September 30, 2015
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Hedging Assets (a) | | Hedging Liabilities (a) | | AOCI Gain (Loss) Net of Tax |
Company | | Commodity | | Interest Rate and Foreign Currency | | Commodity | | Interest Rate and Foreign Currency | | Commodity | | Interest Rate and Foreign Currency |
| | (in thousands) |
APCo | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3,805 |
|
I&M | | — |
| | — |
| | — |
| | — |
| | — |
| | (13,604 | ) |
OPCo | | — |
| | — |
| | — |
| | — |
| | — |
| | 4,572 |
|
PSO | | — |
| | — |
| | — |
| | — |
| | — |
| | 4,374 |
|
SWEPCo | | — |
| | — |
| | — |
| | — |
| | — |
| | (9,470 | ) |
|
| | | | | | | | | | |
| | Expected to be Reclassified to Net Income During the Next Twelve Months | | |
Company | | Commodity | | Interest Rate and Foreign Currency | | Maximum Term for Exposure to Variability of Future Cash Flows |
| | (in thousands) | | (in months) |
APCo | | $ | — |
| | $ | 734 |
| | 0 |
I&M | | — |
| | (1,277 | ) | | 0 |
OPCo | | — |
| | 1,282 |
| | 0 |
PSO | | — |
| | 771 |
| | 0 |
SWEPCo | | — |
| | (1,728 | ) | | 0 |
Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 2014
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Hedging Assets (a) | | Hedging Liabilities (a) | | AOCI Gain (Loss) Net of Tax |
Company | | Commodity | | Interest Rate and Foreign Currency | | Commodity | | Interest Rate and Foreign Currency | | Commodity | | Interest Rate and Foreign Currency |
| | (in thousands) |
APCo | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3,896 |
|
I&M | | — |
| | — |
| | — |
| | — |
| | — |
| | (14,406 | ) |
OPCo | | — |
| | — |
| | — |
| | — |
| | — |
| | 5,602 |
|
PSO | | — |
| | — |
| | — |
| | — |
| | — |
| | 4,943 |
|
SWEPCo | | — |
| | — |
| | — |
| | — |
| | — |
| | (11,036 | ) |
|
| | | | | | | | |
| | Expected to be Reclassified to Net Income During the Next Twelve Months |
Company | | Commodity | | Interest Rate and Foreign Currency |
| | (in thousands) |
APCo | | $ | — |
| | $ | 275 |
|
I&M | | — |
| | (1,090 | ) |
OPCo | | — |
| | 1,372 |
|
PSO | | — |
| | 759 |
|
SWEPCo | | — |
| | (1,998 | ) |
|
| | | | | | | | | | | | | | | | |
| | September 30, 2016 | | December 31, 2015 |
| | | | Interest Rate | | | | Interest Rate |
| | | | and Foreign | | | | and Foreign |
| | Commodity | | Currency | | Commodity | | Currency |
| | (in millions) |
Hedging Assets (a) | | $ | 6.5 |
| | $ | — |
| | $ | 17.6 |
| | $ | — |
|
Hedging Liabilities (a) | | 48.4 |
| | 0.2 |
| | 26.1 |
| | 0.4 |
|
AOCI Gain (Loss) Net of Tax | | (27.1 | ) | | (16.1 | ) | | (5.2 | ) | | (17.2 | ) |
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | | 0.9 |
| | (1.2 | ) | | (0.4 | ) | | (1.5 | ) |
| |
(a) | Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. |
As of September 30, 2016 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 135 months.
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets
|
| | | | | | | | | | | | | | | | |
| | September 30, 2016 | | December 31, 2015 |
| | Interest Rate and Foreign Currency |
| | | | Expected to be | | | | Expected to be |
| | | | Reclassified to | | | | Reclassified to |
| | | | Net Income During | | | | Net Income During |
| | AOCI Gain (Loss) | | the Next | | AOCI Gain (Loss) | | the Next |
Company | | Net of Tax | | Twelve Months | | Net of Tax | | Twelve Months |
| | (in millions) |
APCo | | $ | 3.0 |
| | $ | 0.7 |
| | $ | 3.6 |
| | $ | 0.7 |
|
I&M | | (12.3 | ) | | (1.3 | ) | | (13.3 | ) | | (1.3 | ) |
OPCo | | 3.3 |
| | 1.1 |
| | 4.3 |
| | 1.2 |
|
PSO | | 3.6 |
| | 0.8 |
| | 4.2 |
| | 0.8 |
|
SWEPCo | | (7.8 | ) | | (1.5 | ) | | (9.1 | ) | | (1.7 | ) |
The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.
Credit Risk
AEPSC, on behalf of the Registrant Subsidiaries,Management limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. AEPSC, on behalf of the Registrant Subsidiaries,Management uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.
When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized masterMaster agreements these agreements may include collateral requirements. These master agreementsare typically used to facilitate the netting of cash flows associated with a single counterparty. Cash,counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require aA counterparty is required to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, collateralmaster agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
Collateral Triggering Events
Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo)
Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiariesadditional amounts of collateral are obligated to post an additional amount of collateralrequired if certain credit ratings decline below investment grade.a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant SubsidiariesAEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below investment grade.a specified rating threshold that would require the posting of additional collateral. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following tables representtable represents the Registrant Subsidiaries' exposure if credit ratings were to decline below a specified rating threshold as of September 30, 20152016 and December 31, 2014:2015:
| | | | September 30, 2015 | |
| | | | Amount of Collateral | | | | | |
| | | | the Registrant Subsidiaries | | | | | | | | | | | | | | | | |
| | | | Would Have Been Required | | | | | | September 30, 2016 | | December 31, 2015 | |
| | Fair Value | | to Post for Derivative | | Amount of Collateral | | Amount of | | Amount of Collateral | | Amount of | | Amount of Collateral | | Amount of | |
| | of Contracts | | Contracts as well as Non- | | the Registrant Subsidiaries | | Collateral | | That Would | | Collateral | | That Would | | Collateral | |
| | with Credit | | Derivative Contracts Subject | | Would Have Been Required | | Attributable to | | Have Been Required | | Attributable to | | Have Been Required | | Attributable to | |
| | Downgrade | | to the Same Master Netting | | to Post Attributable to | | Other | | to Post Attributable to | | Other | | to Post Attributable to | | Other | |
Company | | Triggers | | Arrangement | | RTOs and ISOs | | Contracts | | RTOs and ISOs | | Contracts | | RTOs and ISOs | | Contracts | |
| | (in thousands) | | (in millions) | |
AEP | | | $ | 23.9 |
| | $ | 292.4 |
| (a) | | $ | 17.5 |
| | $ | 297.8 |
| (a) |
APCo | | $ | — |
| | $ | — |
| | $ | 2,913 |
| | $ | 97 |
| | 4.4 |
| | — |
| | 4.9 |
| | 0.1 |
| |
I&M | | — |
| | — |
| | 1,976 |
| | 66 |
| | 2.7 |
| | — |
| | 3.3 |
| | 0.1 |
| |
OPCo | | — |
| | — |
| | — |
| | — |
| |
PSO | | — |
| | — |
| | 2,692 |
| | 3,247 |
| | 3.9 |
| | 3.2 |
| | — |
| | 3.2 |
| |
SWEPCo | | — |
| | — |
| | 3,328 |
| | 58 |
| | 4.7 |
| | 0.1 |
| | — |
| | 0.1 |
| |
|
| | | | | | | | | | | | | | | | |
| | December 31, 2014 |
| | | | Amount of Collateral | | | | |
| | | | the Registrant Subsidiaries | | | | |
| | | | Would Have Been Required | | | | |
| | Fair Value | | to Post for Derivative | | Amount of Collateral | | Amount of |
| | of Contracts | | Contracts as well as Non- | | the Registrant Subsidiaries | | Collateral |
| | with Credit | | Derivative Contracts Subject | | Would Have Been Required | | Attributable to |
| | Downgrade | | to the Same Master Netting | | to Post Attributable to | | Other |
Company | | Triggers | | Arrangement | | RTOs and ISOs | | Contracts |
| | (in thousands) |
APCo | | $ | — |
| | $ | — |
| | $ | 6,339 |
| | $ | 74 |
|
I&M | | — |
| | — |
| | 4,299 |
| | 47 |
|
OPCo | | — |
| | — |
| | — |
| | — |
|
PSO | | — |
| | — |
| | 693 |
| | 4,111 |
|
SWEPCo | | — |
| | — |
| | 877 |
| | 166 |
|
| |
(a) | Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. |
Cross-Default Triggers (Applies to AEP, APCo and I&M)
In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess ofthat is $50 million.million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount thisthat the exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of September 30, 20152016 and December 31, 2014:2015:
| | | | September 30, 2015 | | September 30, 2016 |
| | Liabilities for | | | | Additional | | Liabilities for | | | | Additional |
| | Contracts with Cross | | | | Settlement | | Contracts with Cross | | | | Settlement |
| | Default Provisions | | | | Liability if Cross | | Default Provisions | | | | Liability if Cross |
| | Prior to Contractual | | Amount of Cash | | Default Provision | | Prior to Contractual | | Amount of Cash | | Default Provision |
Company | | Netting Arrangements | | Collateral Posted | | is Triggered | | Netting Arrangements | | Collateral Posted | | is Triggered |
| | (in thousands) | | (in millions) |
AEP | | | $ | 285.8 |
| | $ | 10.6 |
| | $ | 253.8 |
|
APCo | | $ | 5,310 |
| | $ | — |
| | $ | 5,288 |
| | 1.3 |
| | — |
| | 1.3 |
|
I&M | | 3,601 |
| | — |
| | 3,586 |
| | 0.8 |
| | — |
| | 0.8 |
|
OPCo | | — |
| | — |
| | — |
| |
PSO | | — |
| | — |
| | — |
| |
SWEPCo | | — |
| | — |
| | — |
| |
| | | | December 31, 2014 | | December 31, 2015 |
| | Liabilities for | | | | Additional | | Liabilities for | | | | Additional |
| | Contracts with Cross | | | | Settlement | | Contracts with Cross | | | | Settlement |
| | Default Provisions | | | | Liability if Cross | | Default Provisions | | | | Liability if Cross |
| | Prior to Contractual | | Amount of Cash | | Default Provision | | Prior to Contractual | | Amount of Cash | | Default Provision |
Company | | Netting Arrangements | | Collateral Posted | | is Triggered | | Netting Arrangements | | Collateral Posted | | is Triggered |
| | (in thousands) | | (in millions) |
AEP | | | $ | 300.1 |
| | $ | 0.8 |
| | $ | 240.6 |
|
APCo | | $ | 9,043 |
| | $ | — |
| | $ | 9,012 |
| | 3.7 |
| | — |
| | 3.7 |
|
I&M | | 6,134 |
| | — |
| | 6,113 |
| | 2.5 |
| | ��� |
| | 2.5 |
|
OPCo | | — |
| | — |
| | — |
| |
PSO | | — |
| | — |
| | — |
| |
SWEPCo | | — |
| | — |
| | — |
| |
9.10. FAIR VALUE MEASUREMENTS
The disclosures in this note apply to all Registrants unless indicated otherwise.
Fair Value Hierarchy and Valuation Techniques
The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The AEP System’sAEPSC's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President.
For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.
AEP utilizes its trustee’s external pricing service in itsto estimate of the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts.
Assets in the nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding and Cash and Cash Equivalents are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual
fixed income securities and cash equivalentsequivalent funds. Fixed income securities generally do not trade on an exchangeexchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in
yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Value Measurements of Long-term Debt
The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
The book values and fair values of Long-term Debt for the Registrant SubsidiariesRegistrants as of September 30, 20152016 and December 31, 20142015 are summarized in the following table:
| | | | September 30, 2015 | | December 31, 2014 | | September 30, 2016 | | December 31, 2015 |
Company | | Book Value | | Fair Value | | Book Value | | Fair Value | | Book Value | | Fair Value | | Book Value | | Fair Value |
| | (in thousands) | | (in millions) |
AEP | | | $ | 19,839.5 |
| (a) | | $ | 22,840.4 |
| | $ | 19,572.7 |
| | $ | 21,201.3 |
|
APCo | | $ | 3,955,295 |
| | $ | 4,460,140 |
| | $ | 3,980,274 |
| | $ | 4,711,210 |
| | 4,033.1 |
| | 4,941.8 |
| | 3,930.7 |
| | 4,416.7 |
|
I&M | | 2,060,651 |
| | 2,241,930 |
| | 2,027,397 |
| | 2,255,124 |
| | 2,407.4 |
| | 2,717.8 |
| | 2,000.0 |
| | 2,193.6 |
|
OPCo | | 2,166,050 |
| | 2,502,105 |
| | 2,297,123 |
| | 2,709,452 |
| | 1,763.4 |
| | 2,213.4 |
| | 2,157.7 |
| | 2,472.7 |
|
PSO | | 1,290,973 |
| | 1,424,300 |
| | 1,041,036 |
| | 1,216,205 |
| | 1,286.2 |
| | 1,502.6 |
| | 1,286.1 |
| | 1,402.9 |
|
SWEPCo | | 2,283,966 |
| | 2,446,716 |
| | 2,140,437 |
| | 2,402,639 |
| | 2,674.0 |
| | 2,943.4 |
| | 2,273.5 |
| | 2,417.2 |
|
| |
(a) | Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. |
Fair Value Measurements of Other Temporary Investments (Applies to AEP)
Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by its protected cell of EIS.
The following is a summary of Other Temporary Investments:
|
| | | | | | | | | | | | | | | | |
| | September 30, 2016 |
Other Temporary Investments | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value |
| | (in millions) |
Restricted Cash (a) | | $ | 159.2 |
| | $ | — |
| | $ | — |
| | $ | 159.2 |
|
Fixed Income Securities – Mutual Funds (b) | | 92.3 |
| | 0.3 |
| | — |
| | 92.6 |
|
Equity Securities – Mutual Funds | | 14.2 |
| | 13.2 |
| | — |
| | 27.4 |
|
Total Other Temporary Investments | | $ | 265.7 |
| | $ | 13.5 |
| | $ | — |
| | $ | 279.2 |
|
|
| | | | | | | | | | | | | | | | |
| �� | December 31, 2015 |
Other Temporary Investments | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value |
| | (in millions) |
Restricted Cash (a) | | $ | 271.0 |
| | $ | — |
| | $ | — |
| | $ | 271.0 |
|
Fixed Income Securities – Mutual Funds (b) | | 91.1 |
| | — |
| | (0.7 | ) | | 90.4 |
|
Equity Securities – Mutual Funds | | 13.7 |
| | 11.7 |
| | — |
| | 25.4 |
|
Total Other Temporary Investments | | $ | 375.8 |
| | $ | 11.7 |
| | $ | (0.7 | ) | | $ | 386.8 |
|
| |
(a) | Primarily represents amounts held for the repayment of debt. |
| |
(b) | Primarily short and intermediate maturities which may be sold and do not contain maturity dates. |
The following table provides the activity for fixed income and equity securities within Other Temporary Investments for the three and nine months ended September 30, 2016 and 2015:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2016 | | 2015 | | 2016 | | 2015 |
| (in millions) |
Proceeds from Investment Sales | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Purchases of Investments | 0.6 |
| | 9.5 |
| | 1.6 |
| | 10.3 |
|
Gross Realized Gains on Investment Sales | — |
| | — |
| | — |
| | — |
|
Gross Realized Losses on Investment Sales | — |
| | — |
| | — |
| | — |
|
For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2016 and 2015, see Note 3.
Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M)
Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:
Acceptable investments (rated investment grade or above when purchased).
Maximum percentage invested in a specific type of investment.
Prohibition of investment in obligations of AEP, I&M or itstheir affiliates.
Withdrawals permitted only for payment of decommissioning costs and trust expenses.
I&M maintains trust records for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.
I&M records securities held in these trust funds for decommissioning nuclear facilitiesin Spent Nuclear Fuel and for the disposal of SNFDecommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed incomedebt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equitydebt and fixed incomeequity investments held in these trusts and generally intends to sell fixed incomedebt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds.
The following is a summary of nuclear trust fund investments as of September 30, 20152016 and December 31, 2014:2015:
| | | September 30, 2015 | | December 31, 2014 | September 30, 2016 | | December 31, 2015 |
| | | Gross | | Other-Than- | | | | Gross | | Other-Than- | | | Gross | | Other-Than- | | | | Gross | | Other-Than- |
| Fair | | Unrealized | | Temporary | | Fair | | Unrealized | | Temporary | Fair | | Unrealized | | Temporary | | Fair | | Unrealized | | Temporary |
| Value | | Gains | | Impairments | | Value | | Gains | | Impairments | Value | | Gains | | Impairments | | Value | | Gains | | Impairments |
| (in thousands) | (in millions) |
Cash and Cash Equivalents | $ | 164,353 |
| | $ | — |
| | $ | — |
| | $ | 19,966 |
| | $ | — |
| | $ | — |
| $ | 35.2 |
| | $ | — |
| | $ | — |
| | $ | 168.3 |
| | $ | — |
| | $ | — |
|
Fixed Income Securities: | |
| | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
| | |
|
United States Government | 704,344 |
| | 45,005 |
| | (2,291 | ) | | 697,042 |
| | 44,615 |
| | (5,016 | ) | 892.7 |
| | 55.5 |
| | (2.1 | ) | | 731.1 |
| | 35.9 |
| | (2.6 | ) |
Corporate Debt | 62,118 |
| | 3,682 |
| | (1,043 | ) | | 47,792 |
| | 4,523 |
| | (1,018 | ) | 66.5 |
| | 6.1 |
| | (1.0 | ) | | 57.9 |
| | 3.2 |
| | (1.1 | ) |
State and Local Government | 50,018 |
| | 996 |
| | (324 | ) | | 208,553 |
| | 1,206 |
| | (319 | ) | 16.4 |
| | 1.2 |
| | (0.3 | ) | | 22.2 |
| | 1.1 |
| | (0.3 | ) |
Subtotal Fixed Income Securities | 816,480 |
| | 49,683 |
| | (3,658 | ) | | 953,387 |
| | 50,344 |
| | (6,353 | ) | 975.6 |
| | 62.8 |
| | (3.4 | ) | | 811.2 |
| | 40.2 |
| | (4.0 | ) |
Equity Securities - Domestic | 1,066,427 |
| | 516,206 |
| | (80,280 | ) | | 1,122,379 |
| | 598,788 |
| | (79,142 | ) | 1,220.0 |
| | 631.6 |
| | (78.0 | ) | | 1,126.9 |
| | 571.6 |
| | (79.3 | ) |
Spent Nuclear Fuel and Decommissioning Trusts | $ | 2,047,260 |
| | $ | 565,889 |
| | $ | (83,938 | ) | | $ | 2,095,732 |
| | $ | 649,132 |
| | $ | (85,495 | ) | $ | 2,230.8 |
| | $ | 694.4 |
| | $ | (81.4 | ) | | $ | 2,106.4 |
| | $ | 611.8 |
| | $ | (83.3 | ) |
The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 20152016 and 2014:2015:
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
| | (in thousands) | | (in millions) |
Proceeds from Investment Sales | | $ | 921,552 |
| | $ | 263,738 |
| | $ | 1,437,336 |
| | $ | 746,272 |
| | $ | 650.0 |
| | $ | 921.5 |
| | $ | 2,427.0 |
| | $ | 1,437.3 |
|
Purchases of Investments | | 938,438 |
| | 280,626 |
| | 1,479,149 |
| | 789,461 |
| | 656.5 |
| | 938.4 |
| | 2,452.9 |
| | 1,479.1 |
|
Gross Realized Gains on Investment Sales | | 15,030 |
| | 7,617 |
| | 33,840 |
| | 24,835 |
| | 13.9 |
| | 15.0 |
| | 41.9 |
| | 33.8 |
|
Gross Realized Losses on Investment Sales | | 13,167 |
| | 1,739 |
| | 22,823 |
| | 10,447 |
| | 6.5 |
| | 13.1 |
| | 22.2 |
| | 22.8 |
|
The adjustedbase cost of fixed income securities was $766$913 million and $903$771 million as of September 30, 20152016 and December 31, 2014,2015, respectively. The adjustedbase cost of equity securities was $551$588 million and $524$555 million as of September 30, 20152016 and December 31, 2014,2015, respectively.
The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 20152016 was as follows:
| | | Fair Value of Fixed Income Securities | Fair Value of Fixed Income Securities |
| (in thousands) | (in millions) |
Within 1 year | $ | 166,336 |
| $ | 330.4 |
|
1 year – 5 years | 335,823 |
| 317.3 |
|
5 years – 10 years | 140,129 |
| 150.4 |
|
After 10 years | 174,192 |
| 177.5 |
|
Total | $ | 816,480 |
| $ | 975.6 |
|
Fair Value Measurements of Financial Assets and Liabilities
The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 20152016 and December 31, 2014.2015. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
AEP
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2016
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Cash and Cash Equivalents (a) | | $ | 12.8 |
| | $ | 5.3 |
| | $ | — |
| | $ | 194.1 |
| | $ | 212.2 |
|
| | | | | | | | | | |
Other Temporary Investments | | | | | | | | | | |
Restricted Cash (a) | | 146.7 |
| | 5.7 |
| | — |
| | 6.8 |
| | 159.2 |
|
Fixed Income Securities – Mutual Funds | | 92.6 |
| | — |
| | — |
| | — |
| | 92.6 |
|
Equity Securities – Mutual Funds (b) | | 27.4 |
| | — |
| | — |
| | — |
| | 27.4 |
|
Total Other Temporary Investments | | 266.7 |
| | 5.7 |
| | — |
| | 6.8 |
| | 279.2 |
|
| | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (d) | | 5.3 |
| | 399.3 |
| | 214.7 |
| | (203.7 | ) | | 415.6 |
|
Cash Flow Hedges: | | |
| | |
| | |
| | |
| | |
|
Commodity Hedges (c) | | — |
| | 10.5 |
| | 1.1 |
| | (5.0 | ) | | 6.6 |
|
Fair Value Hedges | | — |
| | — |
| | — |
| | 0.3 |
| | 0.3 |
|
Total Risk Management Assets | | 5.3 |
| | 409.8 |
| | 215.8 |
| | (208.4 | ) | | 422.5 |
|
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | |
| | |
| | |
| | |
| | |
|
Cash and Cash Equivalents (e) | | 18.7 |
| | — |
| | — |
| | 16.5 |
| | 35.2 |
|
Fixed Income Securities: | | |
| | |
| | |
| | |
| | |
|
United States Government | | — |
| | 892.7 |
| | — |
| | — |
| | 892.7 |
|
Corporate Debt | | — |
| | 66.5 |
| | — |
| | — |
| | 66.5 |
|
State and Local Government | | — |
| | 16.4 |
| | — |
| | — |
| | 16.4 |
|
Subtotal Fixed Income Securities | | — |
| | 975.6 |
| | — |
| | — |
| | 975.6 |
|
Equity Securities – Domestic (b) | | 1,220.0 |
| | — |
| | — |
| | — |
| | 1,220.0 |
|
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,238.7 |
| | 975.6 |
| | — |
| | 16.5 |
| | 2,230.8 |
|
| | | | | | | | | | |
Total Assets | | $ | 1,523.5 |
| | $ | 1,396.4 |
| | $ | 215.8 |
| | $ | 9.0 |
| | $ | 3,144.7 |
|
| | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | |
Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (d) | | $ | 10.0 |
| | $ | 394.2 |
| | $ | 98.7 |
| | $ | (232.6 | ) | | $ | 270.3 |
|
Cash Flow Hedges: | | |
| | |
| | |
| | |
| | |
|
Commodity Hedges (c) | | — |
| | 34.8 |
| | 18.7 |
| | (5.0 | ) | | 48.5 |
|
Interest Rate/Foreign Currency Hedges | | — |
| | 0.2 |
| | — |
| | — |
| | 0.2 |
|
Fair Value Hedges | | — |
| | — |
| | — |
| | 0.3 |
| | 0.3 |
|
Total Risk Management Liabilities | | $ | 10.0 |
| | $ | 429.2 |
| | $ | 117.4 |
| | $ | (237.3 | ) | | $ | 319.3 |
|
AEP
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2015
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Cash and Cash Equivalents (a) | | $ | 3.9 |
| | $ | 4.3 |
| | $ | — |
| | $ | 168.2 |
| | $ | 176.4 |
|
| | | | | | | | | | |
Other Temporary Investments | | | | | | | | | | |
Restricted Cash (a) | | 230.0 |
| | 7.7 |
| | — |
| | 33.3 |
| | 271.0 |
|
Fixed Income Securities – Mutual Funds | | 90.4 |
| | — |
| | — |
| | — |
| | 90.4 |
|
Equity Securities – Mutual Funds (b) | | 25.4 |
| | — |
| | — |
| | — |
| | 25.4 |
|
Total Other Temporary Investments | | 345.8 |
| | 7.7 |
| | — |
| | 33.3 |
| | 386.8 |
|
| | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (f) | | 11.5 |
| | 495.0 |
| | 219.7 |
| | (287.7 | ) | | 438.5 |
|
Cash Flow Hedges: | | |
| | |
| | |
| | |
| | |
|
Commodity Hedges (c) | | — |
| | 15.9 |
| | 1.0 |
| | 0.7 |
| | 17.6 |
|
Fair Value Hedges | | — |
| | — |
| | — |
| | 0.1 |
| | 0.1 |
|
Total Risk Management Assets | | 11.5 |
| | 510.9 |
| | 220.7 |
| | (286.9 | ) | | 456.2 |
|
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | |
| | |
| | |
| | |
| | |
|
Cash and Cash Equivalents (e) | | 160.5 |
| | — |
| | — |
| | 7.8 |
| | 168.3 |
|
Fixed Income Securities: | | |
| | |
| | |
| | |
| | |
|
United States Government | | — |
| | 731.1 |
| | — |
| | — |
| | 731.1 |
|
Corporate Debt | | — |
| | 57.9 |
| | — |
| | — |
| | 57.9 |
|
State and Local Government | | — |
| | 22.2 |
| | — |
| | — |
| | 22.2 |
|
Subtotal Fixed Income Securities | | — |
| | 811.2 |
| | — |
| | — |
| | 811.2 |
|
Equity Securities – Domestic (b) | | 1,126.9 |
| | — |
| | — |
| | — |
| | 1,126.9 |
|
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,287.4 |
| | 811.2 |
| | — |
| | 7.8 |
| | 2,106.4 |
|
| | | | | | | | | | |
Total Assets | | $ | 1,648.6 |
| | $ | 1,334.1 |
| | $ | 220.7 |
| | $ | (77.6 | ) | | $ | 3,125.8 |
|
| | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | |
Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (f) | | $ | 24.1 |
| | $ | 471.5 |
| | $ | 67.3 |
| | $ | (326.3 | ) | | $ | 236.6 |
|
Cash Flow Hedges: | | |
| | |
| | |
| | |
| | |
|
Commodity Hedges (c) | | — |
| | 18.9 |
| | 6.5 |
| | 0.7 |
| | 26.1 |
|
Interest Rate/Foreign Currency Hedges | | — |
| | 0.4 |
| | — |
| | — |
| | 0.4 |
|
Fair Value Hedges | | — |
| | 3.0 |
| | — |
| | 0.1 |
| | 3.1 |
|
Total Risk Management Liabilities | | $ | 24.1 |
| | $ | 493.8 |
| | $ | 73.8 |
| | $ | (325.5 | ) | | $ | 266.2 |
|
APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20152016
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in thousands) |
| | | | | | | | | | |
Restricted Cash for Securitized Funding (a) | | $ | 7,436 |
| | $ | — |
| | $ | — |
| | $ | 57 |
| | $ | 7,493 |
|
| | | | | | | | | | |
Risk Management Assets – Nonaffiliated and Affiliated | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | 185 |
| | 12,785 |
| | 23,743 |
| | (7,328 | ) | | 29,385 |
|
| | | | | | | | | | |
Total Assets: | | $ | 7,621 |
| | $ | 12,785 |
| | $ | 23,743 |
| | $ | (7,271 | ) | | $ | 36,878 |
|
| | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | |
Risk Management Liabilities – Nonaffiliated | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | $ | 198 |
| | $ | 16,031 |
| | $ | 662 |
| | $ | (9,016 | ) | | $ | 7,875 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Restricted Cash for Securitized Funding (a) | | $ | 7.8 |
| | $ | — |
| | $ | — |
| | $ | 0.1 |
| | $ | 7.9 |
|
| | | | | | | | | | |
Risk Management Assets - Nonaffiliated | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | — |
| | 8.3 |
| | 2.8 |
| | (7.7 | ) | | 3.4 |
|
| | | | | | | | | | |
Total Assets | | $ | 7.8 |
| | $ | 8.3 |
| | $ | 2.8 |
| | $ | (7.6 | ) | | $ | 11.3 |
|
| | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | |
Risk Management Liabilities - Nonaffiliated | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 8.8 |
| | $ | 9.9 |
| | $ | (7.7 | ) | | $ | 11.0 |
|
APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 20142015
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in thousands) |
| | | | | | | | | | |
Restricted Cash for Securitized Funding (a) | | $ | 15,599 |
| | $ | — |
| | $ | — |
| | $ | 33 |
| | $ | 15,632 |
|
| | | | | | | | | | |
Risk Management Assets – Nonaffiliated | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | 206 |
| | 20,197 |
| | 17,654 |
| | (9,374 | ) | | 28,683 |
|
| | | | | | | | | | |
Total Assets: | | $ | 15,805 |
| | $ | 20,197 |
| | $ | 17,654 |
| | $ | (9,341 | ) | | $ | 44,315 |
|
| | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | |
Risk Management Liabilities – Nonaffiliated | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | $ | 227 |
| | $ | 20,339 |
| | $ | 1,912 |
| | $ | (9,404 | ) | | $ | 13,074 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Restricted Cash for Securitized Funding (a) | | $ | 14.8 |
| | $ | — |
| | $ | — |
| | $ | 0.1 |
| | $ | 14.9 |
|
| | | | | | | | | | |
Risk Management Assets - Nonaffiliated and Affiliated | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | 0.2 |
| | 13.9 |
| | 12.2 |
| | (10.6 | ) | | 15.7 |
|
| | | | | | | | | | |
Total Assets | | $ | 15.0 |
| | $ | 13.9 |
| | $ | 12.2 |
| | $ | (10.5 | ) | | $ | 30.6 |
|
| | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | |
Risk Management Liabilities - Nonaffiliated | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | $ | 0.2 |
| | $ | 17.8 |
| | $ | 0.5 |
| | $ | (13.6 | ) | | $ | 4.9 |
|
I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20152016
| | | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in thousands) | | (in millions) |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets – Nonaffiliated and Affiliated | | |
| | |
| | |
| | |
| | |
| |
Risk Management Commodity Contracts (b) (c) | | $ | 126 |
| | $ | 10,347 |
| | $ | 7,795 |
| | $ | (6,303 | ) | | $ | 11,965 |
| |
Risk Management Assets - Nonaffiliated | | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | | $ | — |
| | $ | 6.6 |
| | $ | 4.7 |
| | $ | (5.9 | ) | | $ | 5.4 |
|
| | | | | | | | | | | | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Cash and Cash Equivalents (d)(e) | | 157,409 |
| | — |
| | — |
| | 6,944 |
| | 164,353 |
| | 18.7 |
| | — |
| | — |
| | 16.5 |
| | 35.2 |
|
Fixed Income Securities: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
United States Government | | — |
| | 704,344 |
| | — |
| | — |
| | 704,344 |
| | — |
| | 892.7 |
| | — |
| | — |
| | 892.7 |
|
Corporate Debt | | — |
| | 62,118 |
| | — |
| | — |
| | 62,118 |
| | — |
| | 66.5 |
| | — |
| | — |
| | 66.5 |
|
State and Local Government | | — |
| | 50,018 |
| | — |
| | — |
| | 50,018 |
| | — |
| | 16.4 |
| | — |
| | — |
| | 16.4 |
|
Subtotal Fixed Income Securities | | — |
| | 816,480 |
| | — |
| | — |
| | 816,480 |
| | — |
| | 975.6 |
| | — |
| | — |
| | 975.6 |
|
Equity Securities - Domestic (e)(b) | | 1,066,427 |
| | — |
| | — |
| | — |
| | 1,066,427 |
| | 1,220.0 |
| | — |
| | — |
| | — |
| | 1,220.0 |
|
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,223,836 |
| | 816,480 |
| | — |
| | 6,944 |
| | 2,047,260 |
| | 1,238.7 |
| | 975.6 |
| | — |
| | 16.5 |
| | 2,230.8 |
|
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 1,223,962 |
| | $ | 826,827 |
| | $ | 7,795 |
| | $ | 641 |
| | $ | 2,059,225 |
| | $ | 1,238.7 |
| | $ | 982.2 |
| | $ | 4.7 |
| | $ | 10.6 |
| | $ | 2,236.2 |
|
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities – Nonaffiliated | | |
| | |
| | |
| | |
| | |
| |
Risk Management Commodity Contracts (b) (c) | | $ | 135 |
| | $ | 10,945 |
| | $ | 1,419 |
| | $ | (6,636 | ) | | $ | 5,863 |
| |
Risk Management Liabilities - Nonaffiliated | | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | | $ | — |
| | $ | 7.5 |
| | $ | 0.2 |
| | $ | (6.2 | ) | | $ | 1.5 |
|
I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 20142015
| | | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in thousands) | | (in millions) |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets – Nonaffiliated | | |
| | |
| | |
| | |
| | |
| |
Risk Management Commodity Contracts (b) (c) | | $ | 140 |
| | $ | 15,893 |
| | $ | 16,008 |
| | $ | (6,396 | ) | | $ | 25,645 |
| |
Risk Management Assets - Nonaffiliated and Affiliated | | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | | $ | 0.1 |
| | $ | 17.0 |
| | $ | 6.3 |
| | $ | (11.1 | ) | | $ | 12.3 |
|
| | | | | | | | | | | | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Cash and Cash Equivalents (d)(e) | | 9,418 |
| | — |
| | — |
| | 10,548 |
| | 19,966 |
| | 160.5 |
| | — |
| | — |
| | 7.8 |
| | 168.3 |
|
Fixed Income Securities: | | |
| | |
| | |
| | |
| |
|
| | |
| | |
| | |
| | |
| |
|
|
United States Government | | — |
| | 697,042 |
| | — |
| | — |
| | 697,042 |
| | — |
| | 731.1 |
| | — |
| | — |
| | 731.1 |
|
Corporate Debt | | — |
| | 47,792 |
| | — |
| | — |
| | 47,792 |
| | — |
| | 57.9 |
| | — |
| | — |
| | 57.9 |
|
State and Local Government | | — |
| | 208,553 |
| | — |
| | — |
| | 208,553 |
| | — |
| | 22.2 |
| | — |
| | — |
| | 22.2 |
|
Subtotal Fixed Income Securities | | — |
| | 953,387 |
| | — |
| | — |
| | 953,387 |
| | — |
| | 811.2 |
| | — |
| | — |
| | 811.2 |
|
Equity Securities - Domestic (e)(b) | | 1,122,379 |
| | — |
| | — |
| | — |
| | 1,122,379 |
| | 1,126.9 |
| | — |
| | — |
| | — |
| | 1,126.9 |
|
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,131,797 |
| | 953,387 |
| | — |
| | 10,548 |
| | 2,095,732 |
| | 1,287.4 |
| | 811.2 |
| | — |
| | 7.8 |
| | 2,106.4 |
|
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 1,131,937 |
| | $ | 969,280 |
| | $ | 16,008 |
| | $ | 4,152 |
| | $ | 2,121,377 |
| | $ | 1,287.5 |
| | $ | 828.2 |
| | $ | 6.3 |
| | $ | (3.3 | ) | | $ | 2,118.7 |
|
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities – Nonaffiliated | | |
| | |
| | |
| | |
| | |
| |
Risk Management Commodity Contracts (b) (c) | | $ | 154 |
| | $ | 11,440 |
| | $ | 1,304 |
| | $ | (6,280 | ) | | $ | 6,618 |
| |
Risk Management Liabilities - Nonaffiliated | | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | | $ | 0.1 |
| | $ | 17.5 |
| | $ | 2.0 |
| | $ | (11.7 | ) | | $ | 7.9 |
|
OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20152016
| | | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in thousands) | | (in millions) |
| | | | | | | | | | | | | | | | | | | | |
Restricted Cash for Securitized Funding (a) | | $ | 16,195 |
| | $ | — |
| | $ | — |
| | $ | 9 |
| | $ | 16,204 |
| | $ | 16.1 |
| | $ | — |
| | $ | — |
| | $ | 0.1 |
| | $ | 16.2 |
|
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | — |
| | — |
| | 20,719 |
| | 2,546 |
| | 23,265 |
| |
Risk Management Commodity Contracts (c) (g) | | | — |
| | 0.1 |
| | — |
| | (0.1 | ) | | — |
|
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 16,195 |
| | $ | — |
| | $ | 20,719 |
| | $ | 2,555 |
| | $ | 39,469 |
| | $ | 16.1 |
| | $ | 0.1 |
| | $ | — |
| | $ | — |
| | $ | 16.2 |
|
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (b) (c) | | $ | — |
| | $ | 639 |
| | $ | 5,009 |
| | $ | 2,046 |
| | $ | 7,694 |
| |
Risk Management Commodity Contracts (c) (g) | | | $ | — |
| | $ | 0.1 |
| | $ | 109.1 |
| | $ | (0.1 | ) | | $ | 109.1 |
|
OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 20142015
| | | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in thousands) | | (in millions) |
| | | | | | | | | | | | | | | | | | | | |
Restricted Cash for Securitized Funding (a) | | $ | 408 |
| | $ | — |
| | $ | — |
| | $ | 28,288 |
| | $ | 28,696 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 27.7 |
| | $ | 27.7 |
|
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | — |
| | — |
| | 52,343 |
| | 1 |
| | 52,344 |
| |
Risk Management Commodity Contracts (c) (g) | | | — |
| | — |
| | 16.0 |
| | 3.2 |
| | 19.2 |
|
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 408 |
| | $ | — |
| | $ | 52,343 |
| | $ | 28,289 |
| | $ | 81,040 |
| | $ | — |
| | $ | — |
| | $ | 16.0 |
| | $ | 30.9 |
| | $ | 46.9 |
|
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | $ | — |
| | $ | 1,116 |
| | $ | 3,941 |
| | $ | (101 | ) | | $ | 4,956 |
| |
Risk Management Commodity Contracts (c) (g) | | | $ | — |
| | $ | 0.8 |
| | $ | 0.1 |
| | $ | 2.7 |
| | $ | 3.6 |
|
PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20152016
| | | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in thousands) | | (in millions) |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | $ | — |
| | $ | — |
| | $ | 1,166 |
| | $ | (131 | ) | | $ | 1,035 |
| |
Risk Management Commodity Contracts (c) (g) | | | $ | — |
| | $ | 0.1 |
| | $ | 1.2 |
| | $ | (0.2 | ) | | $ | 1.1 |
|
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | $ | — |
| | $ | 358 |
| | $ | 131 |
| | $ | (411 | ) | | $ | 78 |
| |
Risk Management Commodity Contracts (c) (g) | | | $ | — |
| | $ | 0.1 |
| | $ | 0.1 |
| | $ | (0.2 | ) | | $ | — |
|
PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 20142015
| | | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in thousands) | | (in millions) |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | $ | — |
| | $ | — |
| | $ | 360 |
| | $ | (360 | ) | | $ | — |
| |
Risk Management Commodity Contracts (c) (g) | | | $ | — |
| | $ | — |
| | $ | 0.7 |
| | $ | (0.1 | ) | | $ | 0.6 |
|
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | $ | — |
| | $ | 595 |
| | $ | 737 |
| | $ | (414 | ) | | $ | 918 |
| |
Risk Management Commodity Contracts (c) (g) | | | $ | — |
| | $ | 0.5 |
| | $ | 0.1 |
| | $ | (0.4 | ) | | $ | 0.2 |
|
SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20152016
| | | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in thousands) | | (in millions) |
| | | | | | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (a) | | $ | 11,688 |
| | $ | — |
| | $ | — |
| | $ | 2,570 |
| | $ | 14,258 |
| | $ | 12.8 |
| | $ | — |
| | $ | — |
| | $ | 2.4 |
| | $ | 15.2 |
|
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | — |
| | — |
| | 1,442 |
| | (162 | ) | | 1,280 |
| |
Risk Management Commodity Contracts (c) (g) | | | — |
| | 0.1 |
| | 1.4 |
| | (0.1 | ) | | 1.4 |
|
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 11,688 |
| | $ | — |
| | $ | 1,442 |
| | $ | 2,408 |
| | $ | 15,538 |
| | $ | 12.8 |
| | $ | 0.1 |
| | $ | 1.4 |
| | $ | 2.3 |
| | $ | 16.6 |
|
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | $ | — |
| | $ | 2,378 |
| | $ | 162 |
| | $ | (481 | ) | | $ | 2,059 |
| |
Risk Management Commodity Contracts (c) (g) | | | $ | — |
| | $ | — |
| | $ | 0.1 |
| | $ | (0.1 | ) | | $ | — |
|
SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 20142015
| | | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in thousands) | | (in millions) |
| | | | | | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (a) | | $ | 12,660 |
| | $ | — |
| | $ | — |
| | $ | 1,696 |
| | $ | 14,356 |
| | $ | 3.6 |
| | $ | — |
| | $ | — |
| | $ | 1.6 |
| | $ | 5.2 |
|
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | — |
| | 31 |
| | 439 |
| | (439 | ) | | 31 |
| |
Risk Management Commodity Contracts (c) (g) | | | — |
| | — |
| | 0.9 |
| | (0.1 | ) | | 0.8 |
|
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 12,660 |
| | $ | 31 |
| | $ | 439 |
| | $ | 1,257 |
| | $ | 14,387 |
| | $ | 3.6 |
| | $ | — |
| | $ | 0.9 |
| | $ | 1.5 |
| | $ | 6.0 |
|
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (b) (c) | | $ | — |
| | $ | 684 |
| | $ | 899 |
| | $ | (501 | ) | | $ | 1,082 |
| |
Risk Management Commodity Contracts (c) (g) | | | $ | — |
| | $ | 5.5 |
| | $ | 0.1 |
| | $ | (0.4 | ) | | $ | 5.2 |
|
| |
(a) | Amounts in "Other"“Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investmentinvestments in money market funds. |
| |
(b) | Amounts represent publicly traded equity securities and equity-based mutual funds. |
| |
(c) | Amounts in “Other”“Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” |
| |
(c) | Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.’’ |
| |
(d) | The September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 million in periods 2022-2032. Risk management commodity contracts are substantially comprised of power contracts. |
| |
(e) | Amounts in “Other”“Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. |
| |
(e)(f) | Amounts represent publicly traded equity securitiesThe December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and equity-based mutual funds.$(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. Risk management commodity contracts are substantially comprised of power contracts. |
| |
(g) | Substantially comprised of power contracts for the Registrant Subsidiaries. |
There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 20152016 and 2014.2015.
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy for the Registrant Subsidiaries:hierarchy:
| | Three Months Ended September 30, 2015 | | APCo (a) | | I&M (a) | | OPCo | | PSO | | SWEPCo | |
Three Months Ended September 30, 2016 | | | AEP | | APCo (a) | | I&M (a) | | OPCo | | PSO | | SWEPCo |
| | (in thousands) | | (in millions) |
Balance as of June 30, 2015 | | $ | 33,836 |
| | $ | 11,844 |
| | $ | 37,657 |
| | $ | 1,699 |
| | $ | 2,039 |
| |
Balance as of June 30, 2016 | | | $ | 149.3 |
| | $ | (12.9 | ) | | $ | 3.5 |
| | $ | (14.6 | ) | | $ | 1.1 |
| | $ | 1.4 |
|
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) | | 5,065 |
| | 885 |
| | (28 | ) | | (280 | ) | | 2,366 |
| | 34.2 |
| | 22.7 |
| | 3.8 |
| | (0.1 | ) | | 0.4 |
| | 4.0 |
|
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) | | | 12.3 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | (34.4 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Purchases, Issuances and Settlements (d) | | (13,965 | ) | | (3,604 | ) | | 348 |
| | (176 | ) | | (2,912 | ) | | (37.1 | ) | | (17.9 | ) | | (5.0 | ) | | 0.9 |
| | (0.7 | ) | | (4.4 | ) |
Transfers into Level 3 (e) (f) | | | 13.1 |
| | 0.1 |
| | — |
| | — |
| | — |
| | — |
|
Transfers out of Level 3 (f) (g) | | | (10.0 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Changes in Fair Value Allocated to Regulated Jurisdictions (h) | | (1,855 | ) | | (2,749 | ) | | (22,267 | ) | | (208 | ) | | (213 | ) | | (29.0 | ) | | 0.9 |
| | 2.2 |
| | (95.3 | ) | | 0.3 |
| | 0.3 |
|
Balance as of September 30, 2015 | | $ | 23,081 |
| | $ | 6,376 |
| | $ | 15,710 |
| | $ | 1,035 |
| | $ | 1,280 |
| |
Balance as of September 30, 2016 | | | $ | 98.4 |
| | $ | (7.1 | ) | | $ | 4.5 |
| | $ | (109.1 | ) | | $ | 1.1 |
| | $ | 1.3 |
|
| | Three Months Ended September 30, 2014 | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | |
Three Months Ended September 30, 2015 | | | AEP | | APCo (a) | | I&M (a) | | OPCo | | PSO | | SWEPCo |
| | (in thousands) | | (in millions) |
Balance as of June 30, 2014 | | $ | 18,394 |
| | $ | 12,923 |
| | $ | 9,300 |
| | $ | (3 | ) | | $ | (3 | ) | |
Balance as of June 30, 2015 | | | $ | 203.1 |
| | $ | 33.8 |
| | $ | 11.8 |
| | $ | 37.7 |
| | $ | 1.7 |
| | $ | 2.0 |
|
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) | | (5,629 | ) | | (3,832 | ) | | (3,639 | ) | | 2 |
| | 2 |
| | 11.1 |
| | 5.1 |
| | 0.9 |
| | — |
| | (0.3 | ) | | 2.4 |
|
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) | | | 6.2 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | (2.1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Purchases, Issuances and Settlements (d) | | (1,560 | ) | | (1,244 | ) | | (637 | ) | | — |
| | — |
| | (28.9 | ) | | (14.0 | ) | | (3.6 | ) | | 0.3 |
| | (0.2 | ) | | (2.9 | ) |
Transfers into Level 3 (e) (f) | | (6 | ) | | (4 | ) | | — |
| | — |
| | — |
| | 7.8 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Transfers out of Level 3 (f) (g) | | (30 | ) | | (20 | ) | | — |
| | — |
| | — |
| | (5.4 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Changes in Fair Value Allocated to Regulated Jurisdictions (h) | | 4,843 |
| | 4,319 |
| | 2,865 |
| | 335 |
| | 409 |
| | (25.0 | ) | | (1.8 | ) | | (2.7 | ) | | (22.3 | ) | | (0.2 | ) | | (0.2 | ) |
Balance as of September 30, 2014 | | $ | 16,012 |
| | $ | 12,142 |
| | $ | 7,889 |
| | $ | 334 |
| | $ | 408 |
| |
Balance as of September 30, 2015 | | | $ | 166.8 |
| | $ | 23.1 |
| | $ | 6.4 |
| | $ | 15.7 |
| | $ | 1.0 |
| | $ | 1.3 |
|
| | Nine Months Ended September 30, 2015 | | APCo (a) | �� | I&M (a) | | OPCo | | PSO | | SWEPCo | |
Nine Months Ended September 30, 2016 | | | AEP | | APCo (a) | | I&M (a) | | OPCo | | PSO | | SWEPCo |
| | (in thousands) | | (in millions) |
Balance as of December 31, 2014 | | $ | 15,742 |
| | $ | 14,704 |
| | $ | 48,402 |
| | $ | (377 | ) | | $ | (460 | ) | |
Balance as of December 31, 2015 | | | $ | 146.9 |
| | $ | 11.7 |
| | $ | 4.3 |
| | $ | 15.9 |
| | $ | 0.6 |
| | $ | 0.8 |
|
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) | | 1,757 |
| | (193 | ) | | 1,182 |
| | (176 | ) | | 9,187 |
| | 42.1 |
| | 25.5 |
| | 7.0 |
| | (1.8 | ) | | (1.0 | ) | | 7.7 |
|
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) | | | 45.5 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | (16.7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Purchases, Issuances and Settlements (d) | | (16,124 | ) | | (12,807 | ) | | (7,906 | ) | | 553 |
| | (8,727 | ) | | (67.1 | ) | | (36.2 | ) | | (10.3 | ) | | 4.0 |
| | 0.4 |
| | (8.4 | ) |
Transfers into Level 3 (e) (f) | | | 11.2 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Transfers out of Level 3 (f) (g) | | 1,167 |
| | 792 |
| | — |
| | — |
| | — |
| | 1.1 |
| | 0.1 |
| | 0.1 |
| | — |
| | — |
| | — |
|
Changes in Fair Value Allocated to Regulated Jurisdictions (h) | | 20,539 |
| | 3,880 |
| | (25,968 | ) | | 1,035 |
| | 1,280 |
| | (64.6 | ) | | (8.2 | ) | | 3.4 |
| | (127.2 | ) | | 1.1 |
| | 1.2 |
|
Balance as of September 30, 2015 | | $ | 23,081 |
| | $ | 6,376 |
| | $ | 15,710 |
| | $ | 1,035 |
| | $ | 1,280 |
| |
Balance as of September 30, 2016 | | | $ | 98.4 |
| | $ | (7.1 | ) | | $ | 4.5 |
| | $ | (109.1 | ) | | $ | 1.1 |
| | $ | 1.3 |
|
| | Nine Months Ended September 30, 2014 | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | |
Nine Months Ended September 30, 2015 | | | AEP | | APCo (a) | | I&M (a) | | OPCo | | PSO | | SWEPCo |
| | (in thousands) | | (in millions) |
Balance as of December 31, 2013 | | $ | 10,562 |
| | $ | 7,164 |
| | $ | 2,920 |
| | $ | — |
| | $ | — |
| |
Balance as of December 31, 2014 | | | $ | 150.8 |
| | $ | 15.8 |
| | $ | 14.7 |
| | $ | 48.4 |
| | $ | (0.3 | ) | | $ | (0.5 | ) |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) | | 29,467 |
| | 18,438 |
| | 30,768 |
| | — |
| | — |
| | 13.6 |
| | 1.7 |
| | (0.2 | ) | | 1.2 |
| | (0.2 | ) | | 9.2 |
|
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) | | | 54.3 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | (3.8 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Purchases, Issuances and Settlements (d) | | (32,213 | ) | | (20,301 | ) | | (33,688 | ) | | — |
| | — |
| | (60.2 | ) | | (16.1 | ) | | (12.8 | ) | | (7.9 | ) | | 0.5 |
| | (8.7 | ) |
Transfers into Level 3 (e) (f) | | (3,648 | ) | | (2,475 | ) | | — |
| | — |
| | — |
| | 28.3 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Transfers out of Level 3 (f) (g) | | (32 | ) | | (22 | ) | | — |
| | — |
| | — |
| | (17.1 | ) | | 1.2 |
| | 0.8 |
| | — |
| | — |
| | — |
|
Changes in Fair Value Allocated to Regulated Jurisdictions (h) | | 11,876 |
| | 9,338 |
| | 7,889 |
| | 334 |
| | 408 |
| | 0.9 |
| | 20.5 |
| | 3.9 |
| | (26.0 | ) | | 1.0 |
| | 1.3 |
|
Balance as of September 30, 2014 | | $ | 16,012 |
| | $ | 12,142 |
| | $ | 7,889 |
| | $ | 334 |
| | $ | 408 |
| |
Balance as of September 30, 2015 | | | $ | 166.8 |
| | $ | 23.1 |
| | $ | 6.4 |
| | $ | 15.7 |
| | $ | 1.0 |
| | $ | 1.3 |
|
| |
(a) | Includes both affiliated and nonaffiliated transactions. |
| |
(b) | Included in revenues on the condensed statements of income. |
| |
(c) | Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. |
| |
(d) | Represents the settlementpurchases, issuances and settlements of risk management commodity contracts for the reporting period. |
| |
(e) | Represents existing assets or liabilities that were previously categorized as Level 2. |
| |
(f) | Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. |
| |
(g) | Represents existing assets or liabilities that were previously categorized as Level 3. |
| |
(h) | Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. |
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions for the Registrant Subsidiaries as of September 30, 20152016 and December 31, 2014:2015:
Significant Unobservable Inputs
September 30, 2016
AEP
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 207.5 |
| | $ | 103.7 |
| | Discounted Cash Flow | | Forward Market Price (a) | | $ | 10.19 |
| | $ | 143.84 |
| | $ | 43.20 |
|
| | | | | | | Counterparty Credit Risk (b) | | 40 |
| | 840 |
| | 424 |
|
FTRs | 8.3 |
| | 13.7 |
| | Discounted Cash Flow | | Forward Market Price (a) | | $ | (9.89 | ) | | $ | 10.63 |
| | $ | 0.73 |
|
Total | $ | 215.8 |
| | $ | 117.4 |
| | | | | | |
| | |
| | |
Significant Unobservable Inputs
December 31, 2015
AEP
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 212.3 |
| | $ | 70.3 |
| | Discounted Cash Flow | | Forward Market Price (a) | | $ | 9.69 |
| | $ | 165.36 |
| | $ | 36.35 |
|
| | | | | | | Counterparty Credit Risk (c) | | 670 |
FTRs | 8.4 |
| | 3.5 |
| | Discounted Cash Flow | | Forward Market Price (a) | | $ | (6.99 | ) | | $ | 10.34 |
| | $ | 1.10 |
|
Total | $ | 220.7 |
| | $ | 73.8 |
| | | | | | |
| | |
| | |
Significant Unobservable Inputs
September 30, 20152016
APCo
| | | | | Significant | | Forward Price Range | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted | Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average | Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in thousands) | | | | | | | | | | | (in millions) | | | | | | | | | | |
Energy Contracts | $ | 8,724 |
| | $ | 451 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 13.03 |
| | $ | 48.17 |
| | $ | 34.76 |
| $ | 2.1 |
| | $ | 0.2 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 16.51 |
| | $ | 47.42 |
| | $ | 34.85 |
|
FTRs | 15,019 |
| | 211 |
| | Discounted Cash Flow | | Forward Market Price | | (5.95 | ) | | 11.60 |
| | 1.53 |
| 0.7 |
| | 9.7 |
| | Discounted Cash Flow | | Forward Market Price | | (0.99 | ) | | 10.63 |
| | 1.94 |
|
Total | $ | 23,743 |
| | $ | 662 |
| | | | | | |
| | |
| | | $ | 2.8 |
| | $ | 9.9 |
| | | | | | |
| | |
| | |
Significant Unobservable Inputs
December 31, 20142015
APCo
| | | | | Significant | | Forward Price Range | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted | Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average | Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in thousands) | | | | | | | | | | | (in millions) | | | | | | | | | | |
Energy Contracts | $ | 5,801 |
| | $ | 1,799 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 13.43 |
| | $ | 123.02 |
| | $ | 52.47 |
| $ | 7.9 |
| | $ | 0.2 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 12.61 |
| | $ | 47.24 |
| | $ | 32.38 |
|
FTRs | 11,853 |
| | 113 |
| | Discounted Cash Flow | | Forward Market Price | | (14.63 | ) | | 20.02 |
| | 1.01 |
| 4.3 |
| | 0.3 |
| | Discounted Cash Flow | | Forward Market Price | | (6.96 | ) | | 8.43 |
| | 1.34 |
|
Total | $ | 17,654 |
| | $ | 1,912 |
| | | | | | |
| | |
| | | $ | 12.2 |
| | $ | 0.5 |
| | | | | | |
| | |
| | |
Significant Unobservable Inputs
September 30, 2015
I&M
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Forward Price Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in thousands) | | | | | | | | | | |
Energy Contracts | $ | 7,147 |
| | $ | 295 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 13.03 |
| | $ | 48.17 |
| | $ | 34.76 |
|
FTRs | 648 |
| | 1,124 |
| | Discounted Cash Flow | | Forward Market Price | | (5.95 | ) | | 11.60 |
| | 1.53 |
|
Total | $ | 7,795 |
| | $ | 1,419 |
| | | | | | |
| | |
| | |
Significant Unobservable Inputs
December 31, 2014
I&M
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Forward Price Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in thousands) | | | | | | | | | | |
Energy Contracts | $ | 6,375 |
| | $ | 1,219 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 13.43 |
| | $ | 123.02 |
| | $ | 52.47 |
|
FTRs | 9,633 |
| | 85 |
| | Discounted Cash Flow | | Forward Market Price | | (14.63 | ) | | 20.02 |
| | 1.01 |
|
Total | $ | 16,008 |
| | $ | 1,304 |
| | | | | | |
| | |
| | |
Significant Unobservable Inputs
September 30, 20152016
OPCoI&M
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Forward Price Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in thousands) | | | | | | | | | | |
Energy Contracts | $ | 20,719 |
| | $ | 5,009 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 35.71 |
| | $ | 165.93 |
| | $ | 85.99 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 1.6 |
| | $ | 0.2 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 16.51 |
| | $ | 47.42 |
| | $ | 34.85 |
|
FTRs | 3.1 |
| | — |
| | Discounted Cash Flow | | Forward Market Price | | (9.89 | ) | | 10.63 |
| | 1.10 |
|
Total | $ | 4.7 |
| | $ | 0.2 |
| | | | | | |
| | |
| | |
Significant Unobservable Inputs
December 31, 20142015
OPCoI&M
| | | | | | | Significant | | Forward Price Range | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted | Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average | Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in thousands) | | | | | | | | | | | (in millions) | | | | | | | | | | |
Energy Contracts | $ | 45,101 |
| | $ | 3,941 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 48.25 |
| | $ | 159.92 |
| | $ | 84.04 |
| $ | 6.0 |
| | $ | 0.2 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 12.61 |
| | $ | 47.24 |
| | $ | 32.38 |
|
FTRs | 7,242 |
| | — |
| | Discounted Cash Flow | | Forward Market Price | | (14.63 | ) | | 20.02 |
| | 1.01 |
| 0.3 |
| | 1.8 |
| | Discounted Cash Flow | | Forward Market Price | | (6.96 | ) | | 8.43 |
| | 1.34 |
|
Total | $ | 52,343 |
| | $ | 3,941 |
| | | | | | | $ | 6.3 |
| | $ | 2.0 |
| | | | | | |
| | |
| | |
Significant Unobservable Inputs
September 30, 20152016
PSOOPCo
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Forward Price Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in thousands) | | | | | | | | | | |
FTRs | $ | 1,166 |
| | $ | 131 |
| | Discounted Cash Flow | | Forward Market Price | | $ | (5.95 | ) | | $ | 11.60 |
| | $ | 1.53 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | — |
| | $ | 109.1 |
| | Discounted Cash Flow | | Forward Market Price (a) | | $ | 24.38 |
| | $ | 78.45 |
| | $ | 52.45 |
|
| | | | | | | Counterparty Credit Risk (b) | | 40 |
| | 323 |
| | 246 |
|
Total | $ | — |
| | $ | 109.1 |
| | | | | | | | | | |
Significant Unobservable Inputs
December 31, 20142015
PSOOPCo
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Forward Price Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in thousands) | | | | | | | | | | |
FTRs | $ | 360 |
| | $ | 737 |
| | Discounted Cash Flow | | Forward Market Price | | $ | (14.63 | ) | | $ | 20.02 |
| | $ | 1.01 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 16.0 |
| | $ | 0.1 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 41.61 |
| | $ | 165.36 |
| | $ | 86.84 |
|
Significant Unobservable Inputs
September 30, 20152016
SWEPCoPSO
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Forward Price Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in thousands) | | | | | | | | | | |
FTRs | $ | 1,442 |
| | $ | 162 |
| | Discounted Cash Flow | | Forward Market Price | | $ | (5.95 | ) | | $ | 11.60 |
| | $ | 1.53 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
FTRs | $ | 1.2 |
| | $ | 0.1 |
| | Discounted Cash Flow | | Forward Market Price | | $ | (8.33 | ) | | $ | 1.02 |
| | $ | (0.39 | ) |
Significant Unobservable Inputs
December 31, 20142015
PSO
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
FTRs | $ | 0.7 |
| | $ | 0.1 |
| | Discounted Cash Flow | | Forward Market Price | | $ | (6.96 | ) | | $ | 8.43 |
| | $ | 1.34 |
|
Significant Unobservable Inputs
September 30, 2016
SWEPCo
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Forward Price Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in thousands) | | | | | | | | | | |
FTRs | $ | 439 |
| | $ | 899 |
| | Discounted Cash Flow | | Forward Market Price | | $ | (14.63 | ) | | $ | 20.02 |
| | $ | 1.01 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
FTRs | $ | 1.4 |
| | $ | 0.1 |
| | Discounted Cash Flow | | Forward Market Price | | $ | (8.33 | ) | | $ | 1.02 |
| | $ | (0.39 | ) |
Significant Unobservable Inputs
December 31, 2015
SWEPCo
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| (in millions) | | | | | | | | | | |
FTRs | $ | 0.9 |
| | $ | 0.1 |
| | Discounted Cash Flow | | Forward Market Price | | $ | (6.96 | ) | | $ | 8.43 |
| | $ | 1.34 |
|
| |
(a) | Represents market prices in dollars per MWh. |
| |
(b) | Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. |
| |
(c) | Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. |
The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrant SubsidiariesRegistrants as of September 30, 2016 and December 31, 2015:
Sensitivity of Fair Value Measurements
September 30, 2015
|
| | | | | | |
Significant Unobservable Input | | Position | | Change in Input | | Impact on Fair Value Measurement |
Forward Market Price | | Buy | | Increase (Decrease) | | Higher (Lower) |
Forward Market Price | | Sell | | Increase (Decrease) | | Lower (Higher) |
Counterparty Credit Risk | | Loss | | Increase (Decrease) | | Higher (Lower) |
Counterparty Credit Risk | | Gain | | Increase (Decrease) | | Lower (Higher) |
10.11. INCOME TAXES
The disclosures in this note apply to all Registrants unless indicated otherwise.
AEP System Tax Allocation Agreement
The Registrant SubsidiariesAEP and subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System.return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Valuation Allowance (Applies to AEP)
AEP assesses available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by capital loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions.
On the basis of this evaluation, AEP recorded a change in the valuation allowance in the third quarter of 2016. AEP reduced the capital loss valuation allowance by $66 million to reflect the impact of the reclassification of certain assets as held for sale and the filing of the 2015 federal income tax return. The sale of these assets is expected to result in a gain, the character of which allows AEP to use the capital loss and reverse substantially all of the remaining capital loss valuation allowance previously recorded.
A valuation allowance of $9 million has been recorded against AEP’s deferred tax asset balance as of September 30, 2016. The valuation allowance reflects management’s assessment of the amount of deferred tax assets that are more likely than not to be realized. The amount of the deferred tax assets realizable, however, could be adjusted if estimates of future taxable income are materially impacted during the carryforward period.
Federal and State Income Tax Audit Status
The Registrant SubsidiariesAEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. AEP was informed that the IRS expects the Joint Committee to refer the audit back to the IRS exam team for further consideration. Although the outcome of tax audits isare uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant SubsidiariesRegistrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact the Registrant Subsidiaries' net income.
The Registrant SubsidiariesAEP and subsidiaries file income tax returns in various state, and local or foreign jurisdictions. These taxing authorities routinely examine the tax returnsreturns. AEP and the Registrant Subsidiariessubsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact the Registrant Subsidiaries' net income. The Registrant SubsidiariesRegistrants are no longer subject to state, local or localnon-U.S. income tax examinations by tax authorities for years before 2009.
State Tax Legislation (Applies to AEP, PSO and SWEPCo)
House Bill 32 was passed by the state of Texas in June 2015 permanently reducingIn March 2016, the Texas income/Comptroller of Public Accounts issued clarifying guidance regarding the treatment of transmission and distribution expenses included in the computation of taxable income for purposes of calculating the Texas gross margin tax. The guidance clarified which specific transmission and distribution expenses are included in the computation of the cost of goods sold deduction. This guidance resulted in a net favorable adjustment to net income of $21 million, $2 million and $9 million during the first nine months of 2016 for AEP, PSO and SWEPCo, respectively.
In March 2016, Louisiana enacted several tax bills impacting income taxes, franchise taxes and sales taxes. The income tax provisions limit the use of Louisiana net operating losses and the sales tax provisions increase the sales tax rate from 0.95%and suspend or eliminate certain exemptions. The legislation is not expected to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrant Subsidiaries' net income or cash flows or financial condition.flows.
11.12. FINANCING ACTIVITIES
The disclosures in this note apply to all Registrants unless indicated otherwise.
Long-term Debt Outstanding (Applies to AEP)
The following table details long-term debt outstanding as of September 30, 2016 and December 31, 2015:
|
| | | | | | | | | |
Type of Debt | | September 30, 2016 | | | December 31, 2015 |
| | (in millions) |
Senior Unsecured Notes | | $ | 14,073.9 |
| (a) | | $ | 13,629.1 |
|
Pollution Control Bonds | | 1,724.5 |
| | | 1,784.8 |
|
Notes Payable | | 268.5 |
| | | 264.7 |
|
Securitization Bonds | | 1,737.6 |
| | | 2,024.0 |
|
Spent Nuclear Fuel Obligation (b) | | 266.1 |
| | | 265.6 |
|
Other Long-term Debt | | 1,768.9 |
| | | 1,604.5 |
|
Total Long-term Debt Outstanding | | 19,839.5 |
| (a) | | 19,572.7 |
|
Long-term Debt Due Within One Year | | 2,519.6 |
| (a) | | 1,831.8 |
|
Long-term Debt | | $ | 17,319.9 |
| | | $ | 17,740.9 |
|
| |
(a) | Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. |
| |
(b) | Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of September 30, 2016 and December 31, 2015, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. |
Long-term Debt Activity
Long-term debt and other securities issued, retired and principal payments made during the first nine months of 20152016 are shown in the tables below:
| | Company | | Type of Debt | | Principal Amount (a) | | Interest Rate | | Due Date | | Type of Debt | | Principal Amount (a) | | Interest Rate | | Due Date |
Issuances: | | | | (in thousands) | | (%) | | | | | (in millions) | | (%) | |
APCo | | Pollution Control Bonds | | $ | 86,000 |
| | 1.90 | | 2019 | | Other Long-term Debt | | $ | 125.0 |
| | Variable | | 2019 |
APCo | | Senior Unsecured Notes | | 350,000 |
| | 4.45 | | 2045 | | Pollution Control Bonds | | 125.3 |
| | Variable | | 2016 |
APCo | | Senior Unsecured Notes | | 300,000 |
| | 3.40 | | 2025 | | Pollution Control Bonds | | 65.4 |
| | 1.70 | | 2020 |
I&M | | Notes Payable | | 111,300 |
| | Variable | | 2019 | | Notes Payable | | 87.9 |
| | Variable | | 2020 |
I&M | | Other Long-term Debt | | 100,000 |
| | Variable | | 2018 | | Senior Unsecured Notes | | 400.0 |
| | 4.55 | | 2046 |
PSO | | Senior Unsecured Notes | | 125,000 |
| | 3.17 | | 2025 | | Senior Unsecured Notes | | 50.0 |
| | 3.05 | | 2026 |
PSO | | Senior Unsecured Notes | | 125,000 |
| | 4.09 | | 2045 | | Senior Unsecured Notes | | 100.0 |
| | 4.11 | | 2046 |
SWEPCo | | Pollution Control Bonds | | 53,500 |
| | 1.60 | | 2019 | | Other Long-term Debt | | 5.2 |
| | 3.50 | | 2023 |
SWEPCo | | Senior Unsecured Notes | | 400,000 |
| | 3.90 | | 2045 | | Senior Unsecured Notes | | 400.0 |
| | 2.75 | | 2026 |
| | |
|
| |
| |
|
Non-Registrant: | | |
|
| |
| |
|
TCC | | | Other Long-term Debt | | 125.0 |
| | Variable | | 2019 |
TNC | | | Other Long-term Debt | | 75.0 |
| | Variable | | 2019 |
Transource Missouri | | | Other Long-term Debt | | 11.5 |
| | Variable | | 2018 |
Total Issuances | | | $ | 1,570.3 |
| |
| |
|
| |
(a) | Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. |
| | Company | | Type of Debt | | Principal Amount Paid | | Interest Rate | | Due Date | | Type of Debt | | Principal Amount Paid | | Interest Rate | | Due Date |
Retirements and Principal Payments: | | (in thousands) | | (%) | | | (in millions) | | (%) | |
APCo | | Land Note | | $ | 28 |
| | 13.718 | | 2026 | | Pollution Control Bonds | | $ | 125.3 |
| | Variable | | 2016 |
APCo | | Notes Payable - Affiliated | | 86,000 |
| | 3.125 | | 2015 | | Pollution Control Bonds | | 65.3 |
| | 2.25 | | 2016 |
APCo | | Securitization Bonds | | 22,524 |
| | 2.008 | | 2024 | | Securitization Bonds | | 23.0 |
| | 2.008 | | 2024 |
APCo | | Senior Unsecured Notes | | 350,000 |
| | 7.95 | | 2020 | |
APCo | | Senior Unsecured Notes | | 300,000 |
| | 3.40 | | 2015 | |
I&M | | Notes Payable | | 18,600 |
| | Variable | | 2016 | |
I&M | | Notes Payable | | 20,601 |
| | Variable | | 2017 | | Notes Payable | | 0.8 |
| | Variable | | 2016 |
I&M | | Notes Payable | | 26,512 |
| | Variable | | 2019 | | Notes Payable | | 0.5 |
| | 2.12 | | 2016 |
I&M | | Notes Payable | | 16,265 |
| | Variable | | 2019 | | Notes Payable | | 12.6 |
| | Variable | | 2017 |
I&M | | Notes Payable | | 1,273 |
| | Variable | | 2016 | | Notes Payable | | 24.8 |
| | Variable | | 2019 |
I&M | | Notes Payable | | 882 |
| | 2.12 | | 2016 | | Notes Payable | | 31.0 |
| | Variable | | 2019 |
I&M | | Other Long-term Debt | | 93,500 |
| | Variable | | 2015 | | Notes Payable | | 6.1 |
| | Variable | | 2020 |
I&M | | Other Long-term Debt | | 838 |
| | 6.00 | | 2025 | | Other Long-term Debt | | 1.0 |
| | 6.00 | | 2025 |
OPCo | | Other Long-term Debt | | 58 |
| | 1.149 | | 2028 | | Other Long-term Debt | | 0.1 |
| | 1.149 | | 2028 |
OPCo | | Pollution Control Bonds | | 86,000 |
| | 3.125 | | 2015 | | Securitization Bonds | | 45.8 |
| | 0.958 | | 2018 |
OPCo | | Securitization Bonds | | 45,426 |
| | 0.958 | | 2018 | | Senior Unsecured Notes | | 350.0 |
| | 6.00 | | 2016 |
PSO | | Other Long-term Debt | | 319 |
| | 3.00 | | 2027 | | Other Long-term Debt | | 0.3 |
| | 3.00 | | 2027 |
PSO | | | Senior Unsecured Notes | | 150.0 |
| | 6.15 | | 2016 |
SWEPCo | | Notes Payable | | 3,250 |
| | 4.58 | | 2032 | | Notes Payable | | 3.3 |
| | 4.58 | | 2032 |
SWEPCo | | Pollution Control Bonds | | 53,500 |
| | 3.25 | | 2015 | |
SWEPCo | | Senior Unsecured Notes | | 100,000 |
| | 5.375 | | 2015 | |
SWEPCo | | Senior Unsecured Notes | | 150,000 |
| | 4.90 | | 2015 | |
| | | | |
Non-Registrant: | | | | |
AEGCo | | | Senior Unsecured Notes | | 7.3 |
| | 6.33 | | 2037 |
AEP Subsidiaries | | | Notes Payable | | 5.1 |
| | Variable | | 2017 |
AEP Subsidiaries | | | Notes Payable | | 0.1 |
| | 5.75 | | 2021 |
AGR | | | Pollution Control Bonds | | 60.0 |
| | Variable | | 2016 |
TCC | | | Other Long-term Debt | | 100.0 |
| | Variable | | 2016 |
TCC | | | Securitization Bonds | | 44.2 |
| | 6.25 | | 2016 |
TCC | | | Securitization Bonds | | 149.1 |
| | 5.17 | | 2018 |
TCC | | | Securitization Bonds | | 26.9 |
| | 0.88 | | 2017 |
TNC | | | Other Long-term Debt | | 75.0 |
| | Variable | | 2016 |
Total Retirements and Principal Payments | | | $ | 1,307.6 |
| |
In October 2016, I&M retired $16 million of Notes Payable related to DCC Fuel.
As of September 30, 2015,2016, trustees held, on behalf of I&M and OPCo,AEP, $614 million of their reacquired Pollution Control Bonds. Of this total, $40 million and $345 million respectively, of their reacquired Pollution Control Bonds.related to I&M and OPCo, respectively.
Dividend Restrictions
Parent Restrictions (Applies to AEP)
The Registrant Subsidiariesholders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries.
Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of September 30, 2016, none of AEP’s retained earnings were restricted for the purpose of the payment of dividends.
Utility Subsidiaries’ Restrictions
AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiariessubsidiaries to transfer funds to Parent in the form of dividends.
Federal Power ActCertain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%.
The Federal Power Act prohibits each of the Registrant Subsidiariesutility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. This restriction does not limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.
Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to AGR, APCo and I&M. As of September 30, 2016, these restrictions did not limit the ability of the subsidiaries to pay dividends out of retained earnings.
Leverage Restrictions
PursuantCorporate Borrowing Program - AEP System (Applies to the credit agreement leverage restrictions, APCo, I&M, PSO and SWEPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.
Utility Money Pool – AEP SystemRegistrant Subsidiaries)
The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds a majority of AEP'scertain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 20152016 and December 31, 20142015 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ condensed balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 20152016 are described in the following table:
| | | | Maximum | | | | Average | | | | Net Loans to | | | | Maximum | | | | Average | | | | Net Loans to | | |
| | Borrowings | | Maximum | | Borrowings | | Average | | (Borrowings from) | | Authorized | | Borrowings | | Maximum | | Borrowings | | Average | | (Borrowings from) | | Authorized |
| | from the | | Loans to the | | from the | | Loans to the | | the Utility Money | | Short-term | | from the | | Loans to the | | from the | | Loans to the | | the Utility Money | | Short-term |
| | Utility | | Utility | | Utility | | Utility | | Pool as of | | Borrowing | �� | Utility | | Utility | | Utility | | Utility | | Pool as of | | Borrowing |
Company | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | September 30, 2015 | | Limit | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | September 30, 2016 | | Limit |
| | (in thousands) | | (in millions) |
APCo | | $ | 82,417 |
| | $ | 694,785 |
| | $ | 46,664 |
| | $ | 97,657 |
| | $ | (11,689 | ) | | $ | 600,000 |
| | $ | 286.9 |
| | $ | 25.7 |
| | $ | 165.5 |
| | $ | 24.9 |
| | $ | (59.7 | ) | | $ | 600.0 |
|
I&M | | 200,032 |
| | 13,515 |
| | 136,890 |
| | 13,503 |
| | (137,496 | ) | | 500,000 |
| | 369.1 |
| | 97.6 |
| | 118.9 |
| | 21.8 |
| | (13.9 | ) | | 500.0 |
|
OPCo | | — |
| | 367,472 |
| | — |
| | 256,020 |
| | 279,129 |
| | 400,000 |
| | 227.9 |
| | 379.2 |
| | 137.8 |
| | 251.1 |
| | 0.2 |
| | 400.0 |
|
PSO | | 165,947 |
| | 152,498 |
| | 113,117 |
| | 74,225 |
| | 116,345 |
| | 300,000 |
| | 9.6 |
| | 205.4 |
| | 5.1 |
| | 47.0 |
| | 51.1 |
| | 300.0 |
|
SWEPCo | | 112,481 |
| | 299,932 |
| | 52,596 |
| | 121,845 |
| | 43,073 |
| | 350,000 |
| | 249.4 |
| | 308.2 |
| | 171.8 |
| | 302.8 |
| | 297.4 |
| | 350.0 |
|
The activity in the above table does not include short-term lending activity of SWEPCo'sSWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 20152016 and December 31, 20142015 are included in Advances to Affiliates on SWEPCo's condensedSWEPCo’s balance sheets. For the nine months ended September 30, 2015,2016, Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool:
| | Maximum | Maximum | | Maximum | | Average | | Average | | Loans | Maximum | | Average | | Loans |
Borrowings | | Loans | | Borrowings | | Loans | | to the Nonutility | |
from the Nonutility | | to the Nonutility | | from the Nonutility | | to the Nonutility | | Money Pool as of | |
Loans | | Loans | | Loans | | to the Nonutility |
to the Nonutility | | to the Nonutility | | to the Nonutility | | Money Pool as of |
Money Pool | Money Pool | | Money Pool | | Money Pool | | Money Pool | | September 30, 2015 | Money Pool | | Money Pool | | September 30, 2016 |
(in thousands) | |
(in millions) | | (in millions) |
$ | — |
| | $ | 1,948 |
| | $ | — |
| | $ | 1,945 |
| | $ | 1,946 |
| 2.0 |
| | $ | 2.0 |
| | $ | 2.0 |
|
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:
| | | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2016 | | 2015 |
Maximum Interest Rate | | 0.59 | % | | 0.33 | % | | 0.91 | % | | 0.59 | % |
Minimum Interest Rate | | 0.39 | % | | 0.24 | % | | 0.69 | % | | 0.39 | % |
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 20152016 and 20142015 are summarized for all Registrant Subsidiaries in the following table:
| | | | Average Interest Rate | | Average Interest Rate | | Average Interest Rate | | Average Interest Rate |
| | for Funds Borrowed | | for Funds Loaned | | for Funds Borrowed | | for Funds Loaned |
| | from the Utility Money Pool for | | to the Utility Money Pool for | | from the Utility Money Pool for | | to the Utility Money Pool for |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
Company | | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
APCo | | 0.46 | % | | 0.26 | % | | 0.46 | % | | 0.28 | % | | 0.78 | % | | 0.46 | % | | 0.79 | % | | 0.46 | % |
I&M | | 0.47 | % | | 0.27 | % | | 0.46 | % | | 0.30 | % | | 0.73 | % | | 0.47 | % | | 0.78 | % | | 0.46 | % |
OPCo | | — | % | | 0.27 | % | | 0.47 | % | | 0.29 | % | | 0.85 | % | | — | % | | 0.74 | % | | 0.47 | % |
PSO | | 0.49 | % | | 0.27 | % | | 0.46 | % | | — | % | | 0.76 | % | | 0.49 | % | | 0.81 | % | | 0.46 | % |
SWEPCo | | 0.46 | % | | 0.28 | % | | 0.48 | % | | 0.27 | % | | 0.79 | % | | 0.46 | % | | 0.91 | % | | 0.48 | % |
Maximum, minimum and average interest rates for funds either borrowed from or loaned to the Nonutility Money Pool for the nine months ended September 30, 2015 and 20142016 are summarized for Mutual Energy SWEPCo, LLC in the following table:
|
| | | | | | | | | | | | | | | | | | |
| | Maximum | | Minimum | | Maximum | | Minimum | | Average | | Average |
| | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate |
| | for Funds | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds |
Nine Months | | Borrowed from | | Borrowed from | | Loaned to | | Loaned to | | Borrowed from | | Loaned to |
Ended | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility |
September 30, | | Money Pool | | Money Pool | Money Pool | | Money Pool | | Money Pool | | Money Pool |
2015 | | — | % | | — | % | | 0.59 | % | | 0.39 | % | | — | % | | 0.47 | % |
2014 | | — | % | | — | % | | 0.33 | % | | — | % | | — | % | | 0.28 | % |
|
| | | | | | | |
Maximum | | Minimum | | Average |
Interest Rate | | Interest Rate | | Interest Rate |
for Funds | | for Funds | | for Funds |
Loaned to | | Loaned to | | Loaned to |
the Nonutility | | the Nonutility | | the Nonutility |
Money Pool | | Money Pool | | Money Pool |
0.91 | % | | 0.69 | % | | 0.79 | % |
Short-term Debt (Applies to AEP)
Outstanding short-term debt was as follows:
|
| | | | | | | | | | | | | | |
| | September 30, 2016 | | December 31, 2015 |
Type of Debt | | Outstanding Amount | | Interest Rate (a) | | Outstanding Amount | | Interest Rate (a) |
| | (in millions) | | | | (in millions) | | |
Securitized Debt for Receivables (b) | | $ | 750.0 |
| | 0.65 | % | | $ | 675.0 |
| | 0.30 | % |
Commercial Paper | | 728.3 |
| | 0.90 | % | | 125.0 |
| | 0.81 | % |
Total Short-term Debt | | $ | 1,478.3 |
| | |
| | $ | 800.0 |
| | |
|
| |
(a) | Weighted average rate. |
| |
(b) | Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. |
Credit Facilities
For a discussion of credit facilities, see “Letters of Credit” section of Note 5.
Sale of Receivables – AEP Credit (Applies to AEP)
AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.
AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in June 2018.
Accounts receivable information for AEP Credit is as follows:
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (dollars in millions) |
Effective Interest Rates on Securitization of Accounts Receivable | | 0.73 | % | | 0.30 | % | | 0.65 | % | | 0.28 | % |
Net Uncollectible Accounts Receivable Written Off | | $ | 7.7 |
| | $ | 13.5 |
| | $ | 17.5 |
| | $ | 27.5 |
|
|
| | | | | | | | |
| | September 30, 2016 | | December 31, 2015 |
| | (in millions) |
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts | | $ | 1,037.7 |
| | $ | 924.8 |
|
Total Principal Outstanding | | 750.0 |
| | 675.0 |
|
Delinquent Securitized Accounts Receivable | | 47.7 |
| | 48.3 |
|
Bad Debt Reserves Related to Securitization of Accounts Receivable | | 27.8 |
| | 17.5 |
|
Unbilled Receivables Related to Securitization of Accounts Receivable | | 297.1 |
| | 357.8 |
|
AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.
Sale of Receivables – AEP Credit (Applies to Registrant Subsidiaries)
Under athis sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, sold.
which are sold to AEP Credit'sCredit. AEP Credit securitizes the eligible receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 millionfor the operating companies and expires in June 2017.retains the remainder.
The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 20152016 and December 31, 20142015 was as follows:
| | | | September 30, | | December 31, | | | | | |
Company | | 2015 | | 2014 | | September 30, 2016 | | December 31, 2015 |
| | (in thousands) | | (in millions) |
APCo | | $ | 125,153 |
| | $ | 159,823 |
| | $ | 131.9 |
| | $ | 135.4 |
|
I&M | | 139,481 |
| | 137,459 |
| | 152.5 |
| | 134.8 |
|
OPCo | | 354,276 |
| | 365,834 |
| | 407.1 |
| | 351.4 |
|
PSO | | 146,039 |
| | 112,905 |
| | 146.1 |
| | 116.1 |
|
SWEPCo | | 176,113 |
| | 148,668 |
| | 170.0 |
| | 151.8 |
|
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
Company | | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
| | (in thousands) | | (in millions) |
APCo | | $ | 1,952 |
| | $ | 2,166 |
| | $ | 5,979 |
| | $ | 6,626 |
| | $ | 1.6 |
| | $ | 2.0 |
| | $ | 5.4 |
| | $ | 6.0 |
|
I&M | | 2,191 |
| | 2,011 |
| | 6,611 |
| | 5,836 |
| | 2.0 |
| | 2.2 |
| | 5.6 |
| | 6.6 |
|
OPCo | | 8,545 |
| | 7,213 |
| | 23,228 |
| | 21,358 |
| | 8.1 |
| | 8.5 |
| | 23.4 |
| | 23.2 |
|
PSO | | 1,709 |
| | 1,745 |
| | 4,455 |
| | 4,417 |
| | 1.8 |
| | 1.7 |
| | 4.7 |
| | 4.5 |
|
SWEPCo | | 1,997 |
| | 1,890 |
| | 5,344 |
| | 5,035 |
| | 2.1 |
| | 2.0 |
| | 5.3 |
| | 5.3 |
|
The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
Company | | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
| | (in thousands) | | (in millions) |
APCo | | $ | 355,275 |
| | $ | 354,406 |
| | $ | 1,115,492 |
| | $ | 1,137,564 |
| | $ | 361.7 |
| | $ | 355.3 |
| | $ | 1,071.6 |
| | $ | 1,115.5 |
|
I&M | | 401,518 |
| | 372,422 |
| | 1,192,137 |
| | 1,132,603 |
| | 448.0 |
| | 401.5 |
| | 1,220.2 |
| | 1,192.1 |
|
OPCo | | 670,677 |
| | 668,112 |
| | 1,949,042 |
| | 1,980,764 |
| | 750.9 |
| | 670.7 |
| | 2,011.2 |
| | 1,949.0 |
|
PSO | | 411,523 |
| | 398,567 |
| | 1,025,909 |
| | 1,014,320 |
| | 390.6 |
| | 411.5 |
| | 971.9 |
| | 1,025.9 |
|
SWEPCo | | 468,027 |
| | 466,828 |
| | 1,222,294 |
| | 1,278,325 |
| | 460.4 |
| | 468.0 |
| | 1,183.9 |
| | 1,222.3 |
|
12.13. VARIABLE INTEREST ENTITIES
The disclosures in this note apply to all Registrants unless indicated otherwise.
The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they areAEP is the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant SubsidiaryAEP absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.
SWEPCoAEP is the primary beneficiary of Sabine. I&M is the primary beneficiary ofSabine, DCC Fuel. OPCo is the primary beneficiary ofFuel, Transition Funding, Ohio Phase-in-Recovery Funding. APCo is the primary beneficiary ofFunding, Appalachian Consumer Rate Relief Funding.Funding, AEP Credit, a protected cell of EIS and Transource Energy. In addition, the Registrant Subsidiaries haveAEP has not provided material financial or other support to any of these entities that was not previously contractually required. SWEPCoAEP holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M holds a significant variable interest in AEGCo.DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series).
Consolidated Variable Interests Entities
Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended September 30, 2016 and 2015 and 2014 were $41$42 million and $41 million, respectively, and for the nine months ended September 30, 2016 and 2015 and 2014 were $124$127 million and $121$124 million, respectively. See the tabletables below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets.
The balances below represent the assets and liabilities of Sabine that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
September 30, 2015 and December 31, 2014
(in thousands)
|
| | | | | | | | |
| | Sabine |
ASSETS | | 2015 | | 2014 |
Current Assets | | $ | 61,025 |
| | $ | 67,981 |
|
Net Property, Plant and Equipment | | 143,815 |
| | 145,491 |
|
Other Noncurrent Assets | | 60,160 |
| | 51,578 |
|
Total Assets | | $ | 265,000 |
| | $ | 265,050 |
|
| | | | |
LIABILITIES AND EQUITY | | |
| | |
|
Current Liabilities | | $ | 40,311 |
| | $ | 36,286 |
|
Noncurrent Liabilities | | 224,371 |
| | 228,349 |
|
Equity | | 318 |
| | 415 |
|
Total Liabilities and Equity | | $ | 265,000 |
| | $ | 265,050 |
|
I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended September 30, 2016 and 2015 and 2014 were $29$23 million and $28$29 million, respectively, and for the nine months ended September 30, 2016 and 2015 and 2014 were $86$77 million and $84$86 million, respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the tabletables below for the classification of DCC Fuel’s assets and liabilities on I&M’s condensed balance sheets.
Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The balances belowsecuritized bonds totaled $1.3 billion and $1.5 billion as of September 30, 2016 and December 31, 2015, respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Transition
Funding has securitized transition assets of $1.1 billion and $1.3 billion as of September 30, 2016 and December 31, 2015, respectively, which are presented separately on the face of the balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to TCC or any other AEP entity. TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities of DCC Fuel that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
September 30, 2015 and December 31, 2014
(in thousands)
|
| | | | | | | | |
| | DCC Fuel |
ASSETS | | 2015 | | 2014 |
Current Assets | | $ | 104,273 |
| | $ | 97,361 |
|
Net Property, Plant and Equipment | | 193,447 |
| | 158,121 |
|
Other Noncurrent Assets | | 99,811 |
| | 79,705 |
|
Total Assets | | $ | 397,531 |
| | $ | 335,187 |
|
| | | | |
LIABILITIES AND EQUITY | | |
| | |
|
Current Liabilities | | $ | 98,173 |
| | $ | 86,026 |
|
Noncurrent Liabilities | | 299,358 |
| | 249,161 |
|
Total Liabilities and Equity | | $ | 397,531 |
| | $ | 335,187 |
|
on the balance sheets.
Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo'sOPCo’s equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $187$140 million and $232$185 million as of September 30, 20152016 and December 31, 2014,2015, respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $92$68 million and $110$86 million as of September 30, 20152016 and December 31, 2014,2015, respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding'sFunding’s securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the tabletables below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s condensed balance sheets.
The balances below represent the assets and liabilities of Ohio Phase-in-Recovery Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.
OHIO POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
September 30, 2015 and December 31, 2014
(in thousands)
|
| | | | | | | | |
|
| Ohio Phase-In Recovery Funding |
ASSETS |
| 2015 |
| 2014 |
Current Assets |
| $ | 20,236 |
|
| $ | 32,676 |
|
Other Noncurrent Assets (a) |
| 175,189 |
|
| 209,922 |
|
Total Assets |
| $ | 195,425 |
|
| $ | 242,598 |
|
|
| |
|
|
|
|
LIABILITIES AND EQUITY |
| |
|
|
|
|
Current Liabilities |
| $ | 46,592 |
|
| $ | 47,099 |
|
Noncurrent Liabilities |
| 147,496 |
|
| 194,162 |
|
Equity |
| 1,337 |
|
| 1,337 |
|
Total Liabilities and Equity |
| $ | 195,425 |
|
| $ | 242,598 |
|
| |
(a) | Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $81 million and $97 million, respectively. |
Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo'sAPCo’s under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo'sAPCo’s equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $345$319 million and $368$342 million as of September 30, 20152016 and December 31, 2014,2015, respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $333$311 million and $350$328 million as of September 30, 20152016 and December 31, 2014,2015, respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding'sFunding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tabletables below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s condensed balance sheets.
251AEP Credit is a wholly-owned subsidiary of Parent. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings. Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on AEP’s control of AEP Credit, management concluded that AEP is the primary beneficiary and is required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets. See “Sale of Receivables - AEP Credit” section of Note 12.
AEP’s subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the three months ended September 30, 2016 and 2015 was $15 million and $13 million, respectively, and for the nine months ended September 30, 2016 and 2015 was $28 million and $27 million, respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. The amount reported as equity is the protected cell’s policy holders’ surplus.
Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity and AEP’s equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. In January 2014, Transource Missouri (a wholly-owned subsidiary of Transource Energy) acquired transmission assets from the non-controlling owner and issued debt and received a capital contribution to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, construction projects, debt issuance and capital contribution. AEP has provided capital contributions to Transource Energy of $38 million and $47 million during the nine months ended September 30, 2016 and the year ended December 31, 2015, respectively. AEP and the other owner of Transource Energy are required to ensure a specific equity level in Transource Missouri upon completion of projects or if a project is abandoned by the RTO. See the tables below for the classification of Transource Energy’s assets and liabilities on the balance sheets.
The balances below represent the assets and liabilities of Appalachian Consumer Rate Relief Fundingthe VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
September 30, 2015 and December 31, 2014
(in thousands)
| | AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | | AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES |
VARIABLE INTEREST ENTITIES | | VARIABLE INTEREST ENTITIES |
September 30, 2016 | | September 30, 2016 |
| | | | |
| | Registrant Subsidiaries | | Other Consolidated VIEs |
| | | | | | SWEPCo Sabine | | I&M DCC Fuel | | OPCo Ohio Phase-in- Recovery Funding | | APCo Appalachian Consumer Rate Relief Funding | | AEP Credit | | TCC Transition Funding | | Protected Cell of EIS | | Transource Energy |
| | Appalachian Consumer Rate Relief Funding | (in millions) |
ASSETS | | 2015 | | 2014 | | | |
| | |
| | | | | | | | |
| | |
Current Assets | | $ | 10,914 |
| | $ | 18,099 |
| $ | 61.8 |
| | $ | 109.2 |
| | $ | 18.9 |
| | $ | 11.8 |
| | $ | 1,038.7 |
| | $ | 163.5 |
| | $ | 179.4 |
| | $ | 12.2 |
|
Other Noncurrent Assets (a) | | 341,127 |
| | 358,264 |
| |
Net Property, Plant and Equipment | | 123.6 |
| | 165.9 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 298.5 |
|
Other Noncurrent Assets | | 63.9 |
| | 78.8 |
| | 128.1 |
| (a) | 314.7 |
| (b) | 10.3 |
| | 1,210.4 |
| (c) | 1.7 |
| | 5.5 |
|
Total Assets | | $ | 352,041 |
| | $ | 376,363 |
| $ | 249.3 |
| | $ | 353.9 |
| | $ | 147.0 |
| | $ | 326.5 |
| | $ | 1,049.0 |
| | $ | 1,373.9 |
| | $ | 181.1 |
| | $ | 316.2 |
|
| | | | | | | | | | | | | | | | | | | |
LIABILITIES AND EQUITY | | |
| | | |
| | |
| | |
| | |
| | |
| | | | |
| | |
Current Liabilities | | $ | 24,617 |
| | $ | 26,809 |
| $ | 32.0 |
| | $ | 98.2 |
| | $ | 46.9 |
| | $ | 25.0 |
| | $ | 948.2 |
| | $ | 242.6 |
| | $ | 47.7 |
| | $ | 35.4 |
|
Noncurrent Liabilities | | 325,534 |
| | 347,652 |
| 217.0 |
| | 255.7 |
| | 98.8 |
| | 300.2 |
| | 0.6 |
| | 1,113.2 |
| | 91.1 |
| | 127.2 |
|
Equity | | 1,890 |
| | 1,902 |
| 0.3 |
| | — |
| | 1.3 |
| | 1.3 |
| | 100.2 |
| | 18.1 |
| | 42.3 |
| | 153.6 |
|
Total Liabilities and Equity | | $ | 352,041 |
| | $ | 376,363 |
| $ | 249.3 |
| | $ | 353.9 |
| | $ | 147.0 |
| | $ | 326.5 |
| | $ | 1,049.0 |
| | $ | 1,373.9 |
| | $ | 181.1 |
| | $ | 316.2 |
|
| |
(a) | Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $4 million and $4 million, respectively.$60.2 million. |
| |
(b) | Includes an intercompany item eliminated in consolidation of $3.8 million. |
| |
(c) | Includes an intercompany item eliminated in consolidation of $62.9 million. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES |
VARIABLE INTEREST ENTITIES |
December 31, 2015 |
| | | |
| Registrant Subsidiaries | | Other Consolidated VIEs |
| SWEPCo Sabine | | I&M DCC Fuel | | OPCo Ohio Phase-in- Recovery Funding | | APCo Appalachian Consumer Rate Relief Funding | | AEP Credit | | TCC Transition Funding | | Protected Cell of EIS | | Transource Energy |
| (in millions) |
ASSETS | | | |
| | |
| | | | | | | | |
| | |
Current Assets | $ | 61.7 |
| | $ | 91.1 |
| | $ | 31.2 |
| | $ | 18.5 |
| | $ | 925.7 |
| | $ | 234.1 |
| | $ | 165.3 |
| | $ | 10.8 |
|
Net Property, Plant and Equipment | 147.0 |
| | 159.9 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 227.2 |
|
Other Noncurrent Assets | 61.8 |
| | 84.6 |
| | 162.0 |
| (a) | 332.0 |
| (b) | 6.4 |
| | 1,365.7 |
| (c) | 1.9 |
| | 5.5 |
|
Total Assets | $ | 270.5 |
| | $ | 335.6 |
| | $ | 193.2 |
| | $ | 350.5 |
| | $ | 932.1 |
| | $ | 1,599.8 |
| | $ | 167.2 |
| | $ | 243.5 |
|
| | | | | | | | | | | | | | | |
LIABILITIES AND EQUITY | |
| | |
| | |
| | |
| | |
| | | | |
| | |
Current Liabilities | $ | 47.7 |
| | $ | 84.8 |
| | $ | 47.3 |
| | $ | 27.1 |
| | $ | 855.1 |
| | $ | 291.7 |
| | $ | 41.8 |
| | $ | 36.6 |
|
Noncurrent Liabilities | 222.3 |
| | 250.8 |
| | 144.6 |
| | 321.5 |
| | 0.3 |
| | 1,290.0 |
| | 83.9 |
| | 113.0 |
|
Equity | 0.5 |
| | — |
| | 1.3 |
| | 1.9 |
| | 76.7 |
| | 18.1 |
| | 41.5 |
| | 93.9 |
|
Total Liabilities and Equity | $ | 270.5 |
| | $ | 335.6 |
| | $ | 193.2 |
| | $ | 350.5 |
| | $ | 932.1 |
| | $ | 1,599.8 |
| | $ | 167.2 |
| | $ | 243.5 |
|
| |
(a) | Includes an intercompany item eliminated in consolidation of $76.1 million. |
| |
(b) | Includes an intercompany item eliminated in consolidation of $4.0 million. |
| |
(c) | Includes an intercompany item eliminated in consolidation of $68.2 million. |
Non-Consolidated Significant Variable Interests
DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended September 30, 2016 and 2015 and 2014 were $30$15 million and $24$30 million, respectively, and for the nine months ended September 30, 2016 and 2015 and 2014 were $59$43 million and $31$59 million, respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheets.
SWEPCo’s investment in DHLC was:
| | | | September 30, 2015 | | December 31, 2014 | | September 30, 2016 | | December 31, 2015 |
| | As Reported on the Balance Sheet | | Maximum Exposure | | As Reported on the Balance Sheet | | Maximum Exposure | | As Reported on the Balance Sheet | | Maximum Exposure | | As Reported on the Balance Sheet | | Maximum Exposure |
| | (in thousands) | | (in millions) |
Capital Contribution from SWEPCo | | $ | 7,643 |
| | $ | 7,643 |
| | $ | 7,643 |
| | $ | 7,643 |
| | $ | 7.6 |
| | $ | 7.6 |
| | $ | 7.6 |
| | $ | 7.6 |
|
Retained Earnings | | 5,950 |
| | 5,950 |
| | 3,819 |
| | 3,819 |
| | 12.7 |
| | 12.7 |
| | 7.7 |
| | 7.7 |
|
SWEPCo's Guarantee of Debt | | — |
| | 95,180 |
| (a) | — |
| | 104,334 |
| (a) | |
| | | | | | | | | | |
SWEPCo’s Guarantee of Debt | | — |
| | 92.7 |
| | — |
| | 82.9 |
|
Total Investment in DHLC | | $ | 13,593 |
| | $ | 108,773 |
| | $ | 11,462 |
| | $ | 115,796 |
| | $ | 20.3 |
| | $ | 113.0 |
| | $ | 15.3 |
| | $ | 98.2 |
|
| |
(a) | Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $40 million and $56 million in 2015 and 2014, respectively. |
AEP and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH). PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region. PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy. Provisions exist within the PATH-WV agreement that make it a VIE. AEP has no interest or control in the “Allegheny Series”. AEP is not required to consolidate PATH-WV as AEP is not the primary beneficiary, although AEP holds a significant variable interest in PATH-WV. AEP’s equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the balance sheets. AEP and FirstEnergy share the returns and losses equally in PATH-WV. AEP’s subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements. The entities recover costs through regulated rates.
In August 2012, the PJM board cancelled the PATH Project, the transmission project that PATH was intended to develop and removed it from the 2012 Regional Transmission Expansion Plan. In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project’s abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case have been unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at FERC were held in March and April 2015. In April 2015, PATH filed a stipulation agreement with the FERC that agreed to a 50% debt and 50% equity capital structure and a 4.7% cost of long-term debt for the entire amortization period. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, which if adopted by the FERC, would deem certain costs not recoverable. The Initial Decision has no binding effect. Additional briefing was submitted during the fourth quarter of 2015. The case is currently pending before FERC. Depending on the outcome of this proceeding, PATH-WV may be required to refund certain amounts that have been collected under its formula rate. Management believes its financial statements adequately address the potential impact of this proceeding.
AEP’s investment in PATH-WV was:
|
| | | | | | | | | | | | | | | |
| September 30, 2016 | | December 31, 2015 |
| As Reported on the Balance Sheet | | Maximum Exposure | | As Reported on the Balance Sheet | | Maximum Exposure |
| (in millions) |
Capital Contribution from AEP | $ | 18.8 |
| | $ | 18.8 |
| | $ | 18.8 |
| | $ | 18.8 |
|
Retained Earnings | 2.2 |
| | 2.2 |
| | 2.2 |
| | 2.2 |
|
Total Investment in PATH-WV | $ | 21.0 |
| | $ | 21.0 |
| | $ | 21.0 |
| | $ | 21.0 |
|
As of September 30, 2016, AEP’s $21 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows.
AEPSC provides certain managerial and professional services to AEP’s subsidiaries. AEPParent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.
Total AEPSC billings to the Registrant Subsidiaries were as follows:
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
Company | | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
| | (in thousands) | | (in millions) |
APCo | | $ | 63,687 |
| | $ | 50,143 |
| | $ | 164,657 |
| | $ | 154,239 |
| | $ | 55.3 |
| | $ | 63.7 |
| | $ | 165.7 |
| | $ | 164.7 |
|
I&M | | 37,506 |
| | 30,613 |
| | 102,141 |
| | 92,686 |
| | 32.7 |
| | 37.5 |
| | 97.7 |
| | 102.1 |
|
OPCo | | 48,471 |
| | 41,212 |
| | 128,608 |
| | 120,696 |
| | 39.4 |
| | 48.5 |
| | 123.2 |
| | 128.6 |
|
PSO | | 29,851 |
| | 24,317 |
| | 77,817 |
| | 71,646 |
| | 23.6 |
| | 29.9 |
| | 77.1 |
| | 77.8 |
|
SWEPCo | | 39,150 |
| | 32,787 |
| | 102,564 |
| | 98,528 |
| | 31.4 |
| | 39.2 |
| | 101.2 |
| | 102.6 |
|
The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows:
| | | | September 30, 2015 | | December 31, 2014 | | September 30, 2016 | | December 31, 2015 |
Company | | As Reported on the Balance Sheet | | Maximum Exposure | | As Reported on the Balance Sheet | | Maximum Exposure | | As Reported on the Balance Sheet | | Maximum Exposure | | As Reported on the Balance Sheet | | Maximum Exposure |
| | (in thousands) | | (in millions) |
APCo | | $ | 23,783 |
| | $ | 23,783 |
| | $ | 30,692 |
| | $ | 30,692 |
| | $ | 20.0 |
| | $ | 20.0 |
| | $ | 25.8 |
| | $ | 25.8 |
|
I&M | | 13,676 |
| | 13,676 |
| | 22,480 |
| | 22,480 |
| | 11.0 |
| | 11.0 |
| | 16.6 |
| | 16.6 |
|
OPCo | | 18,770 |
| | 18,770 |
| | 24,695 |
| | 24,695 |
| | 13.9 |
| | 13.9 |
| | 23.3 |
| | 23.3 |
|
PSO | | 10,713 |
| | 10,713 |
| | 15,338 |
| | 15,338 |
| | 7.8 |
| | 7.8 |
| | 12.6 |
| | 12.6 |
|
SWEPCo | | 14,295 |
| | 14,295 |
| | 20,772 |
| | 20,772 |
| | 11.8 |
| | 11.8 |
| | 16.4 |
| | 16.4 |
|
AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo andto AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligationobligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the three months ended September 30, 2016 and 2015 and 2014 were $67$65 million and $67 million, respectively, and for the nine months ended September 30, 2016 and 2015 and 2014 were $182$166 million and $202$182 million, respectively. The carrying amount of I&M's&M’s liabilities associated with AEGCo as of September 30, 20152016 and December 31, 20142015 was $17 million and $20$17 million, respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo'sAEGCo’s lease, see "Rockport Lease"“Rockport Lease” section of Note 13 in the 20142015 Annual Report.
13. PROPERTY, PLANT AND EQUIPMENT
Asset Retirement Obligations (ARO)
The Registrant Subsidiaries record ARO in accordance withassets and liabilities of AEGCo’s Lawrenceburg Plant have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities,balance sheet as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected.
As of September 30, 20152016. See “Assets and December 31, 2014, I&M's ARO liabilityLiabilities Held For Sale” section of Note 6 for nuclear decommissioning of the Cook Plant was $1.31 billion and $1.27 billion, respectively. These liabilities are reflected in Asset Retirement Obligations on I&M's condensed balance sheets. As of September 30, 2015 and December 31, 2014, the fair value of I&M's assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.74 billion and $1.79 billion, respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M's condensed balance sheets.additional information.
The Registrant Subsidiaries recorded an increase in asset retirement obligations in the second quarter of 2015, partially related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment.
The following is a reconciliation of the aggregate carrying amounts of ARO by Registrant Subsidiary:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | ARO as of | | | | | | | | Revisions in | | |
| | December 31, | | Accretion | | Liabilities | | Liabilities | | Cash Flow | | ARO as of |
Company | | 2014 | | Expense | | Incurred | | Settled | | Estimates | | September 30, 2015 |
| | (in thousands) |
APCo (a)(d) | | $ | 148,377 |
| | $ | 6,239 |
| | $ | — |
| | $ | (23,471 | ) | | $ | 16,977 |
| | $ | 148,122 |
|
I&M (a)(b)(d) | | 1,342,549 |
| | 47,918 |
| | — |
| | (3,977 | ) | | 5,638 |
| | 1,392,128 |
|
OPCo (d)(e) | | 1,361 |
| | 62 |
| | — |
| | (8 | ) | | — |
| | 1,415 |
|
PSO (a)(d) | | 38,020 |
| | 1,923 |
| | 5,336 |
| | (125 | ) | | 1,916 |
| | 47,070 |
|
SWEPCo (a)(c)(d) | | 94,394 |
| | 4,299 |
| | 12,191 |
| | (3,358 | ) | | 6,349 |
| | 113,875 |
|
| |
(a) | Includes ARO related to ash disposal facilities. |
| |
(b) | Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.31 billion and $1.27 billion as of September 30, 2015 and December 31, 2014. |
| |
(c) | Includes ARO related to Sabine and DHLC. |
| |
(d) | Includes ARO related to asbestos removal. |
| |
(e) | Not impacted by the CCR rule. |
14. DISPOSITION PLANT SEVERANCE
Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits.
The Registrant Subsidiaries' disposition plant severance activity for the nine months ended September 30, 2015 is described in the following table:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Balance as of | | Expense Allocation from | | Incurred by Registrant | | | | | | Remaining Balance as of |
Company | | December 31, 2014 | | AEPSC | | Subsidiaries | | Settled | | Adjustments | | September 30, 2015 |
| | (in thousands) |
APCo | | $ | 9,304 |
| | $ | (6 | ) | | $ | 849 |
| | $ | (6,385 | ) | (a) | $ | (119 | ) | | $ | 3,643 |
|
I&M | | 8,023 |
| | (2 | ) | | 351 |
| | (5,110 | ) | | — |
| | 3,262 |
|
PSO | | 134 |
| | (3 | ) | | 415 |
| | (121 | ) | | — |
| | 425 |
|
SWEPCo | | 84 |
| | (4 | ) | | — |
| | (79 | ) | | — |
| | 1 |
|
(a) Settled includes amounts received from affiliates for expenses related to joint plant.
The Registrant Subsidiaries recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amount incurred in 2014 by Registrant Subsidiary was as follows:
|
| | | | |
Company | | Total Cost Incurred |
| | (in thousands) |
APCo | | $ | 7,112 |
|
I&M | | 8,185 |
|
OPCo | | 80 |
|
PSO | | 288 |
|
SWEPCo | | 289 |
|
These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. The Registrant Subsidiaries incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative.
COMBINED MANAGEMENT’S NARRATIVE DISCUSSION
AND ANALYSIS OF REGISTRANT SUBSIDIARIES
The following is a combined presentation of certain components of the Registrant Subsidiaries’ management’s discussion and analysis. The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (a) Management’s Narrative Discussion and Analysis of Results of Operations, (b) financial statements, (c) footnotes and (d) the schedules of each individual registrant. The Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries section of the 2014 Annual Report should also be read in conjunction with this report.
EXECUTIVE OVERVIEW
Customer Demand
AEP's weather-normalized retail sales volumes for the third quarter of 2015 increased by 0.9% from the third quarter of 2014. Third quarter 2015 industrial sales increased 0.7% compared to the third quarter of 2014 primarily due to increased sales to customers in oil and gas related sectors. Weather-normalized commercial and residential sales increased 1.3% and 0.8% in the third quarter of 2015, respectively, from the third quarter of 2014.
AEP's weather-normalized retail sales volumes for the nine months ended September 30, 2015 increased 0.1% compared to the nine months ended September 30, 2014. Industrial sales volumes increased 0.8% compared to 2014, while weather-normalized commercial sales increased by 1.0%. Weather-normalized residential sales decreased 1.1% in comparison to the first nine months of 2014.
ENVIRONMENTAL ISSUES
The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with environmental control requirements. The Registrant Subsidiaries will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, rules governing the beneficial use and disposal of coal combustion products, proposed and final clean water rules and renewal permits for certain water discharges that are currently under appeal.
The Registrant Subsidiaries are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of I&M’s nuclear units. AEP, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court. Management is also engaged in the development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change. Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.
See a complete discussion of these matters in the “Environmental Issues” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2014 Annual Report. Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If the costs of environmental compliance are not recovered, it would reduce future net income and cash flows and impact financial condition.
Environmental Controls Impact on the Generating Fleet
The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of September 30, 2015, the AEP System had a total generating capacity of approximately 32,100 MWs, of which approximately 18,200 MWs are coal-fired. Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the generating facilities. For the Registrant Subsidiaries, management’s current ranges of estimates of environmental investments to comply with these requirements are listed below:
|
| | | | | | | | |
| | Through 2020 Estimated Environmental Investment |
Company | | Low | | High |
| | (in millions) |
APCo | | $ | 310 |
| | $ | 360 |
|
I&M | | 370 |
| | 430 |
|
PSO | | 270 |
| | 310 |
|
SWEPCo | | 880 |
| | 950 |
|
Total | | $ | 1,830 |
| | $ | 2,050 |
|
For APCo, the projected environmental investment above includes the conversion of 470 MWs of coal generation to natural gas capacity.
The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules. The cost estimates for each Registrant Subsidiary will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans (SIPs) or federal implementation plans (FIPs) that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.
In May 2015, management retired the following plants or units of plants:
|
| | | | | |
| | | | Generating |
Company | | Plant Name and Unit | | Capacity |
| | | | (in MWs) |
APCo | | Clinch River Plant, Unit 3 | | 235 |
|
APCo | | Glen Lyn Plant | | 335 |
|
APCo | | Kanawha River Plant | | 400 |
|
APCo/AGR | | Sporn Plant | | 600 |
|
I&M | | Tanners Creek Plant | | 995 |
|
Total | | | | 2,565 |
|
As of September 30, 2015, the book value of the regulated plants in the table above has been approved for recovery, except for $147 million which is pending regulatory approval.
Subject to the factors listed above and based upon continuing evaluation, management intends to retire the following units of plants during 2016:
|
| | | | | |
| | | | Generating |
Company | | Plant Name and Unit | | Capacity |
| | | | (in MWs) |
PSO | | Northeastern Station, Unit 4 | | 470 |
|
SWEPCo | | Welsh Plant, Unit 2 | | 528 |
|
Total | | | | 998 |
|
As of September 30, 2015, the net book value of the PSO and SWEPCo units listed above before cost of removal, including related materials and supplies inventory and CWIP balances, was $177 million. Volatility in fuel prices, pending environmental rules and other market factors could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of coal-fired units. For Northeastern Station, Unit 4 and Welsh Plant, Unit 2, management is seeking regulatory recovery of remaining net book values.
Management is in the process of obtaining permits following the Virginia SCC and WVPSC's approval for the conversion of APCo's 470 MW Clinch River Plant, Units 1 and 2 to natural gas. In September 2015, management retired the coal-related assets of Clinch River Plant, Units 1 and 2. Of the coal-related assets retired in September 2015, $14 million is pending regulatory approval. Management expects to begin operations as a natural gas unit in the first quarter of 2016 for Clinch River Plant, Unit 1 and the second quarter of 2016 for Clinch River Plant, Unit 2. As of September 30, 2015, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of Clinch River Plant, Units 1 and 2 was $148 million.
To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows and impact financial condition.
Clean Air Act Requirements
The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements.
The Federal EPA issued the Clean Air Interstate Rule (CAIR) in 2005 requiring specific reductions in SO2 and NOx emissions from power plants. The Federal EPA issued the Cross-State Air Pollution Rule (CSAPR) in August 2011 to replace CAIR. The CSAPR was challenged in the courts. In 2012, a panel of the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing CAIR until a replacement rule is finalized. That decision was appealed to the U.S. Supreme Court, which reversed the decision and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit ordered CSAPR to take effect on January 1, 2015 while the remand proceeding was still pending. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit remanded the rule to the Federal EPA. All of the states in which the Registrant Subsidiaries' power plants are located are covered by CSAPR. See "Cross-State Air Pollution Rule (CSAPR)" section below.
The Federal EPA issued the final maximum achievable control technology (MACT) standards for coal and oil-fired power plants in 2012. See “Mercury and Other Hazardous Air Pollutants (HAPs) Regulation” section below.
The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) will address regional haze in federal parks and other protected areas. BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. CAVR will be implemented through SIPs or, if SIPs are not adequate or are not developed on schedule, through FIPs. The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas. In March 2012, the Federal EPA disapproved certain portions of the Arkansas regional haze SIP. In April 2015, the Federal EPA published a proposed FIP to replace the disapproved
portions, including revised BART determinations for the Flint Creek Plant that are consistent with the environmental controls currently under construction. In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the CSAPR trading programs to use those programs in place of source-specific BART for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states. This rule is being challenged in the U.S. Court of Appeals for the District of Columbia Circuit. In July 2015, management submitted comments to the proposed Arkansas FIP and participate in comments filed by industry associations of which the AEP System is a member. Management supports compliance with CSAPR programs as satisfaction of the BART requirements.
In 2009, the Federal EPA issued a final mandatory reporting rule for CO2 and other greenhouse gases covering a broad range of facilities emitting in excess of 25,000 tons of CO2 emissions per year. The Federal EPA issued a final endangerment finding for greenhouse gas emissions from new motor vehicles in 2009. The Federal EPA determined that greenhouse gasemissions from stationary sources will be subject to regulation under the CAA beginning January 2011 and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, SIP calls and FIPs. This rule was overturned by the U.S. Supreme Court. The Federal EPA proposed to include CO2 emissions in standards that apply to new and existing electric utility units. See "Climate Change, CO2 Regulation and Energy Policy" section below.
The Federal EPA also issued new, more stringent national ambient air quality standards (NAAQS) for PM, SO2 and ozone. In October 2015, the Federal EPA announced a lower final NAAQS for ozone of 70 parts per billion. States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for facilities as a result of those evaluations. Management cannot currently predict the nature, stringency or timing of those requirements.
Notable developments in significant CAA regulatory requirements affecting the Registrant Subsidiaries' operations are discussed in the following sections.
Cross-State Air Pollution Rule (CSAPR)
In 2011, the Federal EPA issued CSAPR. Certain revisions to the rule were finalized in 2012. CSAPR relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states. Interstate trading of allowances is allowed on a restricted sub-regional basis. Arkansas and Louisiana are subject only to the seasonal NOx program in the rule. Texas is subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program. The annual SO2 allowance budgets in Indiana, Ohio and West Virginia were reduced significantly in the rule. A supplemental rule includes Oklahoma in the seasonal NOx program. The supplemental rule was finalized in December 2011 with an increased NOx emission budget for the 2012 compliance year. The Federal EPA issued a final Error Corrections Rule and further CSAPR revisions in 2012 to make corrections to state budgets and unit allocations and to remove the restrictions on interstate trading in the first phase of CSAPR.
Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit. In 2012, the court issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing CAIR until a replacement rule is finalized. The majority determined that the CAA does not allow the Federal EPA to “overcontrol” emissions in an upwind state and that the Federal EPA exceeded its statutory authority by failing to allow states an opportunity to develop their own implementation plans before issuing a FIP. The petition for review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013. In April 2014, the U.S. Supreme Court issued a decision reversing in part the decision of the U.S. Court of Appeals for the District of Columbia Circuit and remanding the case for further proceedings consistent with the opinion. The Federal EPA filed a motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. The court granted the Federal EPA's motion. The parties filed briefs and presented oral arguments. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit found that the Federal EPA over-controlled the SO2 and/or NOx budgets of 14 states. The U.S. Court of Appeals for the
District of Columbia Circuit remanded the rule to the Federal EPA to timely revise the rule consistent with the court’s opinion while CSAPR remains in place. The Federal EPA is reviewing the decision and will take further action once their review is complete. Separate appeals of the Error Corrections Rule and the further revisions were filed but no briefing schedules have been established.
Mercury and Other Hazardous Air Pollutants (HAPs) Regulation
In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule establishes unit-specific emission rates for units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of nonmercury metals) and hydrogen chloride (as a surrogate for acid gases). In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. The effective date of the final rule was April 16, 2012 and compliance was required within three years. The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and the revised rule provides alternative work practice standards for operators during start-up and shut down periods. Management has obtained a one-year administrative extension at several units to facilitate the installation of controls or to avoid a serious reliability problem. In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades. Management remains concerned about the availability of compliance extensions, the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines and the lack of coordination among the Mercury and Air Toxics Standards (MATS) schedule and other environmental requirements.
Petitions for administrative reconsideration and judicial review of the final rule were filed. In 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards. The Federal EPA issued revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions in March 2013. A final rule on reconsideration was issued in 2014 and a proposed rule containing technical corrections was issued in early 2015. In April 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the April 2012 final rule. Industry trade groups and several states filed petitions for further review in the U.S. Supreme Court and the court granted those petitions in November 2014.
In June 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit and remanded the MATS rule for further proceedings consistent with its decision that the Federal EPA was unreasonable in refusing to consider costs in its determination whether to regulate emissions of HAPs from power plants. The case has been remanded to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings consistent with the U.S. Supreme Court’s decision. Management will continue to evaluate the impact of this decision and until further action by the U.S. Court of Appeals for the District of Columbia Circuit, the rule remains in place.
Climate Change, CO2 Regulation and Energy Policy
Several states have adopted programs that directly regulate CO2 emissions from power plants. The majority of the states where the Registrant Subsidiaries have generating facilities have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions. The Registrant Subsidiaries are taking steps to comply with these requirements, including increasing wind power purchases and broadening the AEP System's portfolio of energy efficiency programs.
In the absence of comprehensive federal climate change or energy policy legislation, President Obama issued a memorandum to the Administrator of the Federal EPA directing the agency to develop and issue a new proposal regulating carbon emissions from new electric generating units under the CAA. The new proposal was issued in September 2013 and requires new large natural gas units to meet a limit of 1,000 pounds of CO2 per MWh of electricity generated and small natural gas units to meet a limit of 1,100 pounds of CO2 per MWh. New coal-fired units are required to meet a limit of 1,100 pounds of CO2 per MWh, with the option to meet a 1,000 pound per MWh limit if they choose to average emissions over multiple years.
The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from modified and reconstructed electric generating units (EGUs) and to issue guidelines for existing EGUs before June 2014, to finalize those standards by June 2015 and to require states to submit plans implementing the guidelines no later than June 2016.
In August 2015, the Federal EPA announced the final standards for new, modified and reconstructed fossil fired steam generating units and combustion turbines, guidelines for the development of state plans to regulate CO2 emissions from existing sources and proposed two options for a federal plan. The rules will become effective 60 days following publication. The final standard for new combustion turbines is 1,000 pounds of CO2 per MWh and the final standard for new fossil steam units is 1,400 pounds of CO2 per MWh. Reconstructed turbines are subject to the same standard as new units and no standard for modified combustion turbines was issued. Reconstructed fossil steam units are subject to a standard of 1,800 pounds of CO2 per MWh for larger units and 2,000 pounds of CO2 per MWh for smaller units. Modified fossil steam units will be subject to a site specific standard no lower than the standards that would be applied if the units were reconstructed.
The final emissions guidelines for existing sources are based on a series of declining performance standards that are implemented beginning in 2022 through 2029. Affected units must achieve a standard of 771 pounds of CO2 per MWh for existing natural gas combined cycle units and 1,305 pounds of CO2 per MWh for existing fossil steam units by 2030. The Federal EPA also developed a set of rate-based and mass-based state goals and has proposed “model” rules that can be adopted by the states that would allow sources within “trading ready” state programs to trade, bank or sell allowances or credits issued by the states or Federal EPA. The Federal EPA intends to finalize either a rate-based or mass-based trading program that can be enforced in states that fail to submit approved plans by the deadlines established in the final guidelines. States are required to submit final plans or an extension request by September 2016 to the Federal EPA. States receiving an extension request must submit final plans by September 2018. Management is reviewing the pre-publication version of the final rule and evaluating the rule’s impacts as well as the anticipated actions by states where assets are located. The final rule was already challenged in the courts and management expects additional lawsuits once the rule is published in the Federal Register.
In 2012, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO2 emissions from new motor vehicles and its plan to phase in regulation of CO2 emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. In June 2014, the U.S. Supreme Court determined that the Federal EPA was not compelled to regulate CO2 emissions from stationary sources under the Title V or PSD programs as a result of its adoption of the motor vehicle standards, but that sources otherwise required to obtain a PSD permit may be required to perform a Best Available Control Technology (BACT) analysis for CO2 emissions if they exceed a reasonable level. The Federal EPA removed those provisions of the final rule from the Code of Federal Regulations that were inconsistent with the U.S. Supreme Court’s decision but continues to apply a 75,000 ton per year threshold to trigger the need for a BACT analysis. Petitions were filed with the U.S. Court of Appeals for the District of Columbia Circuit seeking to amend the judgment in the case to require Federal EPA to establish a reasonable minimumlevel. Those petitions were denied.
Federal and state legislation or regulations that mandate limits on the emission of CO2 could result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force the Registrant Subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets.
Coal Combustion Residual Rule
In 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The proposed rule contained two alternative proposals. One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management. Both proposals would impose stringent requirements for the construction of new coal ash landfills and existing unlined surface impoundments.
In the final rule, the Federal EPA elected to regulate CCR as a non-hazardous solid waste and issued new minimum federal solid waste management standards. On the effective date, the rule applies to new and existing active CCR landfills and CCR surface impoundments at operating electric utility or independent power production facilities. The rule imposes new and additional construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements. The rule does not apply to inactive CCR landfills and inactive surface impoundments at retired generating stations or the beneficial use of CCR. The rule is self-implementing so state action is not required. Because of this self-implementing feature, the rule contains extensive record keeping, notice and internet posting requirements. Because the Registrant Subsidiaries currently use surface impoundments and landfills to manage CCR materials at the generating facilities, they will incur significant costs to upgrade or close and replace these existing facilities at some point in the future as the new rule is implemented.
In February 2014, the Federal EPA completed a risk evaluation of the beneficial uses of coal fly ash in concrete and FGD gypsum in wallboard and concluded that the Federal EPA supports these beneficial uses. Currently, approximately 40% of the coal ash and other residual products from the AEP System's generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses. Encapsulated beneficial uses are not materially impacted by the new rule but additional demonstrations may be required to continue land applications in significant amounts except in road construction projects.
The final rule was published in the Federal Register in April 2015 and becomes effective six months after publication. The final rule provides for a staggered compliance schedule for the implementation of the rule’s many requirements. Management recorded a $45 million increase in asset retirement obligations in the second quarter of 2015 primarily due to the publication of the final rule. Given the schedule for implementation, management will continue to evaluate the rule's impact on operations.
Clean Water Act (CWA) Regulations
In 2014, the Federal EPA issued a final rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress. The final rule affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to comply with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures at facilities withdrawing more than 125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, are not expected to require any technology changes. Facilities subject to both the impingement standard and site-specific entrainment studies will typically be given at least three years to conduct and submit the results of those studies to the permit agency. Compliance timeframes will then be established by the permit agency through each facility’s National Pollutant Discharge Elimination System (NPDES) permit for installation of any required technology changes, as those permits are renewed over the next five to eight years. Petitions for review of the final rule were filed by industry and environmental groups and are currently pending in the U.S. Court of Appeals for the Second Circuit.
In addition, the Federal EPA developed revised effluent limitation guidelines for electricity generating facilities. A pre-publication copy of the final rule was announced and made available in September 2015. In addition to other requirements, in the final rule the Federal EPA establishes limits on flue gas desulfurization wastewater, zero discharge for fly ash and bottom ash transport water and flue gas mercury control wastewater. Compliance with the final rule is as soon as possible after November 2018 and no later than December 2023. These new requirements will be implemented through each facility’s wastewater discharge permit. Management will continue to review the final rule in detail to evaluate whether the plants are currently meeting the proposed limitations, what technologies have been incorporated into the long-range plans and what additional costs might be incurred.
In June 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This jurisdictional definition applies to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are: permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. The final definition continues to recognize traditional navigable waters of the U.S. as jurisdictional as well as certain exclusions. The rule also contains a number of new specific definitions and criteria for determining whether certain other waters are jurisdictional because of a “significant nexus." Management believes that clarity and efficiency in the permitting process is needed. Management remains concerned that the rule introduces new concepts and could subject more of the operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. The final rule is being challenged in both courts of appeal and district courts. Challengers include industry associations of which the AEP System is a member. The U.S. Court of Appeal for the Sixth Circuit has granted a nationwide stay of the rule pending jurisdictional determinations.
ACCOUNTING PRONOUNCEMENTS
New Accounting Pronouncements Adopted During the First Quarter of 2015
The FASB issued ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. Management adopted ASU 2014-08 effective January 1, 2015. There were no events requiring application of the new accounting guidance.
Pronouncements Effective in the Future
The FASB issued ASU 2014-09 “Revenue from Contracts with Customers” clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted for annual periods beginning after December 15, 2016. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018.
The FASB issued ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. Management plans to adopt ASU 2015-01 effective January 1, 2016.
The FASB issued ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” to simplify the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The Registrant Subsidiaries include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management intends to early adopt ASU 2015-03 for the 2015 Form 10-K.
The FASB issued ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-05 effective January 1, 2016.
The FASB issued ASU 2015-11 “Simplifying the Measurement of Inventory” to simplify the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-11 effective January 1, 2017.
The FASB issued ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. Management has analyzed the impact of this new standard and determined that it will have no impact on the accounting of the Registrant Subsidiaries' contracts. Additionally, adoption has no impact on net income. Management adopted ASU 2015-13 upon its issuance date.
Future Accounting Changes
The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, management cannot determine the impact on the reporting of the Registrant Subsidiaries’ operations and financial position that may result from any such future changes. The FASB is currently working on several projects including financial instruments, leases, insurance, hedge accounting, consolidation policy and balance sheet classification of deferred taxes. The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.
CONTROLS AND PROCEDURES
During the third quarter of 20152016, management, including the principal executive officer and principal financial officer of each of AEP, APCo, I&M, OPCo, PSO and SWEPCo (collectively, the Registrants),Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
As of September 30, 2015,2016, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.
There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the third quarter of 20152016 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 5 incorporated herein by reference.
Item 1A. Risk Factors
The Annual Report on Form 10-K for the year ended December 31, 20142015 includes a detailed discussion of risk factors. As of September 30, 2015,2016, there have been no material changes to the risk factors previously disclosed in the 20142015 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None
Item 4. Mine Safety Disclosures
The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of DHLC and AGR and KPCo, through their use of the Conner Run fly ash impoundment, arewas subject to the provisions of the Mine Act.Act for the quarter ended September 30, 2016.
The Dodd-Frank Wall Street Reform and Consumer Protection Act and its related regulations require companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 contains the notices of violation and proposed assessments received by DHLC and Conner Run under the Mine Act for the quarter ended September 30, 2015.2016.
Item 5. Other Information
None
Item 6. Exhibits
10(a) – AEP Long-Term Incentive Plan Amended and Restated as of September 21, 2016
10(b) – Purchase and Sale Agreement by and among AEP Generation Resources Inc., AEP Generating Company and Burgandy Power LLC dated as of September 13, 2016
10(c) – Change in Control Agreement
10(d) – Executive Severance Plan
12 – Computation of Consolidated Ratio of Earnings to Fixed Charges
31(a) – Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31(b) – Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32(a) – Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
32(b) – Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
95 – Mine Safety Disclosures
101.INS – XBRL Instance Document
101.SCH – XBRL Taxonomy Extension Schema
101.CAL – XBRL Taxonomy Extension Calculation Linkbase
101.DEF – XBRL Taxonomy Extension Definition Linkbase
101.LAB – XBRL Taxonomy Extension Label Linkbase
101.PRE – XBRL Taxonomy Extension Presentation Linkbase
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/ Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer
APPALACHIAN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY
By: /s/ Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer
Date: October 22, 2015November 1, 2016