UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
 
FORM 10-K
 
(Mark One)

T
xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended December 31, 20122015

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from __________ to_________

Commission
File Number
 
Registrants; States of Incorporation;
Address and Telephone Number
 
I.R.S. Employer
Identification Nos.
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)
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 716-1000
 72-0323455

Securities registered pursuant to Section 12(b) of the Act:

 
Registrant
 
 
Title of each class
 
Name of Each Exchange
on Which Registered
American Electric Power Company, Inc. Common Stock, $6.50 par value New York Stock Exchange
Appalachian Power Company None  
Indiana Michigan Power Company None  
Ohio Power Company None  
Public Service Company of Oklahoma None  
Southwestern Electric Power Company None  





Securities registered pursuant to Section 12(g) of the Act:  None


Indicate by check mark if the registrant American Electric Power Company, Inc. is a well-known seasoned issuer, as defined in Rule 405 onof the Securities Act.
Yes Tx
No  o
   
Indicate by check mark if the registrants Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are well-known seasoned issuers, as defined in Rule 405 onof the Securities Act.
Yes  o
No  Tx
   
Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
Yes  o
No  Tx
   
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Yes Tx
No  o
   
Indicate by check mark whether 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 have submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes Tx
No  o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.Tx 
   
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 definitions of ‘large accelerated filer’, ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act.  (Check One)  
Large accelerated filerTxAccelerated filero
Non-accelerated filer
Accelerated filer                                         o
Non-accelerated filer                                             o (Do not check if a smaller reporting company)
Smaller reporting company
o
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 definitions of ‘large accelerated filer’, ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act.  (Check One)
Large accelerated fileroAccelerated filero 
Large acceleratedNon-accelerated filero
Accelerated filer                                         xo
Non-accelerated filer                                            T (Do not check if a smaller reporting company)
Smaller reporting company
o
Indicate by check mark if the registrants are shell companies, as defined in Rule 12b-2 of the Exchange Act.
Yes  o
No  Tx

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 I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K.






 Aggregate Market Value of Voting and Non-Voting Common Equity Held by Non-Affiliates of the Registrants as of June 30, 2012, the Last Trading Date of the Registrants’ Most Recently Completed Second Fiscal Quarter 
 
Number of Shares of Common Stock Outstanding of the Registrants at
December 31, 2012
 Aggregate Market Value of Voting and Non-Voting Common Equity Held by Non-Affiliates of the Registrants as of June 30, 2015 the Last Trading Date of the Registrants' Most Recently Completed Second Fiscal Quarter Number of Shares of Common Stock Outstanding of the Registrants as of December 31, 2015
American Electric Power Company, Inc. $19,378,167,963 485,668,370 $26,011,055,215 491,052,581
   ($6.50 par value)   ($6.50 par value)
Appalachian Power Company None 13,499,500 None 13,499,500
   (no par value)   (no par value)
Indiana Michigan Power Company None 1,400,000 None 1,400,000
   (no par value)   (no par value)
Ohio Power Company None 27,952,473 None 27,952,473
   (no par value)   (no par value)
Public Service Company of Oklahoma None 9,013,000 None 9,013,000
   ($15 par value)   ($15 par value)
Southwestern Electric Power Company None 7,536,640 None 7,536,640
   ($18 par value)   ($18 par value)

Note On Market Value Of Common Equity Held By Non-Affiliates

American Electric Power Company, Inc. owns all of the common stock of Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company (see Item 12 herein).






Documents Incorporated By Reference

Description Part of Form 10-K into which Document is Incorporated
   
Portions of Annual Reports of the following companies for
the fiscal year ended December 31, 2012:
2015:
 Part II
American Electric Power Company, Inc.
  
Appalachian Power Company
  
Indiana Michigan Power Company
  
Ohio Power Company
  
Public Service Company of Oklahoma
  
Southwestern Electric Power Company
  
   
Portions of Proxy Statement of American Electric Power Company, Inc. for 20132016 Annual Meeting of Shareholders. Part III

This combined Form 10-K 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.  Except for American Electric Power Company, Inc., each registrant makes no representation as to information relating to the other registrants.

You can access financial and other information at AEP’s website, including AEP’s Principles of Business Conduct (which also serves as a code of ethics applicable to Item 10 of this Form 10-K), certain committee charters and Principles of Corporate Governance.  The address is www.AEP.com.  AEP makes available, free of charge on its website, copies of its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC.






TABLE OF CONTENTS
Item
Number
 
Page
Number
 Glossary of Termsi
   
 Forward-Looking Informationiii
PART I
1Business1
 General1
 Utility Operations11
 Transmission Operations22
 AEP River Operations24
 Generation and Marketing25
 Executive Officers of AEP26
1ARisk Factors27
1BUnresolved Staff Comments39
2Properties39
 Generation Facilities39
 Transmission and Distribution Facilities42
 Title to Property43
 System Transmission Lines and Facility Siting43
 Construction Program43
 Potential Uninsured Losses44
3Legal Proceedings44
4Mine Safety Disclosure44
   
PART II
5
Market for Registrants’ Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities
 
45
6Selected Financial Data45
7
Management’s Discussion and Analysis of Financial Condition and
Results of Operations
 
45
7AQuantitative and Qualitative Disclosures about Market Risk45
8Financial Statements and Supplementary Data46
9
Changes In and Disagreements with Accountants on Accounting
and Financial Disclosure
 
46
9AControls and Procedures46
9BOther Information46
PART III
10Directors, Executive Officers and Corporate Governance47
11Executive Compensation47
12Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
48
13Certain Relationships and Related Transactions and Director Independence48
14Principal Accounting Fees and Services48
PART IV
15Exhibits and Financial Statement Schedules50
 Financial Statements50
 Signatures51
 Index of Financial Statement SchedulesS-1
 Reports of Independent Registered Public Accounting FirmS-2
 Exhibit IndexE-1

Item
Number
 
Page
Number
 
 
   
1 
 
 
 
 
 AEP Transmission Holdco
 Generation & Marketing
 
 
1A
1B
2
 
 
 
 
 
 
3
4
   
PART II
5Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
6
7Management’s Discussion and Analysis of Financial Condition and Results of Operations
7A
8
9
9AControls and Procedures
9BOther Information
   
 PART III 
10Directors, Executive Officers and Corporate Governance
11Executive Compensation
12
13
14
   
15
 
 
 
 
 





GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:below.

Term Meaning
   
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.company which includes American Electric Power Company, Inc. (Parent) and majority owned consolidated subsidiaries and consolidated affiliates.
AEP East CompaniesEnergy APCo, I&M, KPCoAEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and OPCo.other deregulated electricity markets throughout the United States.
AEP River Operations AEP’s inland river transportation subsidiary, AEP River Operations LLC, operating primarily on the Ohio, Illinois and lower Mississippi rivers.
AEP System American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utilityAEP subsidiaries.
AEP West CompaniesPSO, SWEPCo, TCC and TNC.
AEP Utilities AEP Utilities, Inc., a subsidiary of AEP, formerly, Central and South West Corporation.a holding company for TCC, TNC and interest in ETT.
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 AEPTHCo, an intermediate holding company that owns seven wholly-owned transmission companies.
AEPTHCoAEP Transmission Holding Company, LLC, a subsidiary of AEP, an intermediate holding company for seven wholly-ownedthat owns transmission companies.operations joint ventures and AEPTCo.
AFUDC Allowance for Funds Used During Construction.
AGRAEP Generation Resources Inc., a nonregulated AEP subsidiary in the Generation & Marketing segment.
APCo Appalachian Power Company, an AEP electric utility subsidiary.
APSCArkansas Public Service Commission.
BuckeyeBuckeye Power, Inc., a nonaffiliated corporation.
CAA Clean Air Act.
Clean Power PlanGuidelines regulating CO2 emissions from existing sources published by Federal EPA in October 2015; its implementation was stayed by the U.S. Supreme Court in February 2016.
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 providerCompetitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service.
CSPCo Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
CSWCentral and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Operating AgreementAgreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third party sales.  AEPSC acts as the agent.
EPACT The Energy Policy Act of 2005.
ERCOT Electric Reliability Council of Texas regional transmission organization.
ESPElectric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETT Electric Transmission Texas, LLC, an equity interest joint venture between AEPParent and MidAmericanBerkshire Hathaway Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FERCFederal Energy Regulatory Commission.
Federal EPA United States Environmental Protection Agency.
Interconnection AgreementFERC An agreement by and among APCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
IURCIndiana UtilityFederal Energy Regulatory Commission.
I&M Indiana Michigan Power Company, an AEP electric utility subsidiary.
IMTCoAEP Indiana Michigan Transmission Company, Inc.
IURCIndiana Utility Regulatory Commission.
KGPCo Kingsport Power Company, an AEP electric utility subsidiary.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSCkV Kentucky Public Service Commission.
KWhKilowatthour.
LPSCLouisiana Public Service Commission.Kilovolt.
MISO Midwest Independent Transmission System Operator.
i

TermMMBtu Meaning
MPSCMichigan Public Service Commission.Million British Thermal Units.
MW Megawatt.
MWhMegawatthour.
NOx
 Nitrogen oxide.
Nonutility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.

i



TermMeaning
NRC Nuclear Regulatory Commission.
OATT Open Access Transmission Tariff, filed with FERC.Tariff.
OCC Corporation Commission of the State of Oklahoma.
OHTCo AEP Ohio Transmission Company, Inc.
OKTCo AEP Oklahoma Transmission Company, Inc.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
OVEC Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
ParentAmerican Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PJM Pennsylvania – New Jersey – Maryland regional transmission organization.
PMParticulate Matter.
PSO Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO Public Utilities Commission of Ohio.
PUCT Public Utility Commission of Texas.
Registrant SubsidiariesAEP subsidiaries which are SEC registrants: APCo, I&M, OPCo, PSO and SWEPCo.
RegistrantsSEC registrants: AEP, APCo, I&M, OPCo, PSO and SWEPCo.
REP Texas Retail Electric Provider.
Rockport Plant A generatinggeneration plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana, owned byIndiana.  AEGCo and I&M.&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.
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.
SO2
 Sulfur dioxide.
SPP Southwest Power Pool regional transmission organization.
SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary.
TA Transmission Agreement, dated April 1, 1984,effective November 2010, among APCo, I&M, KGPCo, KPCo, OPCo and OPCoWPCo with AEPSC as agent.
TCA Transmission Coordination Agreement dated January 1, 1997, by and among, PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two public utility subsidiaries.
TCC AEP Texas Central Company, an AEP electric utility subsidiary.
TNC AEP Texas North Company, an AEP electric utility subsidiary.
Utility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
Virginia SCC Virginia State Corporation Commission.
WPCo Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC Public Service Commission of West Virginia.


ii



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,” 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:

·
ŸThe economic climate, growth or contraction within and changes in market demand and demographic patterns in ourAEP service territory.territories.
·ŸInflationary or deflationary interest rate trends.
·ŸVolatility in the financial markets, particularly developments affecting the availability or cost of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.debt.
·ŸThe 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.
·ŸElectric load, customer growth and the impact of competition, including competition for retail competition, particularly in Ohio.customers.
·ŸWeather conditions, including storms and drought conditions, and ourthe ability to recover significant storm restoration costs through applicable rate mechanisms.costs.
·ŸAvailable sourcesThe cost of fuel and costs of, andits transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·ŸAvailability of necessary generatinggeneration capacity and the performance of our generatinggeneration plants.
·ŸOurThe ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·ŸOurThe ability to build or acquire generating capacity and 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 (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.costs.
·ŸNew 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, and cost recovery and/or profitability of ourgeneration plants and related assets.
·ŸEvolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
·ŸA reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
·ŸTiming 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.
·ŸResolution of litigation.
·ŸOurThe ability to constrain operation and maintenance costs.
·ŸOurThe ability to develop and execute a strategy based on a view regarding prices of electricity coal, natural gas and other energy-related commodities.
·ŸPrices and demand for power that we generategenerated and sellsold at wholesale.
·ŸChanges in technology, particularly with respect to new, developing, alternative or alternativedistributed sources of generation.
·ŸOurThe ability to recover through rates or market prices any remaining unrecovered investment in generatinggeneration units that may be retired before the end of their previously projected useful lives.
·ŸVolatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas and other energy-related commodities.capacity auction returns.
iii

·ŸChanges in utility regulation including the implementation of ESPs and the transition to market and expected legal separation for generation in Ohio and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP.
·ŸOurThe market for generation in Ohio and PJM and the ability to recover investments in Ohio generation assets.
ŸThe ability to successfully and profitably manage negotiations with stakeholders and obtain regulatory approval to terminatecompetitive generation assets, including the Interconnection Agreement.evaluation of strategic alternatives for these assets as some of the alternatives could result in a loss.

iii



·
ŸChanges in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·ŸActions of rating agencies, including changes in the ratings of our debt.
·ŸThe 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.
·ŸAccounting pronouncements periodically issued by accounting standard-setting bodies.
·ŸOther risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

The forward looking statements of AEP and its Registrant Subsidiaries speak only as of the date of this report or as of the date they are made.  AEP and its Registrant SubsidiariesThe forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made.  The 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 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.

iv

iv



PART I

ITEM 1.   BUSINESS

GENERAL

Overview and Description of Material Subsidiaries

AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company that owns, directly or indirectly, all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries.

The service areas of AEP’s public utility subsidiaries cover portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. The generating and transmission facilities of AEP’s public utility subsidiaries are interconnected and their operations are coordinated.  Transmission networks are interconnected with extensive distribution facilities in the territories served. The public utility subsidiaries of AEP have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Restructuring legislationlaws in Michigan, Ohio and the ERCOT area of Texas hashave caused AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers.  In Ohio, AEP’s regulated utility operates its distribution and transmission assets while its former generation assets are owned and operated by affiliates.

The AEP System is an integrated electric utility system.  As a result, the member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The companies of the AEP System also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC.

As of December 31, 2012,2015, the subsidiaries of AEP had a total of 18,51317,405 employees. Because it is a holding company rather than an operating company, AEP has no employees. The public utilitymaterial subsidiaries of AEP are:

APCo

Organized in Virginia in 1926, APCo is engaged in the generation, transmission and distribution of electric power to approximately 960,000957,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. APCo owns 6,650 MW of generating capacity.  APCo uses its generation to serve its retail and other customers.  As of December 31, 2012,2015, APCo had 2,1281,836 employees. Among the principal industries served by APCo are paper, rubber, coal mining, textile mill products and stone, clay and glass products. In addition to its AEP System interconnections, APCo is interconnected with the following nonaffiliated utility companies: Carolina Power & Light Company, Duke Carolina and Virginia Electric and Power Company.  APCo has several points of interconnection with Tennessee Valley Authority (TVA) and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems.  APCo is a member of PJM.  APCo is part of AEP’s Vertically Integrated Utilities segment.

I&M

Organized in Indiana in 1907, I&M is engaged in the generation, transmission and distribution of electric power to approximately 584,000588,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants.  I&M owns or leases 3,523 MW of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2012,2015, I&M had 2,6492,489 employees. Among the principal industries served are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and chemicals and allied products, rubber products and transportation equipment.  In addition to its AEP System interconnections, I&M is interconnected with the following nonaffiliated utility companies: Central Illinois Public Service Company, Duke Energy Ohio, Inc., Commonwealth Edison Company, Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, Duke Indiana and Richmond Power & Light Company.  I&M is a member of PJM.  I&M is part of AEP’s Vertically Integrated Utilities segment.


1

1



KPCo

Organized in Kentucky in 1919, KPCo is engaged in the generation, transmission and distribution of electric power to approximately 173,000170,000 retail customers in an area in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants.  KPCo owns 1,058 MW of generating capacity.  KPCo uses its generation to serve its retail and other customers.  As of December 31, 2012,2015, KPCo had 392558 employees. Among the principal industries served are petroleum refining, coal mining and chemical production.  In addition to its AEP System interconnections, KPCo is interconnected with the following nonaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc.  KPCo is also interconnected with TVA.  KPCo is a member of PJM.  KPCo is part of AEP’s Vertically Integrated Utilities segment.

KGPCo

Organized in Virginia in 1917, KGPCo provides electric service to approximately 47,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. KGPCo does not own any generating facilities and is a member of PJM. It purchases electric power from APCo for distribution to its customers. As of December 31, 2012,2015, KGPCo had 5452 employees. KGPCo is part of AEP’s Vertically Integrated Utilities segment.

OPCo

Organized in Ohio in 1907 and re-incorporated in 1924, OPCo is engaged in the generation, transmission and distribution of electric power to approximately 1,459,0001,468,000 retail customers in Ohio,Ohio.  Following corporate separation of OPCo’s generation assets in December 2013, OPCo purchases energy and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants.  OPCo also provides generation capacity to support shopping customer load, and will do so through mid-2015.serve generation service customers.  As of December 31, 2012,2015, OPCo had 3,1311,552 employees.  We have already obtained PUCO authorization for corporate separation and currently we are seeking regulatory approval from the FERC to transfer OPCo's generation assets to a newly formed wholly owned competitive Ohio generation affiliate as of January 1, 2014.  Following this transaction, OPCo will continue to own transmission and distribution assets and to provide transmission and distribution services to its customers in Ohio.  Among the principal industries served by OPCo are primary metals, chemicals and allied products, health services, electronic machinery, petroleum refining, and rubber and plastic products. In addition to its AEP System interconnection, OPCo is interconnected with the following nonaffiliated utility companies: Duke Ohio, The Cleveland Electric Illuminating Company, Dayton Power and Light Company, Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power Company.  OPCo is a member of PJM.  OPCo is part of AEP’s Transmission and Distribution Utilities segment.

PSO

Organized in Oklahoma in 1913, PSO is engaged in the generation, transmission and distribution of electric power to approximately 535,000545,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants.  PSO owns 4,432 MW of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2012,2015, PSO had 1,1271,134 employees. Among the principal industries served by PSO are paper manufacturing and timber products, natural gas and oil extraction, transportation, non-metallic mineral production, oil refining and steel processing. In addition to its AEP System interconnections, PSO is interconnected with Empire District Electric Company, Oklahoma Gas and Electric Company, Southwestern Public Service Company and Westar Energy, Inc.  PSO is a member of SPP.  PSO is part of AEP’s Vertically Integrated Utilities segment.

SWEPCo

Organized in Delaware in 1912, SWEPCo is engaged in the generation, transmission and distribution of electric power to approximately 524,000531,000 retail customers in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. SWEPCo owns 5,798 MW of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2012,2015, SWEPCo had 1,4721,483 employees. Among the principal industries served by SWEPCo are natural gas and oil production, petroleum refining, manufacturing of pulp and paper, chemicals, food processing and metal refining. The territory served by SWEPCo also includes several military installations, colleges and universities. SWEPCo also owns and operates a lignite coal mining operation. In addition to its AEP System interconnections, SWEPCo is interconnected with Central Louisiana Electric Company, Empire District Electric Company, Entergy Corp. and Oklahoma Gas & Electric Company.  SWEPCo is a member of SPP.

  SWEPCo is part of AEP’s Vertically Integrated Utilities segment.
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TCC

Organized in Texas in 1945, TCC is engaged in the transmission and distribution of electric power to approximately 799,000826,000 retail customers through REPs in southern Texas. TCC sold all of its generation assets.  As of December 31, 2012,2015, TCC had 9961,085 employees. Among the principal industries served by TCC are chemical and petroleum refining, chemicals and allied products, oil and natural gas extraction, food processing, metal refining, plastics and machinery equipment. In addition to its AEP System interconnections, TCC is a member of ERCOT. TCC is part of AEP’s Transmission and Distribution Utilities segment.


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TNC

Organized in Texas in 1927, TNC is engaged in the transmission and distribution of electric power to approximately 187,000189,000 retail customers through REPs in west and central Texas. TNC’s generating capacity has been transferred to an affiliate at TNC’s cost pursuant to an agreement effective through 2027. As of December 31, 2012,2015, TNC had 319346 employees. Among the principal industries served by TNC are petroleum refining, agriculture and the manufacturing or processing of cotton seed products, oil products, precision and consumer metal products, meat products and gypsum products. The territory served by TNC also includes several military installations and correctional facilities. In addition to its AEP System interconnections, TNC is a member of ERCOT.  TNC is part of AEP’s Transmission and Distribution Utilities segment.

WPCo

Organized in West Virginia in 1883 and reincorporated in 1911, WPCo provides electric service to approximately 41,000 retail customers in northern West Virginia. On January 31, 2015, WPCo does not own anyacquired an interest in a 780 MW generating facilities.unit owned by AGR. WPCo is a member of PJM. It purchasesPrior to acquiring the 780 MW generating unit interest, WPCo purchased electric power from OPCoAGR for distribution to its customers. As of December 31, 2012,2015, WPCo had 5156 employees.  In December 2011, APCo and WPCo filed an application with the WVPSC requesting approval to merge WPCo into APCo.  In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC.  A hearing at the Virginia SCC is scheduled for April 2013.part of AEP’s Vertically Integrated Utilities segment.

AEGCo

Organized in Ohio in 1982, AEGCo is an electric generating company. AEGCo owns 2,496 MW of generating capacity.  AEGCo sells power at wholesale to OPCo,AGR, I&M and KPCo. AEGCo has nogranted AGR the rights to the power generated at the Lawrenceburg facility, a 1,186 MW natural gas-fired generating unit, pursuant to a unit power agreement through 2017. As of December 31, 2015, AEGCo had 73 employees.  AEGCo is part of AEP’s Vertically Integrated Utilities segment.

AGR

Organized in Delaware in 2011, AGR is a competitive generation company that generates power and sells it into the market.  AGR also engages in power trading activities.  Pursuant to a Power Supply Agreement (PSA) between AGR and OPCo, AGR supplied capacity for OPCo’s switched and non-switched retail load for the period January 1, 2014 through May 31, 2015.  AGR owns 6,752 MW of generating capacity, with rights to an additional 1,186 MW pursuant to a unit power agreement with AEGCo through 2017. As of December 31, 2015, AGR had 857 employees.  AGR is part of AEP’s Generation & Marketing segment.

AEPTHCo

Organized in Delaware in 2012, AEPTHCo is a holding company for AEP’s transmission operations joint ventures.  AEPTHCo also owns AEPTCo, a holding company for seven FERC-regulated transmission-only electric utilities, each of which is geographically aligned with AEP’s existing utility operating companies. The transmission companies develop and own new transmission assets that are physically connected to the AEP System.  Individual transmission companies have obtained the approvals necessary to operate in Indiana, Kentucky, Michigan, Ohio, Oklahoma and West Virginia, subject to any applicable siting requirements, and are authorized to submit projects for commission approval in Virginia. The application for regulatory approval to operate in Louisiana is under consideration, while the application for regulatory approval to operate in Arkansas was denied. Neither AEPTCo nor its subsidiaries have any employees. Instead, AEPSC and certain AEP utility subsidiaries provide the services required by these entities. AEPTCo is part of the AEP Transmission Holdco segment.


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Service Company Subsidiary

AEP also owns a service company subsidiary, AEPSC. AEPSC provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to the AEP affiliated companies.subsidiaries. The executive officers of AEP and certain of its public utility subsidiaries are employees of AEPSC. As of December 31, 2012,2015, AEPSC had 4,7875,622 employees.

AEPTCoThe following table illustrates certain regulatory information with respect to the states in which the public utility subsidiaries of AEP operate:
Jurisdiction Percentage of AEP System Retail Revenues (a) AEP Utility Subsidiaries Operating in that Jurisdiction Authorized Return on Equity (b)
Ohio 24% OPCo 10.20%
       
Texas 14% TCC 9.96%
    TNC 9.96%
    SWEPCo 9.65%
       
Virginia 12% APCo 9.70%
       
West Virginia 12% APCo 9.75%
    WPCo 9.75%
       
Oklahoma 11% PSO 9.85%
       
Indiana 11% I&M 10.20%
       
Louisiana 5% SWEPCo 10.00%
       
Kentucky 5% KPCo 10.25%
       
Arkansas 3% SWEPCo 10.25%
       
Michigan 2% I&M 10.20%
       
Tennessee 1% KGPCo 12.00%

(a)Represents the percentage of public utility subsidiaries revenue from sales to retail customers to total public utility subsidiaries revenue for the year ended December 31, 2015.
(b)Identifies the predominant authorized return on equity and may not include other, less significant, permitted recovery.  Actual return on equity varies from authorized return on equity.
This wholly-owned intermediate holding company holds our seven transmission companies.  The transmission companies are geographically aligned with our existing operating companies and develop and own new transmission assets that are physically connected to AEP’s system.  Individual transmission companies have obtained the approvals necessary to operate in Indiana, Michigan, Ohio, Oklahoma and West Virginia, subject to any applicable siting requirements, and are authorized to submit projects for commission approval in Virginia.  Applications for transmission companies are pending with the applicable commissions in Arkansas, Kentucky and Louisiana.  Neither AEPTCo nor the transmission companies have any employees.  Instead, AEPSC and certain of our utility subsidiaries provide the services required by these entities.


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3



CLASSES OF SERVICE

The principal classes of service from which the public utility subsidiaries of AEP derive revenues and the amount of such revenues during the yearyears ended December 31, 20122015, 2014 and 2013 are as follows:
  Years Ended December 31,
Description 2015 2014 2013
  (in millions)
Vertically Integrated Utilities Segment      
Retail Revenues  
  
  
Residential Sales $3,295.4
 $3,328.5
 $3,216.4
Commercial Sales 2,057.7
 2,032.7
 2,002.4
Industrial Sales 2,096.9
 2,124.5
 2,028.7
PJM Net Charges (0.7) (61.8) 9.3
Provision for Rate Refund 61.5
 (1.7) (15.6)
Other Retail Sales 177.4
 181.9
 172.4
Total Retail Revenues 7,688.2
 7,604.1
 7,413.6
Wholesale Revenues  
  
  
Off-System Sales 1,051.2
 1,529.9
 1,670.9
Transmission 192.2
 113.4
 132.7
Total Wholesale Revenues 1,243.4
 1,643.3
 1,803.6
Other Electric Revenues 110.4
 124.7
 89.7
Other Operating Revenues 27.9
 24.7
 39.7
Sales to Affiliates 102.3
 87.6
 645.9
Total Revenues Vertically Integrated Utilities Segment $9,172.2
 $9,484.4
 $9,992.5
       
Transmission and Distribution Utilities Segment  
  
  
Retail Revenues  
  
  
Residential Sales $2,213.1
 $2,313.1
 $2,164.5
Commercial Sales 1,170.0
 1,178.4
 1,161.1
Industrial Sales 512.5
 502.7
 549.0
PJM Net Charges 
 47.5
 21.3
Provision for Rate Refund 
 (11.9) 22.1
Other Retail Sales 37.7
 39.6
 38.8
Total Retail Revenues 3,933.3
 4,069.4
 3,956.8
Wholesale Revenues      
Off-System Sales 106.1
 143.0
 30.8
Transmission 286.0
 277.7
 227.7
Total Wholesale Revenues 392.1
 420.7
 258.5
Other Electric Revenues 52.7
 51.5
 56.1
Other Operating Revenues 13.9
 11.0
 7.7
Sales to Affiliates 164.6
 261.0
 199.3
Total Revenues Transmission and Distribution Utilities Segment $4,556.6
 $4,813.6
 $4,478.4
       
AEP Transmission Holdco Segment      
Transmission Revenues $100.3
 $73.9
 $26.8
Other Operating Revenues 0.3
 
 
Sales to Affiliates 228.6
 118.0
 50.9
Total Revenues AEP Transmission Holdco Segment $329.2
 $191.9
 $77.7
       
Generation & Marketing Segment  
  
  
Generation Revenues  
  
  
Affiliated $484.9
 $1,306.5
 $2,457.1
Nonaffiliated 1,544.5
 1,396.9
 314.4
Trading, Marketing and Retail Revenues  
  
  
Affiliated 61.1
 158.8
 0.1
Nonaffiliated 1,299.8
 961.9
 868.1
Wind Generation Revenues    
  
Nonaffiliated 22.4
 25.5
 25.5
Total Revenues Generation & Marketing Segment $3,412.7
 $3,849.6
 $3,665.2


Description AEP System (a) APCo I&M OPCo PSO SWEPCo
      (in thousands)
Utility Operations                  
 Retail Sales                  
  Residential Sales $ 5,114,000  $ 1,159,576  $ 505,142  $ 1,636,808  $ 512,372  $ 512,578 
  Commercial Sales   3,216,000    576,153    377,302    945,233    331,125    404,204 
  Industrial Sales   2,772,000    701,603    430,042    742,235    209,446    298,604 
  PJM Net Charges   (43,000)   (13,049)   (9,003)   (18,831)   -    - 
  Provision for Rate Refund   (5,000)   -    -    (2,577)   -    (1,207)
  Other Retail Sales   205,000    72,455    6,508    18,113    70,894    8,074 
   Total Retail   11,259,000    2,496,738    1,309,991    3,320,981    1,123,837    1,222,253 
 Wholesale                  
  Off-System Sales   1,909,000    409,527    481,000    661,513    37,484    247,118 
  Transmission   301,000    14,059    2,092    10,114    30,669    48,404 
   Total Wholesale   2,210,000    423,586    483,092    671,627    68,153    295,522 
 Other Electric Revenues   158,000    28,438    16,986    29,508    14,593    20,758 
 Other Operating Revenues   50,000    9,970    4,582    19,385    3,752    1,860 
 Sales to Affiliates   -    318,199    385,460    886,695    22,603    37,441 
   Total Utility Operating Revenues   13,677,000    3,276,931    2,200,111    4,928,196    1,232,938    1,577,834 
Other   1,268,000    -    -    -    -    - 
Total Revenues $ 14,945,000  $ 3,276,931  $ 2,200,111  $ 4,928,196  $ 1,232,938  $ 1,577,834 
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APCo
  Years Ended December 31,
Description 2015 2014 2013
  (in millions)
Retail Revenues  
  
  
Residential Sales $1,228.3
 $1,257.3
 $1,219.7
Commercial Sales 584.6
 585.9
 583.8
Industrial Sales 657.1
 690.4
 697.0
PJM Net Charges (0.2) 13.5
 5.0
Provision for Rate Refund 25.2
 (6.1) 
Other Retail Sales 79.4
 82.5
 77.2
Total Retail Revenues 2,574.4
 2,623.5
 2,582.7
Wholesale Revenues  
  
  
Off-System Sales 136.0
 191.2
 433.6
Transmission 53.5
 26.9
 21.0
Total Wholesale Revenues 189.5
 218.1
 454.6
Other Electric Revenues 41.7
 57.8
 22.3
Total Electric Generation, Transmission and Distribution Revenues 2,805.6
 2,899.4
 3,059.6
Sales to Affiliates 147.8
 144.5
 347.5
Other Revenues 10.1
 9.2
 10.3
Total Revenues $2,963.5
 $3,053.1
 $3,417.4

(a)Includes revenues of other subsidiaries not shown.  Intercompany transactions have been eliminated for the year ended December 31, 2012.
I&M
  Years Ended December 31,
Description 2015 2014 2013
  (in millions)
Retail Revenues  
  
  
Residential Sales $591.0
 $588.4
 $565.8
Commercial Sales 416.7
 390.4
 400.8
Industrial Sales 482.4
 463.0
 455.1
PJM Net Charges 0.2
 (60.9) 3.3
Provision for Rate Refund 
 (0.6) 
Other Retail Sales 7.0
 6.9
 7.0
Total Retail Revenues 1,497.3
 1,387.2
 1,432.0
Wholesale Revenues  
  
  
Off-System Sales 534.7
 759.5
 571.8
Transmission 25.2
 (9.4) 4.1
Total Wholesale Revenues��559.9
 750.1
 575.9
Other Electric Revenues 16.1
 11.8
 14.4
Total Electric Generation, Transmission and Distribution Revenues 2,073.3
 2,149.1
 2,022.3
Sales to Affiliates 106.2
 98.6
 341.7
Other Revenues 6.7
 2.0
 2.9
Total Revenues $2,186.2
 $2,249.7
 $2,366.9

OPCo
  Years Ended December 31,
Description 2015 2014 2013
  (in millions)
Retail Revenues  
  
  
Residential Sales $1,660.0
 $1,768.1
 $1,676.1
Commercial Sales 725.2
 732.2
 763.8
Industrial Sales 405.9
 405.8
 468.4
PJM Net Charges 
 47.5
 6.9
Provision for Rate Refund 
 (11.9) 22.1
Other Retail Sales 13.3
 14.9
 15.9
Total Retail Revenues 2,804.4
 2,956.6
 2,953.2
Wholesale Revenues  
  
  
Off-System Sales 156.1
 143.0
 563.0
Transmission 63.2
 78.5
 17.7
Total Wholesale Revenues 219.3
 221.5
 580.7
Other Electric Revenues 32.4
 26.8
 28.3
Total Electric Generation, Transmission and Distribution Revenues 3,056.1
 3,204.9
 3,562.2
Sales to Affiliates 84.1
 165.2
 1,185.0
Other Revenues 8.5
 6.8
 15.4
Total Revenues $3,148.7
 $3,376.9
 $4,762.6


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PSO
  Years Ended December 31,
Description 2015 2014 2013
  (in millions)
Retail Revenues  
  
  
Residential Sales $554.5
 $561.2
 $530.5
Commercial Sales 372.4
 375.5
 351.5
Industrial Sales 263.1
 260.4
 234.1
Other Retail Sales 76.7
 78.7
 73.6
Total Retail Revenues 1,266.7
 1,275.8
 1,189.7
Wholesale Revenues  
  
  
Off-System Sales 11.5
 13.8
 34.6
Transmission 38.6
 36.5
 36.4
Total Wholesale Revenues 50.1
 50.3
 71.0
Other Electric Revenues 14.6
 14.2
 17.0
Total Electric Generation, Transmission and Distribution Revenues 1,331.4
 1,340.3
 1,277.7
Sales to Affiliates 4.6
 7.1
 14.2
Other Revenues 3.2
 4.2
 3.6
Total Revenues $1,339.2
 $1,351.6
 $1,295.5

SWEPCo
  Year Ended December 31,
Description 2015 2014 2013
  (in millions)
Retail Revenues  
  
  
Residential Sales $593.5
 $580.4
 $586.5
Commercial Sales 471.5
 457.2
 472.3
Industrial Sales 318.8
 348.9
 316.3
Provision for Rate Refund 36.3
 5.0
 (16.1)
Other Retail Sales 8.2
 8.3
 8.3
Total Retail Revenues 1,428.3
 1,399.8
 1,367.3
Wholesale Revenues  
  
  
Off-System Sales 252.7
 339.3
 294.6
Transmission 60.2
 55.1
 59.1
Total Wholesale Revenues 312.9
 394.4
 353.7
Other Electric Revenues 21.1
 23.7
 21.6
Total Electric Generation, Transmission and Distribution Revenues 1,762.3
 1,817.9
 1,742.6
Sales to Affiliates 16.6
 26.3
 51.8
Other Revenues 2.0
 2.2
 1.4
Total Revenues $1,780.9
 $1,846.4
 $1,795.8

FINANCING

General

Companies within the AEP System generally use short-term debt to finance working capital needs.  Short-term debt may also be used to finance acquisitions, construction and redemption or repurchase of outstanding securities until such needs can be financed with long-term debt.  In recent history, short-term funding needs have been provided for by cash on hand, borrowing under AEP'sAEP’s revolving credit agreements and AEP’s commercial paper program.  Funds are made available to subsidiaries under the AEP corporate borrowing program.  Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 20122015 Annual Reports, under the heading entitled Financial Condition for additional information concerning short-term funding and our access to bank lines of credit, commercial paper and capital markets.

AEP’s revolving credit agreements (which backstop the commercial paper program) include covenants and events of default typical for this type of facility, including a maximum debt/capital test and, for AEP andtest.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of its significantmajor subsidiaries, aprior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, cross-acceleration provision.would cause an event of default under these credit agreements. As of December 31, 2012,2015, AEP was in compliance with its debt covenants.  With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before

7



termination of the agreements.  A voluntary bankruptcy or insolvency of AEP or one of its significant subsidiaries would be considered an immediate termination event.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 20122015 Annual Reports, under the heading entitled Financial Condition for additional information with respect to AEP’s credit agreements.

AEP’s subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as securitization financings and leasing arrangements, including the leasing of coal transportation equipment and facilities.

4


ENVIRONMENTAL AND OTHER MATTERS

General

AEP’sAEP subsidiaries are currently subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities.  The environmental issues that we believemanagement believes are potentially material to the AEP systemSystem are outlined below.

Clean Water Act Requirements

Operations for AEP subsidiaries are subject to the Federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and regulates systems that withdraw surface water for use in power plants.  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.  The standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  Challenges to this final rule have been consolidated in the U.S. Court of Appeals for the Second Circuit, and additional changes could be made to this rule as a result of review by the court.

In November 2015, the Federal EPA issued a final rule to update the technology-based standards that govern discharges from new and existing power plants under the Clean Water Act’s National Pollutant Discharge Elimination System program.  For additional information, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues.

Coal Ash Regulation

AEP’s operations produce a number of different coal combustion products, including fly ash, bottom ash, gypsum and other materials.  Effective October 2015, the Federal EPA adopted a rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units.  The final rule requires certain standards for location, groundwater monitoring and dam stability to be met at landfills and certain surface impoundments at operating facilities on a schedule spanning approximately four years after publication of the final rule in the Federal Register. If existing disposal facilities cannot meet these standards, they will be required to close, but the time frame for closure may be extended if adequate alternative disposal options are not available. For additional information regarding the Federal EPA action taken to regulate the disposal and beneficial re-use of coal combustion residuals and the potential impact on operations, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues-Coal Combustion Residual Rule.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control mobile and stationary sources of air emissions.  The major CAA programs affecting ourAEP’s power plants are described below.  The states implement and administer many of these programs and could impose additional or more stringent requirements.

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AEP has made significant long-term investments in environmental controls to reduce air emissions from its power plants. Between 2000 and 2015, AEP invested approximately $8.1 billion in environmental controls, primarily related to CAA, that have significantly reduced emissions. During the same time period and including our projections through 2017, AEP expects its emissions of mercury to have been reduced by approximately 85%. Since 1990 and including our projections through 2017, AEP expects its emissions of SO2 and NOx to have been reduced by approximately 90% and 85% respectively.

The Acid Rain Program

The 1990 Amendments to the CAA include a cap-and-trade emission reduction program for SO2 emissions from power plants.  By 2000, the program established a nationwide cap on power plant SO2 emissions of 8.9 million tons per year and required further reductions in 2010.  The 1990 Amendments also contain requirements for power plants to reduce NOx emissions through the use of available combustion controls.

The success of the SO2 cap-and-trade program encouraged the Federal EPA and the states to use it as a model for other emission reduction programs.  We continueAEP continues to meet ourits obligations under the Acid Rain Program through the installation of controls, use of alternate fuels and participation in the emissions allowance markets.  Subsequent programs developed by the Federal EPA have imposed more stringent SO2 and NOx emission reduction requirements than the Acid Rain Program on many of ourAEP facilities.  We have installed additionalAdditional controls and taken other actions have been taken to achieve compliance with these programs.programs at these facilities.

National Ambient Air Quality Standards

The CAA requires the Federal EPA to review the available scientific data for criteria pollutants periodically and establish a concentration level in the ambient air for those substances that is adequate to protect the public health and welfare with an extra safety margin.  The Federal EPA also can list additional pollutants and develop concentration levels for them.  These concentration levels are known as national ambient air quality standards (NAAQS).

Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (nonattainment areas).  Each state must develop a state implementation plan (SIP) to bring nonattainment areas into compliance with the NAAQS and maintain good air quality in attainment areas.  All SIPs are submitted to the Federal EPA for approval.  If a state fails to develop adequate plans, the Federal EPA develops and implements a plan.  As the Federal EPA reviews the NAAQS and establishes new concentration levels, the attainment status of areas can change and states may be required to develop new SIPs.  In 2008, the Federal EPA issued revised NAAQS for both ozone and fine particulate matter (PM2.5).  The PM2.5 standard was remanded by the D.C. Circuit Court of Appeals, and a new rule was signed by the administrator in December 2012 that lowerslowered the annual standard.  A new ozone standard is also under development and is expected to be proposedwas adopted in 2013.2015.  The Federal EPA also adopted a new short-term standard for SO2 in 2010,, a lower standard for NOx in 2010, and a lowerconfirmed the existing standard for lead in 2008.2014.  The existing standard for carbon monoxide was retained in 2011.  The states will developare in the process of developing new SIPs for thesethe SO2, PM2.5 and ozone standards, which could result in additionalmore stringent emission reductionslimitations being required from ourimposed on AEP facilities.

In 2005, the Federal EPA issued the Clean Air Interstate Rule (CAIR), which requiresrequired additional reductions in SO2 and NOx emissions from power plants and assists states developing new SIPs to meet the NAAQS.  For additional information regarding CAIR, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – Clean Air Act Requirements.   In August 2011, the Federal EPA issued a final rule to replace CAIR (the Cross State Air Pollution Rule (CSAPR)) that would impose new andcontains more stringent requirements to control SO2and NOx emissions from fossil fuel-fired electric generating units in 27 states and the District of Columbia.  Petitions for review were filed with the U.S. Court of Appeals for
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the District of Columbia Circuit, and CSAPR was vacated.  CAIRThat decision was subsequently reversed by the U.S. Supreme Court and remanded back to the U.S. Court of Appeals for further proceedings. 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, an interim final rule has been issued, and the court has remanded certain state budgets to Federal EPA for further rulemaking while the rule remains in effect until theeffect. Federal EPA develops a replacement rule.has proposed more stringent NOx budgets for 23 states during the 2017 ozone season. For additional information regarding CSAPR, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – CleanIssues-Clean Air Act Requirements.

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Hazardous Air Pollutants

As a result of the 1990 Amendments to the CAA, the Federal EPA investigated hazardous air pollutant (HAP) emissions from the electric utility sector and submitted a report to Congress, identifying mercury emissions from coal-fired power plants as warranting further study.  In 2011, the Federal EPA issued a final rule setting Maximum Achievable Control Technology (MACT) standards for new and existing coal and oil-fired utility units and New Source Performance Standards (NSPS) for emissions from new and modified power plants.  Petitions for review of the MACT standards were denied by the U.S. Court of Appeals for the D.C. Circuit, but in 2014 the U.S. Supreme Court determined that Federal EPA acted unreasonably in refusing to consider costs in determining if it was appropriate and necessary to regulate hazardous air pollutant emissions from electric generating units. Federal EPA has issued a supplemental finding and the rule remains in effect. For additional information regarding the Utility MACT, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – CleanIssues-Clean Air Act Requirements.

Regional Haze

The CAA establishes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing impairment of visibility in these areas (Regional Haze program).  In 2005, the Federal EPA issued its Clean Air Visibility Rule (CAVR), detailing how the CAA’s best available retrofit technology requirements will be applied 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.

PSO is in the process of implementing a settlement with the Federal EPA in order to comply with the Regional Haze program requirements in that state.Oklahoma. Federal EPA issued a proposed Federal Implementation Plan for Arkansas in 2015.  For additional information regarding CAVR and the Regional Haze program requirements, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – CleanIssues-Clean Air Act Requirements.

CO2 RegulationClimate Change

InAEP has taken action to reduce and offset CO2 emissions from its generating fleet and expects CO2 emissions from its operations to continue to decline due to the absenceretirement of comprehensive climate change legislation,some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. AEP’s total CO2 emissions in 2015 (not including emissions from the Kyger Creek and Clifty Creek Plants) were approximately 102.4 million metric tons, a 30% reduction from AEP’s 2005 CO2 emissions of approximately 146 million metric tons. Federal EPA has taken action to regulate CO2 emissions from new and existing fossil fueled electric generating units under the existing requirementsprovisions of the CAA.  For example, the Federal EPA published the Clean Power Plan in October 2015. Such actions, including the Clean Power Plan, are being legally challenged by numerous parties.  parties and final regulatory outcomes remain uncertain.  In February 2016, the U.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 issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review.For additional information regarding the Federal EPA action taken to regulate CO2 emissions, including the Clean Power Plan, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – Clean Air Act Requirements.Issues-Climate Change, CO2 Regulation and Energy Policy.

Our fossil fuel-fired generating units are large sources of CO2 emissions.  If substantial CO2 emission reductions are required, there will be significant increases in capital expenditures and operating costs which would hasten the ultimate retirement of older, less-efficient, coal-fired units.  To the extent we install additional controls on our generating plants to limit CO2 emissions and receive regulatory approvals to increase our rates, return on capital investment would have a positive effect on future earnings.  Prudently incurred capital investments made by our subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment.  We would expect these principles to apply to investments made to address new environmental requirements.  However, requests for rate increases reflecting these costs can affect us adversely because our regulators could limit the amount or timing of increased costs that we would recover through higher rates.  To the extent our costs are relatively higher than our competitors’ costs, it could reduce our off-system sales or cause us to lose customers in jurisdictions that permit customers to choose their supplier of generation service.

Several states have adopted programs that directly regulate CO2 emissions from power plants, but none of these programs are currently in effect in states where we have generating facilities.  Some of our states have established mandatory or voluntary programs to increase the use of energy efficiency, alternative energy, or renewable energy sources (Arkansas, Indiana, Louisiana, Michigan, Ohio, Oklahoma, Texas, Virginia, and West Virginia).  We are taking steps to comply with these requirements primarily through entering into power supply agreements giving us access to power generated by wind turbines.

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Clean Water Act Requirements
Our operations are also subject to the Federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and regulates systems that withdraw surface water for use in our power plants.  In April 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  We submitted comments on the proposal in July and August 2011.  We expect the Federal EPA to issue revised rules in 2013.

The Federal EPA is also engaged in rulemaking to update the technology-based standards that govern discharges from new and existing power plants under the Clean Water Act’s National Pollutant Discharge Elimination System program.  These standards were last updated over 20 years ago, and the Federal EPA has issued two rounds of information collection requests to inform its rulemaking.  In October 2009, the Federal EPA issued a final report for the power plant sector and determined that revisions to its existing standards are necessary.  We expect the Federal EPA to propose revised standards in 2013.  Until new standards are proposed, we cannot predict the outcome or impact of these rules on our operations.

Coal Ash Regulation

Our operations produce a number of different coal combustion products, including fly ash, bottom ash, gypsum and other materials. The Federal EPA completed an extensive study of the characteristics of coal ash in 2000 and concluded that combustion wastes do not warrant regulation as hazardous waste.  In December 2008, the breach of a dike at the Tennessee Valley Authority’s Kingston Station resulted in a spill of several million cubic yards of ash into a nearby river and onto private properties, prompting federal and state reviews of ash storage and disposal practices at many coal-fired electric generating facilities, including ours.  AEP operates 37 ash ponds and we manage these ponds in a manner that complies with state and local requirements, including dam safety rules designed to assure the structural integrity of these facilities.  We also operate a number of dry disposal facilities in accordance with state standards, including ground water monitoring and other applicable standards.  In June 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units.  For additional information regarding the Federal EPA action taken to regulate the disposal and beneficial re-use of coal combustion residuals and the potential impact on our operations, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – Coal Combustion Residual Rule.

Climate Change – Position and Strategy

We continue to support a federal legislative approach to energy policy as the most effective means of reducing emissions of CO2 and other greenhouse gases (generally referred to as CO2) that recognizes that a reliable and affordable electricity supply is vital to economic recovery and growth.  We do not believe regulating CO2 emissions under the Clean Air Act is the appropriate solution.  During the past decade, we have taken voluntary actions to reduce and offset our CO2 emissions.  Unfortunately, two of the voluntary programs that helped businesses such as AEP to set quantitative commitments no longer exist.  The Federal EPA’s Climate Leaders Program and the Chicago Climate Exchange both ended their reduction obligations at the end of 2010.  However, through these programs and others, we voluntarily reduced our CO2 emissions by approximately 96 million metric tons during the 2003 to 2010 period.  We expect ourManagement expects emissions to continue to decline over time as we diversify ourAEP diversifies generating sources and operateoperates fewer coal units.  The projected decline in coal-fired generation is due to a number of factors, including the ongoing cost of operating older units, the relative cost of coal and natural gas as fuel sources, increasing environmental regulations requiring significant capital investments and changing commodity market fundamentals.  OurManagement’s strategy for this transformation is to protect the reliability of the electric system and reduce our emissions by pursuing multiple options.  These includeincludes diversifying ourAEP’s fuel portfolio and generating more electricity from natural gas, increasing energy efficiency and investing in renewable resources, where there is regulatory support.  Meanwhile the Federal EPA began regulating CO2 emissions from large stationary sources such as power plants in 2012 under the NSR prevention of significant deterioration and Title V operating permit programs.


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In March 2012AEP’s fossil fuel-fired generating units are large sources of CO2 emissions.  If substantial additional CO2 emission reductions are required, there will be significant increases in capital expenditures and operating costs which would hasten the Federal EPA proposedultimate retirement of older, less-efficient, coal-fired units.  To the extent additional investments are made to reduce CO2 emissions and receive regulatory approvals to increase rates, return on capital investment would have a Carbon Pollution Standardpositive effect on future earnings.  Prudently incurred capital investments made by AEP subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for New Power Plants. This regulation, basedrecovery and earn a return on EPA authority under section 111(b) of the Clean Air Act,investment.  Management would establish New Source Performance Standardsexpect these principles to apply to investments made to address new environmental requirements.  However, requests for CO2 for new fossil-fueled-fired electric generating units.  The proposed regulationrate increases reflecting these costs can have adverse effects because regulators could limit the ability to construct new coal-fired facilities in the future due to strict emission limits if finalized.amount or timing of increased costs that AEP does not currently have plans to permit or construct any new coal-fired facilities and the proposed rule does not directly impact existing facilities.

would recover through higher rates. For additional information on legislative and regulatory responses to greenhouse gases, including limitations on CO2 emissions, see Management’s Discussion and Analysissales of Financial Condition and Results of Operations under the headings entitled Environmental Issues – Climate Change.  Specific steps taken to reduce CO2 emissions include the following:energy into competitive markets, however, there is no such recovery mechanism.

Renewable Sources of Energy

SomeAll of ourthe states AEP serves (other than Kentucky and Tennessee) have established mandatory or voluntary programs to increase the use of energy efficiency, alternative energy, or renewable energy sources (Arkansas, Indiana, Louisiana, Michigan, Ohio, Oklahoma, Texas, Virginia, and West Virginia).  sources.

At the end of 2012 and in support of our goals or requirements,2015, the companyAEP operating companies had long-term contracts for 1,9842,031.5 MW of wind and 1010.1 MW of solar power delivering renewable energy to the companies’ customers. In addition, I&M began construction on the first of four solar projects that will make up I&M’s 14.7 MW Clean Energy Solar Pilot Project (CESPP) that was approved by the Indiana Utility Regulatory Commission. 599 MWs of recently-completed wind projects under contract for PSO were in service as of late 2015, and the remaining three projects associated with I&M’s CESPP projects are expected to begin deliveries in 2016. This will result in a combined total of 1,9942,655.3 MW to serve its regulated operating company customers.  Weof wind and solar in-service for AEP. Management actively manage ourmanages AEP’s compliance position and areis on pace to meet the relevant requirements or benchmarks in each applicable jurisdiction.

The growth of AEP’s renewable portfolio reflects the company’s strategy to diversify its generation resources to provide clean energy options to customers that meet both energy and capacity needs. In addition to gradually reducing AEP’s reliance on coal-fueled generating units, the growth of renewables and natural gas helps AEP to maintain a diversity of generation resources.

The Clean Power Plan effectively establishes a renewable portfolio standard for each of AEP’s states, creating additional opportunities for renewable growth. Independent of the Clean Power Plan, the integrated resource plans filed with state regulatory commissions by AEP’s regulated utility subsidiaries reflect AEP’s renewable strategy to balance reliability and cost with customers’ desire for clean energy in a carbon-constrained world. The Company has committed significant capital investments to modernize the electric grid and integrate these new resources. Transmission assets of the AEP System interconnect approximately 7,500 MW of renewable energy resources of third parties, and AEP’s transmission development initiatives are designed to facilitate the interconnection of additional renewable energy resources.

End UserUse Energy Efficiency

InBeginning in 2008, AEP established a goalramped up efforts to reduce demand by 1,000 megawatts (MW) and energy consumption by 2,250,000 megawatt-hours (MWh) byand peak demand through the endintroduction of 2012.  Since that time, AEP Operating Companies have implemented a wide variety of new consumer programs across most of the states we serve.  Over 100additional energy efficiency and demand response programs.  These programs, commonly and tariffs are nowcollectively referred to as demand side management, were implemented in place.
Preliminary estimates indicatejurisdictions where appropriate cost recovery was available.  Since that wetime, AEP operating companies have achieved our goal.  Fromimplemented over 100 programs across the AEP service territory and in most of the states AEP serves.  For the period 2008 through 2012,2015, these programs have reduced annual consumption by over 6.0 million megawatt hours and peak demand by over 1,500 MW.  AEP achieved 3,016,400 MWh of energy reduction and 1,011 MW of demand reduction, or 134% and 101% of goal, respectively.  For the sameestimates that its operating companies spent approximately $875 million during that period  AEP Operating Companies have invested over $368 million in energy efficiency and demand response initiatives.  Final results are subject to independent third party evaluation and verification of savings, as required in some jurisdictions.achieve these levels.  

Energy efficiency and demand reduction programs have received regulatory support in most of the states we serve,AEP serves, and appropriate cost recovery will be essential for usAEP operating companies to continue and expand these consumer offerings. Appropriate recovery of program costs, lost revenues, and an opportunity to earn a reasonable return ensures that energy efficiency programs are considered equally with supply side investments.  Going forward, we will work closely with regulators to ensure that plans are in place to meet specific regulatory and legislativeThe Clean Power Plan could

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provide additional opportunities for energy efficiency and/or demand reduction targets presentif states develop implementation plans that require energy efficiency. AEP believes its experience providing robust energy efficiency programs in several states positions the respective jurisdictions.

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gridSMART®company to be a cost-effective provider of these programs as states develop their implementation plans.

AEP’s gridSMART® initiative is designed to demonstrate the potential benefits of the smart grid by integrating advanced grid technologies into existing electric networks.  AEP is deploying smart grid technologies in several jurisdictionsalso developing and marketing a merchant distributed resource portfolio. AEP’s newly-formed subsidiary, OnSite Partners LLC, works directly with regulatory support.

·  AEP Ohio is deploying a comprehensive suite of smart grid technologies in an innovative demonstration project with 110,000 customers.  The $150 million project is being funded through a $75 million federal grant, PUCO cost recovery support and vendor in-kind contributions.
·  AEP Texas is deploying a one million meter smart grid network, along with $1 million in energy use display devices for low income customers.  The $308 million project is targeted for completion by the end of 2013.  We are recovering the costs through an 11-year surcharge.
·  I&M has deployed a smart grid network to 10,000 customers.  The $7 million project was funded pursuant to a settlement agreement approved by the IURC.
·  PSO has deployed smart meters to approximately 31,000 customers, 14,000 of which will be served on circuits equipped with advanced grid management technologies.  The project is being financed through a $8.75 million American Reinvestment and Recovery Act low-interest loan from the Oklahoma Department of Commerce with $2 million annual revenues for cost recovery approved by the Oklahoma Corporation Commission.

Currentwholesale and Projected CO2 Emission

Our total CO2 emissions in 2011 (not including our ownership in the Kyger Creeklarge retail customers to provide tailored solutions based upon market knowledge, technology innovations and Clifty Creek plants) were approximately 136 million metric tons.  Our 2012 emissions decreased to approximately 122 million metric tons.  We expect overall increases in CO2 emissions during the next few years to be small, if any, as our salesdeal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation rebound somewhat from recession lows in 2009.  However, over muchand other forms of the remainder of the decade we expect emissions to decline as modest sales growthcost reducing energy technologies. OnSite Partners LLC pursues projects where a suitably termed power agreement is offset by retirements of older, less efficient coal-fired units and increased utilization of natural gas.entered into with a credit-worthy counterparty.

Corporate Governance

In response to environmental issues and in connection with its assessment of ourAEP’s strategic plan, ourthe Board of Directors continually reviews the risks posed by our actions.new environmental rules and requirements such as the Clean Power Plan that could accelerate the retirement of coal-fired generation assets. The Board of Directors is informed of any new material environmental issues, including changes to regulations and proposed legislation.regulation or legislation that would affect the company.  The Board’s Committee on Directors and Corporate Governance oversees the company’s annual Corporate Accountability Report, which includes information onabout the company’s environmental, issues.financial and social performance.

Other Environmental Issues and Matters

We are engaged in litigation regarding regulated air emissions and/or whether emissions from coal-fired generating plants cause or contribute to global warming.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading entitled Litigation – Environmental Issues and Note 5 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies, included in the 2012 Annual Reports, for further information.

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 imposes costs for environmental remediation upon owners and previous owners of sites, as well as transporters and generators of hazardous material disposed of at such sites.  See Note 56 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies, included in the 20122015 Annual Reports, under the heading entitled The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation for further information.


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Environmental Investments

Investments related to improving AEP System plants’ environmental performance and compliance with air and water quality standards during 2010, 2011 and 2012 and the current estimates for 2013, 2014 and 2015 and the current estimate for 2016 are shown below,below. AFUDC debt is included in each case excluding equity AFUDC and capitalized interest.the historical periods.  These investments include both environmental as well as other related spending. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends and the ability to access capital.  AEP expects to make substantial investments in future years in addition to the amounts set forth below in connection with the modification and addition of facilities at generatinggeneration plants for environmental quality controls.  Such future investments are needed in order to comply with air and water quality standards that have been adopted and have deadlines for compliance after 20122015 or have been proposed and may be adopted.  Future investments could be significantly greater if emissions reduction requirements are accelerated or otherwise become more onerous or if CO2 becomes regulated at existing facilities.  While we expect to recover our expenditures for pollution control technologies, replacement generation and associated operatingonerous. These estimates do not include any projected costs from customers through regulated rates (in regulated jurisdictions) or market prices, without such recovery, those costs could impact future net income and cash flows and impact financial condition.that might be triggered by compliance with the Clean Power Plan.  The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System. AEP typically recovers costs of complying with environmental standards from customers through rates in regulated jurisdictions.  For AEP’s merchant generation units however, there is no such recovery mechanism.  Failure to recover these costs could reduce future net income and cash flows and possibly harm AEP’s financial condition.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading entitled Environmental Issues and Note 56 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies, included in the 20122015 Annual Reports, for more information regarding environmental expenditures in general.
Historical and Projected Environmental Investments
          
  2013 2014 2015 2016 
  Actual Actual Actual Estimate 
  (in millions)
Total AEP (a) $424.2
 $539.8
 $599.4
 $353.2
 
APCo (b) 44.8
 31.3
 78.4
 58.3
 
I&M 28.3
 51.4
 45.6
 60.8
 
OPCo (c) 129.3
 
 
 
 
PSO 56.1
 72.1
 92.3
 29.4
 
SWEPCo 135.7
 225.3
 243.8
 86.3
 

Historical and Projected Environmental Investments
                  
 2010 2011 2012 2013 2014 2015
 Actual Actual Actual Estimate Estimate Estimate
             
 (in thousands)
Total AEP System (a) $303,800  $186,800  $235,400  $544,000  $760,000  $850,000
APCo  202,700   68,900   50,800   59,000   48,000   84,000
I&M  8,100   5,900   30,400   42,000   84,000   88,000
OPCo  97,400   63,000   66,200   191,000   185,000   159,000
PSO  1,200   6,500   26,100   64,000   82,000   98,000
SWEPCo (b)  (10,500)  11,000   23,800   143,000   241,000   325,000
(a)Includes expenditures of the subsidiaries shown and other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies.  Excludes discontinued operations.
(b)  SWEPCo 2010 actual
(b)For APCo, the projected environmental cost includes reclassificationsinvestments above include the conversions of project costs for suspended capital projects.470 MWs of coal generation to natural gas. If natural gas conversion is not completed, the units could be retired sooner than planned.
(c)OPCo transferred all of its generation assets on December 31, 2013.

Management continues to refine the cost estimates of complying with air and water quality standards and other impacts of the environmental proposals. The preceding discussionfollowing cost estimates for periods following 2016 will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules.  These 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 the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired, replaced or sold, including the type and amount of such replacement capacity and (g) other factors.  The following cost estimates do not include any projected costs that might be triggered by compliance with the Clean Power Plan and are limited to only the costs of major projects to comply with existing air and water quality standards. In addition, management is continuing to evaluate the economic feasibility of environmental investments on both regulated and plans for future years reflectsnonregulated plants.

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For the ownershipRegistrant Subsidiaries, management’s current ranges of plants asestimates of December 31, 2012.  The AEP East Companies have filed with the FERC to terminate the Interconnection Agreement and for OPCo to transfer facilities to APCo, KPCo and AEPGenCo.  Management expects the transfers will be effective December 31, 2013.environmental investments beginning in 2017, exclusive of debt AFUDC, are set forth below:
Projected (2017 - 2025)
Environmental Investment
Company Low High
  (in millions)
APCo $245
 $295
I&M 215
 265
PSO 15
 35
SWEPCo 195
 240

BUSINESS SEGMENTS

ElectricAEP’s reportable segments and Magnetic Fields (EMF)their related business activities are outlined below.   See Note 9 to the financial statements entitled Business Segments, included in the 2015 Annual Reports, for additional information on the operating segments. 

EMF are found everywhere there is electricity.  Electric fields are created by the presence of electric charges.  Magnetic fields are produced by the flow of those charges.  This means that EMF are created by electricity flowing inVertically Integrated Utilities

Generation, transmission and distribution lines, electrical equipment, household wiringof electricity for sale to retail and appliances.  A numberwholesale 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 studieselectricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
OPCo purchases energy and capacity to serve standard service offer customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

Development, construction and operation of transmission facilities through investments in the pastAEP’s wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have examined the possibility of adverse health effects from EMF.  While somePUCT-approved or FERC-approved returns on equity.

Generation & Marketing

Nonregulated generation in ERCOT and PJM.
Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO.

AEP River Operations

Commercial barging operations that were sold in November 2015. As a result of the epidemiological studies have indicated some association between exposure to EMF and health effects, none has produced any conclusive evidence that EMF does or does not cause adverse health effects.sale, AEP River Operations is no longer a business segment.


Management cannot predict the ultimate impact of the question of EMF exposure and adverse health effects.  If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially affected unless these costs can be recovered from customers.
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UTILITY OPERATIONSVERTICALLY INTEGRATED UTILITIES

GENERAL

UtilityAEP’s vertically integrated utility operations constitute most of AEP’s business operations.  Utility operations include (a)are engaged in the generation, transmission and distribution of electric powerelectricity for sale to retail and wholesale customers through assets owned and (b) the supplyingoperated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and marketing of electric power at wholesale (through the electric generation function) to other electric utility companies, municipalities and other market participants.WPCo.  AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities.activities on behalf of each of these subsidiaries.

ELECTRIC GENERATION

Facilities

As of December 31, 2012,2015, AEP’s vertically integrated public utility subsidiaries owned or leased approximately 37,30023,600 MW of domestic generation.  See Item 2 – Properties for more information regarding AEP’s generation capacity.

Interconnection Agreement

APCo, I&M, KPCo, OPCo and AEPSC are parties to the Interconnection Agreement, which was originally approved by the FERC in 1951 and subsequently amended in 1951, 1962, 1975, 1979 (twice) and 1980.  This agreement defines how the member companies share the costs and benefits associated with their generating plants.  This sharing is based upon each company’s “member load ratio.” The member load ratio is calculated monthly by dividing each company’s highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all member companies.  The member load ratio multiplied by the aggregate generation capacity of all the member companies determines each member company's capacity obligation.  The difference between each member company's obligation and its own generation capacity determines the capacity surplus or deficit of each member company.  The agreement requires the deficit companies to make monthly capacity equalization payments to the surplus companies based on the surplus companies' average fixed cost of generation.  Member companies that deliver energy to other member companies to meet their internal load requirements are reimbursed at average variable costs.  In addition, all member companies share off-system sales margins based upon each member company's member load ratio.  Consequently, the agreement provides a strong risk sharing and mitigation arrangement among the member companies.  As of December 31, 2012, the member-load-ratios were as follows:

 
Peak
Demand
 Member-Load Ratio
 (MWs) (%)
APCo6,881 30
I&M4,726 21
KPCo1,378 6
OPCo9,670 43

APCo, I&M, KPCo and OPCo are parties to the AEP System Interim Allowance Agreement (Allowance Agreement), which has been approved by the FERC and provides, among other things, for the transfer of SO2 emission allowances associated with transactions under the Interconnection Agreement.  The following table shows the net (credits) or charges allocated among the parties under the Interconnection Agreement during the years ended December 31, 2012, 2011 and 2010:

 Years Ended December 31,
 2012 2011 2010
 (in thousands)
APCo$494,400 $632,100 $757,900
I&M (118,400)  (183,700)  (236,900)
KPCo 93,200  48,400  49,400
OPCo (469,200)  (496,800)  (570,400)


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Termination of the Interconnection Agreement

In October 2012, AEP submitted several applications with the FERC requesting termination of the Interconnection Agreement, termination of the Allowance Agreement, approval of a new Power Coordination Agreement among APCo, I&M and KPCo and the transfer of OPCo’s generating assets to either a new wholly owned unregulated generation company or to APCo and KPCo to fully separate OPCo’s generating assets from its distribution and transmission operations. See Note 3 to the consolidated financial statements, entitled Rate Matters, included in the 2012 Annual Reports, for additional information regarding the termination of the Interconnection Agreement and transfer of OPCo’s generation assets.

CSW Operating Agreement

PSO, SWEPCo and AEPSC are parties to the CSW Operating Agreement, which has been approved by the FERC.  The CSW Operating Agreement requires thesevertically integrated public utility subsidiaries to maintain adequate annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other public utility subsidiary parties as capacity commitments.  Parties are compensated for energy delivered to the recipients based upon the deliverer’s incremental cost plus a portion of the recipient’s savings realized by the purchaser that avoids more costly alternatives.  Revenues and costs arising from third party sales in their region are generally shared based on the amount of energy each west zone public utility subsidiary contributes that is sold to third parties.

The following table shows the net (credits) or charges allocated among the parties under the CSW Operating Agreement during the years ended December 31, 2012, 2011 and 2010:

 Years Ended December 31,
 2012 2011 2010
 (in thousands)
PSO$42,555  $33,091  $20,222 
SWEPCo (42,555)  (33,091)  (20,222)

Power generated by or allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any public utility subsidiary is primarily sold to customers by such public utility subsidiary at rates approved by the public utility commission in the jurisdiction of sale (except in Ohio, where generation rates are currently priced using a hybrid approach that incorporates components of cost and market).  See Regulation – Rates under Item 1, Utility Operations.

Under both the Interconnection Agreement and CSW Operating Agreement, power that is not needed to serve the native load of our public utility subsidiaries is sold in the wholesale market by AEPSC on behalf of those subsidiaries.  See Risk Management and Trading, below, for a discussion of the trading and marketing of such power.

AEP’s System Integration Agreement provides for the integration and coordination of AEP’s East Companies, PSO and SWEPCo.  This includes joint dispatch of generation within the AEP System and the distribution, between the two zones, of costs and benefits associated with the transfers of power between the two zones (including sales to third parties and risk management and trading activities).  It is designed to function as an umbrella agreement in addition to the Interconnection Agreement and the CSW Operating Agreement, each of which controls the distribution of costs and benefits for activities within each zone.

Risk Management and Trading

As agent for AEP’s public utility subsidiaries, AEPSC sells excess power into the market and engages in power, natural gas, coal and emissions allowances risk management and trading activities focused in regions in which AEP traditionally operates and in adjacent regions.  These activities primarily involve the purchase and sale of electricity (and to a lesser extent, natural gas, coal and emissions allowances) under forward contracts at fixed and variable prices.  These contracts include physical transactions, exchange-traded futures, and to a lesser extent, over-the-counter swaps and options.  The majority of forward contracts are typically settled by entering into offsetting
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contracts.  These transactions are executed with numerous counterparties or on exchanges.  Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions.  As of December 31, 2012, counterparties posted approximately $8 million in cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP’s public utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries posted approximately $89 million with counterparties and exchanges).  Since open trading contracts are valued based on market prices of various commodities, exposures change daily.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2012 Annual Reports, under the heading entitled Quantitative and Qualitative Disclosures About Market Risk for additional information.

Fuel Supply

The following2013 results include fuel used and transported by OPCo, a utility subsidiary that is not part of the Vertically Integrated Utilities segment.  OPCo’s results appear here because it retained its generation until year-end 2013 at which point all of its generation was transferred to AGR which transferred portions to APCo and KPCo.

The table shows the generation sources of fuelby type, on an actual net generation (MWhs) basis, used by the AEP System:Vertically Integrated Utilities:

 2012 2011 20102015 2014 2013
Coal and Lignite 71% 78% 82%70% 72% 75%
Nuclear17% 16% 11%
Natural Gas 17% 11% 8%12% 11% 13%
Nuclear 11% 10% 9%
Hydroelectric and other <1% <1% <1%1% 1% <1%

A price increase/decrease in one or more fuel sources relative to other fuels may result in the decreased/increased use of other fuels.  AEP’s overall 20122015 fossil fuel costs are downfor the Vertically Integrated Utilities decreased approximately 2%12% on a dollar per MMBtu basis from 20112014. This was due primarily to the favorable impact of lowa significant decline in natural gas prices along with a marginal decrease in coal prices.

Coal and Lignite

AEP’s public utility subsidiariesVertically Integrated Utilities procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations and spot agreements with various producers and coal trading firms.  Coal consumption in 2012 was down significantly2015 decreased from the same period2014 due to a decrease in 2011power prices and corresponding decrease in demand for the reasons discussed below. The AEP System average target level for coal inventory ranges from 35 to 40 days and as of December 31, 2012, the AEP System average forcoal-fired generation. As a result, coal inventories was 44 days.ended the year at above-target levels on a system basis.

Management believes that AEP’s public utility subsidiariesthe Vertically Integrated Utilities will be able to secure and transport coal and lignite of adequate quality and in adequate quantities to operate their coal and lignite-fired units.  Through subsidiaries, AEP owns, leases or controls more than 7,6004,838 railcars, approximately 600498 barges, 1512 towboats, 8 harbor boats and a coal handling terminal with approximately 18 million tons of annual capacity to move and store coal for use in ourAEP generating facilities.  See AEP River Operations for a discussion of AEP’s for-profit coal and other dry-bulk commodity transportation operations that are not part of AEP’s Utility Operations segment.

Spot market prices for certain coals utilized by AEPcoal continued to decrease throughout 2015.  The decreased significantly in the first half of 2012, but made a modest recovery by the end of the year.  The general decrease in spot coal prices duringreflect the year can be attributed to the persistently weakreduction in demand for domestic coal driven, in large part, by low natural gas pricescoal-fired generation and the displacementoversupply in the market.   As of coal generation with natural gas resources.  MostDecember 31, 2015, slightly less than half of the coal purchased by AEP iswas procured through term contracts.  As those contracts expire, they can beare replaced

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with contracts at the newcurrent market prices.  The price with an impact of this process is reflected in subsequent periods.  The average cost per tonprice paid for coal delivered in 2012 increased2015 decreased from the prior year.year primarily due to a decrease in spot coal prices and heavier reliance on shorter term contracts.


The following table shows the amount of coal and lignite delivered to the AEP SystemVertically Integrated Utilities plants during the past three years and the average delivered price of coal purchased by AEP System companies:the Vertically Integrated Utilities:

 2012 2011 2010
Total coal delivered to AEP System plants (thousands of tons) 60,054 62,956 64,614
2015 2014 2013
Total coal delivered to the plants (millions of tons)37.3
 41.0
 51.1
Average cost per ton of coal delivered $49.22 $46.76 $44.82$45.36
 $46.65
 $51.31

The coal supplies at AEP Systemthe Vertically Integrated Utilities plants vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. As of December 31, 2012,2015, the AEP System’sVertically Integrated Utilities coal inventory was approximately 4447 days of full load burn.

While inventory targets vary by plant and are changed as necessary, the current coal inventory target for the Vertically Integrated Utilities is approximately 30 days.
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Natural Gas

Through its public utility subsidiaries, AEPThe Vertically Integrated Utilities consumed nearly 220over 89 billion cubic feet of natural gas during 20122015 for generating power. This represents an increasea decrease of 32%7% from 2011 and continues a trend that began in 2010.  Since 2009,2014.  While AEP’s natural gas consumptiongas-fired generating capacity has increased approximately 130%.  The increased natural gas consumption is attributable toover the past several years with the addition of the Stall and Dresden units, the implementation of the SPP Market and change in the dispatch of AEP’s natural gas combined cycle unitsfleet resulted in June 2010 and January 2012, respectively, along with increased operation of the Lawrenceburg and Waterford combined cycle units.  The efficient heat rates of these units (low 7,000 British thermal units/KWh range) coupled with sustained lowera decreased natural gas prices have supported the increased operation of AEP’s combined cycle natural gas units.  A mild 2011-12 winter and the continuation of high levels of production from shale gas developments led to higher U.S. natural gas inventories and continued to place downward pressure on natural gas prices as a result of more abundant supplies, making power generated from these units more economic.gas-fired generation.  Several of AEP’s natural gas-fired power plants are connected to at least two pipelines which allowsallow greater access to competitive supplies and improvesimprove delivery reliability. A portfolio of term, monthly, seasonal, firm and daily peaking commoditysupply and transportation agreements (thatprovide natural gas requirements for each plant, as appropriate. AEP’s natural gas supply agreements are entered into on a competitive basis and based on market prices) supplies natural gas requirements for each plant, as appropriate.prices.

The following table shows the amount of natural gas delivered to the AEP SystemVertically Integrated Utilities plants during the past three years and the average delivered price of natural gas purchased by AEP System companies:the Vertically Integrated Utilities. Results for 2013 include natural gas delivered to OPCo, while results for 2015 and 2014 do not.

 2012 2011 2010
Total natural gas delivered to AEP System plants (billion cubic feet) 220.0 166.8 133.6
2015 2014 2013
Total natural gas delivered to the plants (billion cubic feet)89.7
 96.1
 158.3
Average price per MMBtu of purchased natural gas $3.01 $4.48 $4.80$2.80
 $4.70
 $4.01

Nuclear

I&M has made commitments to meet the current nuclear fuel requirements of the Cook Plant.  I&M has made and will make purchases of uranium in various forms in the spot, short-term and mid-term markets.  I&M also continues to lease a portion of its nuclear fuel.

For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M completed modifications to its spent nuclear fuel storage pool more than 10 years ago.  I&M entered into an agreement to provide for onsite dry cask storage of spent nuclear fuel to permit normal operations to continue.  I&M is scheduled to conduct further dry cask loading and storage projects on an ongoing periodic basis.  I&M began and completed its initial loading of spent nuclear fuel into the dry casks in 2012, which consisted of 12 casks (32 spent nuclear fuel assemblies contained within each).  The second loading of spent nuclear fuel into dry casks was completed in 2015, which consisted of 16 casks. The third dry cask loading is expected to occur in 2018.


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Nuclear Waste and Decommissioning

As the owner of the Cook Plant, I&M has a significant future financial commitment to dispose of spent nuclear fuel and decommission and decontaminate the plant safely.  The cost to decommission a nuclear plant is affected by NRC regulations and the spent nuclear fuel disposal program.  The most recent decommissioning cost study was completed in 2012.  In it, the2015.  The estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant ranged from $1.3 billion to $1.7was $1.6 billion in 20122015 non-discounted dollars.  As of December 31, 2012,2015, the total decommissioning trust fund balance for the Cook Plant was approximately $1.4$1.8 billion. The balance of funds available to eventually decommission Cook Plant will differ based on contributions and investment returns.  The ultimate cost of retiring the Cook Plant may be materially different from estimates and funding targets as a result of the:

·  Type of decommissioning plan selected.
Escalation of various cost elements (including, but not limited to, general inflation and the cost of energy).
·  Escalation of various cost elements (including, but not limited to, general inflation and the cost of energy).
Further development of regulatory requirements governing decommissioning.
·  Further development of regulatory requirements governing decommissioning.
Technology available at the time of decommissioning differing significantly from that assumed in studies.
·  Technology available at the time of decommissioning differing significantly from that assumed in studies.
Availability of nuclear waste disposal facilities.
·  Availability of nuclear waste disposal facilities.
Availability of a United States Department of Energy facility for permanent storage of spent nuclear fuel.
·  Availability of a United States Department of Energy facility for permanent storage of spent nuclear fuel.

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Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly different than current projections.  WeAEP will seek recovery from customers through our regulated rates if actual decommissioning costs exceed our projections.  See Note 56 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies under the heading Nuclear Contingencies, included in the 20122015 Annual Reports, for information with respect to nuclear waste and decommissioning.

Low-Level Radioactive Waste

The Low-Level Waste Policy Act of 1980 mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states.  Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials.  Michigan does not currently have a disposal site for such waste available.  I&M cannot predict when such a site may be available. However the states of Utah and Texas have licensed low level radioactive waste disposal sites which currently accept low level radioactive waste from Michigan waste generators.  There is currently no set date limiting I&M’s access to either of these facilities.  The Cook Plant has a facility onsite designed specifically for the storage of low level radioactive waste.  In the event that low level radioactive waste disposal facility access becomes unavailable, then low level radioactive waste can be stored onsite at this facility.

Structured Arrangements Involving Capacity, Energy and Ancillary ServicesCounterparty Risk Management

In January 2000, OPCoThe Vertically Integrated Utilities segment also sells power and National Power Cooperatives (NPC), an affiliate of Buckeye, enteredenters into an agreement relating to the constructionrelated energy transactions with wholesale customers and operation ofother market participants. As a 510 MW gas-fired electric generating peaking facilityresult, counterparties and exchanges may require cash or cash related instruments to be owned by NPC, called the Mone Plant.  The Mone Plant began operationsdeposited on transactions as margin against open positions.  As of December 31, 2015, counterparties posted approximately $9 million in 2002.  OPCo is entitled to 100%cash, cash equivalents or letters of the power generated by the Mone Plant, and is responsiblecredit with AEPSC for the fuelbenefit of AEP’s public utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries posted approximately$52 million with counterparties and other costsexchanges).  Since open trading contracts are valued based on market prices of various commodities, exposures change daily.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the facility through May 2014.  Following that, NPC2015 Annual Reports, under the heading entitled Quantitative and OPCo will be entitled to 80% and 20%, respectively, of the power of the Mone Plant, and both parties will generally be responsibleQualitative Disclosures About Market Risk for their allocable portion of the fuel and other costs of the facility.additional information.


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Certain Power Agreements

I&M

The Unit Power Agreement between AEGCo and I&M, dated March 31, 1982, provides for the sale by AEGCo to I&M of all the capacity (and the energy associated therewith) available to AEGCo at the Rockport Plant.  Whether or not power is available from AEGCo, I&M is obligated to pay a demand charge for the right to receive such power (and an energy charge for any associated energy taken by I&M).  The agreement will continue in effect until the last of the lease terms of Unit 2 of the Rockport Plant hashave expired (currently December 2022) unless extended in specified circumstances.

Pursuant to an assignment between I&M and KPCo, and a unit power agreement between KPCoAEGCo and AEGCo,KPCo, AEGCo sells KPCo 30% of the capacity (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant.  KPCo has agreed to pay to AEGCo the amounts that I&M would have paid AEGCo under the terms of the Unit Power Agreement between AEGCo and I&M for such entitlement.  The KPCo unit power agreement expires in December 2022.

OPCo

The Unit Power Agreement between AEGCo and OPCo dated March 15, 2007, provides for the sale by AEGCo to OPCo of all the capacity and associated unit contingent energy and ancillary services available to OPCo from the Lawrenceburg Plant, a 1,146 MW gas-fired unit owned by AEGCo.  OPCo is obligated to pay a capacity charge (whether or not power is available from the Lawrenceburg Plant), and the fuel, operating and maintenance charges associated with the energy dispatched by OPCo, and to reimburse AEGCo for other costs associated with the operation and ownership of the Lawrenceburg Plant.  The agreement will continue in effect until December 31, 2017 unless extended as set forth in the agreement.

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OVEC

AEP and several nonaffiliated utility companies jointly own OVEC.  The aggregate equity participation of AEP in OVEC is 43.47%.  Until 2001, OVEC supplied from its generating capacityUnder the Inter-Company Power Agreement, which defines the rights of the owners and sets the power requirementsparticipation ratio of a uranium enrichment plant near Portsmouth, Ohio owned byeach, the United States Department of Energy.  The sponsoring companies are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,2002,400 MW) in proportion to their respective power participation ratios.  The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%.  The Inter-Company Power Agreement terminates in June 2040. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and to provide a return on its equity capital.  The Inter-Company Power Agreement, which defines the rights of the owners and sets the power participation ratio of each, was extended by the owners in 2011 from the termination date of March 2026 until June 2040.  AEP and the other owners have authorized environmental investments related to their ownership interests.  OVEC’s Board of Directors has authorizedOVEC financed capital expenditures totaling $1.4$1.3 billion in connection with the engineering and construction of flue gas desulfurization projects and the associated scrubber waste disposal landfills at its two generating plants.  OVEC has completed the financing of the $1.4 billion required for these projectsgeneration plants through debt issuances, including tax-advantaged debt issuances.  OneBoth OVEC generating plant isgeneration plants are operating with the new environmental controls in service.  OPCo attempted to assign its rights and obligations under the Inter-Company Power Agreement to an affiliate as part of its transfer of its generation assets and liabilities in keeping with corporate separation required by Ohio law.  OPCo failed to obtain the consent to assignment from the other owners of OVEC and therefore filed a request with the second scheduledPUCO seeking authorization to be operationalmaintain its ownership of OVEC. In December 2013, the PUCO approved OPCo’s request, subject to the condition that energy from the OVEC entitlements are sold into the day-ahead or real-time PJM energy markets, or on a forward basis through a bilateral arrangement. OPCo has filed an application with the new environmental controls duringPUCO to approve a cost-based purchased power agreement (PPA) rider that would initially be based upon OPCo’s contractual entitlement under the second quarterInter-Company Agreement which is approximately 20% of 2013.OVEC’s capacity.

ELECTRIC TRANSMISSION AND DISTRIBUTIONDELIVERY

General

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power.  See Item 2 – Properties for more information regarding the transmission and distribution lines.  Most of the transmission and distribution services are sold to retail customers of AEP’s vertically integrated public utility subsidiaries in their service territories.  These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC.  See Item 11. BusinessUtility OperationsVertically Integrated Utilities – Regulation – Rates.  The FERC regulates and approves the rates for both wholesale transmission transactions.transactions and wholesale generation contracts.  The use and the recovery of costs associated with the transmission assets of the AEP vertically integrated public utility subsidiaries are subject to the rules, principles, protocols and agreements in place with PJM, SPP and ERCOT, and as approved by the FERC. See Item 11. BusinessUtility OperationsVertically Integrated Utilities – Regulation – FERC.  As discussed below, some transmission services also are separately sold to non-affiliated companies.

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Other than AEGCo, AEP’s vertically integrated public utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas.  In some cases, these franchises provide the utility with the exclusive right to provide electric service.service within a specific territory.  These franchises have varying provisions and expiration dates.  In general, the operating companies consider their franchises to be adequate for the conduct of their business.  For a discussion of competition in the sale of power, see Item 11. BusinessUtility OperationsVertically Integrated Utilities – Competition.

Transmission Agreement

APCo, I&M, KGPCo, KPCo and WPCo own and operate transmission facilities that are used to provide transmission service under the PJM OATT and are parties to the TA.  OPCo, a subsidiary in AEP’s Transmission and Distribution Utilities segment, is also a party to the TA.  The useTA defines how the parties to the agreement share the revenues associated with their transmission facilities and the recoverycosts of costs associated with the transmission assets of the AEP East Companies, including WPCo and KGPCo, are subject to the rules, protocols and agreements in place with PJM and asservice provided by PJM.  The TA has been approved by the FERC.

Transmission Coordination Agreement,TCA, OATT, and ERCOT Protocols

PSO, SWEPCo and AEPSC are parties to the TCA.  Under the TCA, a coordinating committee is charged with the responsibility of (a) overseeing the coordinated planning of the transmission facilities of the parties to the agreement, including the performance of transmission planning studies, (b) the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and (c) compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff.  Pursuant to the TCA, AEPSC has responsibility for monitoring the reliability of their transmission systems and administering the OATT on behalf of the other parties to the agreement.  The TCA also provides for the allocation among the parties of revenues collected for transmission and ancillary services provided under the OATT.  These allocations have been determined by the FERC-approved OATT for the SPP (with respect to PSO and SWEPCo) and PUCT-approved protocols for ERCOT (with respect to TCC and TNC).

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The following table shows the net (credits) or charges allocated pursuant to the TCA, SPP OATT and ERCOT protocols as described above for the years ended December 31, 2012, 2011 and 2010:

Years Ended December 31,
 2012 2011 2010
 (in thousands)
PSO$12,300  $9,000  $10,500 
SWEPCo (12,300)  (9,000)  (10,500)
TCC 2,100   2,100   2,100 
TNC (2,100)  (2,100)  (2,100)

Transmission Services for Non-Affiliates

In addition to providing transmission services in connection with their own power sales, AEP’s public utility subsidiaries through RTOs also provide transmission services for non-affiliated companies.  See Item 1 – Utility Operations – Electric Transmission and Distribution – Regional Transmission Organizations, below.  Transmission of electric power by AEP’s public utility subsidiaries is regulated by the FERC.

Coordination of East and West Zone Transmission

AEP’s System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP East and AEP West Companies.  The System Transmission Integration Agreement functions as an umbrella agreement in addition to the TA and the TCA.  AEP’s System Transmission Integration Agreement contains two service schedules that govern:

·  The allocation of transmission costs and revenues.
·  The allocation of third-party transmission costs and revenues and System dispatch costs.

The System Transmission Integration Agreement contemplates that additional service schedules may be added as circumstances warrant.SPP.

Regional Transmission Organizations

The AEP East CompaniesAEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM, and SWEPCoPSO and PSOSWEPCo are members of the SPP (both FERC-approved RTOs).  RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.  The remaining AEP West Companies (TCC and TNC) are members of ERCOT.

REGULATION

General

Except for transmission and/or retail generation sales in certain of its jurisdictions, AEP’s vertically integrated public utility subsidiaries’ retail rates and certain other matters are subject to traditional cost-based regulation by the state utility commissions.  AEP’s vertically integrated public utility subsidiaries are also subject to regulation by the FERC under the Federal Power Act with respect to wholesale power and transmission service transactions as well as certain unbundled retail transmission rates mainly in Ohio.transactions.  I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant.  AEP and its vertically integrated public utility subsidiaries are also subject to the regulatory provisions of EPACT, much of which is administered by the FERC.  EPACT provides the FERC increased utility merger oversight.

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Rates

Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service.  A utility’s cost of service generally reflects its operating expenses, including operation and maintenance expense, depreciation expense and taxes.  State utility commissions periodically adjust rates pursuant to a review of (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.  Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period

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of time, a state utility commission can review and change rates on its own initiative.  Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers.  Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.

Public utilities have traditionally financed capital investments until the new asset is placed in service.  Provided the asset was found to be a prudent investment, it was then added to rate base and entitled to a return through rate recovery.  Given long lead times in construction, the high costs of plant and equipment and volatile capital markets, we aremanagement is actively pursuing strategies to accelerate rate recognition of investments and cash flow.  AEP representatives continue to engage our state commissioners and legislators on alternative ratemaking options to reduce regulatory lag and enhance certainty in the process.  These options include pre-approvals, a return on construction work in progress, rider/trackers, formula rates and the inclusion of future test-year projections into rates.

In many jurisdictions, theThe rates of AEP’s vertically integrated public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service).  In the ERCOT area of Texas, our utilities have exited the generation business and they currently charge unbundled cost-based rates for transmission and distribution service only.  In Ohio, rates for electric service are unbundled for generation, transmission and distribution service.  Historically, the state regulatory frameworks in the service area of the AEP Systemvertically integrated public utility subsidiaries reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility’s rates and tariffs.  Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes.

The following state-by-state analysis summarizes the regulatory environment of certain major jurisdictions in which AEP operates.AEP’s vertically integrated public utility subsidiaries operate.  Several public utility subsidiaries operate in more than one jurisdiction.  See Note 34 to the consolidated financial statements, entitled Rate Matters, included in the 20122015 Annual Reports, for more information regarding pending rate matters.

Indiana

I&M provides retail electric service in Indiana at bundled rates approved by the IURC, with rates set on a cost-of-service basis.  Indiana provides for timely fuel and purchased power cost recovery through a fuel cost recovery mechanism.

Ohio

OPCo provides “default” retail electric service to customers at unbundled rates pursuant to the Ohio electric restructuring legislation.  OPCo provides distribution and transmission services to retail customers within its service territory at cost-based rates approved by the PUCO or by the FERC.  While Ohio transmission and distribution services continue to be established using more traditional cost-based methods, generation rates are currently priced using a hybrid approach that incorporates components of cost and market.  We are seeking regulatory approval from the FERC to transfer the Ohio generation assets to a newly formed wholly owned competitive Ohio generation affiliate as of January 1, 2014.  The recovery of those generation assets will be subject to market prices starting in mid-May 2015.

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Oklahoma

PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC.  PSO’s rates are set on a cost-of-service basis.  Fuel and purchased energy costs above or below the amount included in base rates are recovered or refunded by applying fuel adjustment and other factors to retail kilowatt-hour sales.  The factors are generally adjusted annually and are based upon forecasted fuel and purchased energy costs.  Over or under collections of fuel and purchased energy costs for prior periods are returned to or recovered from customers in the yearperiod following when new annual factors are established.

Texas

Retail customers in TCC’s and TNC’s ERCOT service area of Texas are served through REPs.  TCC and TNC provide transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules.  Effective September 2009, competition in the SPP area of Texas has been delayed until certain steps defined by statute and by PUCT rule have been accomplished.  As such, the PUCT continues to approve base and fuel rates for SWEPCo’s Texas operations on a cost of service basis.

Virginia

APCo currently provides retail electric service in Virginia at unbundled rates approved by the Virginia SCC.  Virginia generally allows for timely recovery of fuel costs through a fuel adjustment clause.  Transmission services are provided at OATT rates based on rates established by the FERC.  In addition to base rates and fuel cost recovery, APCo is permitted to recover a variety of costs through rate adjustment clauses.

West Virginia

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis.  West Virginia generally allows for timely recovery of fuel costs through an expanded net energy cost which trues-up to actual expenses.


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The following table illustrates certain regulatory information with respect to the states in which the public utility subsidiaries of AEP operate:

Jurisdiction Percentage of AEP System Retail Revenues (a) Percentage of OSS Profits Shared with Ratepayers AEP Utility Subsidiaries Operating in that Jurisdiction Authorized Return on Equity (b)
         
Ohio 29% No sharing included in the ESP OPCo 10.2% (c)
         
Texas 13% Not applicable in ERCOT TCC 9.96%
   Not applicable in ERCOT TNC 9.96%
   90% in SPP SWEPCo 10.33%
         
West Virginia 12% 100% APCo 10.00%
   100% WPCo 10.00%
         
Virginia 12% 75% APCo 10.90%
         
         
Oklahoma 10% 75% PSO 10.15%
         
Indiana 9% 50% below and above certain level (d) I&M 10.20%
         
Louisiana 5% 50% to 100% (e) SWEPCo 10.57%
         
Kentucky 4% 60% below and above certain level (f) KPCo 10.50%
         
Arkansas 3% 50% to 100% (g) SWEPCo 10.25%
         
Michigan 2% 80% I&M 10.20%
         
Tennessee 1% Not applicable KGPCo 12.00%

(a)Represents the percentage of Utility Operations segment revenue from sales to retail customers to total Utility Operations segment revenue for the year ended December 31, 2012.
(b)Identifies the predominant authorized return on equity and may not include other, less significant, permitted recovery.  Actual return on equity varies from authorized return on equity.
(c)OPCo’s authorized return on equity for distribution rates is 10.2%.  OPCo’s generation revenues are governed by its Electric Security Plan (ESP) as approved by the PUCO.
(d)There is an annual $26.9 million credit established for off-system sales in base rates.  If the off-system sales profits do not meet the level built into base rates, ratepayers reimburse I&M 50% of the shortfall.  If the off-system sales profits exceed the level built into base rates, I&M reimburses ratepayers 50% of the excess.
(e)
$874,000 and below, 100% is given to customers.
From $874,001 to $1,314,000, 85% is given to customers.
Above $1,314,000, 50% is given to customers.
(f)There is an annual $15.3 million credit established for off-system sales in base rates.  If the monthly off-system sales profits do not meet the monthly level built into base rates, ratepayers reimburse KPCo 60% of the shortfall.  If the monthly off-system sales profits exceed the monthly level built into base rates, KPCo reimburses ratepayers 60% of the excess.
(g)
$758,600 and below, 100% is given to customers.
From $758,601 to $1,167,078, 85% is given to customers.
Above $1,167,078, 50% is given to customers.
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FERC

Under the Federal Power Act, the FERC regulates rates for interstate power sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects.  The FERC regulations require AEPAEP’s vertically integrated public utility subsidiaries to provide open access transmission service at FERC-approved rates.  The FERC also regulates unbundled transmission service to retail customers.  The FERC also regulates the sale of power for resale in interstate commerce by (a) approving contracts for wholesale sales to municipal and cooperative utilities and (b) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices.  Except for wholesale power that AEP delivers within its balancing area of the SPP, AEP has market-rateAEP’s vertically integrated public utility subsidiaries have market-based rate authority from the FERC, under which much of itstheir wholesale marketing activity takes place.  The FERC requires each public utility that owns or controls interstate transmission facilities to, directly or through an RTO, to file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system.  The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees.

The FERC oversees RTOs, entities created to operate, plan and control utility transmission assets.  Order 2000 also prescribes certain characteristics and functions of acceptable RTO proposals.  The AEP East CompaniesAEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM.  SWEPCoPSO and PSOSWEPCo are members of SPP.

The FERC has jurisdiction over the issuances of securities of most of ourAEP’s public utility subsidiaries, the acquisition of securities of utilities, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company.  In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system.  EPACT gives the FERC increased utility merger oversight.

Competition

Under current Ohio law, electric generation is sold in a competitive market in Ohio and native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service.  CRES providers are targeting retail customers by offering alternative generation service.  In 2011, based upon an average annual load, approximately 10% of our Ohio load had switched to CRES providers.  As of December 31, 2012, that amount had increased to 51%.COMPETITION

The vertically integrated public utility subsidiaries of AEP, like the electric industry generally, face competition in the sale of available power on a wholesale basis, primarily to other public utilities and power marketers.  The Energy Policy Act of 1992 was designed, among other things, to fosterFederal policy generally fosters competition in the wholesale market by creating a generation market with fewer barriers to entry and mandatingmandates that all generators have equal access to transmission services.  As a result, there are more generators able to participate in this market.  The principal factors in competing for wholesale sales are price (including fuel costs), reliability of service, and availability of capacity and power and reliability of service.power.

Technology advancements, increased demand for clean energy, changing consumer behaviors, low-priced and abundant natural gas, and regulatory and public policy reforms are among the catalysts for transformation within the industry that impact competition for AEP’s vertically integrated public utility subsidiaries. AEP’s vertically integrated public utility subsidiaries also compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil, renewables and coal, within their service areas.  The primary factors in such competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power. With respect to competing generators and self-generation, the public utility subsidiaries of AEP believe that they generallycurrently maintain a favorable competitive position. With respect

Changes in regulatory policies and advances in newer technologies for batteries or energy storage, fuel cells, microturbines, wind turbines and photovoltaic solar cells are reducing costs of new technology to alternative sourceslevels that are making them competitive with some central station electricity production.  The costs of photovoltaic solar cells in particular have continued to become increasingly competitive. The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AEP’s competitiveness.


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While the adoption rate of distributed generation in AEP’s service areas has not reached the levels seen in other parts of the country, AEP’s vertically integrated utility companies are focused on providing customers with more choices by working with regulators and policymakers to expand, and potentially accelerate, renewable energy theofferings. Such additional customer choices consider not only long-term cost, but are also focused on expanding resource diversity. This includes proposed new revenue structures that enable deployment of advanced technologies and resources. In 2015, AEP formed an Enterprise Technology Council to develop and deploy new programs and services designed to receive regulatory support. The vertically integrated public utility subsidiaries of AEP believe that the reliability of their service, and the limited ability of customers to substitute other cost-effectiveeconomical sources for electric power and their ability to cost-effectively deploy advanced technologies, such as solar, on a large scale place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy.position.

SignificantIn the event that alternative generation resources are mandated, subsidized or encouraged through legislation or regulationor otherwise are economically competitive and added to the available generation supply, such resources could displace a higher marginal cost fossil plant, which could reduce the price at which market participants sell their electricity. This occurrence could then reduce the market price at which all generators in that region would be able to sell their output. These events could cause AEP to retire generating capacity prior to the end of its estimated useful life.  If AEP retires generation plants prior to the end of their estimated useful life, there can be no assurance that AEP will recover the remaining costs associated with such plants.  AEP typically recovers undepreciated plant balances and associated operating costs from customers through regulated rates in regulated jurisdictions.  Failure to recover these costs could reduce future net income and cash flows and possibly harm financial condition.

Recent changes in the global economy have led to increased price competition for many industrial customers in the United States, including those served by the AEP System. Some of these industrial customers have requested price reductions from their suppliers of electric power.  In addition, industrialIndustrial customers that are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power.  The vertically integrated public utility subsidiaries of AEP cooperatework with such customers to meet their business needs through,
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for example, providing various off-peak or interruptible supply options pursuant to tariffs filed with, and approved by, the various state commissions. Occasionally, these rates are negotiatedThe vertically integrated public utility subsidiaries of AEP also work with customers that seek to source more of their electric power from renewable resources. Depending on the customer, and then filed with the state commissions for approval.jurisdiction, customers may have access to green power tariffs. In other instances, AEP purchases renewable power that is available to all customers in a specific jurisdiction.

SeasonalitySEASONALITY

The sale of electric power is generally a seasonal business.  In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time.  In other areas, power demand peaks during the winter.  The pattern of this fluctuation may change due to the nature and location of AEP’s facilities and the terms of power sale contracts into which AEP enters.  In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder.  Unusually mild weather in the future could diminish AEP’s results of operations and may impact its financial condition.  Conversely, unusually extreme weather conditions could increase AEP’s results of operations.


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TRANSMISSION OPERATIONSAND DISTRIBUTION UTILITIES

AEPTCo OverviewGENERAL

AEPTCo,This segment consists of the transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC. OPCo is engaged in the transmission and distribution of electric power to approximately 1,468,000 retail customers in Ohio.  TCC is engaged in the transmission and distribution of electric power to approximately 826,000 retail customers through REPs in southern Texas. TNC is engaged in the transmission and distribution of electric power to approximately 189,000 retail customers through REPs in west and central Texas.

AEP’s transmission and distribution utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power.  See Item 2 – Properties for more information regarding the transmission and distribution lines.  Most of the transmission and distribution services are sold to retail customers of AEP’s transmission and distribution utility subsidiaries in their service territories.  These sales are made at rates approved by the PUCT for TCC and TNC and by the PUCO and the FERC for OPCo.  The FERC regulates and approves the rates for wholesale transmission transactions.  As discussed below, some transmission services also are separately sold to non-affiliated companies.

AEP’s transmission and distribution utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas.  In some cases, these franchises provide the utility with the exclusive right to provide electric service.  These franchises have varying provisions and expiration dates.  In general, the operating companies consider their franchises to be adequate for the conduct of their business.

The use and the recovery of costs associated with the transmission assets of the AEP transmission and distribution utility subsidiaries are subject to the rules, protocols and agreements in place with PJM and ERCOT, and as approved by the FERC.  In addition to providing transmission services in connection with power sales in their service areas, AEP’s transmission and distribution utility subsidiaries through RTOs also provide transmission services for non-affiliated companies.

Transmission Agreement

OPCo, together with APCo, I&M, KGPCo, KPCo and WPCo, is a subsidiaryparty to the TA.  The TA defines how the parties to the agreement share the cost of their transmission facilities.  The TA has been approved by the FERC.

Regional Transmission Organizations

OPCo is a member of PJM, a FERC-approved RTO.  RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.  TCC and TNC are members of ERCOT.

REGULATION

OPCo provides distribution and transmission services to retail customers within its service territory at cost-based rates approved by the PUCO or by the FERC.  TCC and TNC provide transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules.  Transmission and distribution rates are established on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service.  The cost of service generally reflects operating expenses, including operation and maintenance expense, depreciation expense and taxes.  Utility commissions periodically adjust rates pursuant to a review of (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.


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FERC

Under the Federal Power Act, the FERC regulates rates for transmission of electric power, accounting and other matters.  The FERC regulations require AEP to provide open access transmission service at FERC-approved rates.  The FERC also regulates unbundled transmission service to retail customers.  The FERC requires each public utility that owns or controls interstate transmission facilities to, directly or through an RTO, file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system.  The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system.  EPACT gives the FERC increased utility merger oversight.

SEASONALITY

The delivery of electric power is generally a seasonal business.  In many parts of the country, demand for power peaks during the hot summer months.  In other areas, power demand peaks during the winter months.  The pattern of this fluctuation may change due to the nature and location of AEP’s transmission and distribution facilities.  In addition, AEP transmission and distribution has historically delivered less power, and consequently earned less income, when weather conditions are milder.  Unusually mild weather in the future could diminish AEP transmission and distribution’s results of operations and may impact its financial condition.  Conversely, unusually extreme weather conditions could increase AEP transmission and distribution’s results of operations.

AEP TRANSMISSION HOLDCO (AEPTHCO)

GENERAL

AEPTHCo is a holding company for (a) AEPTCo, which is the direct holding company for the seven wholly-owned FERC-regulated transmission-only electric utilities (Transcos) listed below, each of which is geographically aligned with ourAEP’s existing utility operating companies.  AEPTCo is an indirect wholly-owned subsidiary of AEP.  AEPTCo’s seven wholly-owned transmission-only public utility companies (Transcos) are:and (b) AEP’s transmission joint ventures.  

AEPTCo TRANSCOS

AEP East Transmission Companies( (the “AEP East Transmission Companies”, all operatinglocated within PJM)

·  AEP Appalachian Transmission Company, Inc. (APTCo) (covering Virginia)
·  AEP Indiana Michigan Transmission Company, Inc. (IMTCo)
·  AEP Kentucky Transmission Company, Inc. (KTCo)
·  AEP Ohio Transmission Company, Inc. (OHTCo)
·  AEP West Virginia Transmission Company, Inc. (WVTCo)

AEP West Transmission Companies( (the “AEP West Transmission Companies”, all operatinglocated within SPP)

·  AEP Oklahoma Transmission Company, Inc. (OKTCo)
·  AEP Southwestern Transmission Company, Inc. (SWTCo) (covering Arkansas and Louisiana)

Transmission development through the Transcos is primarily driven by:

Improvements to local area reliability by upgrading, rebuilding or replacing existing, aging infrastructure.
Construction of new facilities to support customer points of delivery, generation interconnections, new facilities to provide transmission service directed by the RTOs, and new facilities required to maintain grid reliability.

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Projects assigned as a result of the regional planning initiatives conducted by PJM and SPP.  PJM and SPP identify the need for transmission in support of regional reliability, congestion reduction and the integration of and retirement of generation facilities.

The Transcos develop, own and operate transmission assets that are physically connected to AEP’s existing system.  They are regulated for rate-making purposes exclusively by the FERC and employ a forward-looking formula rate tariff design.  The Transcos are independent of, but overlay AEP’s existing vertically-integratedvertically integrated utility operating companies.companies and the transmission operations of OPCo.  IMTCo, KTCo, OHTCo, OKTCo and WVTCo have received all necessary approvals for formation.formation or did not require state commission approval to operate.  IMTCo, KTCo, OHTCo, OKTCo and OKTCoWVTCo currently own and operate transmission assets.  APTCo has received approval from the Virginia SCC, although the approval requires APTCo to request project-by-project approval from the Virginia SCC.  ApplicationsAn application for regulatory approvals have been filedapproval for the remaining Transcos and are currentlySWTCo is under consideration in Arkansas, Kentucky and Louisiana. As of December 31, 2012, AEPTCo2015, AEPTCo’s subsidiaries had $378 million$2.8 billion of transmission assets in-service with plans to construct nearly $1.9approximately $3.5 billion of additional transmission assets through 2015.2018.


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AEPTHCo JOINT VENTURE INITIATIVES

Capital Investment StrategyAEP has established joint ventures with other electric utility companies for the purpose of developing, building, and owning transmission assets that seek to improve reliability and market efficiency and provide transmission access to remote generation sources in North America. 

All ofAEP is currently participating in the Transcos’ capital needsfollowing joint venture initiatives:
Joint Venture Name Location Projected or Actual Completion Date 
Owners
 (Ownership %)
 Total Estimated Project Costs at Completion  AEP's Investment as of December 31, 2015 (i) Approved Return on Equity
        (in millions)   
ETT Texas (a) Berkshire Hathaway $3,528.0
(a) $572.0
 9.96% 
  (ERCOT)    Energy (50%)   
   
  
 
      AEP (50%)   
   
  
 
               
Prairie Wind Kansas 2014 Westar Energy (50%)  158.0
  20.6
 12.8% 
      Berkshire Hathaway Energy         
      (25%)  
   
  
 
      AEP (25%) (b)        
 
               
Pioneer Indiana 2018(c)Duke Energy (50%)  1,100.0
(c) 16.9
 12.54% 
      AEP (50%)   
   
  
 
               
RITELine IN Indiana  2026 Exelon (12.5%) 400.0
  0.1
(e)11.43% 
     AEP (87.5%) (d)   
   
  
 
               
RITELine IL Illinois  2026 Commonwealth  1,200.0
  
(e)11.43% 
     Edison (75%)   
   
   
      Exelon (12.5%)  
   
   
      AEP (12.5%) (d)   
   
   
               
Transource Missouri 2016 Great Plains Energy  331.0
  81.3
 11.1%(g)
Missouri     (13.5%)  
   
   
      AEP (86.5%) (f)   
   
   
               
Transource West 2019 Great Plains Energy 60.0
  
 
(h)
West Virginia Virginia   (13.5%) (f)         
      AEP (86.5%) (f)         

(a)ETT is undertaking multiple projects and the completion dates will vary for those projects. ETT’s investment in completed, current and future projects in ERCOT over the next ten years is expected to be $3.5 billion.  Future projects will be evaluated on a case-by-case basis.
(b)AEP owns 25% of Prairie Wind Transmission, LLC (Prairie Wind) through its ownership interest in ETA.  ETA is a 50/50 joint venture with Berkshire Hathaway Energy (formerly known as MidAmerican Energy) and AEP.
(c)The Pioneer project consists of approximately 286 miles of new 765 kV transmission lines, which is estimated to cost $1.1 billion at completion.  Pioneer is developing the first 66-mile segment jointly with Northern Indiana Public Service Company at a total estimated cost of $386 million.  The projected completion date for the first 66-mile segment is 2018.  The projected completion dates for the remaining segments have not been determined.
(d)AEP owns 87.5% of RITELine Indiana, LLC (RITELine IN) through its ownership interest in RITELine Transmission Development, LLC (RTD) and AEP Transmission Holding Company, LLC (AEPTHCo).  AEP owns 12.5% of RITELine Illinois, LLC (RITELine IL) through its ownership interest in RTD.  RTD is a 50/50 joint venture with Exelon Transmission Company, LLC and AEPTHCo.
(e)RITELine IN is a consolidated variable interest entity.  RTD received an order from the FERC in October 2011 granting incentives for the RITELine IN and RITELine IL projects.  The projects and other segments that are electrically equivalent in nature will continue to be submitted for consideration in the interregional planning process between PJM and MISO as dictated by emerging system needs.
(f)AEP owns 86.5% of Transource Missouri and Transource West Virginia through its ownership interest in Transource Energy, LLC (Transource).  Transource is a joint venture with AEPTHCo and Great Plains Energy formed to pursue competitive transmission projects.  AEPTHCo and Great Plains Energy own 86.5% and 13.5% of Transource, respectively.
(g)The ROE represents the weighted average approved return on equity based on the projected costs of two projects currently under development by Transource Missouri:  the $65 million Iatan-Nashua project (10.3%) and the $266 million Sibley-Nebraska City project (11.3%).
(h)An application for recovery has been filed and a settlement is pending which calls for 10% Base ROE, together with a 0.50% rider, for Transource West Virginia’s 15 mile 138kV line Thorofare project.
(i)RITELine IN, Transource Missouri and Transource West Virginia are consolidated joint ventures by AEP.  Therefore, the investment value listed reflects applicable income taxes that are the responsibility of AEP.  All other investments in this schedule are joint ventures that are not consolidated by AEP.  Therefore, these investment values listed do not reflect income taxes that are the responsibility of AEP.

AEP’s joint ventures do not have employees.  Business services for the joint ventures are provided by Parent, AEPTCo and/AEPSC and other AEP subsidiaries and the joint venture partners. During 2015 approximately 521 AEPSC employees and 253 operating company employees provided service to one or the AEP Utility Money Pool.  The Utility Money Pool is used to meet the short-term borrowing needs of AEP regulated utility subsidiaries.  The Utility Money Pool operates in accordance with the terms and conditions approved in regulatory orders.  We forecast approximately $700 million, excluding AFUDC, of construction expenditures in 2013 for the Transcos.
more joint ventures.

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In October 2012, AEPTCo completed a $250 million debt offering and immediately loaned $200 million and $50 million in proceeds to OHTCo and IMTCo, respectively.  In December 2012, AEPTCo issued an additional $75 million in debt and immediately loaned the proceeds to OKTCo.  APTCo will issue an additional $25 million in March 2013 but it is not yet determined which subsidiaries of AEPTCo will receive the proceeds.

Transmission development through the Transcos is primarily driven by

·  Improvements to local area reliability by upgrading, rebuilding or replacing existing, aging infrastructure.
·  Construction of new facilities to support both customer points of delivery and generation interconnections and new facilities required to maintain grid reliability associated with generation resource retirements.
·  Projects assigned as a result of the regional planning initiatives conducted by PJM and SPP.  PJM and SPP identify the need for transmission in support of regional reliability, congestion reduction and the integration of supply-side resources (primarily renewable) and retirements of generation facilities.

Regulatory EnvironmentREGULATION

The Transcos and joint ventures located outside of ERCOT establish transmission rates annually through forward looking formula rate filings with the FERC pursuant to the FERC-approved formula rate implementation protocols.  FERC hasThe protocols include a transparent, formal review process in place to ensure the updated transmission rates are prudently incurred and reasonably calculated.

The annual updatesTranscos’ and joint ventures’ (where applicable) rates are submitted toincluded in the respective OATT for PJM and SPP, respectively, for public posting on their respective websites and submitted to FERC in an informational filing.  Any interested party may participate in the review of the annual update and must comply with defined timelines to request additional information on such rate updates.

SPP.  An OATT is the FERC rate schedule that provides the terms and conditions for transmission and related services on a transmission provider’s transmission system (for the Transcos, PJM or SPP).system.  The FERC requires transmission providers such as PJM and SPP to offer transmission service to all eligible customers (i.e.,(for example, load-serving entities, power marketers, generators and customers in states with supplier choice)customers) on a non-discriminatory basis.

The FERC-approved formula rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners in annual rate base filings with FERC.  The formula rates establish rates for a one-year period based on the current projects in-service and proposed projects for a defined timeframe.  The formula rates also include a true-up calculation for the previous year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR.  PJM and SPP OATTs provide standard termspay the transmission owners their ATRR for use of their facilities and conditions to ensure consistent service availability and treatment of all transmission customers.

The Transcos’ rates are included in the respective OATT for PJM and SPP.  PJM and SPP collect the Transcos’ rates frombill transmission customers taking service under the PJM and SPP OATTs, based on the terms and conditions in the respective OATTsOATT for the service taken.  Some charges are directly assigned to a transmission customer, but the majority of the charges are paid by transmission customers taking transmission service to serve load, deliver power, or to connect generation resources.

The FERC establishes transmission service rates for transmission owners (including the Transcos), as derived from their annual transmission revenue requirement (ATRR).  Each of the Transcos’ ATRR establishes rates for a one-year period based on the current projects in-service and proposed projects for a defined timeframe.  The ATRR also includes a true-up calculation during the annual formula update for the previous year’s billings, eliminating any potential for over- or under-recovery of the allowed return on and of the plant in-service.  The Transcos collectively filed rate base increases of $283 million and $104 million for 2012 and 2011, respectively.  The total transmission revenue requirement filed in the ATRR for 2012 and 2011 equaled $35 million and $13 million, respectively.

The cost of service formula rate mechanism allows for a return on equity of 11.49% based on a capital structure of up to 50% equity for the AEP East Transmission Companies.  The AEP West Transmission Companies are allowed a return on equity of 11.20%11.2% based on a capital structure of up to 50% equity. The authorized returns on equity for the Transcos are commensurate with the FERC-authorized returns on equity in the PJM and SPP OATTs, respectively, for AEP’s utility subsidiaries.

Joint Venture InitiativesIn the annual rate base filings described above, the Transcos in aggregate filed rate base totals of $2.3 billion in 2015, $1.4 billion for 2014 and $776 million for 2013.  The total transmission revenue requirement filed in the ATRR, including prior year over/under-recovery of revenue and associated carrying charges, for 2015, 2014, 2013 and 2012 was $363 million, $231 million, $107 million and $34 million, respectively.

AEP has establishedThe rates of ETT, which is located in ERCOT, are determined by the PUCT.  ETT sets its rates through a combination of base rate cases and interim Transmission Costs of Services (TCOS) filings.  ETT may file interim TCOS filings semi-annually to update its rates to reflect changes in its net invested capital. In November 2015, the PUCT ordered ETT 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 TCOS increase was based. A refund of interim transmission rates would reduce future net income and cash flows. Management is unable to determine a range of potential losses that are reasonably possible of occurring. See Note 4 to the financial statements, entitled Rate Matters, included in the 2015 Annual Reports, for more information regarding pending rate matters.

AEP’s joint ventures with other electric utility companies for the purpose of developing, building, and owning Extra High Voltage (EHV) transmission lines that seekhave approved returns on equity ranging from 9.96% to improve reliability and market efficiency and provide transmission access12.8% based on equity capital structures ranging from 40% to remote generation sources in North America.  Our joint ventures are at various stages of regulatory and RTO approval.
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ETT, our largest joint venture, was established with MidAmerican Energy Holdings Company (MidAmerican) to construct, fund, own and operate electric transmission assets within ERCOT, including transmission projects in the Competitive Renewable Energy Zone (CREZ)60%.  The PUCT has awarded approximately $1.5 billion of total CREZ investment to ETT.  AEP has a 50% ownership interest in ETT.

Electric Transmission America (ETA)COMPETITION

One of the most significant provisions of FERC Order No. 1000 is a joint venture between AEPthe removal of the federal right of first refusal for incumbent utilities within tariffs and MidAmericanagreements for certain regional transmission projects. Historically, vertically integrated public utilities had the right to build and own electric transmission assets.  Prairie Wind Transmission, a joint venture between ETA and Westar Energy, began construction of a Kansas EHV transmission project in 2012.  The approximately $180 million project is expected to be in servicelines proposed by the endregion’s planning processes when those lines connected to facilities within their respective retail service territories.  FERC Order No. 1000 eliminates the federal right of 2014.  AEP has a 50% ownership interestfirst refusal in ETARTO tariffs for incumbent utilities to construct certain regional transmission projects within their own service territories, thereby creating the opportunity for any qualified entity to build and a 25% interestown regional transmission facilities in Prairie Wind through its ownership interest in ETA.any service territory.  Transource was created to respond to FERC Order No. 1000 competitive processes at the RTO level.


Pioneer Transmission, LLC (Pioneer) is a joint venture between AEP and Duke Energy.  AEP has a 50% ownership interest in Pioneer.  The first segment of Pioneer’s proposed line linking Duke Energy’s Greentown Station to AEP’s Rockport Station was included in the 2011 MISO Transmission Expansion Plan as a Multi-Value Project (MVP).  Subject to regulatory approval, Pioneer has agreed to jointly develop the first segment with Northern Indiana Public Service Company as part of the settlement of a dispute regarding the rights to develop the project.  The remaining portion of the project will be evaluated by MISO and PJM as part of their next planning review cycles.  The estimated cost to complete the entire Pioneer project is $950 million.
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RITELine Transmission Development, LLC (RTD) is a joint venture between AEP and Exelon.  AEP owns 50% of RTD.  RITELine Indiana, LLC (RITELine IN) is a joint venture between AEP and RTD.  AEP, directly and indirectly through RTD, has an 87.5% ownership interest in RITELine IN.  RITELine Illinois, LLC (RITELine IL) is a joint venture between RTD and Commonwealth Edison.  Through its ownership interest in RTD, AEP has a 12.5% interest in RITELine IL.  The RITELine project companies will build and operate approximately 420 miles of high-voltage transmission lines and related facilities in Indiana (with a projected cost of $400 million) and Illinois (with a projected cost of $1.2 billion).  RTD received an order from the FERC in October 2011 granting incentives for the RITELine IN and RITELine IL projects.  The projects are currently under evaluation by PJM.

Transource Energy, LLC (Transource), a joint venture between AEP and Great Plains Energy, was formed in 2012 primarily to pursue competitive transmission projects in the PJM, SPP and MISO transmission regions.  Its first two projects are the Iatan-Nashua Project and the Sibley-Nebraska City Project, which were approved by the SPP in 2009 and 2010, respectively.  AEP has an 86.5% ownership interest, and Great Plains Energy Incorporated holds a minority ownership interest, in Transource.

Business services for the joint ventures are provided by AEPSC and other AEP subsidiaries and the joint venture partners.  Therefore, the joint ventures do not have any employees.  For the equity investments within our Transmission Operations segment, we forecast approximately $55 million of AEP equity contributions in 2013 to support construction expenditures and the payment of operating expenses.

AEP RIVER OPERATIONS

Our AEP River Operations segment transports coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi rivers.  Almost all of our customers are nonaffiliated third parties who obtain the transport of coal and dry bulk commodities for various uses.  We charge these customers market rates for the purpose of making a profit.  Depending on market conditions and other factors, including barge availability, we permit AEP utility subsidiary affiliates to use certain of our equipment at rates that reflect our cost.  Our affiliated utility customers procure the transport of coal for use as fuel in their respective generating plants.  AEP River Operations includes approximately 2,500 barges, 45 towboats and 25 harbor boats that we own or lease.  These assets are separate from the barges and towboats dedicated exclusively to transporting coal for use as fuel in our own generating facilities discussed under the prior segment.  See Item 1 – Utility Operations – Electric Generation – Fuel Supply – Coal and Lignite.

Competition within the barging industry for major commodity contracts is intense, with a number of companies offering transportation services in the waterways we serve.  We compete with other carriers primarily on the basis of commodity shipping rates, but also with respect to customer service, available routes, value-added services (including scheduling convenience and flexibility).  The industry continues to experience consolidation.  The resulting companies increasingly offer the widespread geographic reach necessary to support major national
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customers.  Demand for barging services can be seasonal, particularly with respect to the movement of harvested agricultural commodities (beginning in the late summer and extending through the fall).  Cold winter weather, water levels and inefficient older river locks operated by others may also limit our operations when certain of the waterways we serve are closed or commercial traffic is limited.

Our transportation operations are subject to regulation by the U.S. Coast Guard, federal laws, state laws and certain international conventions.  Legislation has been proposed that could make our towboats subject to inspection by the U.S. Coast Guard.

GENERATION AND& MARKETING

OurGENERAL

The AEP Generation and& Marketing Segment consistssegment subsidiaries consist of competitive nonutility generating assets, a wholesale energy trading and marketing business and a retail supply and energy management business.  The largest subsidiary in the Generation & Marketing segment is AGR.  AGR owns 6,752 MW of generating capacity, with rights to an additional 1,186 MW pursuant to a unit power agreement (see below).  Other subsidiaries in this segment own or have the right to receive power from additional generation assets.  See Item 2 – Properties for more information regarding the generation assets of the Generation & Marketing segment. AGR is a competitive generation subsidiary.

With respect to our wholesale energy trading and marketing business, weAEP Generation & Marketing segment subsidiaries enter into short and long-term transactions to buy or sell capacity, energy and ancillary services primarily in ERCOT, PJMSPP, MISO and MISO.PJM.  These subsidiaries sell power into the market and engage in power, natural gas, coal and emissions allowances risk management and trading activities.  

These activities primarily involve the purchase and sale of electricity (and to a lesser extent, natural gas, coal and emissions allowances) under forward contracts at fixed and variable prices.  These contracts include physical transactions, exchange-traded futures, and to a lesser extent, over-the-counter swaps and options.  The majority of forward contracts are typically settled by entering into offsetting contracts.  These transactions are executed with numerous counterparties or on exchanges.

With respect to the retail supply and energy management business, AEP’s subsidiary AEP Energy is a retail energy supplier that supplies electricity to residential, commercial, and industrial customers.  AEP Energy provides an array of energy solutions and is operating in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C.  AEP Energy also provides demand-side management solutions nationwide.  AEP Energy had approximately 375,000 customer accounts as of December 31, 2015.

REGULATION

AGR is a public utility under the Federal Power Act, and is subject to FERC’s exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or deny market-based rates for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable.  FERC granted AGR market-based rate authority in December 2013.  FERC’s jurisdiction over ratemaking also includes the authority to suspend the market-based rates of utilities (including AGR, which is a public utility as defined by the FERC) and set cost-based rates if FERC subsequently determines that such utility can exercise market power, create barriers to entry or engage in abusive affiliate transactions.  As a condition to the order granting AGR market-based rate authority, every three years AGR is required to file a market power update to show that it continues to meet FERC’s standards with respect to generation market power and other criteria used to evaluate whether it continues to qualify for market-based rates.  Other matters subject to FERC jurisdiction include, but are not limited to, review of mergers, and dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility.

Specific operations of AGR are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including Federal and state environmental protection agencies.  AGR is also regulated by the PUCT for transactions inside ERCOT.  Additionally, AGR is subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation, with the approval of FERC. 

COMPETITION

The AEP Generation & Marketing segment subsidiaries face competition for the sale of available power, capacity and ancillary services.  The principal factors of impact are electricity and fuel prices, new market entrants, construction or retirement of generating assets by others and technological advances in power generation. Because much of AGR’s

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generation is coal-fired, lower relative natural gas prices will favor competitors that have a higher concentration of natural gas fueled generation.  Other factors impacting competitiveness include environmental regulation, transmission congestion or transportation constraints at or near generation facilities, inoperability or inefficiencies, outages and deactivations and retirements at generation facilities.

Technology advancements, increased demand for clean energy, changing consumer behaviors, low-priced and abundant natural gas, and regulatory and public policy reforms are among the catalysts for transformation within the industry that impact competition for AEP’s Generation & Marketing segment. AGR also competes with self-generation and with distributors of other energy sources, such as natural gas, fuel oil, renewables and coal, within their service areas.  The primary factors in such competition are price, unit availability and the capability of customers to utilize sources of energy other than electric power.

Changes in regulatory policies and advances in newer technologies for batteries or energy storage, fuel cells, microturbines, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production.  The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AGR’s competitiveness. The costs of photovoltaic solar cells in particular have continued to become increasingly competitive.

While the adoption rate of distributed generation in areas that AGR sells power has not reached the levels seen in other parts of the country, AEP expects these trends to continue. AGR believes that the unit availability, the limited ability of customers to substitute other economical sources for electric power and its ability to cost-effectively deploy advanced technologies, such as solar, on a large scale place it in a favorable competitive position.

In the event that alternative generation resources are mandated, subsidized or encouraged through climate legislation or regulation or otherwise are economically competitive and added to the available generation supply, such resources could displace a higher marginal cost fossil plant, which could reduce the price at which market participants sell their electricity. This occurrence could then reduce the market price at which all generators in that region would be able to sell their output. These events could cause AGR to retire generating capacity prior to the end of its estimated useful life.   If AGR retires generation plants prior to the end of their estimated useful life, there can be no assurance that AGR will recover the remaining costs associated with such plants and may be forced to shut down competitive units.  

Recent changes in the global economy have led to increased competition for many industrial customers in the United States, including those served by the Generation & Marketing segment. Industrial customers that are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power.  The Generation & Marketing segment works with such customers to meet their business needs through, for example, providing various off-peak or interruptible supply options. The Generation & Marketing segment also works with customers that seek to source more of their electric power from renewable resources.

SEASONALITY

The sale of electric power is generally a seasonal business.  In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time.  In other areas, power demand peaks during the winter months.  The pattern of this fluctuation may change.

Fuel Supply

The table shows the generation sources by type, on an actual net generation (MWhs) basis, used by the Generation and Marketing segment, not including the Oklaunion generating unit:
 2015 2014
Coal   75%    88%
Natural Gas   25%    12%
Fuel Oil and other< 1% < 1%

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A price increase/decrease in one or more fuel sources relative to other fuels may result in the decreased/increased use of other fuels.

Coal and Consumables
AGR procures coal and consumables needed to burn the coal under a combination of purchasing arrangements including long-term and spot contracts with various producers and coal trading firms.  As contracts expire, they are replaced, as needed, with contracts at market prices. Coal and consumable inventories remain adequate to meet generation requirements.
Management believes that AGR will be able to secure and transport coal and consumables of adequate quality and in adequate quantities to operate their coal fired units.  AGR, through its contracts with third party transporters, has the ability to adequately move and store coal and consumables for use in its generating facilities. AGR plants consumed 11.2 million tons of coal in 2015.

The coal supplies at AGR plants vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, coal quality, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. AGR likes to maintain the coal inventory of its managed plants in the range of 15 to 40 days of full load burn.  As of December 31, 2012,2015, the coal inventory of AGR was approximately 57 days of full load burn.

Natural Gas

Despite the availability of natural gas due to the increased shale supply, the U.S. pipeline infrastructure remains a limiting factor in the expansion of natural gas-fired generation.  A portfolio of term, monthly, seasonal firm and daily peaking purchase and transportation agreements (that are entered into on a competitive basis and based on market prices) supplies natural gas requirements for each plant, as appropriate. AGR plants consumed 86 billion cubic feet of natural gas in 2015, an increase of approximately 73% from 2014.

Counterparty Risk Management

Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions.  As of December 31, 2015, counterparties posted approximately $26 million in cash, cash equivalents or letters of credit with AEP for the benefit of AEP’s Generation & Marketing segment subsidiaries (while, as of that date, AEP’s Generation & Marketing segment subsidiaries posted approximately$225 million with counterparties and exchanges).  Since open trading contracts are valued based on market prices of various commodities, exposures change daily.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2015 Annual Reports, under the heading entitled Quantitative and Qualitative Disclosures About Market Risk for additional information.

Certain Power Agreements

AEGCo

The Unit Power Agreement between AEGCo and AGR (assigned from OPCo) dated March 15, 2007, provides for the sale by AEGCo to AGR of all the capacity and associated unit contingent energy and ancillary services available to AGR from the Lawrenceburg Plant, a 1,186 MW natural gas-fired unit owned by AEGCo.  AGR is obligated to pay a capacity charge (whether or not power is available from the Lawrenceburg Plant), and the fuel, operating and maintenance charges associated with the energy dispatched by AGR, and to reimburse AEGCo for other costs associated with the operation and ownership of the Lawrenceburg Plant.  The agreement will continue in effect until December 31, 2017 unless extended.


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OPCo

Pursuant to a Power Supply Agreement (PSA) between AGR and OPCo, AGR supplied capacity for OPCo’s switched and non-switched retail load for the period January 1, 2014 through May 31, 2015.

Other

As of December 31, 2015, the assets utilized in this segment included approximately 310 MW of company-owned domestic wind power facilities, 177 MW of domestic wind power from long-term purchase power agreements and 377355 MW of coal-fired capacity which was obtained through an agreement effective through 2027 that transfers TNC’s interest in the Oklaunion power station to AEP Energy Partners, Inc.  The power obtained from the Oklaunion power station is marketed and sold in ERCOT.  We are regulated by

AEP RIVER OPERATIONS

Prior to its sale in November 2015, AEP River Operations segment transported liquid, coal and dry bulk commodities primarily on the PUCT for transactions inside ERCOTOhio, Illinois and bylower Mississippi rivers.  As a result of the FERC for transactions outside of ERCOT.  While peak load in ERCOT typically occurs in the summer, we do not necessarily expect seasonal variation in our operations. With respect to our retail supply and energy managementsale, AEP River Operations is no longer a business AEP Energy is a retail electricity supplier that supplies electricity to residential, commercial, and industrial customers.  AEP Energy provides an array of energy solutions and is operating in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C.  AEP Energy also provides energy demand-side management solutions nationwide.  AEP Energy  had more than 160,000 customer accounts as of December 31, 2012.segment.



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EXECUTIVE OFFICERS OF AEP as of February 26, 2013

The following persons are executive officers of AEP.  Their ages are given as of February 1, 2013.23, 2016.  The officers are appointed annually for a one-year term by the board of directors of AEP.

Nicholas K. Akins
Chairman of the Board, President and Chief Executive Officer
Age 5255
Chairman of the Board since January 2014, President since January 2011 and Chief Executive Officer since November 2011 and President since January 2011. Was Executive Vice President-Generation from September 2006 to December 2010.

Lisa M. Barton
Executive Vice President – Transmission
Age 4750
Executive Vice President-TransmissionPresident – Transmission of AEPSC since August 2011. Was Senior Vice President-TransmissionPresident – Transmission Strategy and Business Development of AEPSC from November 2010 to July 2011, Vice President-Transmission Strategy and Business Development of AEPSC from October 2007 to November 2010.2011.

David M. Feinberg
Executive Vice President, General Counsel and Secretary
Age 4346
Executive Vice President since January 2013.  Was Senior Vice President, General Counsel and Secretary from January 2012 to December 2012 and Senior Vice President and General Counsel of AEPSC from May 2011 to December 2011. Previously served as Vice President, General Counsel and Secretary of Allegheny Energy, Inc. from 2006 to 2011.

Lana L. Hillebrand
Senior Vice President and Chief Administrative Officer
Age 5255
Senior Vice President and Chief Administrative Officer since December 2012.  Previously served as South Region leader-Seniorleader – Senior Partner at Aon Hewitt since 2010.  Was U.S. Consulting Client Development leader-managing principal at Aon Hewitt from 2008-2010.

Mark C. McCullough
Executive Vice President – Generation
Age 5356
Executive Vice President-GenerationPresident – Generation of AEPSC since January 2011. Was Senior Vice President-Fossil & Hydro Generation of AEPSC from February 2008 to December 2010 and Vice President-Baseload Generation of AEPSC from June 2005 to February 2008.

Robert P. Powers
Executive Vice President and Chief Operating Officer
Age 5862
Executive Vice President and Chief Operating Officer since November 2011.  Was President-UtilityPresident – Utility Group from April 2009 to November 2011, President-AEP Utilities from January 2008 to April 2009.2011.

Brian X. Tierney
Executive Vice President and Chief Financial Officer
Age 4548
Executive Vice President and Chief Financial Officer since October 2009.  Was Executive Vice President-AEP Utilities East of AEPSC from January 2008 to October 2009.

DennisCharles E. WelchZebula
Executive Vice President and Chief External Officer– Energy Supply
Age 6155
Executive Vice President and Chief External Officer– Energy Supply since January 2013. Was ExecutiveSenior Vice President – Investor Relations and Chief Administrative OfficerTreasurer from October 2011September 2008 to December 2012. Was Executive Vice President-Environment, Safety & Health and Facilities from January 2008 to September 2011.

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ITEM 1A.   RISK FACTORS

In addition to other disclosures within this report, including Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other documents filed with the SEC from time to time, the following factors should be considered in evaluating the Registrants. Such factors could affect actual results of operations and cause results to differ substantially from those currently expected or sought. As indicated below, many of the following risk factors apply to AEP and several or all of the Registrant Subsidiaries and, accordingly, such risk factors should be read to include the applicable Registrants.

GENERAL RISKS OF OUR REGULATED OPERATIONS

WeAEP may not be able to recover the costs of our substantial planned investment in capital improvements and additions. – Affecting each Registrant(Applies to all Registrants)

OurAEP’s business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits, construction of additional transmission facilities, modernizing existing infrastructure as well as other initiatives.  OurAEP’s public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions.  If these regulatory commissions do not approve adjustments to the rates we charge, wecharged, affected AEP subsidiaries would not be able to recover the costs associated with ourtheir planned extensive investment.  This would cause our financial results to be diminished.  While we

Regulated electric revenues, earnings and results are dependent on state regulation that may seeklimit AEP’s ability to limit the impact of any denied recovery by attempting to reduce the scope of our capital investment, there can be no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurredrecover costs and commitments.other amounts. (Applies to all Registrants)

ApprovalThe rates customers pay to AEP regulated utility businesses are subject to approval by the FERC and the respective state utility commissions of Ohio, Texas, Virginia, West Virginia, Oklahoma, Indiana, Louisiana, Kentucky, Arkansas, Michigan and Tennessee. If regulated utility earnings exceed the new ESP order in Ohioreturns established by the relevant commissions, retail electric rates may be overturned. – Affecting AEPsubject to review and OPCo

In August 2012,possible reduction by the PUCO issued an ordercommissions, which adopted and modified a new ESP through May 2015.  The ESP allowed the continuation of the fuel adjustment clause and established a non-bypassable Distribution Investment Rider effective September 2012 through May 2015 to recover, with certain caps, post-August 2010 distribution investment.  The ESP also maintainedmay decrease future earnings. Additionally, if regulatory bodies do not allow recovery of several previous ESP riders and approvedcosts incurred in providing service on a storm damage recovery mechanism which allowed OPCo to defer the majority of the incremental distribution operation and maintenance costs from 2012 storms.    In January 2013, the PUCO issued its Order on Rehearing for the ESP which generally upheld its August 2012 order.  The PUCO addressed certain issues around the energy auctions while other SSO issues were deferred to a separate docket.  Comments on the rehearing order are permitted to be filed by intervenors through March 2013.  If the PUCO reverses all or part of the ESP rehearing order,timely basis, it could reduce future net income and cash flows and negatively impact financial condition. Similarly, if recovery or other rate relief authorized in the past is overturned or reversed on appeal, future earnings could be negatively impacted. Any regulatory action or litigation outcome that triggers a reversal of a regulatory asset or deferred cost, including fuel and related costs, generally results in an impairment to the balance sheet and a charge to the income statement of the company involved.

We may not fully collect deferred capacity costs. – Affecting AEP and OPCo

The PUCO adopted and modified the new ESP and established a non-bypassable Retail Stability Rider (RSR).  A portion of the RSR provides for the collection of deferred capacity costs.  The deferred capacity costs may exceed the amount we will collect under the RSR.  In addition, the Industrial Energy Users-Ohio filed a claim before the Supreme Court of Ohio stating, among other things, that OPCo’s recovery of its capacity costs is illegal.  If OPCo is ultimately not permitted to fully collect its deferred capacity costs, it would reduce future net income and cash flows and impact financial condition.

We may not recover deferred fuel costs. – Affecting AEP and OPCo

In August 2012, the PUCO ordered recovery of deferred fuel costs beginning September 2012 through the Phase-In Recovery Rider.  The August 2012 order was upheld by the PUCO in October 2012.  OPCo and intervenors have filed appeals at the Supreme Court of Ohio.  If the Supreme Court of Ohio does not permit full recovery of OPCo’s deferred fuel costs, it would reduce future net income and cash flows and impact financial condition.

Prior ESP rate recovery approved in Ohio may have to be returned, may not provide full recovery of costs and is subject to appeal. – Affecting AEP and OPCo

The PUCO issued an order in March 2009 that modified and approved the prior ESP which established rates through 2011.  The prior ESP order generally authorized rate increases during the ESP period, subject to caps that limited the rate increases, and also provided a fuel adjustment clause for the three-year period of that ESP.  There remain three risks associated with this prior approved recovery:  (a) amounts collected by us for the years 2010 and 2011 are subject to an excessive earnings test administered by the PUCO, which could require us to refund amounts to customers, (b) the recovery under the fuel adjustment clause includes significant deferrals of costs associated with an interim arrangement with a major steel producing customer and is subject to the PUCO’s ultimate decision regarding those deferrals plus related carrying charges, and (c) intervenors are challenging various issues at the Supreme Court of Ohio, asserting that charges that the PUCO reversed going forward also should have been
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reversed retrospectively and challenging various aspects of approved environmental carrying charges.  If the PUCO and/or the Supreme Court of Ohio reverses all or part of the rate recovery or if deferred amounts are not recovered for other reasons, it could reduce future net income and cash flows and impact financial condition.

Ohio may require us to refund additional fuel costs. – Affecting AEP and OPCo

In January 2012, the PUCO ordered that proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance and that an outside consultant be hired to review our fuel procurement through 2011.  The audit by the outside consultant included recommendations that would limit some of our fuel recovery or require us to refund certain fuel costs already incurred.  In addition, an intervenor filed a claim for refund of certain fuel costs with the Supreme Court of Ohio.   If the PUCO orders result in a reduction to our fuel recovery and/or the Supreme Court of Ohio ultimately determines to grant all or part of the requested refund, it could reduce future net income and cash flows and impact financial condition.

We may not fully recover all of the investment in and expenses related to the Turk Plant – Affecting AEP and SWEPCo

In December 2012, SWEPCo placed the Turk Plant in Arkansas into commercial operation.  SWEPCo holds a 73% ownership interest in the 600 MW coal-fired generating facility.  SWEPCo had originally intended that 88 MW of the Turk Plant would become part of the rate base for its retail customers in Arkansas.  Following a proceeding at the Arkansas Supreme Court, the APSC issued an order which reversed and set aside a previously granted Certificate of Environmental Compatibility and Public Need.  This portion of the Turk Plant output is currently not subject to cost based rate recovery and is being sold into the SPP market.  SWEPCo has included a request to recover a portion of the costs of the Turk Plant in its base rate case filed in Texas and has made a formula rate filing with the LPSC, and a subsequent settlement seeking recovery for a portion of the costs of the Turk Plant.  If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant either through retail rates or sales into the SPP market, it could reduce future net income and cash flows and impact financial condition.

We may not fully recover all of the investment in and expenses related to extending the useful life of the Cook Plant – Affecting AEP and I&M

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects for Cook Plant Units 1 and 2 intended to ensure the safe and reliable operation of the plant through its licensed life.  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of December 31, 2012, I&M has incurred $176 million related to the LCM Project, including AFUDC.  If I&M is not ultimately permitted to recover its LCM Project costs, it would reduce future net income and cash flows and impact financial condition.

Request for rate recovery in Texas may not be approved in its entirety. – Affecting AEP and SWEPCo

In July 2012, SWEPCo filed a request with the PUCT for an annual increase in Texas base rates.  A portion of the increase seeks recovery for costs associated with the construction and operation of the Texas jurisdictional share (approximately 33%) of the Turk Plant.  In April 2012, the Texas Industrial Energy Consumers filed a petition for review at the Supreme Court of Texas contending that the Turk Plant is unnecessary to serve retail customers.  The Supreme Court of Texas has requested full briefing from the parties.  If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it would reduce future net income and cash flows and impact financial condition.

OurAEP’s transmission investment strategy and execution bears certain risks associated with these activities. – Affecting AEP(Applies to all Registrants)

We expectManagement expects that a growing portion of ourAEP’s earnings in the future will derivebe derived from the transmission investments and activities of AEPTCo and our transmission joint ventures.  FERC policy currently favors the expansion and updating of the transmission infrastructure within its jurisdiction.  If FERC were to adopt a different policy, if states were to limit or restrict such policies, or if transmission needs do not continue or develop as projected, ourAEP’s strategy of investing in transmission could be curtailed.  We believe ourimpacted.  Management believes AEP’s experience with transmission facilities construction and operation gives usAEP an advantage over other competitors in securing authorization to install, construct and operate new transmission lines and facilities.
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However, there can be no assurance that PJM, SPP or other RTOs will authorize any new transmission projects or will award any such projects to us.AEP.  If the FERC were to lower the rate of return it has authorized for ourAEP’s transmission investments and facilities, or if one or more states were to successfully limit FERC jurisdiction on recovery of costs on transmission investment and its return, it could reduce future net income and cash flows and negatively impact financial condition.


We
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AEP may not recover costs incurred to begin construction on projects that are canceled. – Affecting each Registrant(Applies to all Registrants)

OurAEP’s business plan for the construction of new projects involves a number of risks, including construction delays, nonperformance by equipment and other third party suppliers, and increases in equipment and labor costs.  To limit the risks of these construction projects, weAEP and its subsidiaries enter into equipment purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals and/or siting or environmental permits.  If any of these projects isare canceled for any reason, including our failure to receive necessary regulatory approvals and/or siting or environmental permits, we could incur significant cancellation penalties under the equipment purchase orders and construction contracts.contracts could occur.  In addition, if we have recorded any construction work or investments have been recorded as an asset, wean impairment may need to impair that assetbe recorded in the event the project is canceled.

Rate regulation may delay or deny full recovery of capital improvements, additions, storm damage operations and maintenance expense repairs and other costs. – Affecting each Registrant

Our public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions.  These rates are generally regulated based on an analysis of the applicable utility’s expenses incurred in a test year.  Thus, commission-approved rates may or may not match a utility’s expenses at any given time.  There may also be a delay between the timing of when these costs are incurred and when these costs are recovered.  Traditionally, we have financed capital investments and improvements until the new asset was placed in service.  Provided the asset was found to be a prudent investment, the asset was then added to rate base and entitled to a return through rate recovery.  Similarly, we often finance the operations and maintenance expense to repair facilities damaged by storms or other severe weather events until the operations and maintenance storm costs, including any deferred regulatory assets, are recovered in rates. Long lead times in construction and scheduled repairs, the high costs of plant and equipment and volatile capital markets have heightened the risks involved in our capital investments, repairs and improvements.  While we are actively pursuing strategies to accelerate rate recognition of investments and cash flow, including pre-approvals, a return on construction work in progress, rider/trackers, formula rates and the inclusion of future test-year projections into rates, there can be no assurance that these will be adopted, that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will be done in a timely manner.

Certain of our revenues and results of operations are subject to risks that are beyond our control. – Affecting each Registrant

Our operations are structured to comply with all applicable federal and state laws and regulations and we take measures to minimize the risk of significant disruptions. Material disruptions at one or more of our operational facilities, however, could negatively impact our revenues, operating and capital expenditures and results of operations.  Such events may also create additional risks related to the supply and/or cost of equipment and materials.  We could experience unexpected but significant interruption due to several events, including, but not limited to:

·  Major facility or equipment failure.
·  An environmental event such as a serious spill or release.
·  Fires, floods, droughts, earthquakes, hurricanes, tornados or other natural disasters.
·  Wars, terrorist acts (including cyber-terrorism) or threats and other catastrophic events.
·  Significant health impairments or disease events.
·  Other serious operational problems.

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We areAEP is exposed to nuclear generation risk. – Affecting(Applies to AEP and I&M&M)

Through I&M, we ownAEP owns the Cook Plant.  It consists of two nuclear generating units for a rated capacity of 2,191 MW, or about 6%7% of the generating capacity in the AEP System.  WeAEP and I&M are, therefore, subject to the risks of nuclear generation, which include the following:

·  The potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials such as spent nuclear fuel.
·  Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations.
·  Uncertainties with respect to contingencies and assessment amounts triggered by a loss event (federal law requires owners of nuclear units to purchase the maximum available amount of nuclear liability insurance and potentially contribute to the losses of others).
·  Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

There can be no assurance that I&M’s preparations or risk mitigation measures will be adequate if and when these risks are triggered.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities.  In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved.  Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as ours.plants.  In addition, although we havemanagement has no reason to anticipate a serious nuclear incident at our plants,the Cook Plant, if an incident did occur, it could harm our results of operations or financial condition.  A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.  Moreover, a major incident at any nuclear facility in the U.S. could require usAEP or I&M to make material contributory payments.

Costs associated with the operation (including fuel), maintenance and retirement of nuclear plants continue to be more significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the operation of nuclear facilities.  Costs also may include replacement power, any unamortized investment at the end of the useful life of the Cook Plant (whether scheduled or premature), the carrying costs of that investment and retirement costs.  OurThe ability to obtain adequate and timely recovery of costs associated with the Cook Plant is not assured.


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The different regional power markets in which weAEP subsidiaries compete or will compete in the future have changing market and transmission structures, which could affect our performance in these regions. – Affecting each Registrant(Applies to all Registrants)

Our resultsResults are likely to be affected by differences in the market and transmission structures in various regional power markets.  The rules governing the various regional power markets, including SPP and PJM, may also change from time to time which could affect our costs or revenues.  Because the manner in which RTOs will evolve remains unclear, we aremanagement is unable to assess fully the impact that changes in these power markets may have on ourthe business.

WeAEP could be subject to higher costs and/or penalties related to mandatory reliability standards. – Affecting each Registrant(Applies to all Registrants)

As a result of EPACT, owners and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation and enforced by the FERC.  These standards, which previously were being applied on a voluntary basis, became mandatory in June 2007.  The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles.  Compliance with new reliability standards may subject usAEP to higher operating costs and/or increased capital expenditures.  While we expectmanagement expects to recover costs and expenditures from customers through regulated rates, there can be no assurance that the applicable commissions will approve full recovery in a timely manner.  If weAEP were found not to be in compliance with the mandatory reliability standards, weAEP could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.
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RISKS RELATED TO MARKET, ECONOMIC OR FINANCIAL VOLATILITY AND OTHER RISKS

OurAEP’s financial performance may be adversely affected if we areAEP is unable to successfully operate our facilities or perform certain corporate functions. – Affecting each Registrant(Applies to all Registrants)

Our performancePerformance is highly dependent on the successful operation of our generation, transmission and distribution facilities.  Operating these facilities involves many risks, including:

·  Operator error and breakdown or failure of equipment or processes.
·  Operating limitations that may be imposed by environmental or other regulatory requirements.
·  Labor disputes.
·  Compliance with mandatory reliability standards, including mandatory cyber security standards.
·  Information technology failure that impairs ourInformation technology failure that impairs AEP’s information technology infrastructure or disrupts normal business operations.
·  Information technology failure that affects our ability to access customer information or causes us to lose confidential or proprietary data that materially and adversely affects our reputation or exposes usInformation technology failure that affects AEP’s ability to access customer information or causes loss of confidential or proprietary data that materially and adversely affects AEP’s reputation or exposes AEP to legal claims.
·  Fuel or water supply interruptions caused by transportation constraints, adverse weather such as drought, non-performance by our suppliers and other factors.
·  Catastrophic events such as fires, earthquakes, explosions, hurricanes, tornados, ice storms, terrorism (including cyber-terrorism), floods or other similar occurrences.
Catastrophic events such as fires, earthquakes, explosions, hurricanes, tornados, ice storms, terrorism (including cyber-terrorism), floods or other similar occurrences.
Fuel costs and related requirements triggered by financial stress in the coal industry.

Hostile cyber intrusions could severely impair our operations, lead to the disclosure of confidential information and damage ourAEP’s reputation. – Affecting each Registrant(Applies to all Registrants)

We ownAEP owns assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run ourAEP facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or ourAEP operations could view ourAEP’s computer systems, software or networks as attractive targets for cyber attack.  In addition, ourthe business requires that weAEP collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.

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A successful cyber attack on the systems that control our generation, transmission, distribution or other assets could severely disrupt business operations, preventing us from servingservice to customers or collectingcollection of revenues. The breach of certain business systems could affect ourthe ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to ourAEP’s reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring.  We maintain property and casualty insurance that may cover certain physical damage or third party injuries caused by potential cybersecurity incidents.  However, other damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available.  For these reasons, a significant cyber incident could reduce future net income and cash flows and negatively impact financial condition.

In an effort to reduce the likelihood and severity of cyber intrusions, we haveAEP has a comprehensive cybersecuritycyber security program designed to protect and preserve the confidentiality, integrity and availability of data and systems. In addition, we areAEP is subject to mandatory cybersecuritycyber security regulatory requirements. However, cyber threats continue to evolve and adapt, and, as a result, there is a risk that weAEP could experience a successful cyber attack despite our current security posture and regulatory compliance efforts.

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If we areAEP is unable to access capital markets on reasonable terms, it could reduce future net income and cash flows and negatively impact financial condition. – Affecting each Registrant(Applies to all Registrants)

We relyAEP relies on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows.  Volatility and reduced liquidity in the financial markets could affect ourAEP’s ability to raise capital and fund our capital needs, including construction costs and refinancing maturing indebtedness.  In addition, ifcertain sources of debt and equity capital is available onlygave expressed increasing unwillingness to invest in companies, such as AEP, that rely on less than reasonable terms or to borrowers whose creditworthiness is better than ours,fossil fuels. If sources of capital for AEP disappear, capital costs could increase materially.  Restricted access to capital markets and/or increased borrowing costs could reduce future net income and cash flows and negatively impact financial condition.

Downgrades in ourAEP’s credit ratings could negatively affect ourits ability to access capital and/or to operate ourthe power trading businesses. – Affecting each Registrant(Applies to all Registrants)

The credit ratings agencies periodically review ourAEP’s capital structure and the quality and stability of our earnings.  Any negative ratings actions could constrain the capital available to usAEP and could limit our access to funding for our operations.  OurAEP’s business is capital intensive, and we areAEP is dependent upon ourthe ability to access capital at rates and on terms we determinemanagement determines to be attractive.  In periods of market turmoil, access to capital is difficult for all borrowers.  If ourAEP’s ability to access capital becomes significantly constrained, ourAEP’s interest costs will likely increase and could reduce future net income and cash flows and negatively impact financial condition.

OurAEP’s power trading business relies on the investment grade ratings of ourAEP’s individual public utility subsidiaries’ senior unsecured long-term debt or on the investment grade ratings of AEP parent.AEP.  Most of our counterparties require the creditworthiness of an investment grade entity to stand behind transactions.  If those ratings were to decline below investment grade, ourAEP’s ability to operate ourthe power trading business profitably would be diminished because weAEP would likely have to deposit cash or cash-related instruments which would reduce our profits.future net income and cash flows and negatively impact financial condition.

AEP has no income or cash flow apart from dividends paid or other obligations due it from its subsidiaries. – Affecting AEP(Applies to AEP)

AEP is a holding company and has no operations of its own.  Its ability to meet its financial obligations associated with its indebtedness and to pay dividends on its common stock is primarily dependent on the earnings and cash flows of its operating subsidiaries, primarily its regulated utilities, and the ability of its subsidiaries to pay dividends to, or repay loans from, AEP.  Its subsidiaries are separate and distinct legal entities that have no obligation (apart from loans from AEP) to provide AEP with funds for its payment obligations, whether by dividends, distributions or other payments.  Payments to AEP by its subsidiaries are also contingent upon their earnings and business considerations.  In addition, any payment of dividends, distributions or advances by the utility subsidiaries to AEP could be subject to regulatory restrictions.  AEP indebtedness and common stock dividends are structurally subordinated to all subsidiary indebtedness and preferred stock obligations, if any.indebtedness.


Our
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AEP’s operating results may fluctuate on a seasonal or quarterly basis and with general economic and weather conditions. – Affecting each Registrant(Applies to all Registrants)

Electric power generation is generally a seasonal business.  In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time.  In other areas, power demand peaks during the winter.  As a result, our overall operating results in the future may fluctuate substantially on a seasonal basis.  The pattern of this fluctuation may change depending on the terms of power sale contracts that we enterAEP enters into.  In addition, we haveAEP has historically sold less power, and consequently earned less income, when weather conditions are milder.  Unusually mild weather in the future could diminish our results of operationsreduce future net income and harm ourcash flows and negatively impact financial condition.  Conversely,In addition, unusually extreme weather conditions could increaseimpact AEP’s results of operations in a manner that would not likely be sustainable.

Further, deteriorating economic conditions generally result in reduced consumption by our customers, particularly industrial customers who may curtail operations or cease production entirely, while an expanding economic environment generally results in increased revenues.  As a result, our overall operating results in the future may fluctuate on the basis of prevailing economic conditions.conditions may reduce future net income and cash flows and negatively impact financial condition.
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Failure to attract and retain an appropriately qualified workforce could harm our results of operations. – Affecting each Registrant(Applies to all Registrants)

Certain events, such as an aging workforce without appropriate replacements, mismatch of skillset or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs.  The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development.  In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise.  Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate ourthe business.  If we areAEP is unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.

Parties we have engaged to provide construction materials or services may fail to perform their obligations, which could harm our results of operations. – Affecting each Registrant

Our business plan calls for extensive investment in capital improvementsfuture net income and additions, including the installation of environmental upgrades, construction of additional generation units and transmission facilities as well as other initiatives.  We are exposed to the risk of substantial price increases in the costs of materials used in construction.  We have engaged numerous contractors and entered into a large number of agreements to acquire the necessary materials and/or obtain the required construction related services.  As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us.  Should the counterparties to these arrangements fail to perform, wecash flows may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and almost certainly cause delays in that and related projects.  Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions.  This would cause our financial results to be diminished, and we might incur losses or delays in completing construction.reduced.

Changes in commodity pricesthe price of commodities, emission allowances for criteria pollutants and the costs of transport may increase ourAEP’s cost of producing power or decrease the amount we receivereceived from selling power, harming ourimpacting financial performance. – Affecting each Registrant(Applies to all Registrants)

We areAEP is exposed to changes in the price and availability of coal and the price and availability to transport coal because most of our generating capacity is coal-fired.  We havecoal.  AEP has existing contracts of varying durations for the supply of coal, for most of our existing generation capacity, but as these contracts end or otherwiseif they are not honored, weAEP may not be able to purchase coal on terms as favorable as the current contracts.  Similarly, we areAEP is exposed to changes in the price and availability of emission allowances.  We useAEP uses emission allowances based on the amount of coal we useused as fuel and the reductions achieved through emission controls and other measures.  As long as current environmental programs remain in effect, we haveAEP has sufficient emission allowances to cover the majority of ourthe projected needs for the next two years and beyond.  If the Federal EPA is able to create a replacement rule to reduce interstate transport, and it is acceptable by the courts, additional costs may be incurred either to acquire additional allowances or to achieve further reductions in emissions.  If we needAEP needs to obtain allowances under a replacement rule, those purchases may not be on as favorable terms as those under the current environmental programs.  OurAEP’s risks relative to the price and availability to transport coal include the volatility of the price of diesel which is the primary fuel used in transporting coal by barge.

WeAEP also ownowns natural gas-fired facilities which exposes usAEP to market prices of natural gas.  Historically, natural gas prices have tended to be more volatile than prices for other fuel sources. Recently however, the availability of natural gas from shale production has lessened price volatility. OurAEP’s ability to make off-system sales at a profit is highly dependent on the price of natural gas.  As the price of natural gas falls, other market participants that utilize natural gas-fired generation will be able to offer electricity at increasingly competitive prices relative to our off-systemAEP’s sales prices, so the margins we realizerealized from sales will be lower and, on occasion, weAEP may need to curtail operation of marginal plants.  We expectManagement expects the availability of shale natural gas and issues related to its accessibility will have a long-term material effect on the price and volatility of natural gas.


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Prices for coal, natural gas and emission allowances have shown material upward and downward swings in the past.  Changes in the cost of coal, emission allowances or natural gas and changes in the relationship between such costs and the market prices of power will affect ourcould reduce future net income and cash flows and negatively impact financial results.condition.
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In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to value our trading and marketing transactions, and those differences may be material.  As a result, our financial results may be diminished in the future as those transactions are marked to market.market, they may impact future results of operations and cash flows and impact financial condition.

Our AEP River Operations business segment cannot operate if river levels are too low or too high. – Affecting AEPis subject to physical and financial risks associated with climate change. (Applies to all Registrants)

Our AEP River Operations business segment transports coalClimate change creates physical and dry bulk commoditiesfinancial risk.  Physical risks from climate change may include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events.  Customers’ energy needs vary with weather conditions, primarily temperature and humidity.  For residential customers, heating and cooling represent their largest energy use.  To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the Ohio, Illinoisduration and lower Mississippi rivers.  Ifmagnitude of the changes.

Increased energy use due to weather changes may require AEP to invest in additional generating assets, transmission and other infrastructure to serve increased load.  Decreased energy use due to weather changes may affect financial condition through decreased revenues.  Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions.  Weather conditions outside of the AEP service territory could also have an impact on revenues.  AEP buys and sells electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand on AEP’s own and/or other systems may raise electricity prices as AEP buys short-term energy to serve AEP’s own system, which would increase the cost of energy AEP provides to customers.

Severe weather impacts AEP’s service territories, primarily when thunderstorms, tornadoes, hurricanes, floods and snow or ice storms occur.  To the extent the frequency of extreme weather events increases, this could increase AEP’s cost of providing service.  Changes in precipitation resulting in droughts, water shortages or floods could adversely affect operations, principally the fossil fuel generating units.  A negative impact to water supplies due to long-term drought conditions or other factors causesevere flooding could adversely impact AEP’s ability to provide electricity to customers, as well as increase the water levelsprice they pay for energy.  AEP may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region’s economic health, it may also impact revenues.  AEP’s financial performance is tied to the health of one or morethe regional economies AEP serves.  The price of these rivers to drop belowenergy, as a factor in a region’s cost of living as well as an important input into the amount necessary to permit commercial barging traffic, it would prevent our AEP River Operations from transporting cargocost of goods and services, has an impact on the affected river.  Conversely, if unusually high amounts of precipitation or other factors cause the water levels of one or more of these rivers to be too high to permit commercial barging traffic, it would prevent our AEP River Operations from transporting cargo on the affected river.   Extreme water levels that do not close river basin commercial traffic can still harm our business if the levels curtail the total volume permitted to move on the affected river. The levels on portionseconomic health of the Mississippi Rivercommunities within the AEP System.

Management cannot predict the outcome of the legal proceedings relating to AEP’s business activities. (Applies to all Registrants)

AEP is involved in 2013 have been reported aslegal proceedings, claims and litigation arising out of its business operations, the lowest sincemost significant of which are summarized in Note 6 of the levels caused by severe droughtNotes to Financial Statements entitled Commitments, Guarantees and Contingencies.  Adverse outcomes in 1988.  Any reduction in the commercial activities of our AEP River Operations due to low water levelsthese proceedings could require significant expenditures that could reduce future net income and cash flows.flows and negatively impact financial condition.


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RISKS RELATING TO STATE RESTRUCTURING

We are unable to fully predict the effects of corporate separation in Ohio and Ohio generation becoming subject to market forces. – Affecting AEP and OPCo

While Ohio rates for transmission and distribution services continue to be established using a more traditional cost-based method, in October 2012, the PUCO approved OPCo’s corporate separation plan to transfer its generation assets to a new competitive, unregulated generation affiliate.  During this transition, generation rates will be priced using a hybrid approach that incorporates components of cost and market.  Starting in mid-2015, generation rates will be subject entirely to market prices. We have made additional filings at the FERC and other state commissions related to this corporate separation.  If all regulatory approvals are received, our results of operations related to generation previously held by OPCo will be largely determined by the prevailing market conditions.  We can give no assurance that the FERC will not impose material adverse terms as a condition to approving our corporate separation filings.  Additionally, some of these generation units may no longer be cost effective and may be retired prior to the end of their anticipated useful life.  This could result in material impairments.

We are unable to fully predict the effects of terminating the Interconnection Agreement. – Affecting AEP, APCo, I&M and OPCo

In October 2012, we submitted several filings with the FERC seeking approval to fully separate OPCo’s generating assets from its distribution and transmission operations.  The filings requested approval to transfer approximately 9,200 MW of OPCo-owned generation assets to a new competitive, unregulated generation affiliate.  We also requested approval from the FERC and, as applicable, the KPSC, the Virginia SCC and the WVPSC to transfer 1,647 MW of OPCo-owned generation assets to APCo and 780 MW of OPCo-owned generation assets to KPCo.  Additionally, we asked for FERC approval to terminate the existing Interconnection Agreement and to authorize a new Power Coordination Agreement among APCo, I&M and KPCo.  A decision from the FERC is expected in mid-2013.  Significant gaps could emerge if the Interconnection Agreement is terminated without approval of the generation asset transfers and/or the new Power Coordination Agreement.  Surplus members would no longer automatically sell to deficit members, and they may not be able to otherwise sell that surplus in amounts or at rates equal to what they obtained under the Interconnection Agreement.  Conversely, deficit members would no longer automatically purchase from surplus members, and they may not be able to otherwise purchase in amounts or at rates equal to what they obtained under the Interconnection Agreement.  The possible loss of these sales by the surplus members and the potential increase in costs for the deficit members could reduce future net income and cash flows.  In addition, we can give no assurance that the FERC or other state commissions will not impose material adverse terms as a condition to approving these arrangements and asset transfers.

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Customers are choosing alternative electric generation service providers, as allowed by Ohio law and regulation. – Affecting AEP and OPCo

Under current Ohio law, electric generation is sold in a competitive market in Ohio and native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service.  CRES providers are targeting retail customers by offering alternative generation service.  As of December 31, 2012, based upon an average annual load, approximately 51% of our Ohio load had switched to CRES providers.  These evolving market conditions will continue to impact our results of operations.

Collection of our revenues in Texas is concentrated in a limited number of REPs. – Affecting AEP(Applies to AEP)

Our revenuesRevenues from the distribution of electricity in the ERCOT area of Texas are collected from REPs that supply the electricity we distributeAEP distributes to theirREP customers.  Currently, we doAEP does business with approximately one hundred REPs.  In 2012,2015, TCC’s largest REP accounted for 16%23% of its operating revenue and its second largest REP accounted for 7%22% of its operating revenue; TNC’s largest REP accounted for 19%11% of its operating revenues, and its second largest REP accounted for 12%10% of its operating revenues.  Adverse economic conditions, structural problems in the Texas market or financial difficulties of one or more REPs could impair the ability of these REPs to pay for our services or could cause them to delay such payments.  We dependAEP depends on these REPs for timely remittance of payments.  Any delay or default in payment could reduce future cash flows and negatively impact financial condition.

RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Our costsCosts of compliance with existing environmental laws are significant. – Affecting each Registrant(Applies to all Registrants)

Our operationsOperations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety.  Approximately 90% of the electricity generated by the AEP System is produced by the combustion of fossil fuels.  Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generatinggeneration plants are subject to increased regulations, controls and mitigation expenses.  Compliance with these legal requirements requires usAEP to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at all of ourAEP facilities and could cause usAEP to retire generating capacity prior to the end of its estimated useful life.  These expenditures have been significant in the past, and we expectmanagement expects that they will continue to be significant in order to comply with the current and proposed regulations.  Costs of compliance with environmental regulations could reduce future net income and negatively impact financial condition, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed or additional substances become regulated and the number and types of assets we operate increase.regulated.  If we retire generatingAEP retires generation plants prior to the end of their estimated useful life, there can be no assurance that weAEP will recover the remaining costs associated with such plants.  While we expect to recover ourAEP typically recovers expenditures for pollution control technologies, replacement generation, undepreciated plant balances and associated operating costs from customers through regulated rates (inin regulated jurisdictions) or market prices, without such recovery thosejurisdictions.  Failure to recover these costs could reduce our future net income and cash flows and possibly harm ourfinancial condition.   For AEP’s merchant generation units, there is no such cost-recovery mechanism.   As a result, AEP may not recover costs through the market and may be forced to shut competitive units down.  The costs of compliance for AEP’s competitive units could reduce future net income and cash flows and possibly harm financial condition.

Regulation of CO2 emissions either through legislation or by the Federal EPA, could materially increase costs to usAEP and ourits customers or cause some of our electric generating units to be uneconomical to operate or maintain. – Affecting each Registrant(Applies to all Registrants)

The U.S. Congress has not taken any significant steps toward enacting legislation to control CO2 emissions since 2009.  In December 2009,2015, the Federal EPA issued a final endangerment finding under the CAA regarding CO2 emissions from motor vehicles.  The Federal EPA also finalized CO2 emission standards for new motor vehicles, and issued a rule that implements a permitting program for new and modified stationary sources of CO2 emissions in a phased manner through 2014.  Several groups have filed challenges to the endangerment finding and the Federal EPA’s subsequent rulemakings.  In 2012, the Federal EPA issued a proposed CO2 emissions standard for new power generation sources, with a CO2 limit equivalent to aand final emission guidelines for existing fossil fuel fired electric generating units.  The standards for new coal-fired generating units are based on the use of partial carbon capture and storage. The standards for natural gas unit.  Acombined cycle units are based on the use of efficient combined cycle generating technology. The Clean Power Plan guidelines for existing sources include aggressive emission rate goals that are composed of a number of measures and seek nationwide reductions of CO2 emissions of approximately 32% from 2005 levels by 2030. The Clean Power Plan is intended to be implemented pursuant to individual state plans beginning in 2022. In February 2016, the U.S. Supreme Court issued a stay on the final ruleClean 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 expectedissued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review.All of the final requirements are currently the subject of litigation in the first half of 2013.  Management believes some policy approaches being discussed would have significant and widespread negative consequences for the national economy and major U.S. Industrial enterprises, including us and our customers.federal courts.


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If CO2 and other emission standards are imposed, the standards could require significant increases in capital expenditures and operating costs which would impactand could cause AEP to retire generating capacity prior to the ultimate retirementend of older, less-efficient, coal-fired units.  While we expectits estimated useful life.  If AEP retires generation plants prior to the end of their estimated useful life, there can be no assurance that AEP will recover the remaining costs of complyingassociated with new CO2such plants.  AEP typically recovers expenditures for pollution control technologies, replacement generation, undepreciated plant balances and other greenhouse gases emission standards will be treated like all other reasonableassociated operating costs of serving customers and should be recoverable from customers as costs of doing business, without such recovery thosethrough regulated rates in regulated jurisdictions.  Failure to recover these costs could reduce ourfuture net income and cash flows and possibly harm financial condition.   For AEP’s merchant generation units, there is no such cost-recovery mechanism.   As a result, AEP may not recover costs through the market and may be forced to shut competitive units down.  The costs of compliance for AEP’s competitive units could reduce future net income and cash flows and possibly harm financial condition.

AEP’s financial performance may be adversely affected if the merchant generation fleet is not profitable or loses value. (Applies to AEP)

Management is evaluating strategic alternatives for AEP’s merchant generation fleet, which primarily includes AGR’s generation fleet which operates in PJM. Management has not made a decision regarding the potential alternatives, nor have they set a specific timeframe for a decision.  Certain of these alternatives could result in a loss which could reduce future net income and cash flow and harm financial condition.

Amounts AEP receives from the results of PJM capacity auctions associated with nonregulated generation assets could fail to adequately compensate AEP. (Applies to AEP)

Financial returns on AGR’s generation capacity are subject to the results of annual PJM capacity auctions.  Auction results indicate a great deal of volatility and the possibility of clearing prices substantially lower than the cost of such capacity.  If the PJM capacity auctions result in clearing prices lower than the cost of AEP’s capacity, it could reduce future net income and cash flows and harm our financial condition.

Courts adjudicating nuisance and other similar claims against usin the future may order usAEP to pay damages or to limit or reduce our CO2emissions. – Affecting each Registrant(Applies to all Registrants)

In the past, there have been several cases and currently there is one pending case, seeking damages based on allegations of federal and state common law nuisance in which we,AEP, among others, arewere defendants.  In general, the actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance due to impacts of global warming and climate change.nuisance.  The plaintiffs in these actions generally seek recovery of damages and other relief.  If the pending or other future actions are resolved against us,AEP, substantial modifications of ourAEP’s existing coal-fired power plants could be required and weAEP might be required to limit or reduce CO2emissions.  Such remedies could require usAEP to purchase power from third parties to fulfill ourAEP’s commitments to supply power to ourAEP customers.  This could have a material impact on our costs.  In addition, weAEP could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay damages or penalties and/or halt operations.  While management believes such costs should be recoverable from customers as costs of doing business in ourAEP jurisdictions where generation rates are set on a cost of service basis, without such recovery, those costs could reduce our future net income and cash flows and harm our financial condition.  Moreover, our results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.

Our revenuesChanges in technology and regulatory policies may lower the value of generating facilities. (Applies to all Registrants)

AEP primarily generates electricity at large central facilities. This method results in economies of scale and generally lower costs than (a) newer technologies such as fuel cells and microturbines, and (b) distributed generation using either new or existing technology.  Other technologies, such as light emitting diodes (LEDs), increase the efficiency of electricity and, as a result, lower the demand for it. Changes in regulatory policies and advances in batteries or energy storage, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production.  The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AEP’s competitiveness. The costs of photovoltaic solar cells in particular have continued to become increasingly competitive. It is possible that advances in technologies, the availability of distributed generation or changes in

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regulatory policies will lower the demand for electricity or reduce the costs of new technology to levels that are equal to or below that of most central station electricity production, either of which could have a material adverse effect on results of operations.

Further, in the event that alternative generation resources are mandated, subsidized or encouraged through climate legislation or regulation or otherwise are economically competitive and added to the available generation supply, such resources could displace a higher marginal cost fossil plant, which could reduce the price at which market participants sell their electricity. This occurrence could then reduce the market price at which all generators in that region would be able to sell their output. These events could adversely affect AEP’s financial condition, results of operations and cash flows, and could also result in an impairment of certain long-lived assets.

Profitability is impacted by AEP’s continued authorization to sell power at market-based rates. (Applies to all Registrants)

FERC has granted AGR, APCo, I&M, KPCo, OPCo, PSO and SWEPCo authority to sell electricity at market-based rates. FERC reserves the right to revoke or revise this market-based rate authority if it subsequently determines that one or more of these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions.  Each company that has obtained market-based rate authority from FERC must file a market power update every three years to show that they continue to meet FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates.  The loss of market-based rate authority by any of these entities, especially by AGR, could have a material adverse effect on results of operations.

Revenues and results of operations from selling power are subject to market risks that are beyond ourAEP’s control. – Affecting each Registrant(Applies to all Registrants)

We sellAEP sells power from ourits generation facilities into the spot market and other competitive power markets on a contractual basis.  WeAEP also enterenters into contracts to purchase and sell electricity, natural gas, emission allowances and coal as part of ourits power marketing and energy trading operations.  With respect to such transactions, the rate of return on our capital investments is not determined through mandated rates, and our revenues and results of operations are likely to depend, in large part, upon prevailing market prices for power in our regional markets and other competitive markets.  These market prices can fluctuate substantially over relatively short periods of time.  TradingSales margins may erode as markets mature and there may be diminished opportunities for gain should volatility decline.  In addition, the FERC, which has jurisdiction over wholesale power rates, as well as RTOs that oversee some of these markets, may impose price limitations, bidding rules and other mechanisms to address some of the volatility in these markets.  Power supply and other similar agreements entered into during extreme market conditions may subsequently be held to be unenforceable by a reviewing court or the FERC.  Fuel and emissions prices may also be volatile, and the price weAEP can obtain for power sales may not change at the same rate as changes in fuel and/or emissions costs.  These factors could reduce our margins and therefore diminish our revenues and results of operations.  Volatility in market prices for fuel and power may result from:

·  Weather conditions, including storms.
·  Economic conditions.
·  Outages of major generation or transmission facilities.
·  Seasonality.
·  Power usage.
·  Illiquid markets.
·  Transmission or transportation constraints or inefficiencies.
·  Availability of competitively priced alternative energy sources.
·  Demand for energy commodities.
·  Natural gas, crude oil and refined products and coal production levels.
·  Natural disasters, wars, embargoes and other catastrophic events.
·  Federal, state and foreign energy and environmental regulation and legislation.
Federal, state and foreign energy and environmental regulation and legislation and/or incentives.
RTO market structures.


41

36



Our power trading (including coal, gas and emission allowancesCommodity trading and power marketing)marketing activities are subject to inherent risks which can be reduced and risk management policies cannot eliminate the risk associated with these activities. – Affecting each Registrantcontrolled but not eliminated. (Applies to all Registrants)

OurThe exposure of AEP’s power trading (including coal, gas and emission allowances trading and power marketing) activities expose us to risks of commodity price movements.  We attempt to manage our exposureis managed by establishing and enforcing risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate the risks associated with these activities.  As a result, wemanagement cannot predict the impact that ourAEP’s energy trading and risk management decisions may have on ourAEP’s business, operating results or financial position.

WeAEP routinely havehas open trading positions in the market, within guidelines we set by AEP, resulting from the management of ourAEP’s trading portfolio.  To the extent open trading positions exist, fluctuating commodity prices can improve or diminish our financial results and financial position.

OurAEP’s power trading and risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as the future market prices and demand for power and other energy-related commodities.  These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made.  Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be diminishedimpacted if the judgments and assumptions underlying those calculations prove to be inaccurate.

AEP’s power trading activities also expose AEP to risks of commodity price movements.  To the extent that AEP’s power trading does not hedge the price risk associated with the generation it owns, or controls, through long-term power purchase agreements, AEP would be exposed to the risk of rising and falling spot market prices.

In connection with these trading activities, AEP routinely enters into financial contracts, including futures and options, over-the counter options, financially-settled swaps and other derivative contracts.  These activities expose AEP to risks from price movements.  If the values of the financial contracts change in a manner AEP does not anticipate, it could harm financial position or reduce the financial contribution of trading operations.

Parties with whom we haveAEP has contracts may fail to perform their obligations, which could harm ourAEP’s results of operations. – Affecting each Registrant(Applies to all Registrants)

We areAEP is exposed to the risk that counterparties that owe usAEP money or power could breach their obligations.  Should the counterparties to these arrangements fail to perform, weAEP may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices that may exceed ourAEP’s contractual prices, which would cause our financial results to be diminished and weAEP might incur losses.  Although our estimates take into account the expected probability of default by a counterparty, our actual exposure to a default by a counterparty may be greater than the estimates predict.

We relyAEP relies on electric transmission facilities that we doAEP does not own or control.  If these facilities do not provide usAEP with adequate transmission capacity, weAEP may not be able to deliver our wholesale electric power to the purchasers of ourAEP’s power. – Affecting each Registrant(Applies to all Registrants)

We dependAEP depends on transmission facilities owned and operated by other nonaffiliated power companies to deliver the power we sellAEP sells at wholesale.  This dependence exposes usAEP to a variety of risks.  If transmission is disrupted, or transmission capacity is inadequate, weAEP may not be able to sell and deliver ourAEP wholesale power.  If a region’s power transmission infrastructure is inadequate, ourAEP’s recovery of wholesale costs and profits may be limited.  If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

The FERC has issued electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales.  Although these initiatives are designed to encourage wholesale market transactions, for electricity and gas, access to transmission systems may in fact not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable.  WeManagement also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.

42


We do not fully hedge against price changes in commodities. – Affecting each Registrant

We routinely enter into contracts to purchase and sell electricity, natural gas, coal and emission allowances as part of our power marketing and energy and emission allowances trading operations.  In connection with these trading activities, we routinely enter into financial contracts, including futures and options, over-the counter options, financially-settled swaps and other derivative contracts.  These activities expose us to risks from price movements.  If the values of the financial contracts change in a manner we do not anticipate, it could harm our financial position or reduce the financial contribution of our trading operations.
37


We manage our exposure by establishing risk limits and entering into contracts to offset some of our positions (i.e., to hedge our exposure to demand, market effects of weather and other changes in commodity prices).  However, we do not always hedge the entire exposure of our operations from commodity price volatility.  To the extent we do not hedge against commodity price volatility, our results of operations and financial position may be improved or diminished based upon our success in the market.

Financial derivatives reforms could increase the liquidity needs and costs of our commercial trading operations. – Affecting each Registrant

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was signed into law (Dodd-Frank Act).  The federal legislation was enacted to reform financial markets and significantly alter how over-the-counter (OTC) derivatives are regulated.  The law increased regulatory oversight of OTC energy derivatives, including: (a) imposing pervasive regulation by the Commodity Futures Trading Commission (CFTC) on dealers and traders who hold significant positions in swaps, (b) requiring certain standardized OTC derivatives to be traded on registered exchanges as directed by CFTC, (c) imposing new and potentially higher capital and margin requirements on swap dealers and traders who hold significant positions in swaps and (d) increasing the monitoring and compliance obligations of parties who engage in swaps, including new recordkeeping and reporting requirements with governmental entities.  The CFTC has issued regulations exempting certain end users of energy commodities from being required to clear OTC derivatives, provided that they (a) are using the swaps to hedge or mitigate commercial risk and (b) satisfy certain other requirements.  To the extent we meet such requirements, the end user exemption could reduce the effect of the law's clearing requirements on our hedging activity.  Pursuant to authority granted under the Dodd-Frank Act, the CFTC has also issued rules that, among other things, further define the OTC derivative products and entities subject to additional regulatory oversight, which recently became effective.  These requirements could subject us to additional regulatory oversight related to our OTC derivative transactions, cause our OTC derivative transactions to be more costly and have an impact on financial condition due to additional capital requirements.  In addition, as these reforms aim to standardize OTC products it could limit the effectiveness of our hedging programs because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to manage.

38

ITEM 1B.   UNRESOLVED STAFF COMMENTS

None.

ITEM 2.   PROPERTIES

GENERATION FACILITIES

Utility Operations

As of December 31, 2012,2015 the AEP System owned (or leased where indicated) generatinggeneration plants, all situated in the states in which ourAEP’s electric utilities serve retail customers, where applicable, with net maximum power capabilities (winter rating) shown in the following tables:

AEGCo          
          Year Plant
        Net Maximum or First Unit
Plant Name Units State Fuel Type Capacity (MWs) Commissioned
Rockport (Units 1 and 2, 50% of each) (a) 2 IN Steam - Coal 1,310 1984
Lawrenceburg 6 IN Natural Gas 1,186 2004
Total MWs       2,496  
           
(a)  Rockport Unit 2 is leased.
Vertically Integrated Utilities Segment
AEGCo          
Plant Name Units State Fuel Type 
Net Maximum
 Capacity (MWs)
 
Year Plant
 or First Unit Commissioned
Rockport, Units 1 and 2 – 50% of each (a) 2 IN Steam - Coal 1,310
 1984
Lawrenceburg (b) 6 IN Natural Gas 1,186
 2004
Total MWs       2,496
  

APCo          
          Year Plant
        Net Maximum or First Unit
Plant Name Units State Fuel Type Capacity (MWs) Commissioned
Buck 3 VA Hydro 9 1912
Byllesby 4 VA Hydro 22 1912
Claytor 4 VA Hydro 76 1939
Leesville 2 VA Hydro 50 1964
London 3 WV Hydro 14 1935
Marmet 3 WV Hydro 14 1935
Niagara 2 VA Hydro 2 1906
Reusens 5 VA Hydro 13 1904
Winfield 3 WV Hydro 15 1938
Ceredo 6 WV Natural Gas 516 2001
Dresden 3 OH Natural Gas 608 2012
Smith Mountain 5 VA Pumped Storage 586 1965
Amos (Units 1,2 and 3) 3 WV Steam - Coal 2,033 1971
Clinch River 3 VA Steam - Coal 705 1958
Glen Lyn 2 VA Steam - Coal 335 1918
Kanawha River 2 WV Steam - Coal 400 1953
Mountaineer 1 WV Steam - Coal 1,320 1980
Sporn 2 WV Steam - Coal 300 1950
Total MWs       7,018  

39



I&M          
          Year Plant
        Net Maximum or First Unit
Plant Name Units State Fuel Type Capacity (MWs) Commissioned
Berrien Springs 12 MI Hydro 7 1908
Buchanan 10 MI Hydro 4 1919
Constantine 4 MI Hydro 1 1921
Elkhart 3 IN Hydro 3 1913
Mottville 4 MI Hydro 2 1923
Twin Branch 6 IN Hydro 5 1904
Rockport (Units 1 and 2, 50% of each) (a) 2 IN Steam - Coal 1,310 1984
Tanners Creek 4 IN Steam - Coal 995 1951
Cook 2 MI Steam - Nuclear 2,191 1975
Total MWs       4,518  
           
(a)  Rockport Unit 2 is leased.

KPCo          
          Year Plant
        Net Maximum or First Unit
Plant Name Units State Fuel Type Capacity (MWs) Commissioned
Big Sandy 2 KY Steam - Coal 1,078 1963

OPCo          
          Year Plant
        Net Maximum or First Unit
Plant Name Units State Fuel Type Capacity (MWs) Commissioned
Racine 2 OH Hydro 48 1982
Darby 6 OH Natural Gas 507 2001
Waterford 4 OH Natural Gas 840 2003
Stuart (a) 4 OH Oil 3 1970
Amos (Unit 3) 1 WV Steam - Coal 867 1973
Beckjord (a) 1 OH Steam - Coal 53 1969
Cardinal 1 OH Steam - Coal 595 1967
Conesville (a) 3 OH Steam - Coal 1,139 1957
Gavin 2 OH Steam - Coal 2,640 1974
Kammer 3 WV Steam - Coal 630 1958
Mitchell 2 WV Steam - Coal 1,560 1971
Muskingum River 5 OH Steam - Coal 1,440 1953
Picway 1 OH Steam - Coal 100 1926
Sporn 2 WV Steam - Coal 300 1950
Stuart (a) 4 OH Steam - Coal 600 1971
Zimmer (a) 1 OH Steam - Coal 330 1991
Total MWs       11,652  
 
(a) Jointly-owned with non-affiliated entities.  Figures presented reflect only the portion owned by OPCo.

40


PSO           
          Year Plant 
        Net Maximum or First Unit 
Plant Name Units State Fuel Type Capacity (MWs) Commissioned 
Comanche 3 OK Natural Gas 260 1973 
Riverside (Units 3 and 4) 2 OK Natural Gas 157 2008 
Southwestern (Units 4 and 5) 2 OK Natural Gas 170 2008 
Tulsa 2 OK Natural Gas 309 1956 
Weleetka 3 OK Natural Gas 196 1975 
Comanche 2 OK Oil 4 1962 
Northeastern 1 OK Oil 3 1961 
Northeastern 1 OK Oil 1 1980 
Riverside 1 OK Oil 3 1976 
Southwestern 1 OK Oil 2 1962 
Weleetka 2 OK Oil 4 1963 
Northeastern (Units 3 and 4) 2 OK Steam - Coal 930 1979 
Oklaunion (a) 1 TX Steam - Coal 102 1986 
Northeastern (Units 1 and 2) 2 OK Steam - Natural Gas 920 1961 
Riverside (Units 1 and 2) 2 OK Steam - Natural Gas 909 1974 
Southwestern (Units 1, 2 and 3) 3 OK Steam - Natural Gas 466 1952 
Total MWs       4,436   
 
(a) Jointly-owned with TNC and non-affiliated entities.  Figures presented reflect only the portion owned by PSO.

SWEPCo          
          Year Plant
        Net Maximum or First Unit
Plant Name Units State Fuel Type Capacity (MWs) Commissioned
Mattison 4 AR Natural Gas 316 2007
Stall 1 LA Natural Gas 543 2010
Flint Creek 1 AR Steam - Coal 264 1978
Turk (a) 1 AR Steam - Coal 440 2012
Welsh 3 TX Steam - Coal 1,584 1977
Dolet Hills 1 LA Steam - Lignite 256 1986
Pirkey 1 TX Steam - Lignite 580 1985
Arsenal Hill 1 LA Steam - Natural Gas 110 1960
Knox Lee 4 TX Steam - Natural Gas 475 1950
Lieberman 4 LA Steam - Natural Gas 268 1947
Lone Star 1 TX Steam - Natural Gas 49 1954
Wilkes 3 TX Steam - Natural Gas 845 1964
Total MWs       5,730  
           
(a)Figures presented reflect only the portion owned by SWEPCo.  The capacity rating for the Turk Plant is accurate as of December 31, 2012.  In February 2013, the Turk Plant’s capacity was rated at 650 MW, of which 471 MW reflects the portion owned by SWEPCo.
           
TNC          
           
        Net Maximum Year Plant
Plant Name Units State Fuel Type Capacity (MWs) Commissioned
Oklaunion (a) 1 TX Steam - Coal 355 1986
(a) Jointly-owned with PSORockport, Unit 2 is leased.
(b)The capacity and non-affiliated entities.  Figures presented reflect only the portion owned by TNC.output of this plant is under contract to (and its financial impact is included with) AGR through 2017.

APCo          
Plant Name Units State Fuel Type 
Net Maximum
 Capacity (MWs)
 
Year Plant
 or First Unit Commissioned
Buck 3 VA Hydro 9
 1912
Byllesby 4 VA Hydro 22
 1912
Claytor 4 VA Hydro 76
 1939
Leesville 2 VA Hydro 50
 1964
London 3 WV Hydro 14
 1935
Marmet 3 WV Hydro 14
 1935
Niagara 2 VA Hydro 2
 1906
Reusens 5 VA Hydro 13
 1904
Winfield 3 WV Hydro 15
 1938
Ceredo 6 WV Natural Gas 516
 2001
Dresden 3 OH Natural Gas 613
 2012
Smith Mountain 5 VA Pumped Storage 586
 1965
Amos 3 WV Steam - Coal 2,930
 1971
Clinch River (a) 2 VA Steam - Coal 470
 1958
Mountaineer 1 WV Steam - Coal 1,320
 1980
Total MWs (b)       6,650
  

Domestic Independent Power (Generation
(a)Clinch River Unit 3 was retired on May 31, 2015. Clinch River Units 1 and Marketing Segment)2 are currently being converted to gas and will be re-rated in 2016.
(b)Glen Lyn, Kanawha River and Sporn Plants were retired in May 2015.
           
        Net Maximum Year Plant
Plant Name Units State Fuel Type Capacity (MWs) Commissioned
Trent Mesa 100 TX Wind 150 2001
Desert Sky 107 TX Wind 161 2001
Total MWs       311  


43



41

The source of fuel in terms of total megawatts as well as a percentage of all of the generation units set forth in the tables above consists of the following:
I&M          
Plant Name Units State Fuel Type 
Net Maximum
Capacity (MWs)
 
Year Plant
 or First Unit Commissioned
Berrien Springs 12 MI Hydro 7
 1908
Buchanan 10 MI Hydro 4
 1919
Constantine 4 MI Hydro 1
 1921
Elkhart 3 IN Hydro 3
 1913
Mottville 4 MI Hydro 2
 1923
Twin Branch 8 IN Hydro 5
 1904
Rockport (Units 1 and 2, 50% of each) (a) 2 IN Steam - Coal 1,310
 1984
Cook 2 MI Steam - Nuclear 2,191
 1975
Total MWs (b)       3,523
  

Coal/Lignite (a) 24,551 65%
Natural Gas/Oil 9,670 26%
Nuclear 2,191 6%
Wind/Hydro/Pumped Storage 1,182 3%
Total MWs Generating Capacity 37,594 100%
     
(a)   Does not include AEP’s 43% ownership of OVEC.

Cook Nuclear Plant
(a)Rockport, Unit 2 is leased.
(b)Tanners Creek was retired in May 2015.

The following table provides operating information related to the Cook Plant:

 Cook Plant
 Unit 1 (a) Unit 2
Year Placed in Operation1975 1978
Year of Expiration of NRC License2034 2037
Nominal Net Electrical Rating in Kilowatts1,084,000 1,107,000
Annual Capacity Utilization   
201296.9% 87.4%
201181.3% 99.4%
201082.2% 80.8%
20092.8% 83.1%
 
(a)Unit 1 Net Capacity Factor for 2009 was impacted by a 2008 forced outage caused by a low pressure turbine blade failure event.  The reduced-capacity, repaired turbine was replaced with a full-capacity, new turbine in late 2011.
 Cook Plant
 Unit 1 Unit 2
Year Placed in Operation1975
 1978
Year of Expiration of NRC License2034
 2037
Nominal Net Electrical Rating in Kilowatts1,084,000
 1,107,000
Annual Capacity Utilization   
201582.4% 89.7%
201482.7% 86.9%
201396.9% 87.4%

KPCo          
Plant Name Units State Fuel Type 
Net Maximum
Capacity (MWs)
 
Year Plant
 or First Unit Commissioned
Big Sandy (a) 1 KY Steam - Coal 278
 1963
Mitchell (b) 2 WV Steam - Coal 780
 1971
Total MWs       1,058
  

(a)Big Sandy Unit 2 was retired on May 31, 2015.  Big Sandy Unit 1 is being converted to gas and will be re-rated in 2016.
(b)KPCo owns a 50% interest in the Mitchell Units.  WPCo owns the remaining 50%. Figures presented reflect only the portion owned by KPCo.

44



PSO          
Plant Name Units State Fuel Type 
Net Maximum
Capacity (MWs)
 
Year Plant
 or First Unit Commissioned
Comanche 3 OK Natural Gas 260
 1973
Riverside, Units 3 and 4 2 OK Natural Gas 170
 2008
Southwestern, Units 4 and 5 2 OK Natural Gas 170
 2008
Weleetka 3 OK Natural Gas 185
 1975
Northeastern, Unit 1 1 OK Natural Gas 464
 1961
Northeastern, Units 3 and 4 2 OK Steam - Coal 936
 1979
Oklaunion (a) 1 TX Steam - Coal 102
 1986
Northeastern, Unit 2 1 OK Steam - Natural Gas 461
 1961
Riverside, Units 1 and 2 2 OK Steam - Natural Gas 907
 1974
Southwestern, Units 1, 2 and 3 3 OK Steam - Natural Gas 458
 1952
Tulsa 2 OK Steam - Natural Gas 319
 1956
Total MWs       4,432
  

(a)Jointly-owned with TNC and non-affiliated entities.  Figures presented reflect only the portion owned by PSO.

SWEPCo          
Plant Name Units State Fuel Type 
Net Maximum
Capacity (MWs)
 
Year Plant
 or First Unit Commissioned
Mattison 4 AR Natural Gas 315
 2007
Stall 3 LA Natural Gas 534
 2010
Flint Creek (a) 1 AR Steam - Coal 264
 1978
Turk (a) 1 AR Steam - Coal 477
 2012
Welsh 3 TX Steam - Coal 1,584
 1977
Dolet Hills (a) 1 LA Steam - Lignite 256
 1986
Pirkey (a) 1 TX Steam - Lignite 580
 1985
Arsenal Hill 1 LA Steam - Natural Gas 110
 1960
Knox Lee 4 TX Steam - Natural Gas 475
 1950
Lieberman 3 LA Steam - Natural Gas 242
 1947
Lone Star 1 TX Steam - Natural Gas 50
 1954
Wilkes 3 TX Steam - Natural Gas 911
 1964
Total MWs       5,798
  

(a)Jointly-owned with nonaffiliated entity(ies).  Figures presented reflect only the portion owned by SWEPCo.

WPCo
Plant Name UnitsStateFuel Type 
Net Maximum
Capacity (MWs)
 
Year Plant
 or First Unit Commissioned
Mitchell (a) 2WVSteam - Coal 780  1971
Total MWs     780   

(a)AGR owned a 50% interest in the Mitchell Units until January 2015 when that interest was transferred to WPCo. A portion of WPCo’s interest in the Mitchell Units is not in rate base. KPCo owns the remaining 50%. Figures presented reflect only the portion owned by WPCo.

45



Generation & Marketing Segment
AGR 
          
Plant Name Units State Fuel Type 
Net Maximum
Capacity (MWs)
 
Year Plant
 or First Unit Commissioned
Racine 2 OH Hydro 48
 1982
Darby 6 OH Natural Gas 510
 2001
Waterford 4 OH Natural Gas 840
 2003
Cardinal 1 OH Steam - Coal 595
 1967
Conesville (a) 3 OH Steam - Coal 1,159
 1957
Gavin 2 OH Steam - Coal 2,670
 1974
Mitchell (b) 2 WV Steam - Coal 
 1971
Stuart (a) 4 OH Steam - Coal 600
 1971
Zimmer (a) 1 OH Steam - Coal 330
 1991
Total MWs(c)(d)
       6,752
  

(a)Jointly-owned with nonaffiliated entities.  Figures presented reflect only the portion owned by AGR.
(b)AGR owned a 50% interest in the Mitchell Units until January 2015 when the 50% ownership was transferred to WPCo.
(c)AGR has contractual rights through 2017 to a natural gas-fired 1,186 MW generating unit located in Lawrenceburg, IN.
(d)Kammer, Muskingum River, Picway and Sporn Plants were retired in May 2015.

Domestic Independent Power          
Plant Name Units State Fuel Type 
Net Maximum
Capacity (MWs)
 Year Plant Commissioned
Trent Mesa 100 TX Wind 150
 2001
Desert Sky 107 TX Wind 161
 2001
Total MWs       311
  

In addition to the AGR and Domestic Independent Power generation set forth above, a subsidiary in the Generation & Marketing segment has contractual rights through 2027 from TNC to 355 MWs from the Oklaunion Generating Plant, a coal-fired unit located in Vernon, TX.  TNC co-owns the Oklaunion Generating Plant with PSO and several non-affiliated entities.

TRANSMISSION AND DISTRIBUTION FACILITIES

The following table sets forth the total overhead circuit miles of transmission and distribution lines of the AEP System and its operating companies and that portion of the total representing 765kV lines:companies.

 Total Overhead Circuit Miles of Transmission and Distribution Lines 
Circuit Miles of
765kV Lines
AEP System (a)229,705(b)2,116
APCo52,307 734
I&M21,985 615
KGPCo1,360 -
KPCo11,140 258
OPCo (a)46,417 509
PSO21,021 -
SWEPCo27,238 -
TCC29,326 -
TNC17,171 -
WPCo1,739 -
    
(a)Includes 766 miles of 345,000-volt jointly owned lines.
(b)Includes 73 miles of overhead transmission lines not identified with an operating company.
Vertically Integrated Utilities Segment
Total Overhead Circuit Miles of Transmission and Distribution Lines
APCo51,602
I&M21,845
KGPCo1,403
KPCo11,207
PSO20,878
SWEPCo27,462
WPCo1,739
Total Circuit Miles136,136

46



Transmission and Distribution Utilities Segment
Total Overhead Circuit Miles of Transmission and Distribution Lines
OPCo (a)45,244
TCC29,622
TNC17,148
Total Circuit Miles92,014
(a)Includes 766 miles of 345,000 volt jointly owned lines.
42

TRANSMISSION OPERATIONSAEP Transmission Holdco Segment

The following table sets forth the total overhead circuit miles of transmission lines of ETT, OHTCocertain wholly-owned and OKTCo:joint venture-owned entities:

 Total Overhead Circuit Miles of Transmission Lines
ETT8621,544
IMTCo62
OHTCo61310
OKTCo93256
Prairie Wind216
Total Circuit Miles2,388

TITLE TO PROPERTY

The AEP System’s generating facilities are generally located on lands owned in fee simple.  The greater portion of the transmission and distribution lines of the AEP System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority.  The rights of AEP’s public utility subsidiaries in the realty on which their facilities are located are considered adequate for use in the conduct of their business.  Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties affected thereby.properties.  AEP’s public utility subsidiaries generally have the right of eminent domain which permits them, if necessary, to acquire, perfect or secure titles to or easements on privately held lands used or to be used in their utility operations.  Recent legislationLegislation in Ohio and Virginia has restricted the right of eminent domain previously granted for power generation purposes.

SYSTEM TRANSMISSION LINES AND FACILITY SITING

Laws in the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Tennessee, Texas, Tennessee, Virginia and West Virginia require prior approval of sites of generating facilities and/or routes of high-voltage transmission lines.  We haveAEP has experienced delays and additional costs in constructing facilities as a result of proceedings conducted pursuant to such statutes and in proceedings in which ourAEP’s operating companies have sought to acquire rights-of-way through condemnation.  These proceedings may result in additional delays and costs in future years.

CONSTRUCTION PROGRAM

With input from its state utility commissions, the AEP System continuously assesses the adequacy of its generation, transmission, distribution and other facilities to plan and provide for the reliable supply of electric power and energy to its customers.  In this assessment process, assumptions are continually being reviewed as new information becomes available and assessments and plans are modified, as appropriate.  AEP forecasts approximately $3.6$5 billion of construction expenditures for 2013, excluding equity AFUDC, capitalized interest and assets acquired under leases.2016. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business

47



opportunities, market volatility, economic trends, weather legal reviews and the ability to access capital.

43

  For additional information on AEP’s construction program, see Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2015 Annual Reports, under the heading entitled Budgeted Construction ExpendituresExpenditures.

The following table shows construction expenditures (including environmental expenditures) during 2012, 2011 and 2010 and a current estimate of 2013 construction expenditures.  Actual amounts for 2012, 2011 and 2010 and budgeted amounts for 2013 exclude equity AFUDC, capitalized interest and assets acquired under leases.

  2013 Estimate (b) 2012 Actual 2011 Actual 2010 Actual
  (in thousands)
Total AEP System (a) $3,578,000 $3,025,000 $2,669,000 $2,345,000
APCo  370,000  469,052  463,077  534,334
I&M  484,000  317,285  301,241  333,238
OPCo  617,000  517,744  460,125  512,637
PSO  295,000  224,295  140,326  194,896
SWEPCo (b)  398,000  542,427  551,163  420,485
                
(a)Includes expenditures of other subsidiaries not shown.  The figure reflects construction expenditures, not investments in subsidiary companies.  Excludes discontinued operations.
(b)Excludes Sabine.

The AEP System construction program is reviewed continuously and is revised from time to time in response to changes in estimates of customer demand, business and economic conditions, the cost and availability of capital, environmental requirements and other factors.  Changes in construction schedules and costs and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, federal income and other taxes and other factors affecting cash requirements may increase or decrease the estimated capital requirements for the AEP System’s construction program.

POTENTIAL UNINSURED LOSSES

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to our generatingAEP’s generation plants and costs of replacement power.  Unless allowed to be recovered through rates, future losses or liabilities which are not completely insured could reduce net income and impact the financial conditions of AEP and other AEP System companies.  For risks related to owning a nuclear generating unit, see Note 56 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies under the heading Nuclear Contingencies for information with respect to nuclear incident liability insurance.

ITEM 3.   LEGAL PROCEEDINGS

For a discussion of material legal proceedings, see Note 56 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies, incorporated by reference in Item 8.

ITEM 4.MINE SAFETY DISCLOSURE

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 Dolet Hills Lignite Company, LLC (DHLC), a wholly-owned lignite mining subsidiary of SWEPCo, and OPCo,AGR and KPCo, through its ownership of Conesville Coal Preparation Company (CCPC) and its use oftheir interest in the Conner Run fly ash impoundment, are subject to the provisions of the Mine Act.  OPCo is in the process of selling CCPC.

The Dodd-Frank Wall Street Reform and Consumer Protection Act and the regulations promulgated thereunder 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 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC CCPC and Conner Run under the Mine Act for the yearquarter ended December 31, 2012.
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PART II
2015.


48



PART II

ITEM 5.MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

AEP

In addition to the discussion below, the remaining information required by this item is incorporated herein by reference to the material under AEP Common Stock and Dividend Information and Note 1314 to the consolidated financial statements entitled Financing Activities under the heading Dividend Restrictions in the 20122015 Annual Report.

APCo, I&M, OPCo, PSO and SWEPCo

The common stock of these companies is held solely by AEP.  The information regarding the amounts of cash dividends on common stock paid by these companies to AEP during 2012, 20112015, 2014 and 20102013 are incorporated by reference to the material under Statements of Changes in Common Shareholder’s Equity and Note 1314 to the consolidated financial statements entitled Financing Activities under the heading Dividend Restrictions in the 20122015 Annual Reports.

During the quarter ended December 31, 2012,2015, neither AEP nor its publicly-traded subsidiaries purchased equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act.

ITEM 6.SELECTED FINANCIAL DATA

AEP

The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 20122015 Annual Reports.

APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(a). Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 20122015 Annual Reports.

ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

AEP

The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 20122015 Annual Reports.Reports.

APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(a).  Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 20122015 Annual Reports.


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ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

AEP, APCo, I&M, OPCo, PSO and SWEPCo

The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Quantitative and Qualitative Disclosures about Market and Credit Risk in the 20122015 Annual Reports.

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ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

AEP, APCo, I&M, OPCo, PSO and SWEPCo

The information required by this item is incorporated herein by reference to the financial statements and financial statement schedules described under Item 15 herein.

ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

AEP, APCo, I&M, OPCo, PSO and SWEPCo

None.

ITEM 9A.CONTROLS AND PROCEDURES

During 2012,2015, management, including the principal executive officer and principal financial officer of each of American Electric Power Company, Inc. (“AEP”), Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company (each a “Registrant” and collectively the “Registrants”) evaluated each respective Registrant’s disclosure controls and procedures.  Disclosure controls and procedures are defined as controls and other procedures of the RegistrantsRegistrant 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 Commission’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 each Registrant’s 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 December 31, 2012,2015, 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 have been no changes 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 fourth quarter of 20122015 that materially affected, or areis reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

Management is required to assessassessed and reportreported on the effectiveness of its internal control over financial reporting as of December 31, 2012.2015.  As a result of that assessment, management determined that there were no material weaknesses as of December 31, 20122015 and, therefore, concluded that each Registrant’s internal control over financial reporting was effective.

Additional information required by this item of the Registrants is incorporated by reference to Management’s Report on Internal Control over Financial Reporting, included in the 20122015 Annual Report of each Registrant.

ITEM 9B.   OTHER INFORMATION

None.

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46



PART III

ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

AEP

Directors, Director Nomination Process and Audit Committee

Certain of the information called for in this Item 10, including the information relating to directors, is incorporated herein by reference to AEP'sAEP’s definitive proxy information statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to 20132016 Annual Meeting of Shareholders (the 20132016 Annual Meeting) including under the captions “Election of Directors,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “AEP's“AEP’s Board of Directors and Committees,” “Directors,” "Involvement by Mr. Hoaglin in Certain Legal Proceedings"“Directors” and “Shareholder Nominees for Directors.”

Executive Officers

Reference also is made to the information under the caption Executive Officers of the RegistrantsAEP in Part I, Item 41 of this report.

Code of Ethics

AEP’s Principles of Business Conduct is the code of ethics that applies to AEP’s Chief Executive Officer, Chief Financial Officer and principal accounting officer.  The Principles of Business Conduct is available on AEP’s website at www.aep.com.  The Principles of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Investor Relations, American Electric Power Company, Inc., 1 Riverside Plaza, Columbus, Ohio  43215.

If any substantive amendments to the Principles of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Principles of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or principal accounting officer, AEP will disclose the nature of such amendment or waiver on AEP’s website, www.aep.com, or in a report on Form 8-K.

Section 16(a) Beneficial Ownership Reporting Compliance

The information required by this item is incorporated herein by reference to information contained in the definitive proxy statement of AEP for the 20132016 Annual Meeting.

ITEM 11.EXECUTIVE COMPENSATION

APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

AEP

The information called for by this Item 11 is incorporated herein by reference to AEP'sAEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 20132016 Annual Meeting including under the captions “Compensation Discussion and Analysis,” “Executive Compensation”, “Director Compensation” and “2012“2015 Director Compensation Table”.  The information set forth under the subcaption “Human Resources Committee Report” and “Audit Committee Report” should not be deemed filed nor should it be incorporated by reference into any other filing under the Securities Act of 1933, as amended, or the Exchange Act except to the extent weAEP specifically incorporateincorporates such report by reference therein.


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47



ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

AEP

The information relating to Security Ownership of Certain Beneficial Owners is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to 20132016 Annual Meeting under the caption “Share Ownership of Certain Beneficial Owners and Management"Management” and "Share“Share Ownership of Directors and Executive Officers."

EQUITY COMPENSATION PLAN INFORMATION

The following table summarizes the ability of AEP to issue common stock pursuant to equity compensation plans as of December 31, 2012:2015:

Plan Category Number of Securities to be Issued upon Exercise of Outstanding Options Warrants and Rights Weighted Average Exercise Price of Outstanding Options, Warrants and Rights 
Number of Securities Remaining
Available for Future Issuance under Equity Compensation Plans (Excluding Securities Reflected in Column A(a)
Equity Compensation Plans Approved by Security Holders (b) 188,472 $30.17 17,907,559
Equity Compensation Plans Not Approved by Security Holders -  - -
Total 188,472 $30.17 17,907,559

(a)
AEP deducts equity compensation granted in stock units that are paid in cash, rather than AEP common shares, such as AEP’s performance units and deferred stock units, from the number
Plan CategoryNumber of shares available for future grants under the Amended and Restated American Electric Power System Long-Term Incentive Plan.  The number of shares available under this plan would be 1,091,485 higher if equity compensation that is paid in cash were not deducted from this column.
(b)Consists of sharesSecurities to be issuedIssued upon exerciseExercise of outstanding options grantedOutstanding Options Warrants and RightsWeighted Average Exercise Price of Outstanding Options, Warrants and Rights
Number of Securities Remaining
Available for Future Issuance under the Amended and Restated American Electric Power System Long-Term Incentive Plan.Equity Compensation Plans
Equity Compensation Plans Approved by Security Holders
NA9,975,626
Equity Compensation Plans Not Approved by Security Holders


Total
NA9,975,626

NA    Not applicable.

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

AEP

The information called for by this Item 13 is incorporated herein by reference to AEP'sAEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 20132016 Annual Meeting under the captions “Transactions with Related Persons” and “Director Independence.”


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ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES

AEP

The information called for by this Item 14 is incorporated herein by reference to AEP'sAEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 20132016 Annual Meeting under the captions “Audit and Non-Audit Fees,” "Audit“Audit Committee Report"Report” and “Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Auditor.”

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APCo, I&M, OPCo, PSO and SWEPCo

Each of the above is a wholly-owned subsidiary of AEP and does not have a separate audit committee.  A description of the AEP Audit Committee pre-approval policies, which apply to these companies, is contained in the definitive proxy statement of AEP for the 20132016 Annual Meeting of shareholders.  The following table presents directly billed fees for professional services rendered by Deloitte & Touche LLP for the audit of these companies’ annual financial statements for the years ended December 31, 20122015 and 2011,2014, and fees directly billed for other services rendered by Deloitte & Touche LLP during those periods.  Deloitte & Touche LLP also provides additional professional and other services to the AEP System, the cost of which may ultimately be allocated to these companies though not billed directly to them.  For a description of these fees and services, see the description of principal accounting fees and services for AEP, above.

 APCo I&M  OPCo APCo I&M OPCo
 2012  2011 2012  2011  2012  2011 2015 2014 2015 2014 2015 2014
Audit Fees $2,026,590  $2,241,610  $1,447,948  $1,610,206  $2,459,868  $2,849,269 $2,123,309
 $2,103,482
 $1,638,081
 $1,563,434
 $1,166,775
 $1,111,667
Audit-Related Fees  57,556   6,900   47,022   6,900   60,901   6,900 125,961
 108,305
 70,341
 53,508
 94,931
 83,594
Tax Fees  22,623   9,000   16,806   12,000   28,842   18,000 24,603
 26,915
 20,255
 21,117
 39,696
 15,719
Total $2,106,769  $2,257,510  $1,511,776  $1,629,106  $2,549,611  $2,874,169 $2,273,873
 $2,238,702
 $1,728,677
 $1,638,059
 $1,301,402
 $1,210,980

 PSO SWEPCo 
 2012 2011 2012 2011 
Audit Fees $612,686  $714,097  $1,014,601  $894,582 
Audit-Related Fees  25,125   6,900   778,130   70,900 
Tax Fees  7,177   9,000   11,413   8,977 
Total $644,988  $729,997  $1,804,144  $974,459 

  PSO SWEPCo 
  2015 2014 2015 2014 
 Audit Fees$666,984
 $599,890
 $1,280,749
 $1,216,430
 
 Audit-Related Fees33,214
 25,622
 52,693
 41,118
 
 Tax Fees8,401
 8,482
 14,620
 15,503
 
 Total$708,599
 $633,994
 $1,348,062
 $1,273,051
 

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49



PART IV

ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are filed as a part of this report:

The following documents are filed as a part of this report:
1.FINANCIAL STATEMENTS:
The following financial statements have been incorporated herein by reference pursuant to Item 8.

1.  FINANCIAL STATEMENTS:
The following financial statements have been incorporated herein by reference pursuant to Item 8.
AEP and Subsidiary Companies:
Reports of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2012, 2011 and 2010; Consolidated Statements of Changes in Equity for the years ended December 31, 2012, 2011 and 2010; Consolidated Balance Sheets as of December 31, 2012 and 2011; Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010; Notes to Consolidated Financial Statements.
APCo, I&M and OPCo:
Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2012, 2011 and 2010; Consolidated Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2012, 2011 and 2010; Consolidated Balance Sheets as of December 31, 2012 and 2011; Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.
PSO:
Statements of Income for the years ended December 31, 2012, 2011 and 2010; Statements of Comprehensive Income (Loss) for the years ended December 31, 2012, 2011 and 2010; Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2012, 2011 and 2010; Balance Sheets as of December 31, 2012 and 2011; Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.
SWEPCo:
Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2012, 2011 and 2010; Consolidated Statements of Changes in Equity for the years ended December 31, 2012, 2011 and 2010; Consolidated Balance Sheets as of December 31, 2012 and 2011; Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.
AEP and Subsidiary Companies:
Reports of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2015, 2014 and 2013; Consolidated Statements of Changes in Equity for the years ended December 31, 2015, 2014 and 2013; Consolidated Balance Sheets as of December 31, 2015 and 2014; Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013; Notes to Financial Statements of Registrants.

APCo, I&M and OPCo:
Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2015, 2014 and 2013; Consolidated Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2015, 2014 and 2013; Consolidated Balance Sheets as of December 31, 2015 and 2014; Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013; Notes to Financial Statements of Registrants; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.

PSO:
Statements of Income for the years ended December 31, 2015, 2014 and 2013; Statements of Comprehensive Income (Loss) for the years ended December 31, 2015, 2014 and 2013; Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2015, 2014 and 2013; Balance Sheets as of December 31, 2015 and 2014; Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013; Notes to Financial Statements of Registrants; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.

SWEPCo:
Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2015, 2014 and 2013; Consolidated Statements of Changes in Equity for the years ended December 31, 2015, 2014 and 2013; Consolidated Balance Sheets as of December 31, 2015 and 2014; Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013; Notes to Financial Statements of Registrants; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.
Page
2.  FINANCIAL STATEMENT SCHEDULES:Page Number
Financial Statement Schedules are listed in the Index of Financial Statement Schedules.  (Certain schedules have been omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable). Reports of Independent Registered Public Accounting Firm.S-1
  
3.  EXHIBITS: 
Exhibits for AEP, APCo, I&M, OPCo, PSO and SWEPCo are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference.E-1

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50

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 American Electric Power Company, Inc.
   
 By:/s/   Brian X. Tierney
  (Brian X. Tierney, Executive Vice President
  and Chief Financial Officer)

Date: February 26, 201323, 2016

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature Title Date
     
(i)Principal Executive Officer:    
     
 
/s/   Nicholas K. Akins
 
Chairman of the Board,
Chief Executive Officer President and Director
 February 26, 201323, 2016
(Nicholas K. Akins)   
     
 
(ii)Principal Financial Officer:    
     
/s/   Brian X. Tierney Executive Vice President and Chief Financial Officer February 26, 201323, 2016
(Brian X. Tierney) Chief Financial Officer  
     
(iii)Principal Accounting Officer:    
     
/s/   Joseph M. Buonaiuto Senior Vice President, Controller and Chief Accounting Officer February 26, 201323, 2016
(Joseph M. Buonaiuto) Chief Accounting Officer  
     
(iv)           A Majority of the Directors:    
     
*Nicholas K. Akins    
*David J. Anderson    
* James F. CordesJ. Barnie Beasley, Jr.    
*Ralph D. Crosby, Jr.    
*Linda A. Goodspeed    
*Thomas E. Hoaglin    
*Sandra Beach Lin    
*Michael G. Morris
*Richard C. Notebaert    
*Lionel L. Nowell, III
*Stephen S. Rasmussen
*Oliver G. Richard, III
*Richard L. Sandor
*Sara Martinez Tucker
*John F. Turner    
 *Stephen S. Rasmussen
*Oliver G. Richard, III
*Sara Martinez Tucker    
      
*By:/s/   Brian X. Tierney   February 26, 201323, 2016
 (Brian X. Tierney, Attorney-in-Fact)    


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51



SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 Appalachian Power Company
 Ohio Power Company
 Public Service Company of Oklahoma
 Southwestern Electric Power Company
   
 By:/s/   Brian X. Tierney
  (Brian X. Tierney, Executive Vice President
and Chief Financial Officer)

Date: February 26, 201323, 2016

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.  The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature Title Date
     
(i)Principal Executive Officer:    
     
/s/   Nicholas K. Akins Chairman of the Board, Chief Executive Officer and Director February 26, 201323, 2016
(Nicholas K. Akins)   
     
(ii)Principal Financial Officer:    
     
/s/   Brian X. Tierney Vice President, Chief Financial Officer and Director February 26, 201323, 2016
(Brian X. Tierney) Chief Financial Officer and Director  
     
(iii) Principal Accounting Officer:    
     
/s/   Joseph M. Buonaiuto Controller and Chief Accounting Officer February 26, 201323, 2016
(Joseph M. Buonaiuto) Chief Accounting Officer  
     
(iv)A Majority of the Directors:    
     
*Nicholas K. Akins    
*Lisa M. Barton    
*David M. Feinberg
*Lana L. Hillebrand
    
*Lana L. Hillebrand
*Mark C. McCullough    
*Robert P. Powers    
*Dennis E. WelchBrian X. Tierney    
     
*By:                                                                          ��         
/s/   Brian X. Tierney
   February 26, 201323, 2016
 (Brian X. Tierney, Attorney-in-Fact)    

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52

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 Indiana Michigan Power Company
   
 By:/s/   Brian X. Tierney
  (Brian X. Tierney, Executive Vice President
  and Chief Financial Officer)

Date: February 26, 201323, 2016

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.  The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature Title Date
     
(i)Principal Executive Officer:    
     
/s/   Nicholas K. Akins Chairman of the Board, Chief Executive Officer and Director February 26, 201323, 2016
(Nicholas K. Akins)   
     
(ii)Principal Financial Officer:    
     
/s/   Brian X. Tierney Vice President, Chief Financial Officer and Director February 26, 201323, 2016
(Brian X. Tierney) Chief Financial Officer and Director  
     
(iii)Principal Accounting Officer:    
     
/s/   Joseph M. Buonaiuto Controller and Chief Accounting Officer February 26, 201323, 2016
(Joseph M. Buonaiuto) Chief Accounting Officer  
     
(iv)A Majority of the Directors:    
     
*Nicholas K. Akins    
*Lisa M. Barton    
*Sarah L. Bodner
*Paul Chodak, III    
*J. Edward EhlerThomas A. Kratt    
*Scott M. Krawec
*Marc E. Lewis    
*David A. Lucas
*Mark C. McCullough    
*Robert P. Powers    
*Carla E. Simpson
Brian X. Tierney
*Barry O. Wiard    
     
*By:
/s/   Brian X. Tierney
   February 26, 201323, 2016
 (Brian X. Tierney, Attorney-in-Fact)    

57



53

INDEX OF FINANCIAL STATEMENT SCHEDULES

 
Page
Number
  
The following financial statement schedules are included in this report on the pages indicated: 
  
American Electric Power Company, Inc. (Parent): 
  
American Electric Power Company, Inc. and Subsidiary Companies: 
  
Appalachian Power Company and Subsidiaries: 
  
Indiana Michigan Power Company and Subsidiaries: 
  
Ohio Power Company and Subsidiary:Subsidiaries: 
S-10
  
Public Service Company of Oklahoma: 
  
Southwestern Electric Power Company Consolidated: 


S-1



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
American Electric Power Company, Inc.:

We have audited the consolidated financial statements of American Electric Power Company, Inc. and subsidiary companies (the “Company”) as of December 31, 20122015 and 2011,2014, and for each of the three years in the period ended December 31, 2012,2015, and the Company's internal control over financial reporting as of December 31, 2012,2015, and have issued our reports thereon dated February 26, 2013;23, 2016; such consolidated financial statements and our reports are included in the Company’s 20122015 Annual Report and are incorporated herein by reference.  Our audits also included the financial statement schedules of the Company listed in Item 15.  These financial statement schedules are the responsibility of the Company's management.  Our responsibility is to express an opinion based on our audits.  In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Columbus, Ohio
February 26, 201323, 2016




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Appalachian Power Company
Indiana Michigan Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company

We have audited the financial statements of Appalachian Power Company and subsidiaries, Indiana Michigan Power Company and subsidiaries, Ohio Power Company and subsidiary,subsidiaries, Public Service Company of Oklahoma, and Southwestern Electric Power Company Consolidated (collectively the “Companies”) as of December 31, 20122015 and 2011,2014, and for each of the three years in the period ended December 31, 2012,2015, and have issued our reports thereon dated February 26, 2013;23, 2016; such financial statements and reports are included in the Companies’ 20122015 Annual Reports and are incorporated herein by reference.  Our audits also included the financial statement schedule of each of the Companies listed in Item 15.  These financial statement schedules are the responsibility of the Companies’ management.  Our responsibility is to express an opinion based on our audits.  In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Columbus, Ohio
February 26, 201323, 2016

S-2

S-2




SCHEDULE I
SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2012, 2011 and 2010
(in millions, except per-share and share amounts)
           
   Years Ended December 31,
  2012  2011  2010 
REVENUES         
Affiliated Revenues $ 4  $ 5  $ 4 
           
EXPENSES         
Other Operation   22    23    54 
          
OPERATING LOSS   (18)   (18)   (50)
          
Other Income (Expense):         
Interest Income   22    19    22 
Interest Expense   (90)   (42)   (52)
          
LOSS BEFORE INCOME TAX CREDIT AND         
 EQUITY EARNINGS   (86)   (41)   (80)
          
Income Tax Credit   -    2    - 
Equity Earnings of Unconsolidated Subsidiaries   1,345    1,980    1,291 
           
NET INCOME   1,259    1,941    1,211 
           
Other Comprehensive Income (Loss)   133    (89)   (7)
           
TOTAL COMPREHENSIVE INCOME $ 1,392  $ 1,852  $ 1,204 
           
WEIGHTED AVERAGE NUMBER OF BASIC AEP         
 COMMON SHARES OUTSTANDING   484,682,469    482,169,282    479,373,306 
           
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE         
 TO AEP COMMON SHAREHOLDERS $ 2.60  $ 4.02  $ 2.53 
           
WEIGHTED AVERAGE NUMBER OF DILUTED AEP         
 COMMON SHARES OUTSTANDING   485,084,694    482,460,328    479,601,442 
           
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE         
 TO AEP COMMON SHAREHOLDERS $ 2.60  $ 4.02  $ 2.53 
          
See Condensed Notes to Condensed Financial Information beginning on page S-7.
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2015, 2014 and 2013
(in millions, except per-share and share amounts)
S-3

  Years Ended December 31,
  2015 2014 2013
REVENUES      
Affiliated Revenues $10.7
 $7.4
 $4.4
       
EXPENSES  
  
  
Other Operation 29.0
 27.3
 21.8
Depreciation 0.7
 
 
TOTAL EXPENSES 29.7
 27.3
 21.8
       
OPERATING LOSS (19.0) (19.9) (17.4)
       
Other Income (Expense):  
  
  
Interest Income 5.9
 6.9
 20.7
Interest Expense (19.1) (16.6) (16.3)
       
LOSS BEFORE INCOME TAX CREDIT AND EQUITY EARNINGS (32.2) (29.6) (13.0)
       
Income Tax Credit (1.5) 
 
Equity Earnings of Unconsolidated Subsidiaries 1,794.1
 1,615.9
 1,483.2
       
INCOME FROM CONTINUING OPERATIONS 1,763.4
 1,586.3
 1,470.2
       
INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX 283.7
 47.5
 10.3
       
NET INCOME 2,047.1
 1,633.8
 1,480.5
       
Other Comprehensive Income (Loss) (30.0) 12.1
 216.6
       
TOTAL COMPREHENSIVE INCOME $2,017.1
 $1,645.9
 $1,697.1
       
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING 490,340,522
 488,592,997
 486,619,555
       
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS $3.59
 $3.24
 $3.02
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS 0.58
 0.10
 0.02
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $4.17
 $3.34
 $3.04
       
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING 490,574,568
 488,899,840
 487,040,956
       
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS $3.59
 $3.24
 $3.02
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS 0.58
 0.10
 0.02
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $4.17
 $3.34
 $3.04

 SCHEDULE I
 AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
 CONDENSED FINANCIAL INFORMATION
 CONDENSED BALANCE SHEETS
 ASSETS
 December 31, 2012 and 2011
 (in millions)
  
         December 31,
   2012  2011 
 CURRENT ASSETS      
 Cash and Cash Equivalents $ 166  $ 127 
 Other Temporary Investments   2    2 
 Advances to Affiliates   650    944 
 Accounts Receivable:      
  General   71    17 
  Affiliated Companies   36    43 
   Total Accounts Receivable   107    60 
 Prepayments and Other Current Assets   5    7 
 TOTAL CURRENT ASSETS   930    1,140 
        
 PROPERTY, PLANT AND EQUIPMENT      
 General   1    2 
 Total Property, Plant and Equipment   1    2 
 Accumulated Depreciation and Amortization   1    2 
 TOTAL PROPERTY, PLANT AND EQUIPMENT - NET   -    - 
        
 OTHER NONCURRENT ASSETS      
 Investments in Unconsolidated Subsidiaries   15,679    15,170 
 Affiliated Notes Receivable   285    290 
 Deferred Charges and Other Noncurrent Assets   54    59 
 TOTAL OTHER NONCURRENT ASSETS   16,018    15,519 
        
 TOTAL ASSETS $ 16,948  $ 16,659 
        
 See Condensed Notes to Condensed Financial Information beginning on page S-7.      
              

S-4



 SCHEDULE I
 AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
 CONDENSED FINANCIAL INFORMATION
 CONDENSED BALANCE SHEETS
 LIABILITIES AND EQUITY
 December 31, 2012 and 2011
 (dollars in millions)
  
         December 31,
   2012  2011 
 CURRENT LIABILITIES  
 Accounts Payable:      
  General $ 1  $ 1 
  Affiliated Companies   435    445 
 Long-term Debt Due Within One Year   5    1 
 Short-term Debt   321    967 
 Other Current Liabilities   74    7 
 TOTAL CURRENT LIABILITIES   836    1,421 
        
 NONCURRENT LIABILITIES      
 Long-term Debt   847    554 
 Deferred Credits and Other Noncurrent Liabilities   28    20 
 TOTAL NONCURRENT LIABILITIES   875    574 
        
 TOTAL LIABILITIES   1,711    1,995 
        
        
 COMMON SHAREHOLDERS' EQUITY      
 Common Stock – Par Value – $6.50 Per Share:      
    2012  2011        
  Shares Authorized600,000,000  600,000,000        
  Shares Issued506,004,962  503,759,460        
 (20,336,592 Shares were Held in Treasury as of December 31, 2012 and 2011)   3,289    3,274 
 Paid-in Capital   6,049    5,970 
 Retained Earnings   6,236    5,890 
 Accumulated Other Comprehensive Income (Loss)   (337)   (470)
 TOTAL AEP COMMON SHAREHOLDERS’ EQUITY   15,237    14,664 
        
 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 16,948  $ 16,659 
        
 See Condensed Notes to Condensed Financial Information beginning on page S-7.      
See Condensed Notes to Condensed Financial Information beginning on page S-7.


S-3



SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED BALANCE SHEETS
ASSETS
December 31, 2015 and 2014
(in millions)
  December 31,
  2015 2014
CURRENT ASSETS  
  
Cash and Cash Equivalents $93.3
 $63.2
Other Temporary Investments 2.1
 2.2
Advances to Affiliates 636.9
 769.1
Accounts Receivable:  
  
General 13.2
 8.0
Affiliated Companies 8.5
 12.6
Total Accounts Receivable 21.7
 20.6
Prepayments and Other Current Assets 2.1
 4.0
TOTAL CURRENT ASSETS 756.1
 859.1
     
PROPERTY, PLANT AND EQUIPMENT  
  
General 0.7
 1.1
Total Property, Plant and Equipment 0.7
 1.1
Accumulated Depreciation and Amortization 0.4
 1.1
TOTAL PROPERTY, PLANT AND EQUIPMENT  NET
 0.3
 
     
OTHER NONCURRENT ASSETS  
  
Investments in Unconsolidated Subsidiaries 18,344.9
 17,204.9
Equity Investment Held for Sale 
 270.6
Affiliated Notes Receivable 20.0
 45.0
Deferred Charges and Other Noncurrent Assets 49.0
 52.3
TOTAL OTHER NONCURRENT ASSETS 18,413.9
 17,572.8
     
TOTAL ASSETS $19,170.3
 $18,431.9
S-5

 SCHEDULE I
 AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
 CONDENSED FINANCIAL INFORMATION
 CONDENSED STATEMENTS OF CASH FLOWS
 For the Years Ended December 31, 2012, 2011 and 2010
 (in millions)
              
      Years Ended December 31,
   2012  2011  2010 
 OPERATING ACTIVITIES         
 Net Income $ 1,259  $ 1,941  $ 1,211 
 Adjustments to Reconcile Net Income to Net Cash Flows         
  from Operating Activities:         
   Equity Earnings of Unconsolidated Subsidiaries   (1,345)   (1,980)   (1,291)
   Cash Dividends Received from Unconsolidated Subsidiaries   1,294    1,113    854 
   Change in Other Noncurrent Assets   13    2    - 
   Change in Other Noncurrent Liabilities   22    20    14 
   Changes in Certain Components of Working Capital:         
    Accounts Receivable, Net   (47)   72    (93)
    Accounts Payable   (10)   (103)   89 
    Other Current Liabilities   72    (3)   (12)
 Net Cash Flows from Operating Activities   1,258    1,062    772 
           
 INVESTING ACTIVITIES         
 Purchases of Investment Securities   -    (69)   (333)
 Sales of Investment Securities   -    166    267 
 Change in Advances to Affiliates, Net   294    (388)   (299)
 Capital Contributions to Unconsolidated Subsidiaries   (325)   (99)   (6)
 Issuance of Notes Receivable to Affiliated Companies   -    -    (20)
 Repayments of Notes Receivable from Affiliated Companies   5    5    300 
 Net Cash Flows Used for Investing Activities   (26)   (385)   (91)
           
 FINANCING ACTIVITIES         
 Issuance of Common Stock, Net   83    92    93 
 Issuance of Long-term Debt   843    -    - 
 Commercial Paper and Credit Facility Borrowings   -    429    466 
 Change in Short-term Debt, Net   (646)   769    80 
 Retirement of Long-term Debt   (558)   -    (490)
 Change in Advances from Affiliates, Net   -    (295)   6 
 Commercial Paper and Credit Facility Repayments   -    (881)   (15)
 Dividends Paid on Common Stock   (911)   (892)   (820)
 Other Financing Activities   (4)   (3)   (3)
 Net Cash Flows Used for Financing Activities   (1,193)   (781)   (683)
           
 Net Increase (Decrease) in Cash and Cash Equivalents   39    (104)   (2)
 Cash and Cash Equivalents at Beginning of Period   127    231    233 
 Cash and Cash Equivalents at End of Period $ 166  $ 127  $ 231 
           
 See Condensed Notes to Condensed Financial Information beginning on page S-7.         
See Condensed Notes to Condensed Financial Information beginning on page S-7.


S-4



SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2015 and 2014
(dollars in millions)
  December 31,
  2015 2014
CURRENT LIABILITIES    
Advances from Affiliates $244.6
 $115.9
Accounts Payable:    
General 0.3
 0.8
Affiliated Companies 2.0
 2.1
Long-term Debt Due Within One Year 0.1
 2.8
Short-term Debt 125.0
 602.0
Other Current Liabilities 21.0
 11.1
TOTAL CURRENT LIABILITIES 393.0
 734.7
     
NONCURRENT LIABILITIES    
Long-term Debt 843.3
 836.3
Deferred Credits and Other Noncurrent Liabilities 42.3
 40.7
TOTAL NONCURRENT LIABILITIES 885.6
 877.0
     
TOTAL LIABILITIES 1,278.6
 1,611.7
     
     
COMMON SHAREHOLDERS’ EQUITY    
Common Stock – Par Value – $6.50 Per Share:    
 2015 2014     
Shares Authorized600,000,000 600,000,000     
Shares Issued511,389,173 509,739,159     
(20,336,592 Shares were Held in Treasury as of December 31, 2015 and 2014) 3,324.0
 3,313.3
Paid-in Capital 6,296.5
 6,203.4
Retained Earnings 8,398.3
 7,406.6
Accumulated Other Comprehensive Income (Loss) (127.1) (103.1)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY 17,891.7
 16,820.2
     
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $19,170.3
 $18,431.9

See Condensed Notes to Condensed Financial Information beginning on page S-7.


S-5



SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2015, 2014 and 2013
(in millions)
  Years Ended December 31,
  2015 2014 2013
OPERATING ACTIVITIES  
  
  
Net Income $2,047.1
 $1,633.8
 $1,480.5
Income from Discontinued Operations 283.7
 47.5
 10.3
Income from Continuing Operations 1,763.4
 1,586.3
 1,470.2
Adjustments to Reconcile Income from Continuing Operations to Net Cash      
Flows from Continuing Operating Activities:      
Depreciation and Amortization 0.7
 
 
Deferred Income Taxes (1.0) 
 
Equity Earnings of Unconsolidated Subsidiaries (1,794.1) (1,615.9) (1,483.2)
Cash Dividends Received from Unconsolidated Subsidiaries 984.5
 931.5
 1,022.2
Change in Other Noncurrent Assets 8.2
 0.2
 1.0
Change in Other Noncurrent Liabilities 14.1
 16.5
 17.7
Changes in Certain Components of Continuing Working Capital:      
Accounts Receivable, Net 4.4
 (9.4) 95.8
Accounts Payable (0.6) (10.7) (422.4)
Other Current Assets (0.7) 0.2
 0.2
Other Current Liabilities 9.2
 5.7
 (73.9)
Net Cash Flows from Continuing Operating Activities 988.1
 904.4
 627.6
       
INVESTING ACTIVITIES      
Construction Expenditures (1.0) 
 
Change in Advances to Affiliates, Net 132.2
 (230.5) 111.3
Capital Contributions to Unconsolidated Subsidiaries (473.0) (522.5) (358.2)
Return of Capital Contributions from Unconsolidated Subsidiaries 179.0
 122.5
 375.0
Repayments of Notes Receivable from Affiliated Companies 25.0
 20.0
 200.0
Net Cash Flows from (Used for) Continuing Investing Activities (137.8) (610.5) 328.1
       
FINANCING ACTIVITIES      
Issuance of Common Stock, Net 81.6
 73.6
 83.2
Issuance of Long-term Debt 
 
 199.4
Change in Short-term Debt, Net (477.0) 545.0
 (264.0)
Retirement of Long-term Debt 
 
 (200.0)
Change in Advances from Affiliates, Net 128.7
 74.5
 41.4
Dividends Paid on Common Stock (1,054.2) (991.9) (948.8)
Other Financing Activities (7.4) (8.4) (6.0)
Net Cash Flows Used for Continuing Financing Activities (1,328.3) (307.2) (1,094.8)
       
Net Cash Flows from Discontinued Operating Activities 24.6
 25.0
 5.0
Net Cash Flows from Discontinued Investing Activities 483.5
 15.0
 5.0
Net Cash Flows from Discontinued Financing Activities 
 
 
       
Net Increase (Decrease) in Cash and Cash Equivalents 30.1
 26.7
 (129.1)
Cash and Cash Equivalents at Beginning of Period 63.2
 36.5
 165.6
Cash and Cash Equivalents at End of Period $93.3
 $63.2
 $36.5

See Condensed Notes to Condensed Financial Information beginning on page S-7.

S-6



SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL INFORMATION

1.Summary of Significant Accounting Policies
 
2.Commitments, Guarantees and Contingencies
 
3.Financing Activities
 
4.Related Party Transactions


S-7




1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The condensed financial information of AEP (Parent)Parent is required as a result of the restricted net assets of consolidated subsidiaries exceeding 25% of consolidated net assets as of December 31, 2012.2015.  Parent is a public utility holding company that owns all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries, including joint ventures and equity investments.  The primary source of income for Parent is equity in its subsidiaries’ earnings.  Its major source of cash is dividends from the subsidiaries.  Parent borrows the funds for the money pool that is used by the subsidiaries for their short-term cash needs.

Income Taxes

Parent files a consolidated federal income tax return with its subsidiaries.  The AEP System’s current consolidated federal income tax is allocated to the AEP System companies so that their current tax expense reflects a separate return result for each company in the consolidated group.  The tax benefit of Parent is allocated to its subsidiaries with taxable income.

2.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

Parent and its subsidiaries are parties to environmental and other legal matters.  For further discussion of commitments, guarantees and contingencies, see Note 56 in the 20122015 Annual Reports.

3.  FINANCING ACTIVITIES

The following details long-term debt outstanding as of December 31, 20122015 and 2011:2014:

Long-term Debt
      
     Outstanding as of
   Interest Rate Ranges as of December 31, December 31,
 Type of Debt and Maturity 2012  2011  2012  2011 
       (in millions)
 Senior Unsecured Notes (a)          
  2015-2022 1.65% - 2.95% 5.25% $ 850  $ 243 
             
 Junior Subordinated Debentures (a)          
  2063    8.75%   -    315 
               
 Fair Value of Interest Rate Hedges       3    7 
 Unamortized Discount, Net       (1)   (10)
 Total Long-term Debt Outstanding       852    555 
 Long-term Debt Due Within One Year       5    1 
 Long-term Debt     $ 847  $554
Long-term Debt

(a)  In 2012, Parent issued $850 million of Senior Unsecured Notes used to retire $243 million of Senior Unsecured Notes and $315 million of Junior Subordinated Debentures.
  Weighted Average Interest Rate Ranges as of Outstanding as of
  Interest Rate as of December 31, December 31,
Type of Debt and Maturity December 31, 2015 2015 2014 2015 2014
        (in millions)
Senior Unsecured Notes          
2017-2022 2.11% 1.65% - 2.95% 1.65% - 2.95% $843.4
 $839.1
Total Long-term Debt Outstanding       $843.4
 $839.1

Long-term debt outstanding as of December 31, 20122015 is payable as follows:

          After  
2013  2014  2015  2016  2017  2017  Total2016 2017 2018 2019 2020 After 2020 Total
(in millions)(in millions)
Principal Amount$ 5  $ 2  $ 3  $ (2) $ 545  $ 300  $ 853 $0.1
 $546.9
 $
 $
 $
 $300.0
 $847.0
Unamortized Discount, Net               (1)
Unamortized Discount, Net and Debt Issuance Costs         
  
 (3.6)
Total Long-term Debt Outstanding             $ 852          
  
 $843.4


S-8




Short-term Debt

Short-term Debt
Parent's outstanding short-term debt was as follows:
              
   December 31,
   2012  2011 
   Outstanding Weighted Average Outstanding Weighted Average
Type of DebtAmountInterest Rate AmountInterest Rate
  (in millions)    (in millions)   
Commercial Paper $ 321   0.42 % $ 967   0.51 %
Total Short-term Debt $ 321     $ 967    
Parent’s outstanding short-term debt was as follows:
  December 31,
  2015 2014
Type of Debt 
Outstanding
Amount
 
Weighted Average
Interest Rate
 
Outstanding
Amount
 
Weighted Average
Interest Rate
  (in millions)  
 (in millions)  
Commercial Paper $125.0
 0.81% $602.0
 0.59%
Total Short-term Debt $125.0
  
 $602.0
  

4.  RELATED PARTY TRANSACTIONS

Payments on Behalf of Subsidiaries

Due to occasional time sensitivity and complexity of payments, Parent makes certain insurance, tax and benefit payments on behalf of subsidiary companies.  Parent is then fully reimbursed by the subsidiary companies.

Short-term Lending to Subsidiaries

Parent uses a commercial paper program to meet the short-term borrowing needs of 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 program also allows some direct borrowers to invest excess cash with Parent.

Interest expense related to Parent’s short-term borrowing is included in Interest Expense on Parent’s statements of income.  Parent incurred interest expense for amounts borrowed from subsidiaries of $11 thousand, $199$2 million, $413 thousand and $1 million$7 thousand for the years ended December 31, 2012, 20112015, 2014 and 2010,2013, respectively.

Interest income related to Parent’s short-term lending is included in Interest Income on Parent’s statements of income.  Parent earned interest income for amounts advanced to subsidiaries of $5$4 million, $3$4 million and $2$4 million for the years ended December 31, 2012, 20112015, 2014 and 2010,2013, respectively.

Global Borrowing Notes

Parent issued long-term debt, portions of which were loaned to its subsidiaries.  Parent pays interest on the global notes, but the subsidiaries accrue interest for their share of the global borrowing and remit the interest to Parent.  Interest income related to Parent’s loans to subsidiaries is included in Interest Income on Parent’s statements of income.  Parent earned interest income on loans to subsidiaries of $15$1 million, $15$3 million and $18$15 million for the years ended December 31, 2012, 20112015, 2014 and 2010,2013, respectively.

S-9




SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
AEPAEP     Additions       Additions    
   Balance at BlueStar Charged to Charged to   Balance at
   Beginning Acquisition Costs and Other   End of
DescriptionDescription of Period in March 2012 Expenses Accounts (a) Deductions (b) Period 
Balance at
 Beginning
of Period
 
Charged to
Costs and
Expenses
 
Charged to Other
Accounts (a)
 Deductions (b) 
Balance at
End of
Period
 (in thousands) (in millions)
Deducted from Assets:Deducted from Assets:              
  
  
  
  
Accumulated Provision for UncollectibleAccumulated Provision for Uncollectible              
  
  
  
  
 Accounts:            
 Year Ended December 31, 2012 $ 32,551  $ 344  $ 52,399  $ 2,815  $ 52,443  $ 35,666 
 Year Ended December 31, 2011  41,555   -   36,457   1,994   47,455   32,551 
 Year Ended December 31, 2010  37,399   -   36,699   (1,036)  31,507   41,555 
              
(a)Recoveries offset by reclasses to other liabilities.
(b)Uncollectible accounts written off.
Accounts:          
Year Ended December 31, 2015 $20.8
 $51.9
 $2.7
 $46.4
 $29.0
Year Ended December 31, 2014 59.0
 50.2
 10.0
 98.4
 20.8
Year Ended December 31, 2013 35.6
 50.8
 21.2
 48.6
 59.0

(a)Recoveries offset by reclasses to other assets and liabilities.
(b)Uncollectible accounts written off.
APCo   Additions    
    Balance at Charged to Charged to   Balance at
    Beginning Costs and Other   End of
Description of Period Expenses Accounts (a) Deductions (b) Period
  (in thousands)
Deducted from Assets:               
Accumulated Provision for Uncollectible               
  Accounts:               
  Year Ended December 31, 2012 $ 5,289  $ 15,652  $ 1,689  $ 16,543  $ 6,087 
  Year Ended December 31, 2011   6,667    6,041    1,535    8,954    5,289 
  Year Ended December 31, 2010   5,408    6,573    292    5,606    6,667 
                  
(a)Recoveries offset by reclasses to other liabilities.
(b)Uncollectible accounts written off.

APCo   Additions    
Description 
Balance at
 Beginning
of Period
 
Charged to
Costs and
Expenses
 
Charged to Other
Accounts (a)
 Deductions (b) 
Balance at
End of
Period
  (in millions)
Deducted from Assets:  
  
  
  
  
Accumulated Provision for Uncollectible  
  
  
  
  
Accounts:          
Year Ended December 31, 2015 $2.4
 $9.4
 $2.3
 $9.8
 $4.3
Year Ended December 31, 2014 2.4
 9.0
 2.5
 11.5
 2.4
Year Ended December 31, 2013 6.1
 4.7
 1.8
 10.2
 2.4

(a)Recoveries offset by reclasses to other assets and liabilities.
(b)Uncollectible accounts written off.
I&M   Additions    
    Balance at Charged to Charged to   Balance at
    Beginning Costs and Other   End of
Description of Period Expenses Accounts (a) Deductions (b) Period
  (in thousands)
Deducted from Assets:               
Accumulated Provision for Uncollectible               
  Accounts:               
  Year Ended December 31, 2012 $ 1,750  $ 20  $ -  $ 1,541  $ 229 
  Year Ended December 31, 2011   1,692    151    -    93    1,750 
  Year Ended December 31, 2010   2,265    (139) (c)  (424)   10    1,692 
                  
(a)Recoveries offset by reclasses to other liabilities.
(b)Uncollectible accounts written off.
(c)Recoveries on previous reserve balance.

I&M   Additions    
Description 
Balance at
 Beginning
of Period
 
Charged to
Costs and
Expenses
 
Charged to Other
Accounts (a)
 Deductions (b) 
Balance at
End of
Period
  (in millions)
Deducted from Assets:  
  
  
  
  
Accumulated Provision for Uncollectible  
  
  
  
  
Accounts:          
Year Ended December 31, 2015 $0.5
 $(0.2)(c)$(0.2)(c)$
 $0.1
Year Ended December 31, 2014 0.2
 0.2
 0.2
 0.1
 0.5
Year Ended December 31, 2013 0.2
 
 
 
 0.2

OPCo   Additions    
    Balance at Charged to  Charged to   Balance at
    Beginning Costs and  Other   End of
Description of Period Expenses  Accounts (a) Deductions (b) Period
  (in thousands)
Deducted from Assets:                
Accumulated Provision for Uncollectible                
  Accounts:                
  Year Ended December 31, 2012 $ 3,563  $ (9) (c) $ 43  $ 3,468  $ 129 
  Year Ended December 31, 2011   3,768    59     (10)   254    3,563 
  Year Ended December 31, 2010   6,146    59     (928)   1,509    3,768 
                   
(a)Recoveries offset by reclasses to other liabilities.
(b)Uncollectible accounts written off.
(c)Recoveries on previous reserve balance.
(a)Recoveries offset by reclasses to other assets and liabilities.
(b)Uncollectible accounts written off.
(c)Recoveries on previous reserve balance.

S-10





PSO   Additions    
    Balance at Charged to  Charged to   Balance at
    Beginning Costs and  Other   End of
Description of Period Expenses  Accounts (a) Deductions (b) Period
  (in thousands)
Deducted from Assets:                
Accumulated Provision for Uncollectible                
  Accounts:                
  Year Ended December 31, 2012 $ 777  $ 95   $ -  $ -  $ 872 
  Year Ended December 31, 2011   971    (194) (c)   -    -    777 
  Year Ended December 31, 2010   304    709     -    42    971 
                   
(a)Recoveries on accounts previously written off.
(b)Uncollectible accounts written off.
(c)Recoveries on previous reserve balance.
OPCo   Additions    
Description 
Balance at
 Beginning
of Period
 
Charged to
Costs and
Expenses
 
Charged to Other
Accounts (a)
 Deductions (b) 
Balance at
End of
Period
  (in millions)
Deducted from Assets:  
  
  
  
  
Accumulated Provision for Uncollectible  
  
  
  
  
 Accounts:          
Year Ended December 31, 2015 $0.2
 $0.3
 $
 $0.3
 $0.2
Year Ended December 31, 2014 35.0
 1.2
 8.0
 44.0
 0.2
Year Ended December 31, 2013 0.1
 15.7
 19.2
 
 35.0

(a)Recoveries offset by reclasses to other assets and liabilities.
(b)Uncollectible accounts written off.
SWEPCo   Additions    
    Balance at Charged to Charged to   Balance at
    Beginning Costs and Other   End of
Description of Period Expenses Accounts (a) Deductions (b) Period
  (in thousands)
Deducted from Assets:               
Accumulated Provision for Uncollectible               
  Accounts:               
  Year Ended December 31, 2012 $ 989  $ 71  $ 981  $ -  $ 2,041 
  Year Ended December 31, 2011   588    149    376    124    989 
  Year Ended December 31, 2010   64    400    166    42    588 
                  
(a)Recoveries on accounts previously written off.
(b)Uncollectible accounts written off.


PSO   Additions    
Description 
Balance at
Beginning
of Period
 
Charged to
Costs and
Expenses
 
Charged to Other
Accounts (a)
 Deductions (b) 
Balance at
End of
Period
  (in millions)
Deducted from Assets:  
  
  
  
  
Accumulated Provision for Uncollectible  
  
  
  
  
Accounts:          
Year Ended December 31, 2015 $0.1
 $0.4

$0.2
 $0.1
 $0.6
Year Ended December 31, 2014 0.5
 (0.3)(c)
 0.1
 0.1
Year Ended December 31, 2013 0.9
 (0.1)(c)
 0.3
 0.5

(a)Recoveries offset by reclasses to other assets and liabilities.
(b)Uncollectible accounts written off.
(c)Recoveries on previous reserve balance.

SWEPCo   Additions    
Description 
Balance at
Beginning
of Period
 
Charged to
Costs and
Expenses
 
Charged to Other
Accounts (a)
 Deductions (b) 
Balance at
End of
Period
  (in millions)
Deducted from Assets:  
  
  
  
  
Accumulated Provision for Uncollectible  
  
  
  
  
Accounts:          
Year Ended December 31, 2015 $0.5
 $0.3

$0.1
 $
 $0.9
Year Ended December 31, 2014 1.4
 0.5
 (1.4)(c)
 0.5
Year Ended December 31, 2013 2.0
 (0.1)(c)
 0.5
 1.4

(a)Recoveries offset by reclasses to other assets and liabilities.
(b)Uncollectible accounts written off.
(c)Recoveries on previous reserve balance.

S-11




EXHIBIT INDEX

The documents listed below are being filed or have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof.  Exhibits (“Ex”) not identified as previously filed are filed herewith.  Exhibits designated with a dagger (†) are management contracts or compensatory plans or arrangements required to be filed as an Exhibit to this Form.  Exhibits designated with an asterisk (*) are filed herewith.

Exhibit
Designation
 Nature of Exhibit Previously Filed as Exhibit to:
   
AEP‡   File No. 1-3525  
     
3(a) Composite of the Restated Certificate of Incorporation of AEP, dated April 28, 2009.23, 2015. 2009 Form 10-K,10-Q, Ex 3(a)3, June 30, 2015
     
3(b) Composite By-Laws of AEP, as amended as of September 25, 2012.October 20, 2015. Form 8-K, Ex 3.1 dated September 26, 2012October 21, 2015
     
4(a) Indenture (for unsecured debt securities), dated as of May 1, 2001, between AEP and The Bank of New York, as Trustee. 
Registration Statement No. 333-86050, Ex 4(a)(b)(c)
Registration Statement No. 333-105532, Ex 4(d)(e)(f)
Registration Statement No. 333-200956, Ex 4(b)
     
4(b)Company Order and Officer’s Certificate to The Bank of New York Mellon Trust Company, N.A. dated  December 3, 2012 establishing terms  1.65% Senior Notes, Series E, due 2017 and 2.95% Senior Notes, Series F, due 2022.Form 8-K, Ex. 4(a) dated December 3, 2012.
*4(c) $1.75 Billion Second Amended and Restated Credit Agreement, dated as of February 13, 2013, among AEP, the banks, financial institutions and other institutional lenders listed on the signature pages thereof, and JP Morgan Chase Bank, N.A., as Administrative Agent.
*4(d)$1.75 Billion Amended and Restated Credit Agreement, dated as of February 13, 2013,November 10, 2014, among AEP, the banks, financial institutions and other institutional lenders listed on the signature pages thereof, and Barclays Bank PLC, as Administrative Agent. 2014 Form 10-K, Ex 4(b)
     
*4(e)4(c) $11.75 Billion TermThird Amended and Restated Credit Agreement, dated as of February 13, 2013,November 10, 2014, among AEP, the banks, financial institutions and other institutional lenders listed on the signature pages thereof, and Wells FargoJPMorgan Chase Bank, National Association,N.A. as Administrative Agent. 
2014 Form 10-K, Ex 4(c)

     
10(a) InterconnectionTransmission Agreement, dated July 6, 1951,effective November 2010, among APCo, CSPCo, I&M, KGPCo, KPCo, OPCo and I&M andWPCo with AEPSC as amended.agent. 
Registration Statement No. 2-52910, Ex 5(a)
Registration Statement No. 2-61009, Ex 5(b)
19902013 Form 10-K, Ex 10(a)(3)
10(c)
     
10(b)Restated and Amended Operating Agreement, among PSO, SWEPCo and AEPSC, Issued on February 10, 2006, Effective May 1, 2006.Form 10-Q, Ex 10(b), March 31, 2006
E-1

Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
10(c)Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended.
1985 Form 10-K, Ex 10(b)
1988 Form 10-K, Ex 10(b)(2)
*10(d) Transmission Coordination Agreement dated January 1, 1997, restated and amended by and among PSO, SWEPCo and AEPSC. 2009 Form 10-K, Ex 10(d)
     
10(e)10(c) Amended and Restated Operating Agreement dated as of June 2, 1997, of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo. 2004 Form 10-K, Ex 10(e)(1)
     
10(e)10(c)(1) PJM West Reliability Assurance Agreement, dated as of March 14, 2001, among Load Serving Entities in the PJM West service area. 2004 Form 10-K, Ex 10(e)(2)
     
10(e)10(c)(2) Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo. 2004 Form 10-K, Ex 10(e)(3)
     
10(f)10(d) Lease Agreements, dated as of December 1, 1989, between AEGCo or I&M and Wilmington Trust Company, as amended. 
Registration Statement No. 33-32752, Ex 28(c)(1-6)(C)
Registration Statement No. 33-32753, Ex 28(a)(1-6)(C)
AEGCo 1993 Form 10-K, Ex 10(c)(1-6)(B)
I&M 1993 Form 10-K, Ex 10(e)(1-6)(B)
     
10(g)Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.1996 Form 10-K, Ex 10(l)
10(h)10(e) Consent Decree with U.S. District Court dated October 9, 2007.2007, as modified. 
Form 8-K, Ex 10.1 dated October 9, 2007
Form 10-Q, Ex 10, June 30, 2013
     
10(i)10(f) AEP Accident Coverage Insurance Plan for Directors. 1985 Form 10-K, Ex 10(g)

E-1



Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
     
10(j)10(g) AEP Retainer Deferral Plan for Non-Employee Directors, effective January 1, 2005, as amended February 9, 2007. 2007 Form 10-K, Ex 10(j)(i)
     
10(k)10(h)
 
 
Amended and Restated AEP Stock Unit Accumulation Plan for Non-Employee Directors effective January 1, 2013.
 Form 10-Q, Ex 10, March 31, 2012
10(l)10(i) AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2008. 2008 Form 10-K, Ex 10(l)(1)(A)
     
10(l)10(i)(1) Guaranty by AEP of AEPSC Excess Benefits Plan. 1990 Form 10-K, Ex 10(h)(1)(B)
     
10(l)(2)10(j) AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2011 (Non-Qualified). 2010 Form 10-K, Ex 10(l)(2)
     
10(l)(3)10(j)(1)(A)Amendment to AEP System Supplemental Retirement Savings Plan, as Amended and Restated as of January 1, 2011 (Non-Qualified).2014 Form 10-K, Ex †10(l)(1)(A)
†10(k) AEPSC Umbrella Trust for Executives. 1993 Form 10-K, Ex 10(g)(3)
E-2

Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
     
10(l)(3)10(k)(1)(A) First Amendment to AEPSC Umbrella Trust for Executives. 
2008 Form 10-K, Ex10(l)(3)(A)
     
10(m)10(l) Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers. 2002 Form 10-K, Ex 10(m)(4)
     
10(m)10(l)(1)(A) Amendment to Employment Agreement dated December 9, 2008 between AEPSC and Robert P. Powers. 2008 Form 10-K, Ex 10(m)(4)(A)
     
10(n)10(m)
 
 
 AEP System Senior Officer Annual Incentive Compensation Plan amended and restated as of February 26, 2013.28, 2012. 
Form 10-Q, Ex 10, June 30, 2012
 
 
     
10(o)10(n) AEP System Survivor Benefit Plan, effective January 27, 1998. Form 10-Q, Ex 10, September 30, 1998
     
10(o)10(n)(1)(A) First Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 31, 2000. 2002 Form 10-K, Ex 10(o)(2)
     
10(o)10(n)(2)(A) Second Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 1, 2008. 2008 Form 10-K, Ex 10(o)(1)(B)
     
10(p)10(o) AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008. 2008 Form 10-K, Ex 10(p)
     
10(p)10(o)(1)(A) First Amendment to AEP System Incentive Compensation Deferral Plan as Amended and Restated as of January 1, 2008. 2011 Form 10-K, Ex 10(p)(1)(A)
     
*10(q)10(o)(2)(A) Second Amendment to AEP System Nuclear Performance Long Term Incentive Compensation Deferral Plan dated August 1, 1998.2002 Form 10-K, Ex 10(r)
†10(r)Nuclear Key Contributor Retention Planas Amended and Restated as of January 1, 2008. 20082014 Form 10-K, Ex 10(r)
†10(r)(1)(A)First Amendment to Nuclear Key Contributor Retention Plan Amended and Restated as of January 1, 2008.2011 Form 10-K, Ex 10(r)(1)†10(q)(2)(A)
     
*†10(s)10(p) AEP Change In Control Agreement, effectiveas Revised Effective January 1, 2013.2015. 2014 Form 10-K, Ex †10(r)
     
10(t)10(q) Amended and Restated AEP System Long-Term Incentive Plan as of September 25, 2012. Form 10-Q, Ex 10, September 30, 20102012

E-2



Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
†10(q)(1)AEP System 2015 Long-Term Incentive Plan as of April 21, 2015.Form 10-Q, Ex 10, March 30, 2015
     
10(t)10(q)(1)(A) Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended. 2011 Form 10-K, Ex 10(t)(1)(A)
     
*10(t)10(q)(2)(A) Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan Amended and Restated effective January 1, 2013. 2012 Form 10-K, Ex 10 (t)(2)(A)
E-3

Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
     
10(u)10(t) AEP System Stock Ownership Requirement Plan Amended and Restated effective January 1, 2010.2014. 2010 Form 10-K,10-Q, Ex 10(u)10, June 30, 2014
     
10(u)10(t)(1)(A) First Amendment to AEP System Stock Ownership Requirement Plan as Amended and Restated effective January 1, 2010.2014. 2011
2014 Form 10-K, Ex 10(u)†10(t)(1)(A)

     
10(v)10(u) Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2009. 2008 Form 10-K, Ex 10(v)
*†10(v)AEP Executive Severance Plan Amended and Restated effective January 25, 2016.
†10(w)Letter Agreement dated November 20, 2012 between AEPSC and Lana Hillebrand2013 Form 10-K, Ex 10(s)
     
*12 Statement re: Computation of Ratios.  
     
*13 Copy of those portions of the AEP 20122015 Annual Report (for the fiscal year ended December 31, 2012)2015) which are incorporated by reference in this filing.  
     
*21 List of subsidiaries of AEP.  
     
*23 Consent of Deloitte & Touche LLP.  
     
*24 Power of Attorney.  
     
*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.  
     
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.
  

E-3



E-4

Exhibit
Designation
 Nature of Exhibit Previously Filed as Exhibit to:
APCo‡   File No. 1-3457  
2(a)Agreement and Plan of Merger dated as of December 31, 2013 by and between Newco Appalachian Inc. and Appalachian Power Company.Form 8-K, Ex 2.1 dated December 31, 2013
     
3(a) Composite of the Restated Articles of Incorporation of APCo, amended as of March 7, 1997. 1996 Form 10-K, Ex 3(d)
     
3(b) 
Composite By-Laws of APCo, amended as of February 26, 2008.
 2007 Form 10-K, Ex 3(b)
     
4(a) 
Indenture (for unsecured debt securities), dated as of January 1, 1998, between APCo and The Bank of New York, As Trustee.
 
Registration Statement No. 333-45927, Ex 4(a)(b)
Registration Statement No. 333-49071, Ex 4(b)
Registration Statement No. 333-84061, Ex 4(b)(c)
Registration Statement No. 333-100451, Ex 4(b)(c)(d)
Registration Statement No. 333-116284, Ex 4(b)(c)
Registration Statement No. 333-123348, Ex 4(b)(c)
Registration Statement No. 333-136432, Ex 4(b)(c)(d)
Registration Statement No. 333-161940, Ex 4(b)(c)(d)
Registration Statement No. 333-182336, Ex 4(b)(c)
Registration Statement No. 333-200750, Ex. 4(b)(c)
     
4(b)
 Company Order and Officer’sOfficers Certificate to The Bank of New York Mellon Trust Company, N.A., dated August 16, 2012May 18, 2015 establishing terms of Floating Rate3.400% Senior Notes, Series V, due 2013.2025 and 4.450% Senior Notes, Series W, due 2045. Form 8-K, Ex 4(a) dated August 16, 2012May 18, 2015
     
10(a)Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended.
Registration Statement No. 2-60015, Ex 5(a)
Registration Statement No. 2-63234, Ex 5(a)(1)(B) Registration Statement No 2-66301, Ex 5(a)(1)(C) Registration Statement No. 2-67728, Ex 5(a)(1)(D)
1989 Form 10-K, Ex 10(a)(1)(F)
1992 Form 10-K, Ex 10(a)(1)(B)
10(a)(1) Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended March 13, 2006.September 10, 2010. 20052013 Form 10-K, Ex 10(a)(2)
10(a)(2)Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended.Registration Statement No. 2-60015, Ex 5(e)
     
10(b) InterconnectionTransmission Agreement, dated July 6, 1951,effective November 2010, among APCo, CSPCo, I&M, KGPCo, KPCo, OPCo and I&M andWPCo with AEPSC as amended.agent. 
Registration Statement No. 2-52910, Ex 5(a)
Registration Statement No. 2-61009, Ex 5(b)
19902013 Form 10-K, Ex 10(a)(3), File No. 1-3525
10(c)
     
10(c)Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended.
1985 Form 10-K, Ex 10(b)
1988 Form 10-K, Ex 10(b)(2)
10(d) Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo. 2004 Form 10-K, Ex 10(d)(1)
     
10(d)10(c)(1) PJM West Reliability Assurance Agreement among Load Serving Entities in the PJM West service area. 2004 Form 10-K, Ex 10(d)(2)
E-5

Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
     
10(d)10(c)(2) Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo. 2004 Form 10-K, Ex 10(d)(3)
     
10(e)Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.1996 Form 10-K, Ex 10(l), File No. 1-3525
10(f)10(d) Consent Decree with U.S. District Court.Court, as modified. 
Form 8-K, Ex 10.1 dated October 9, 2007
Form 10-Q, Ex 10, June 30, 2013
     
*12 Statement re: Computation of Ratios.  
     
*13 Copy of those portions of the APCo 20122015 Annual Report (for the fiscal year ended December 31, 2012)2015) which are incorporated by reference in this filing.  
     
*23 Consent of Deloitte & Touche LLP.  
     
*24 Power of Attorney.  
     
*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.

E-4



Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
  
     
*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.  
     
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.  
   
I&M‡   File No. 1-3570  
     
3(a) Composite of the Amended Articles of Acceptance of I&M, dated of March 7, 1997. 1996 Form 10-K, Ex 3(c)
E-6

Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
     
3(b) Composite By-Laws of I&M, amended as of February 26, 2008. 2007 Form 10-K, Ex 3(b)
     
4(a) Indenture (for unsecured debt securities), dated as of October 1, 1998, between I&M and The Bank of New York, as Trustee. 
Registration Statement No. 333-88523, Ex 4(a)(b)(c)
Registration Statement No. 333-58656, Ex 4(b)(c)
Registration Statement No. 333-108975, Ex 4(b)(c)(d)
Registration Statement No. 333-136538, Ex 4(b)(c)
Registration Statement No. 333-156182, Ex 4(b)
Registration Statement No. 333-185087, Ex 4(b)
10(a)Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended.
Registration Statement No. 2-60015,333-207836, Ex 5(a)
Registration Statement No. 2-63234, Ex 5(a)(1)(B)
Registration Statement No. 2-66301, Ex 5(a)(1)(C)
Registration Statement No. 2-67728, Ex 5(a)(1)(D)
APCo 1989 Form 10-K, Ex 10(a)(1)(F), File No. 1-3457
APCo 1992 Form 10-K, Ex 10(a)(1)(B), File No. 1-34574(b)
     
10(a)(1) Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended March 13, 2006.September 10, 2010. 20052013 Form 10-K, Ex 10(a)(2)
10(a)(2)Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended.Registration Statement No. 2-60015, Ex 5(e)
10(a)(3)Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended.
Registration Statement No. 2-60015, Ex 5(c)
Registration Statement No. 2-67728, Ex 5(a)(3)(B)
APCo 1992 Form 10-K, Ex 10(a)(2)(B), File No. 1-3457
     
10(b)Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, I&M, and OPCo and with AEPSC, as amended.
Registration Statement No. 2-52910, Ex 5(a)
Registration Statement No. 2-61009, Ex 5(b)
1990 Form 10-K, Ex 10(a)(3), File No. 1-3525
10(b)(1) Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended. 
Registration Statement No. 33-32752,
Ex 28(b)(1)(A)(B)
     
10(c) Transmission Agreement, dated April 1, 1984,effective November 2010, among APCo, CSPCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent, as amended.agent. 
19852013 Form 10-K, Ex 10(b), File No. 1-3525
1988 Form 10-K, File No. 1-3525, Ex 10(b)(2)
10(c)
     
10(d) Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo. 2004 Form 10-K, Ex 10(d)(1)
     
10(d)(1) PJM West Reliability Assurance Agreement among Load Serving Entities in the PJM West service area. 2004 Form 10-K, Ex 10(d)(2)
     
10(d)(2) Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo. 2004 Form 10-K, Ex 10(d)(3)
E-7

Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
     
10(e) Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.Consent Decree with U.S. District Court, as modified. 1996
Form 10-K,8-K, Ex 10(l), File No. 1-352510.1 dated October 9, 2007
Form 10-Q, Ex 10, June 30, 2013
     
10(f)Consent Decree with U.S. District Court.Form 8-K, Ex 10.1 dated October 9, 2007
10(g) Lease Agreements, dated as of December 1, 1989, between I&M and Wilmington Trust Company, as amended. 
Registration Statement No. 33-32753, Ex 28(a)(1-6)(C)
1993 Form 10-K, Ex 10(e)(1-6)(B)
     
*12 Statement re: Computation of Ratios.  
     

E-5



Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
*13 Copy of those portions of the I&M 20122015 Annual Report (for the fiscal year ended December 31, 2012)2015) which are incorporated by reference in this filing.  
     
*23 Consent of Deloitte & Touche LLP.  
     
*24 Power of Attorney.  
     
*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.  
     
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.  
   
OPCo‡   File No.1-6543  
     
3(a)2(a) CompositeAsset Contribution Agreement effective as of the Amended Articles of Incorporation of OPCo, dated June 3, 2002.December 31, 2013 by and between Ohio Power Company and AEP Generation Resources Inc. Form 10-Q,8-K, Ex 3(e), June 30, 2002
E-8

Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
3(b)Amended Code of Regulations of OPCo.Form 10-Q, Ex 3(b), June 30, 20082.1 dated December 31, 2013
     
3(c)2(b) Agreement and Plan of Merger of Ohio Power Company and Columbus Southern Power Company entered into as of December 31, 2012. Form 8-K, Ex 2.1 dated January 6, 2012
3(a)Composite of the Amended Articles of Incorporation of OPCo, dated June 3, 2002.Form 10-Q, Ex 3(e), June 30, 2002
3(b)Amended Code of Regulations of OPCo.Form 10-Q, Ex 3(b), June 30, 2008
     
4(a) Indenture (for unsecured debt securities), dated as of September 1, 1997, between OPCo and Bankers Trust Company (now Deutsche Bank Trust Company Americas), as Trustee. 
Registration Statement No. 333-49595, Ex 4(a)(b)(c)
Registration Statement No. 333-106242, Ex 4(b)(c)(d)
Registration Statement No. 333-75783, Ex 4(b)(c)
Registration Statement No. 333-127913, Ex 4(b)(c)
Registration Statement No. 333-139802, Ex 4(a)(b)(c)
Registration Statement No. 333-139802, Ex 4(b)(c)(d)
Registration Statement No. 333-161537, Ex 4(b)(c)(d)
     
4(b) Company Order and Officer’s Certificate to Deutsche Bank Trust Company Americas, dated September 24, 2009, establishing terms of 5.375% Senior Notes, Series M due 2021. Form 8-K, Ex 4(a) dated September 24, 2009
     
4(c) Indenture (for unsecured debt securities), dated as of February 1, 2003, between OPCo and Bank One, N.A., as Trustee. Registration Statement No. 333-127913, Ex 4(d)(e)(f)
  

E-6



Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
   
4(d) Indenture (for unsecured debt securities), dated as of September 1, 1997, between CSPCo (predecessor in interest to OPCo) and Bankers Trust Company, as Trustee. 
Registration Statement No. 333-54025, Ex 4(a)(b)(c)(d)
Registration Statement No. 333-128174, Ex 4(b)(c)(d)
Registration Statement No. 333-150603. Ex 4(b)
     
4(e) Indenture (for unsecured debt securities), dated as of February 1, 2003, between CSPCo (predecessor in interest to OPCo) and Bank One, N.A., as Trustee. 
Registration Statement No. 333-128174, Ex 4(e)(f)(g)
Registration Statement No. 333-150603 Ex 4(b)
     
4(f) First Supplemental Indenture, dated as of December 31, 2012,2011, by and between OPCo and Deutsche Bank Trust Company Americas, as trustee, supplementing the Indenture dated as of September 1, 1997 between CSPCo (predecessor in interest to OPCo) and the trustee. Form 8-K, Ex 4.1 dated January 6, 2012
     
4(g) Third Supplemental Indenture, dated as of December 31, 2012,2011, by and between OPCo and The Bank of New York Mellon Trust Company, N.A., as trustee, supplementing the Indenture dated as of February 14, 2003 between CSPCo (predecessor in interest to OPCo) and the trustee. Form 8-K, Ex 4.2 dated January 6, 2012
     
4(h) CSPCo (predecessor in interest to OPCo) Company Order and Officer’s Certificate to Deutsche Bank Trust Company Americas, dated May 16, 2008, establishing terms of 6.05% Senior Notes, Series G, due 2018. Form 8-K, Ex 4(a), dated May 16, 2008
E-9

Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
10(a)Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended.
Registration Statement No. 2-60015, Ex 5(a)
Registration Statement No. 2-63234, Ex 5(a)(1)(B)
Registration Statement No. 2-66301, Ex 5(a)(1)(C)
Registration Statement No. 2-67728, Ex 5(a)(1)(B)
APCo 1989 Form 10-K, Ex 10(a)(1)(F), File No. 1-3457
APCo 1992 Form 10-K, Ex 10(a)(1)(B), File No.1-3457
     
10(a)(1)
 
 Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended March 13, 2006.September 10, 2010. 20052013 Form 10-K, Ex 10(a)(2)
10(a)(2)Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended.Registration Statement No. 2-60015, Ex 5(e)
     
10(b) InterconnectionTransmission Agreement, dated July 6, 1951,effective November 2010, among APCo, CSPCo, KPCo, I&M, andKGPCo, KPCo, OPCo and WPCo with AEPSC as amended.agent. 
Registration Statement No. 2-52910, Ex 5(a)
Registration Statement No. 2-61009, Ex 5(b)
19902013 Form 10-K, Ex 10(a)(3), File 1-3525
     
10(c)Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent.
1985 Form 10-K, Ex 10(b), File No. 1-3525
1988 Form 10-K, Ex 10(b)(2), File No. 1-3525
10(d)Unit Power Agreement, dated March 15, 2007 between AEGCo and CSPCo (predecessor in interest to OPCo).2007 Form 10-K, Ex 10(b)(2)
10(e) Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo. 2004 Form 10-K, Ex 10(d)(1)
     
10(f)10(d) PJM West Reliability Assurance Agreement among Load Serving Entities in the PJM West service area. 2004 Form 10-K, Ex 10(d)(2)
     
10(g)10(e) Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo. 2004 Form 10-K, Ex 10(d)(3)
     
10(h)Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.1996 Form 10-K, Ex 10(l), File No. 1-3525
10(i)10(f) Consent Decree with U.S. District Court.Court, as modified. 
Form 8-K, Item Ex 10.1 dated October 9, 2007
10(i)(1)Amendment No. 9, dated July 1, 2003, to Station Agreement dated January 1, 1968, among OPCo, Buckeye and Cardinal Operating Company, and amendments thereto.
Form 10-Q, Ex 10(a), September10, June 30, 2004
10(j)Amendment No. 1, dated October 1, 1973, to Station Agreement dated January 1, 1968, among OPCo, Buckeye and Cardinal Operating Company, and amendments thereto.
1993 Form 10-K, Ex 10(f)
2003 Form 10-K, Ex 10(e)2013
E-10

Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
     
*12 Statement re: Computation of Ratios.  
     
*13 Copy of those portions of the OPCo 20122015 Annual Report (for the fiscal year ended December 31, 2012)2015) which are incorporated by reference in this filing.
*23Consent of Deloitte & Touche LLP.  
     
*24 Power of Attorney.  
     
*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.  
  

E-7



Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
   
*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 Disclosure.  
     
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.  
   
PSO‡   File No. 0-343  
     
3(a) Certificate of Amendment to Restated Certificate of Incorporation of PSO. Form 10-Q, Ex 3(a), June 30, 2008
     
3(b) Composite By-Laws of PSO amended as of February 26, 2008. 2007 Form 10-K, Ex 3 (b)
     
4(a) 
Indenture (for unsecured debt securities), dated as of November 1, 2000, between PSO and The Bank of New York, as Trustee.
 
 
Registration Statement No. 333-100623, Ex 4(a)(b)
Registration Statement No. 333-114665, Ex 4(b)(c)
Registration Statement No. 333-133548, Ex 4(b)(c)
Registration Statement No. 333-156319, Ex 4(b)(c)
E-11

Exhibit
Designation
 Nature of Exhibit Previously Filed as Exhibit to:
4(b) Eighth Supplemental Indenture, dated as of November 13, 2009 between PSO and The Bank of New York Mellon, as Trustee, establishing terms of the 5.15% Senior Notes, Series H, due 2019. Form 8-K, Ex 4(a), dated November 13, 2009
     
4(c) Ninth Supplemental Indenture, dated as of January 19, 2011 between PSO and The Bank of New York Mellon Trust Company, N.A., as Trustee, establishing terms of 4.40% Senior Notes, Series I, due 2021. Form 8-K, Ex 4(a) dated January 20, 2011
     
10(a) Restated and Amended Operating Agreement, among PSO, SWEPCo and AEPSC, Issued on February 10, 2006, Effective May 1, 2006.Form 10-Q, Ex 10(a), March 31, 2006
*10(b)Third Restated and Amended Transmission Coordination Agreement Between PSO, SWEPCo and AEPSC dated February 18, 2011. 2012 Form 10-K, Ex 10(b)
     
*12 Statement re: Computation of Ratios.  
     
*13 Copy of those portions of the PSO 20122015 Annual Report (for the fiscal year ended December 31, 2012)2015) which are incorporated by reference in this filing.  
     
*2324 ConsentPower of Deloitte & Touche LLP.Attorney.
*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.

E-8



Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
*32(b)Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
101.INSXBRL Instance Document.
101.SCHXBRL Taxonomy Extension Schema.
101.CALXBRL Taxonomy Extension Calculation Linkbase.
101.DEFXBRL Taxonomy Extension Definition Linkbase.
101.LABXBRL Taxonomy Extension Label Linkbase.
101.PREXBRL Taxonomy Extension Presentation Linkbase.
SWEPCo‡   File No. 1-3146
3(a)Composite of Amended Restated Certificate of Incorporation of SWEPCo.2008 Form 10-K, Ex 3(a)
3(b)Composite By-Laws of SWEPCo amended as of February 26, 2008.2007 Form 10-K, Ex 3(b)
4(a)Indenture (for unsecured debt securities), dated as of February 4, 2000, between SWEPCo and The Bank of New York, as Trustee.
Registration Statement No. 333-96213
Registration Statement No. 333-87834, Ex 4(a)(b)
Registration Statement No. 333-100632, Ex 4(b)
Registration Statement No. 333-108045, Ex 4(b)
Registration Statement No. 333-145669, Ex 4(c)(d)
Registration Statement No. 333-161539, Ex 4(b)(c)
Registration Statement No. 333-194991, Ex 4(b)(c)
Registration Statement No. 333-208535, Ex 4(b)(c)
10(a)Third Restated and Amended Transmission Coordination Agreement Between PSO, SWEPCo and AEPSC dated February 18, 2011.2012 Form 10-K, Ex 10(b)
*12Statement re: Computation of Ratios.
*13Copy of those portions of the SWEPCo 2015 Annual Report (for the fiscal year ended December 31, 2015) which are incorporated by reference in this filing.  
     
*24 Power of Attorney.  
     
*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.  
     
101.INSXBRL Instance Document.
101.SCHXBRL Taxonomy Extension Schema.
101.CALXBRL Taxonomy Extension Calculation Linkbase.
101.DEFXBRL Taxonomy Extension Definition Linkbase.
101.LABXBRL Taxonomy Extension Label Linkbase.
E-12

Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
101.PREXBRL Taxonomy Extension Presentation Linkbase.
SWEPCo‡   File No. 1-3146
3(a)Composite of Amended Restated Certificate of Incorporation of SWEPCo.2008 Form 10-K, Ex 3(a)
3(b)Composite By-Laws of SWEPCo amended as of February 26, 2008.2007 Form 10-K, Ex 3(b)
4(a)
Indenture (for unsecured debt securities), dated as of February 4, 2000, between SWEPCo and The Bank of New York, as Trustee.
Registration Statement No. 333-96213
Registration Statement No. 333-87834, Ex 4(a)(b)
Registration Statement No. 333-100632, Ex 4(b)
Registration Statement No. 333-108045, Ex 4(b)
Registration Statement No. 333-145669, Ex 4(c)(d)
Registration Statement No. 333-161539, Ex 4(b)(c)
4(b)Eighth Supplemental Indenture dated as of March 1, 2010 between SWEPCo and The Bank of New York Mellon establishing terms of 6.20% Senior Notes, Series H, due 2040.Form 8-K, Ex 4(a), dated March 8, 2010
4(c)Ninth Supplemental Indenture dated as of February 1, 2012 between SWEPCo and The Bank of New York Mellon Trust Company, N.A. establishing terms of 3.55% Senior Notes, Series I, due 2022.Form 8-K, Ex 4(a), dated February 3, 2012
10(a)Restated and Amended Operating Agreement, among PSO, TCC, TNC, SWEPCo and AEPSC, Issued on February 10, 2006, Effective May 1, 2006.Form 10-Q, Ex 10(a), March 31, 2006
*10(b)Third Restated and Amended Transmission Coordination Agreement Between PSO, SWEPCo and AEPSC dated February 18, 2011.
*12Statement re: Computation of Ratios.
*13Copy of those portions of the SWEPCo 2012 Annual Report (for the fiscal year ended December 31, 2012) which are incorporated by reference in this filing.
*23Consent of Deloitte & Touche LLP.
*24Power of Attorney.
*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.
E-13

Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
*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 Disclosure.  
     
101.INS XBRL Instance Document.  
     
101.SCH XBRL Taxonomy Extension Schema.  
     
101.CAL XBRL Taxonomy Extension Calculation Linkbase.  
     

E-9



Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
101.DEF XBRL Taxonomy Extension Definition Linkbase.  
     
101.LAB XBRL Taxonomy Extension Label Linkbase.  
     
101.PRE XBRL Taxonomy Extension Presentation Linkbase.  

‡ Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants.  The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request.
‡ Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants.  The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request.




E-10
E-14