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, 20132015

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 filer
T
x		Accelerated filero
Non-accelerated filer
o (Do not check if a smaller reporting company)
Smaller reporting companyo
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
Non-accelerated filer
xT (Do not check if a smaller reporting company)
Smaller reporting companyo
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, 2013, 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, 2013
 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. $21,842,670,718 487,777,372 $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, 2013:
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 20142016 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
TABLE OF CONTENTS
Item   Page
Number   Number
Item
Number
 
Page
Number
Glossary of Terms
i
Glossary of Termsi
Forward-Looking Information
iii
Forward-Looking Informationiii 
PART IPART I
PART I
1Business  
Business
 
 General 1
General
1
 Business Segments14
Business Segments
14
 Vertically Integrated Utilities14
Vertically Integrated Utilities
15
 Transmission and Distribution Utilities23
Transmission and Distribution Utilities
23
 Generation & Marketing24AEP Transmission Holdco
24
 AEP Transmission Holdco27Generation & Marketing
28
 AEP River Operations30
AEP River Operations
31
 Executive Officers of AEP31
Executive Officers of AEP
32
1ARisk Factors 32
Risk Factors
33
1BUnresolved Staff Comments45
Unresolved Staff Comments
43
2Properties 45
Properties
43
 Generation Facilities45
Generation Facilities
43
 Transmission and Distribution Facilities48
Transmission and Distribution Facilities
46
 Title to Property48
Title to Property
47
 System Transmission Lines and Facility Siting49
System Transmission Lines and Facility Siting
47
 Construction Program49
Construction Program
47
�� Potential Uninsured Losses49
Potential Uninsured Losses
48
3Legal Proceedings49
Legal Proceedings
48
4Mine Safety Disclosure49
Mine Safety Disclosure
48
     
PART II
5Market for Registrants’ Common Equity, Related Stockholder Matters Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
49
    and Issuer Purchases of Equity Securities50
6Selected Financial Data50
Selected Financial Data
49
7Management’s Discussion and Analysis of Financial Condition and Management’s Discussion and Analysis of Financial Condition and Results of Operations
49
    Results of Operations50
7AQuantitative and Qualitative Disclosures about Market Risk50
Quantitative and Qualitative Disclosures about Market Risk
50
8Financial Statements and Supplementary Data51
Financial Statements and Supplementary Data
50
9Changes In and Disagreements with Accountants on Accounting 
Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
50
    and Financial Disclosure51
9AControls and Procedures51Controls and Procedures
50
9BOther Information51Other Information
50
     
PART III
PART III 
10Directors, Executive Officers and Corporate Governance52Directors, Executive Officers and Corporate Governance
51
11Executive Compensation52Executive Compensation
51
12Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters53
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
52
13Certain Relationships and Related Transactions and Director Independence53
Certain Relationships and Related Transactions and Director Independence
52
14Principal Accounting Fees and Services53
Principal Accounting Fees and Services
53
    
PART IVPART IV
PART IV
15Exhibits and Financial Statement Schedules55
Exhibits and Financial Statement Schedules
54
Financial Statements55
Financial Statements
54
Signatures 56
Signatures
55
Index of Financial Statement SchedulesS-1
Index of Financial Statement Schedules
S-1
Reports of Independent Registered Public Accounting FirmS-2
Reports of Independent Registered Public Accounting Firm
S-2
Exhibit Index E-1
Exhibit Index
E-1



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 Utilities AEP Utilities, Inc., a subsidiary of AEP, formerly, Central and South West Corporation.
AEP West CompaniesPSO, SWEPCo,a holding company for TCC, TNC and TNC.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, is an intermediate holding company that owns seven wholly-owned transmission companies.
AEPTHCo AEP Transmission Holding Company, LLC, a subsidiary of AEP, is an intermediate holding company that owns our transmission operations joint ventures and AEPTCo.
AFUDC Allowance for Funds Used During Construction.
AGR AEP Generation Resources Inc,Inc., a nonregulated AEP subsidiary that acquiredin the generation assets and liabilities of OPCo.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.
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.
Federal EPA United States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
I&M Indiana Michigan Power Company, an AEP electric utility subsidiary.
Interconnection AgreementIMTCo An agreement by and among APCo, I&M, KPCo and OPCo, that defined the sharing of costs and benefits associated with their respective generation plants.  This agreement was terminated January 1, 2014.AEP Indiana Michigan Transmission Company, Inc.
IURC Indiana Utility Regulatory Commission.
KGPCo Kingsport Power Company, an AEP electric utility subsidiary.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
kV Kilovolt.
LPSCLouisiana Public Service Commission.
i
MISO Midwest Independent Transmission System Operator.
MMBtu Million British Thermal Units.
MPSCMichigan Public Service Commission.
MW Megawatt.
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.
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.
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 generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.  AEGCo and I&M jointly-own Unit 1.  In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
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, effective November 2010, among APCo, CSPCo, I&M, KGPCo, KPCo, OPCo and WPCo 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 generation capacity and the performance of our generation plants.
·ŸOurThe ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·ŸOurThe ability to build or acquire generation 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, cost recovery and/or profitability of our generation 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 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 generation 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.gas and capacity auction returns.
iii
·ŸChanges in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP.
·ŸThe transition to market for generation in Ohio includingand PJM and the implementation of ESPs.ability to recover investments in Ohio generation assets.
·ŸOurThe ability to successfully and profitably manage our Ohiocompetitive generation assets, including the evaluation of strategic alternatives for these assets as some of the alternatives could result in a startup, nonregulated merchant business.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.
·Ÿ
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

The forward 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 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 laws in Michigan, Ohio and the ERCOT area of Texas have caused AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers.  In Ohio, AEP’s regulated utility recently separated its generation assets fromoperates its distribution and transmission assets.assets while its former generation assets are owned and operated by affiliates.

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, 2013,2015, the subsidiaries of AEP had a total of 18,52117,405 employees. Because it is a holding company rather than an operating company, AEP has no employees. The material 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 7,8856,650 MW of generating capacity, including 867 MW which acquired it from OPCo in a year-end transaction.capacity.  APCo uses its generation to serve its retail and other customers.  As of December 31, 2013,2015, APCo had 1,9671,836 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 utility businessVertically 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 587,000588,000 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 4,5183,523 MW of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2013,2015, I&M had 2,5822,489 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
1
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 utility businessVertically Integrated Utilities segment.


1


KPCo

Organized in Kentucky in 1919, KPCo is engaged in the generation, transmission and distribution of electric power to approximately 172,000170,000 retail customers in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants.  KPCo owns 1,8581,058 MW of generating capacity, including 780 MW which acquired it from OPCo in a year-end transaction.capacity.  KPCo uses its generation to serve its retail and other customers.  As of December 31, 2013,2015, KPCo had 642558 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 utility businessVertically 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, 2013,2015, KGPCo had 5752 employees. KGPCo is part of AEP’s vertically integrated utility businessVertically Integrated Utilities segment.

OPCo

Organized in Ohio in 1907 and re-incorporated in 1924, OPCo is engaged in the transmission and distribution of electric power to approximately 1,464,0001,468,000 retail customers in Ohio.  Following corporate separation of OPCo’s generation assets in December 2013, OPCo purchases energy and capacity to serve remaining generation service customers.  Effective December 31, 2013, OPCo transferred all of its generation assets at net book value to AGR, a newly formed competitive generation affiliate.  As of December 31, 2013,2015, OPCo had 1,5421,552 employees.  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 transmissionTransmission and distribution utility businessDistribution Utilities segment.

PSO

Organized in Oklahoma in 1913, PSO is engaged in the generation, transmission and distribution of electric power to approximately 540,000545,000 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 4,4274,432 MW of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2013,2015, PSO had 1,1481,134 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 utility businessVertically Integrated Utilities segment.

SWEPCo

Organized in Delaware in 1912, SWEPCo is engaged in the generation, transmission and distribution of electric power to approximately 526,000531,000 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 5,7245,798 MW of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2013,2015, SWEPCo had 1,449
2
1,483 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 utility businessVertically Integrated Utilities segment.

TCC

Organized in Texas in 1945, TCC is engaged in the transmission and distribution of electric power to approximately 806,000826,000 retail customers through REPs in southern Texas. TCC sold all of its generation assets. As of December 31, 2013,2015, TCC had 1,0211,085 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 transmissionTransmission and distribution utility businessDistribution Utilities segment.


2


TNC

Organized in Texas in 1927, TNC is engaged in the transmission and distribution of electric power to approximately 188,000189,000 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, 2013,2015, TNC had 312346 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 transmissionTransmission and distribution utility businessDistribution 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 AGR for distribution to its customers. As of December 31, 2013,2015, WPCo had 4756 employees.  WPCo is part of AEP’s vertically integrated utility businessVertically 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 AGR, I&M and KPCo. AEGCo has granted 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, 2013,2015, AEGCo had 7973 employees.  AEGCo is part of AEP’s vertically integrated utility businessVertically Integrated Utilities segment.

AGR

Organized in Delaware in 2011, AGR is a nonregulated AEP subsidiary that acquired OPCo’s generation assets and liabilities at net book value as of December 31, 2013.  AGR is a competitive generation company that generates power thatand sells it sells into the market.  AGR also engages in power trading activities.  Pursuant to a Power Supply Agreement (PSA) between AGR and OPCo, AGR suppliessupplied capacity for OPCo’s switched and non-switched retail load for the period January 1, 2014 through May 31, 2015.  AGR also supplies the energy needs of OPCo’s non-switched retail load that is not acquired through auctions from January 1, 2014 through December 31, 2014 under the PSA.  AGR owns 10,0026,752 MW of generating capacity, with rights to an additional 1,186 MW pursuant to a unit power agreement with AEGCo.AEGCo through 2017. As of December 31, 2013,2015, AGR had 929857 employees.  AGR is part of AEP’s Generation & Marketing business segment.

3

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 ourAEP’s existing utility operating companies. The transmission companies develop and own new transmission assets that are physically connected to AEP’s system.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. ApplicationsThe application for transmission companies are pending withregulatory approval to operate in Louisiana is under consideration, while the applicable commissionsapplication for regulatory approval to operate in Arkansas and Louisiana.was denied. Neither AEPTCo nor the transmission companiesits subsidiaries have any employees. Instead, AEPSC and certain of ourAEP utility subsidiaries provide the services required by these entities. AEPTCo is part of the AEP Transmission Holdco business segment.


3


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, 2013,2015, AEPSC had 5,3925,622 employees.

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) AEP Utility Subsidiaries Operating in that Jurisdiction Authorized Return on Equity (b) Percentage of AEP System Retail Revenues (a) AEP Utility Subsidiaries Operating in that Jurisdiction Authorized Return on Equity (b)
      
Ohio 26% OPCo 10.2% (c) 24% OPCo 10.20%
       
Texas 14% TCC 9.96% 14% TCC 9.96%
 TNC 9.96% TNC 9.96%
 SWEPCo 9.65% SWEPCo 9.65%
       
Virginia 12% APCo 9.70%
 
West Virginia 12% APCo 10.00% 12% APCo 9.75%
 WPCo 10.00% WPCo 9.75%
      
Virginia 13% APCo 10.90%
       
Oklahoma 10% PSO 10.15% 11% PSO 9.85%
       
Indiana 10% I&M 10.20% 11% I&M 10.20%
       
Louisiana 5% SWEPCo 10.00% 5% SWEPCo 10.00%
       
Kentucky 5% KPCo 10.50% 5% KPCo 10.25%
       
Arkansas 2% SWEPCo 10.25% 3% SWEPCo 10.25%
       
Michigan 2% I&M 10.20% 2% I&M 10.20%
       
Tennessee 1% KGPCo 12.00% 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, 2013.2015.
(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.
(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.

4




4


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 years ended December 31, 2013, 20122015, 2014 and 20112013 are as follows:

   Years Ended December 31, Years Ended December 31,
DescriptionDescription 2013  2012  2011  2015 2014 2013
 (in millions) (in millions)
Vertically Integrated Utilities SegmentVertically Integrated Utilities Segment            
Retail Revenues      
 Residential Sales $ 3,216  $ 2,993  $ 3,061 
 Commercial Sales  2,002   1,886   1,884 
 Industrial Sales  2,029   1,951   1,905 
 PJM Net Charges  10   (25)  (43)
 Provision for Rate Refund  (16)  (3)  1 
 Other Retail Sales   172    164    164 
 Total Retail Revenues  7,413   6,966   6,972 
Wholesale Revenues      
 Off-System Sales  1,671   1,583   1,788 
 Transmission   133    103    43 
 Total Wholesale Revenues  1,804   1,686   1,831 
Other Electric Revenues  90   98   87 
Other Operating Revenues  39   35   52 
Sales to Affiliates   646    633    760 
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 SegmentTotal Revenues Vertically Integrated Utilities Segment  9,992   9,418   9,702  $9,172.2
 $9,484.4
 $9,992.5
              
Transmission and Distribution Utilities SegmentTransmission 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
Retail Revenues            
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
 Residential Sales  2,164   2,121   2,146       
 Commercial Sales  1,161   1,331   1,435 
 Industrial Sales  549   821   1,048 
 PJM Net Charges  21   22   45 
 Provision for Rate Refund  22   (3)  6 
 Other Retail Sales   39    41    40 
 Total Retail Revenues  3,956   4,333   4,720 
Wholesale Revenues      
 Off-System Sales  31   57   34 
 Transmission   228    205    153 
 Total Wholesale Revenues  259   262   187 
Other Electric Revenues  56   58   70 
Other Operating Revenues  8   6   5 
Sales to Affiliates   199    159    174 
Total Revenues Transmission and Distribution      
Utilities Segment  4,478   4,818   5,156 
        
Generation and Marketing Segment      
Generation Revenues      
 Affiliated  2,457   2,584   3,331 
 Nonaffiliated  314   282   258 
Trading, Marketing and Retail Revenues      
 Affiliated  -   1   1 
 Nonaffiliated  868   572   278 
Wind Generation Revenues      
 Nonaffiliated   26    28    27 
Total Revenues Generation and Marketing Segment $ 3,665  $ 3,467  $ 3,895 
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


5
5



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

APCo         
  Years Ended December 31,
Description 2013  2012  2011 
      (in thousands)
Retail Revenues         
 Residential Sales $ 1,219,649  $ 1,159,576  $ 1,107,199 
 Commercial Sales   583,835    576,153    535,040 
 Industrial Sales   697,043    701,603    638,854 
 PJM Net Charges   4,998    (13,049)   (23,696)
 Other Retail Sales   77,182    72,455    64,741 
  Total Retail Revenues   2,582,707    2,496,738    2,322,138 
Wholesale Revenues         
 Off-System Sales   433,575    409,527    504,955 
 Transmission   21,049    14,059    (19,723)
  Total Wholesale Revenues   454,624    423,586    485,232 
Other Electric Revenues   22,246    28,438    29,649 
 Total Electric Generation, Transmission and Distribution Revenues   3,059,577    2,948,762    2,837,019 
Sales to Affiliates   347,484    318,199    358,264 
Other Revenues   10,345    9,970    9,942 
Total Revenues $ 3,417,406  $ 3,276,931  $ 3,205,225 
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

I&M         
  Years Ended December 31,
Description 2013  2012  2011 
      (in thousands)
Retail Revenues         
 Residential Sales $ 565,822  $ 505,142  $ 503,554 
 Commercial Sales   400,810    377,302    369,471 
 Industrial Sales   455,067    430,042    412,562 
 PJM Net Charges   3,318    (9,003)   (14,485)
 Provision for Rate Refund   -    -    (461)
 Other Retail Sales   6,945    6,508    6,693 
  Total Retail Revenues   1,431,962    1,309,991    1,277,334 
Wholesale Revenues         
 Off-System Sales   571,802    481,000    499,291 
 Transmission   4,145    2,092    (14,531)
  Total Wholesale Revenues   575,947    483,092    484,760 
Other Electric Revenues   14,348    16,986    8,353 
 Total Electric Generation, Transmission and Distribution Revenues   2,022,257    1,810,069    1,770,447 
Sales to Affiliates   341,686    385,460    429,237 
Other Revenues   2,916    4,582    15,086 
Total Revenues $ 2,366,859  $ 2,200,111  $ 2,214,770 
OPCo

OPCo      
 Years Ended December 31, Years Ended December 31,
DescriptionDescription 2013  2012  2011  2015 2014 2013
   (in thousands) (in millions)
Retail RevenuesRetail Revenues        
  
  
Residential Sales $ 1,676,138  $ 1,636,808  $ 1,680,179 
Commercial Sales  763,820   945,233   1,077,742 
Industrial Sales  468,358   742,235   979,424 
PJM Net Charges  6,916   (18,831)  (30,768)
Provision for Rate Refund  22,091   (2,577)  6,035 
Other Retail Sales   15,881    18,113    17,714 
 Total Retail Revenues  2,953,204   3,320,981   3,730,326 
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 RevenuesWholesale Revenues        
  
  
Off-System Sales  563,040   661,513   667,593 
Transmission   17,699    10,114    (26,697)
 Total Wholesale Revenues  580,739   671,627   640,896 
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 RevenuesOther Electric Revenues   28,281    29,508    36,008  32.4
 26.8
 28.3
Total Electric Generation, Transmission and Distribution Revenues  3,562,224   4,022,116   4,407,230 
Total Electric Generation, Transmission and Distribution Revenues 3,056.1
 3,204.9
 3,562.2
Sales to AffiliatesSales to Affiliates  1,184,994   886,695   1,005,486  84.1
 165.2
 1,185.0
Other RevenuesOther Revenues   15,397    19,385    18,395  8.5
 6.8
 15.4
Total RevenuesTotal Revenues $ 4,762,615  $ 4,928,196  $ 5,431,111  $3,148.7
 $3,376.9
 $4,762.6


6
6



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

PSO         
      Years Ended December 31,
Description 2013  2012  2011 
      (in thousands)
Retail Revenues         
 Residential Sales $ 530,446  $ 512,372  $ 572,404 
 Commercial Sales   351,521    331,125    364,701 
 Industrial Sales   234,072    209,446    241,026 
 Provision for Rate Refund   -    -    (158)
 Other Retail Sales   73,649    70,894    78,722 
  Total Retail Revenues   1,189,688    1,123,837    1,256,695 
Wholesale Revenues         
 Off-System Sales   34,636    37,484    42,241 
 Transmission   36,393    30,669    31,903 
  Total Wholesale Revenues   71,029    68,153    74,144 
Other Electric Revenues   16,994    14,593    14,713 
 Total Electric Generation, Transmission and Distribution Revenues   1,277,711    1,206,583    1,345,552 
Sales to Affiliates   14,246    22,603    14,192 
Other Revenues   3,565    3,752    3,644 
Total Revenues $ 1,295,522  $ 1,232,938  $ 1,363,388 
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

SWEPCo         
      Year Ended December 31,
Description 2013  2012  2011 
      (in thousands)
Retail Revenues         
 Residential Sales $ 586,517  $ 512,578  $ 554,663 
 Commercial Sales   472,264    404,204    411,652 
 Industrial Sales   316,282    298,604    288,474 
 Provision for Rate Refund   (16,110)   (1,207)   1,604 
 Other Retail Sales   8,360    8,074    8,118 
  Total Retail Revenues   1,367,313    1,222,253    1,264,511 
Wholesale Revenues         
 Off-System Sales   294,594    247,118    259,877 
 Transmission   59,097    48,404    47,782 
  Total Wholesale Revenues   353,691    295,522    307,659 
Other Electric Revenues   21,571    20,758    22,022 
 Total Electric Generation, Transmission and Distribution Revenues   1,742,575    1,538,533    1,594,192 
Sales to Affiliates   51,812    37,441    57,615 
Other Revenues   1,416    1,860    2,019 
Total Revenues $ 1,795,803  $ 1,577,834  $ 1,653,826 

(a)
Intercompany transactions have been eliminated for the years ended December 31, 2013, 2012 and 2011.


7


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 20132015 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, 2013,2015, 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 20132015 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.

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.

8


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.

8


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.was adopted in 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 the District of Columbia Circuit, and CSAPR was vacated.  That decision is currently under reviewwas subsequently reversed by the U.S. Supreme Court. CAIRCourt 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.

9


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 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.

9


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 generation 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. For our sales of energy based on market rate authority, however, there is no such recovery mechanism.

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.  Federal EPA has been consulting with states to see whether and how such programs might become part of a CO2 emission reduction program for existing utility generating units.  For additional information, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – Clean Air Act Requirements.
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 this proposal and we expect the Federal EPA to issue revised rules in 2014.

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.  The Federal EPA  proposed revised standards in 2013.  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

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
10
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 New Source Review prevention of significant deterioration and Title V operating permit programs.


In September 2013, the Federal EPA reproposed a Carbon Pollution Standard for New Power Plants. This regulation, based on EPA authority under section 111(b) of the Clean Air Act, would establish New Source Performance Standards for CO2 for new fossil-fueled-fired electric generating units.  The proposed regulation would limit the ability to construct new coal-fired facilities in the future due to strict emission limits if they are finalized. 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. The EPA is scheduled to propose standards, regulations or guidelines, as appropriate, for CO2 from existing fossil fuel units in June 2014, though the scope and extent of the standards is currently unknown.
10


ForAEP’s fossil fuel-fired generating units are large sources of CO2 emissions.  If substantial additional information on legislativeCO2 emission reductions are required, there will be significant increases in capital expenditures and regulatory responses to greenhouse gases, including limitations on CO2 emissions, see Management’s Discussion and Analysisoperating costs which would hasten the ultimate retirement of Financial Condition and Results of Operations underolder, less-efficient, coal-fired units.  To the headings entitled Environmental Issues – Climate Change.  Specific steps takenextent additional investments are made to reduce CO2 emissions includeand receive regulatory approvals to increase rates, return on capital investment would have a positive 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 recovery and earn a return on investment.  Management would expect these principles to apply to investments made to address new environmental requirements.  However, requests for rate increases reflecting these costs can have adverse effects because regulators could limit the following:amount or timing of increased costs that AEP would recover through higher rates. For sales of energy into competitive markets, however, there is no such recovery mechanism.

Renewable Sources of Energy

SomeAll of the states we serveAEP 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 2013 and in support of our goals or requirements, our2015, the AEP operating companies had long-term contracts for 1,9842,031.5 MW of wind and 1010.1 MW of solar power. When additional contracts forpower 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 construction and/or pending regulatory approvalcontract for PSO were in service as of late 2015, and the remaining three projects associated with I&M’s CESPP projects are addedexpected to begin deliveries in 2016. This will result in a total of 2,655.3 MW of wind and netted against one wind contract that is expiring at the end of 2015, the total renewable portfolio will be 2,698 MW to serve our regulated operating company customers.  Wesolar 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.

11The 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 Use Energy Efficiency

InBeginning in 2008, AEP ramped up efforts to reduce energy consumption and peak demand through the introduction of additional energy efficiency and demand response programs.  These programs, commonly and collectively referred to as demand side management, were implemented in jurisdictions where appropriate cost recovery was available.  Since that time, AEP Operating Companiesoperating companies have implemented over 100 programs across the AEP service territory and in most of the states we serve.AEP serves.  For the period 2008 through 2013,2015, these programs have reduced annual consumption by over 4,000,0006.0 million megawatt hours and peak demand by over 1,2001,500 MW.  ToAEP estimates that its operating companies spent approximately $875 million during that period  to achieve these levels, AEP Operating Companies invested approximately $540 million during the same period.   These results are preliminary and subject to independent third party evaluation and verification of savings, as required.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

11


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

CurrentAEP is also developing and Projected CO2 Emissions

Our total CO2 emissions in 2012 (not including our ownership in the Kyger Creekmarketing a merchant distributed resource portfolio. AEP’s newly-formed subsidiary, OnSite Partners LLC, works directly with wholesale and Clifty Creek plants) were approximately 122 million metric tons.  Our 2013 emissions decreasedlarge retail customers to approximately 114  million metric tons.  We expect overall increases in CO2 emissions during the next few years to be small, if any, as our salesprovide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation 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 issues, including changes to environmental regulations and proposed regulation or legislation that couldwould affect the Company.company.  The Board’s Committee on Directors and Corporate Governance oversees the Company’scompany’s annual Corporate Accountability Report, which includes information about the Company’scompany’s environmental, financial and social performance.

Other Environmental Issues and Matters

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 6 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies, included in the 20132015 Annual Reports, under the heading entitled The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation for further information.


12


Environmental Investments

Investments related to improving AEP System plants’ environmental performance and compliance with air and water quality standards during 2011, 20122013, 2014 and 20132015 and the current estimatesestimate for 2014, 2015 and 2016 are shown below,below. AFUDC debt is included in each case excluding equity AFUDC.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 generation 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 20132015 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.onerous. These estimates do not include any projected costs 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. WeAEP typically recoverrecovers costs of complying with environmental standards from
12
customers through rates in regulated jurisdictions.  For our sales of energy based on market rate authority,AEP’s merchant generation units however, there is no such recovery mechanism.  Failure to recover these costs could reduce our future net income and cash flows and possibly harm ourAEP’s financial condition.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading entitled Environmental Issues and Note 6 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies, included in the 20132015 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
                  
  2011 2012 2013 2014 2015 2016
  Actual Actual Actual Estimate Estimate Estimate
             
  (in thousands)
Total AEP (a)$186,800 $235,400 $415,000 $588,000 $644,000 $447,000
APCo 68,900  50,800  44,500  48,000  67,000  68,000
I&M 5,900  30,400  27,300  55,000  42,000  52,000
OPCo (b) 63,000  66,200  123,900  -  -  -
PSO 6,500  26,100  55,500  66,000  75,000  49,000
SWEPCo 11,000  23,800  134,000  217,000  312,000  118,000
(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)Estimates for 2014, 2015 and 2016 reflectFor APCo, the transferprojected environmental investments above include the conversions of 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 OPCoits generation assets which occurred on December 31, 2013.
Electric and Magnetic Fields (EMF)

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 in transmission and distribution lines, electrical equipment, household wiring and appliances.  A number of studies in the past have examined the possibility of adverse health effects from EMF.  While some 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.

Management cannot predictcontinues to refine the ultimate impactcost estimates of complying with air and water quality standards and other impacts of the questionenvironmental proposals. The following cost estimates for periods following 2016 will change depending on the timing of EMF exposureimplementation and adverse health effects.  If further research showswhether 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 EMF exposure contributesimpose more stringent standards, (b) additional rulemaking activities in response to increased riskcourt decisions, (c) the actual performance of cancerthe 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 health problems, or iffactors.  The following cost estimates do not include any projected costs that might be triggered by compliance with the courts conclude that EMF exposure harms individualsClean Power Plan and that utilities are liable for damages, or if states limitlimited to only the strengthcosts of magnetic fieldsmajor projects to such a level thatcomply with existing air and water quality standards. In addition, management is continuing to evaluate the economic feasibility of environmental investments on both regulated and nonregulated plants.

13


For the Registrant Subsidiaries, management’s current electricity delivery system must be significantly changed, then the resultsranges of operations and financial conditionestimates of AEP and its operating subsidiaries could be materially affected unless these costs can be recovered from customers.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


13


BUSINESS SEGMENTS

During the fourth quarter of 2013, we realigned our business segments as a result of corporate separation and plant transfers.  See Note 9 to the consolidated financial statements entitled Business Segments, included in the 2013 Annual Reports, for additional information on our operating segments.  OurAEP’s reportable segments and their related business activities are outlined below:below.   See Note 9 to the financial statements entitled Business Segments, included in the 2015 Annual Reports, for additional information on the operating segments. 

Vertically Integrated Utilities

·  Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

·  Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
·  OPCo purchases energy and capacity to serve remaining generation service customers.
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 AEP’s wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.

Generation & Marketing

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

AEP Transmission Holdco

·  Development, construction and operation of transmission facilities through investments in our wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.

AEP River Operations

·  Commercial barging operations that transport liquid, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.
Commercial barging operations that were sold in November 2015. As a result of the sale, AEP River Operations is no longer a business segment.


14


VERTICALLY INTEGRATED UTILITIES

GENERAL

AEP’s vertically integrated utility operations are engaged in the generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.  AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities on behalf of each of these subsidiaries.

ELECTRIC GENERATION

Facilities and Coordination

As of December 31, 2013,2015, AEP’s vertically integrated public utility subsidiaries owned or leased approximately 26,90023,600 MW of domestic generation.  See Item 2 – Properties for more information regarding the generation capacity of vertically integrated public utility subsidiaries.

14


Interconnection Agreement

Until January 1, 2014, AEPSC, APCo, I&M, KPCo and OPCo were parties to the Interconnection Agreement. This agreement defined how the member companies shared the costs and benefits associated with their generation plants.  The agreement required the deficit companies to make monthly capacity equalization payments to the surplus companies based on the surplus companies' average fixed cost of generation.  All member companies shared off-system sales margins based upon each member company's member load ratio. As of December 31, 2013, the member-load-ratios were as follows:

 Peak Demand Member-Load Ratio
 (MWs) (%)
APCo6,839 31 
I&M4,540 21 
KPCo1,409 6 
OPCo9,385 42 

APCo, I&M, KPCo and OPCo were also parties to the AEP System Interim Allowance Agreement (Allowance Agreement), that provided, 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, 2013, 2012 and 2011:

 Years Ended December 31,
 2013 2012 2011
 (in thousands)
APCo$637,300 $494,400 $632,100
I&M (36,500)  (118,400)  (183,700)
KPCo 124,200  93,200  48,400
OPCo (725,000)  (469,200)  (496,800)

Termination of the Interconnection Agreement

Effective as of January 1, 2014, the Interconnection Agreement and the Allowance Agreement were each terminated.  The transfer of OPCo’s generation assets and related liabilities to AGR occurring on December 31, 2013 removed a large proportion of the pooled generation resources governed under the Interconnection Agreement and Allowance Agreement.  As a result of these transfers, which were approved by the PUCO and the FERC, the parties terminated the Interconnection Agreement and the Allowance Agreement.  See Notes 1 and 4 to the consolidated financial statements, included in the 2013 Annual Reports, for additional information regarding the termination of the Interconnection Agreement and Corporate Separation.

Operating Agreement

AEPSC, PSO and SWEPCo are parties to the Operating Agreement which has been approved by the FERC.  The Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies 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 are generally shared based on the amount of energy PSO or SWEPCo contributes that is sold to third parties.

In January 2014, the FERC approved the modification of the Operating Agreement to address changes resulting from the anticipated March 2014 implementation of a “Day-Ahead” power market by the SPP.

15

The following table shows the net (credits) or charges allocated among the parties under the Operating Agreement during the years ended December 31, 2013, 2012 and 2011:

 Years Ended December 31,
 2013 2012 2011
 (in thousands)
PSO$46,171  $42,555  $33,091 
SWEPCo (46,171)  (42,555)  (33,091)

Power generated by or allocated or provided under the 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.

Power that is not needed to serve the native load of our vertically integrated public utility subsidiaries is sold in the wholesale market by AEPSC on behalf of that subsidiary.  See Risk Management and Trading, below, for a discussion of the trading and marketing of such power.

Counterparty Risk Management

Counterparties and exchanges may require cash or cash related instruments to be deposited on transactions as margin against open positions.  As of December 31, 2013, counterparties posted approximately $11 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 $59 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 2013 Annual Reports, under the heading entitled Quantitative and Qualitative Disclosures About Market Risk for additional information.

Fuel Supply

The following table and fuel supply presentation under “Fuel Supply”, “Coal and Lignite” and “Natural Gas”2013 results include the results of the fuel used and transported by OPCo, a utility subsidiary that is not part of the vertically integrated utilityVertically 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:

 2013 2012 20112015 2014 2013
Coal and Lignite 75% 71% 78%70% 72% 75%
Nuclear17% 16% 11%
Natural Gas 13% 17% 11%12% 11% 13%
Nuclear 11% 11% 10%
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 20132015 fossil fuel costs increasedfor the Vertically Integrated Utilities decreased approximately 9%12% on a dollar per MMBtu basis from 20122014. This was due primarily to an increasea 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 2013 was down slightly2015 decreased from the same period2014 due to a decrease in 2012, butpower prices and corresponding decrease in demand for coal-fired generation. As a result, coal inventories ended the year at targetabove-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 5,7004,838 railcars, approximately 600498 barges, 1512 towboats, 8 harbor boats and a coal handling
16
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 liquid, coal and other dry-bulk commodity transportation operations that are not part of this business segment.

Spot market prices for coal remained relatively flatcontinued to decrease throughout 2013, and2015.  The decreased for certain coals used by AEP.  The relatively flat spot coal price performance duringprices reflect the year can be attributed to weak European coalreduction in demand a persistently sluggish domestic economy,for coal-fired generation and relatively inexpensive natural gas.  Approximatelythe oversupply in the market.   As of December 31, 2015, slightly less than half of the coal purchased by AEP iswas procured through term contracts.  As those contracts expire, they are replaced

15


with contracts at current market prices.  The price impact of this process is reflected in subsequent periods.  The price paid for coal delivered in 2013 increased2015 decreased from the prior year primarily due to an increasea decrease in rail rates for western coal.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:

 2013 2012 2011
Total coal delivered to AEP System plants (thousands of tons) 51,057 60,054 62,956
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 $51.31 $49.22 $46.76$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. AtAs of December 31, 2013,2015, the System’sVertically Integrated Utilities coal inventory was approximately 3447 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.

Natural Gas

Through its public utility subsidiaries, AEPThe Vertically Integrated Utilities consumed over 15889 billion cubic feet of natural gas during 20132015 for generating power. This represents a decrease of 28%7% from 2012 and reverses a trend that began in 2010.2014.  While AEP’s natural gas-fired generating capacity has increased over the past several years with the addition of the Stall and Dresden units, the increaseimplementation of the SPP Market and change in the dispatch of AEP’s natural gas pricesfleet resulted in 2013 led to a decrease in demand for natural gas-fired generation.  Despite the availability of natural gas due to the increased shale supply, the U.S. pipeline infrastructure remains a limiting factor in the expansion ofdecreased natural gas-fired generation.  Several of AEP’s natural gas-fired power plants are connected to at least two pipelines however, which allowsallow greater access to competitive supplies and improvesimprove delivery reliability. A portfolio of term, monthly, seasonal, firm and daily peaking purchasesupply 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.

 2013 2012 2011
Total natural gas delivered to AEP System plants (billion cubic feet) 158.3  220.0  166.8
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 $4.01 $3.01 $4.48$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 2015.2018.


16
17


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, 2013,2015, the total decommissioning trust fund balance for the Cook Plant was approximately $1.6$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.

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 6 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies under the heading Nuclear Contingencies, included in the 20132015 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.

Counterparty Risk Management

The Vertically Integrated Utilities segment also sells power and enters into related energy transactions with wholesale customers and other market participants. As a result, counterparties and exchanges may require cash or cash related instruments to be deposited on transactions as margin against open positions.  As of December 31, 2015, counterparties posted approximately $9 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$52 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.


17


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 AEGCo and 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.

18


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 generation 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 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 generation plants.  OVEC has completed the financing of the $1.4 billion required for these projectsplants through debt issuances, including tax-advantaged debt issuances.  Both OVEC generation 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 PUCO seeking authorization to maintain 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.arrangement. OPCo has filed an application with the PUCO to approve a cost-based purchased power agreement (PPA) rider that would initially be based upon OPCo’s contractual entitlement under the Inter-Company Agreement which is approximately 20% of OVEC’s capacity.

ELECTRIC DELIVERY

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. Business – Vertically 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. Business – Vertically Integrated Utilities – Regulation – FERC.  As discussed below, some transmission services also are separately sold to non-affiliated companies.

18


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. Business – Vertically Integrated Utilities – Competition.

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, protocols and agreements in place with PJM, SPP and ERCOT, and as approved by the FERC.

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 our transmissionAEP’s Transmission and distribution utilityDistribution Utilities segment, is also a party to the TA.  The TA defines how the parties to the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM.  The TA has been approved by the FERC.

19


The following table shows the net charges allocated among the certain parties to the TA during the years ended December 31, 2013, 2012 and 2011:

   Years Ended December 31,
Company 2013  2012  2011 
  (in thousands)
APCo $40,609  $20,264  $4,608 
I&M   19,947    5,689    1,538 

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.

The following table shows the net (credits) or charges allocated pursuant to the TCA and SPP OATT protocols as described above for the years ended December 31, 2013, 2012 and 2011:

 Years Ended December 31,
 2013 2012 2011
 (in thousands)
PSO$14,700  $12,300  $9,000 
SWEPCo (14,700)  (12,300)  (9,000)

Transmission Services for Non-Affiliates

In addition to providing transmission services in connection with their own power sales, AEP’s vertically integrated public utility subsidiaries through RTOs also provide transmission services for non-affiliated companies.  See Item 1 – Vertically Integrated Utilities – 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 Companies 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.

Regional Transmission Organizations

AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM, and PSO and SWEPCo 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.

20


REGULATION

General

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.  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.

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

19


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.

The 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).  Historically, the state regulatory frameworks in the service area of the AEP vertically 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 4 to the consolidated financial statements, entitled Rate Matters, included in the 20132015 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.

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.

21


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.


20


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 AEP’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’s vertically integrated public utility subsidiaries have market-ratemarket-based rate authority from the FERC, under which much of their 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.  AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM.  PSO and SWEPCo 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.

CompetitionCOMPETITION

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.


21


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.

In 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.
22
SignificantRecent 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, 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.


22


TRANSMISSION AND DISTRIBUTION UTILITIES

GeneralGENERAL

This business 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 1,464,0001,468,000 retail customers in Ohio.  TCC is engaged in the transmission and distribution of electric power to approximately 806,000826,000 retail customers through REPs in southern Texas. TNC is engaged in the transmission and distribution of electric power to approximately 188,000189,000 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 party 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.  OPCo’s net charges allocated to it under the TA during the years ended December 31, 2013, 2012 and 2011 were $8.9 million, $6.1 million and $17.2 million, respectively.

23
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.


23


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.

SeasonalitySEASONALITY

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 AEP’s existing utility operating companies and (b) AEP’s transmission joint ventures.  

AEPTCo TRANSCOS

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

AEP Appalachian Transmission Company, Inc. (APTCo)
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 located within SPP)

AEP Oklahoma Transmission Company, Inc. (OKTCo)
AEP Southwestern Transmission Company, Inc. (SWTCo) (covering 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.

24


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 integrated utility operating companies and the transmission operations of OPCo.  IMTCo, KTCo, OHTCo, OKTCo and WVTCo have received approvals for formation or did not require state commission approval to operate.  IMTCo, KTCo, OHTCo, OKTCo and WVTCo currently own and operate transmission assets.  An application for regulatory approval for SWTCo is under consideration in Louisiana. As of December 31, 2015, AEPTCo’s subsidiaries had $2.8 billion of transmission assets in-service with plans to construct approximately $3.5 billion of additional transmission assets through 2018.


25


AEPTHCo JOINT VENTURE INITIATIVES

AEP 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. 

AEP is currently participating in the following 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 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 more joint ventures.

26


REGULATION

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

The Transcos’ and joint ventures’ (where applicable) rates are included in the respective OATT for PJM and 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.  The FERC requires transmission providers such as PJM and SPP to offer transmission service to all eligible customers (for example, load-serving entities, power marketers, generators and 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 pay the transmission owners their ATRR for use of their facilities and bill transmission customers taking service under the PJM and SPP OATTs, based on the terms and conditions in the respective OATT for the service taken.

The 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 11.2% 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.

In 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.

The 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 have approved returns on equity ranging from 9.96% to 12.8% based on equity capital structures ranging from 40% to 60%.

COMPETITION

One of the most significant provisions of FERC Order No. 1000 is the removal of the federal right of first refusal for incumbent utilities within tariffs and agreements for certain regional transmission projects. Historically, vertically integrated public utilities had the right to build and own transmission lines proposed by the region’s planning processes when those lines connected to facilities within their respective retail service territories.  FERC Order No. 1000 eliminates the federal right of first refusal in RTO 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 own regional transmission facilities in any service territory.  Transource was created to respond to FERC Order No. 1000 competitive processes at the RTO level.


27


GENERATION & MARKETING

OurGENERAL

The AEP Generation & Marketing segment 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 ourthe Generation & Marketing segment is AGR.  On December 31, 2013, AGR acquired the generation assets and related liabilities at net book value of OPCo in a series of transactions approved by the PUCO and the FERC.  AGR transferred a portion of the generation assets and liabilities at net book value that it received to APCo and KPCo.  As a result of these transactions, AGR owns 10,0026,752 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, SPP, MISO and PJM.  WeThese subsidiaries sell power into the market and engage in power, natural gas, coal and emissions allowances risk management and trading activities.  
24

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 ourthe retail supply and energy management business, ourAEP’s subsidiary AEP Energy is a retail electricityenergy 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 215,000375,000 customer accounts as of December 31, 2013.2015.

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, third-party financings; review of mergers;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.  We areAGR is also regulated by the PUCT for transactions inside ERCOT.  Additionally, AGR is subject to mandatory reliability standards promulgated by the NERC,North American Electric Reliability Corporation, with the approval of FERC. We are also regulated by the PUCT for transactions inside ERCOT.

COMPETITION

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

28


generation is possible that changes in regulatory policies or advances in newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells will reduce costs of new technology to levels that are equal to or below that of most central station electricity production.  Our ability to maintain relatively low cost, efficient and reliable operations is a significant determinate of our competitiveness.

With over 70% of our generation fleet fueled by coal, our overall competitive position is impacted by the price of natural gas relative to coal.  While higher relative natural gas prices generally favor our competitive position,coal-fired, lower relative natural gas prices will favor our competitors that have a higher concentration of natural gas fueled generation.  Other factors impacting our competitiveness include environmental regulation, transmission congestion or transportation constraints at or near our generation facilities, inoperability or inefficiencies, outages and deactivations and retirements at our generation facilities.

SeasonalityTechnology 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%

25
29


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, 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, 2013,2015, counterparties posted approximately $14$26 million in cash, cash equivalents or letters of credit with AEP for the benefit of AEP’s generation and marketingGeneration & Marketing segment subsidiaries (while, as of that date, AEP’s generation and marketingGeneration & Marketing segment subsidiaries posted approximately $165$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 20132015 Annual Reports, under the heading entitled Quantitative and Qualitative Disclosures About Market Risk for additional information.

Fuel Supply

AEP’s generation and marketing subsidiaries procure coal under a combination of purchasing arrangements including long-term contracts, affiliate operations and spot agreements with various producers and coal trading firms.  Management believes that AEP’s generation and marketing subsidiaries will be able to secure and transport coal of adequate quality and in adequate quantities to operate their coal-fired units. Through subsidiaries, AEP owns, leases or controls more than 5,700 railcars, approximately 600 barges and 15 towboats to move and store coal for use in our generating facilities.

Most of the coal purchased by AEP is procured through term contracts.  As those contracts expire, they can be replaced at the new market price with an impact in subsequent periods.  Several of AEP’s natural gas-fired power plants are connected to at least two pipelines, which allows greater access to competitive supplies and improves delivery reliability. A portfolio of term, monthly, seasonal firm and daily peaking commodity 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.

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.


30


OPCo

Pursuant to a Power Supply Agreement (PSA) between AGR and OPCo, AGR suppliessupplied capacity for OPCo’s switched and non-switched retail load for the period January 1, 2014 through May 31, 2015.  AGR also supplies the energy needs of OPCo’s non-switched retail load that is not acquired through auctions from January 1, 2014 through December 31, 2014 under the PSA.

Other

As of December 31, 2013,2015, 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.

26


AEP TRANSMISSION HOLDCO (AEPTHCO)

AEPTHCO OVERVIEW

AEPTHCo is a holding company for AEPTCo and for AEP’s transmission joint ventures.  AEPTCo is a holding company for seven wholly-owned FERC-regulated transmission-only electric utilities (Transcos), each of which is geographically aligned with our existing utility operating companies.  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.
·  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.

AEPTCo’s seven Transcos are:

AEP East Transmission Companies (all located 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 (all located within SPP)

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

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-integrated utility operating companies and the transmission operations of OPCo.  IMTCo, KTCo, OHTCo, OKTCo and WVTCo have received approvals for formation or did not require state commission approval to operate.  IMTCo, OHTCo, OKTCo and WVTCo currently own and operate transmission assets or have assets under construction.  Applications for regulatory approvals have been filed for SWTCo and are currently under consideration in Arkansas and Louisiana.  As of December 31, 2013, AEPTCo had $991 million of transmission assets in-service with plans to construct nearly $2 billion of additional transmission assets through 2016.

JOINT VENTURE INITIATIVES

AEP 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.  Transource Energy, LLC (Transource) is a joint venture between AEPTHC (86.5%) and Great Plains Energy (13.5%). Transource was formed to pursue competitive projects resulting from FERC Order No. 1000 described further below under the heading Competition.  Our other joint ventures are at various stages of regulatory and RTO approval.

27



We are currently participating in the following joint venture initiatives:
                   
         Total      
         Estimated  AEP's  
    Projected    Project Costs  Investment at Approved
Project   Completion  Owners at  December 31, Return on
Name Location Date  (Ownership %) Completion  2013 (h) Equity
          (in thousands)    
ETT Texas  2023   MidAmerican   $ 3,057,000 (a) $ 440,719   9.96 % 
  (ERCOT)     Energy (50%)            
       AEP (50%)            
                   
Prairie Wind Kansas  2014   Westar Energy (50%)    170,000     11,533   12.8 % 
       MidAmerican Energy            
       (25%) (b)            
       AEP (25%) (b)            
                   
Pioneer Indiana  2018 (c) Duke Energy (50%)    1,100,000 (c)   2,466   12.54 % 
       AEP (50%)            
                   
RITELine IN Indiana  2026   Exelon (12.5%) (d)    400,000     685 (e) 11.43 % 
       AEP (87.5%) (d)            
                   
RITELine IL Illinois  2026   Commonwealth    1,200,000     13 (e) 11.43 % 
       Edison (75%)            
       Exelon (12.5%) (d)            
       AEP (12.5%) (d)            
                   
Transource Missouri  2017   Great Plains Energy    398,000 (g)    2,275  11.1 %(g)
Missouri      (13.5%) (f)            
       AEP (86.5%) (f)            

(a)ETT’s investment in completed, current and future projects in ERCOT over the next ten years is expected to be $3.057 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 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 $330 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 (AEPTHC).  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 AEPTHC.
(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 are currently under consideration for inclusion in the interregional planning process between PJM and MISO.
(f)AEP owns 86.5% of Transource Missouri through its ownership interest in Transource Energy, LLC (Transource).  Transource is a joint venture with AEPTHC and Great Plains Energy formed to pursue competitive transmission projects.  AEPTHC 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 $333 million Sibley-Nebraska City project (11.3%).
(h)RITELine IN and Transource Missouri 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.

In August 2012, the PJM board cancelled the Potomac-Appalachian Transmission Highline Project (PATH Project), our transmission joint venture with FirstEnergy, and removed it from the 2012 Regional Transmission Expansion Plan.  In September 2012, the PATH Project companies submitted an application to the FERC requesting authority
28
to recover prudently-incurred costs associated with the Project.  In November 2012, the FERC issued an order accepting the PATH Project's abandonment cost recovery application, subject to settlement procedures and hearing.  The settlement proceedings are on-going.  AEP’s investment in the PATH Project as of December 31, 2013 was $25 million.

Our joint ventures do not have employees.  Business services for the joint ventures are provided by AEPSC and other AEP subsidiaries and the joint venture partners.

REGULATION

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

The Transcos’ and Joint Ventures’ (where applicable) rates are included in the respective Open Access Transmission Tariff (OATT) for PJM and 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.  The FERC requires transmission providers such as PJM and SPP to offer transmission service to all eligible customers (for example, load-serving entities, power marketers, generators and 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.  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- and under-recovery of the transmission owner’s ATRR.  PJM and SPP pay the transmission owners their ATRR for use of their facilities and bill transmission customers taking service under the PJM and SPP OATTs, based on the terms and conditions in the respective OATT for the service taken.

The 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.

Our joint ventures have approved returns on equity ranging from 9.96% to 12.8% based on equity capital structures ranging from 40% to 60%.

The Transcos collectively filed rate base totals of $776 million in 2013, $283 million for 2012 and $104 million for 2011.  The total transmission revenue requirement filed in the ATRR for 2013, 2012 and 2011 was $99 million, $35 million and $13 million, respectively.

The 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% 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.

COMPETITION

One of the most significant provisions of FERC Order No. 1000 is the removal of the federal right of first refusal for incumbent utilities within tariffs and agreements for certain regional transmission projects. Historically, vertically integrated public utilities had the right to build and own transmission lines proposed by the region’s planning processes when those lines connected to facilities within their respective retail service territories.  FERC Order No. 1000 eliminates the federal right of first refusal in regional transmission organization (RTO) 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 own regional transmission facilities in any service territory.  Transource was created to respond to FERC Order No. 1000 competitive processes at the RTO level as described above.

29


AEP RIVER OPERATIONS

OurPrior to its sale in November 2015, AEP River Operations segment transportstransported liquid, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi rivers.  Almost allAs a result 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 generation plants.sale, AEP River Operations includes approximately 2,300 barges, 36 towboats and 20 harbor boats that we own or lease. In 2014, River Operations will add at least 20 ten thousand barrel tank barges.  Those barges will provide an entry into the tank bargeis no longer a business which will serve both current and new customers that transport liquid commodities.  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 – Vertically Integrated Utilities – 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 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.

31

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.

30


EXECUTIVE OFFICERS OF AEP as of February 25, 2014

The following persons are executive officers of AEP.  Their ages are given as of February 1, 2014.23, 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 5355
Chairman of the Board since January 2014, President since January 2011 and Chief Executive Officer since November 2011. Was Executive Vice President-Generation from September 2006 to December 2010.

Lisa M. Barton
Executive Vice President – Transmission
Age 4850
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 4446
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 5355
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 5456
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.

Robert P. Powers
Executive Vice President and Chief Operating Officer
Age 5962
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 4648
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 6255
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.

32
31


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.

ApprovalRegulated electric revenues, earnings and results are dependent on state regulation that may limit AEP’s ability to recover costs and other amounts. (Applies to all Registrants)

The 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 June 2012 through May 2015 ESP order in Ohioreturns established by the relevant commissions, retail electric rates may be overturned and is subject to appeal. – Affecting AEPreview and OPCo

In August 2012,possible reduction by the PUCO issued an ordercommissions, which adopted and modified an ESP through May 2015 (the “2012 ESP”).  The 2012 ESP allowed the continuation of the fuel adjustment clause, 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.  The 2012 ESP further established (a) a non-bypassable Distribution Investment Rider effective September 2012 through May 2015 to recover certain distribution investment, and (b) a non-bypassable Retail Stability Rider (RSR), a portion of which provides for the collection of deferred capacity costs.  The deferred capacity costs may exceed the amount we will collect under the RSR.  In January 2013, the PUCO issued an order on rehearing for the 2012 ESP which generally upheld its prior order.  Intervenors are challenging various parts of these orders at the PUCO and with the Supreme Court of Ohio.  In parallel proceedings, the PUCO addressed certain issues around the energy auctions while other issues were deferred to a separate docket.  The PUCO has agreed to issue a request for an independent auditor in the fuel adjustment clause proceeding to separately examine the recovery of the fixed fuel costs.  If all or part of 2012 ESP is overturned by the PUCO or the Supreme Court of Ohio, or if deferred capacity and other costs are not recoverable,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.

Our request for an ESP from June 2015 through May 2018 may not be approved in its entirety. – Affecting AEP and OPCo

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, effective June 2015 through May 2018.  The proposal includes a return on common equity of 10.65% for certain riders.  Additionally, the application identifies OPCo’s intention to submit a separate application to continue the RSR in which the unrecovered portion of the deferred capacity costs will continue to be collected until the balance of the capacity deferrals has been collected.  If the PUCO denies all or part of the requested ESP, it could reduce future net income and cash flows and impact financial condition.

Ohio may require us to refund revenue that we have collected. – Affecting AEP and OPCo

Ohio law requires that the PUCO determine on an annual basis if rate adjustments included in prior orders resulted in significantly excessive earnings.  If the PUCO determines there were significantly excessive earnings, the excess amount could be returned to customers.  In November 2013, OPCo filed its 2011 and 2012 significantly excessive earnings filings with the PUCO.  If the PUCO determines that OPCo’s earnings were significantly excessive, and requires OPCo to return a portion of its revenues to customers, it could 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.

32
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 an appeal with the Supreme Court of Ohio challenging the recovery of certain fuel costs.  Any reduction to our fuel recovery by the PUCO and/or the Supreme Court of Ohio 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 the Arkansas jurisdictional share of the Turk Plant (approximately 20%) 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.  The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market.  In addition, in February 2013, the LPSC granted recovery for the Louisiana portion of the Turk Plant costs in a formula rate filing, subject to refund based on the staff review of the cost of service and prudence review 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 wholesale market, it could reduce future net income and cash flows and impact financial condition.

Request for rate recovery in Indiana may be overturned on appeal. – Affecting AEP and I&M

In February 2013, the IURC issued an order granting an annual increase in base rates.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the order with the Indiana Court of Appeals.  In September 2013, the OUCC filed a brief on appeal that included objections to certain aspects of the rate case.  If any part of the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

Approved recovery related to enabling the useful life of the Cook Plant may be overturned on appeal or further consideration. – Affecting AEP and I&M

In April and May 2012, I&M filed petitions 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 extended licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.  In July 2013, the IURC approved I&M’s proposed project apart from a minor exception which the IURC stated I&M could seek recovery in a base rate case.  I&M was granted recovery through an LCM Project Rider to be determined in a series of proceedings beginning in the fourth quarter of 2013 and then semi-annually thereafter.  If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

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

In July 2012, SWEPCo filed a request with the PUCT for an increase in Texas base rates.  In October 2013, the PUCT issued an order that granted part of the requested rate recovery.  Additionally, the PUCT determined that it would defer consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.  If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Turk Plant transmission lines or Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

33
Request for rate recovery in Oklahoma may not be approved in its entirety. – Affecting AEP and PSO

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity.  If PSO cannot ultimately recover its costs that are the subject of this request, it could 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.  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
33


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.  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.  We have also traditionally 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, 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.

34


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.

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.


34
35



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.  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.

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 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.

35
36



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 cyber security 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 cyber security program designed to protect and preserve the confidentiality, integrity and availability of data and systems. In addition, we areAEP is subject to mandatory cyber 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.

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.  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.  AEP indebtedness and common stock dividends are structurally subordinated to all subsidiary indebtedness.


36
37


OurAEP’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.

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.  We haveAEP has existing contracts of varying durations for the supply of coal, 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
38
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.


37


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.

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 is subject to risks that are beyond our control. – Affecting AEP

Our AEP River Operations business segment transports liquid, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi rivers.  These activities can be hazardous and depend on natural conditions and forces.  Our river transport operations could result in an environmental event such as a serious spill or release.  In addition, if drought conditions or other factors cause the water levels of one or more of these rivers to drop below the amount necessary to permit commercial barging traffic, it would prevent our AEP River Operations from transporting cargo 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 portions of the Mississippi River in 2013 have been reported as remaining at or approaching the lowest since the levels caused by severe drought in 1988.  Any reduction in the commercial activities of our AEP River Operations due to low water levels could reduce future net income and cash flows.

We are subject to physical and financial risks associated with climate change. – Affecting each Registrant(Applies to all Registrants)

There is a growing consensus on the evidence of global climate change.  Climate change creates physical and financial 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.  Our customers’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 duration and magnitude of the changes.

Increased energy use due to weather changes may require usAEP to invest in additional generating assets, transmission and other infrastructure to serve increased load.  Decreased energy use due to weather changes may affect our 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 ourthe AEP service territory could also have an impact on our revenues.  We buyAEP buys and sellsells electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand on ourAEP’s own and/or other systems may raise electricity prices as we buyAEP buys short-term energy to serve ourAEP’s own system, which would increase the cost of energy we provideAEP provides to our customers.

39

Severe weather impacts ourAEP’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 ourAEP’s cost of providing service.  Changes in precipitation resulting in droughts, or water shortages or floods could adversely affect our operations, principally ourthe fossil fuel generating units.  A negative impact to water supplies due to long-term drought conditions or severe flooding could adversely impact ourAEP’s ability to provide electricity to customers, as well as increase the price they pay for energy.  WeAEP 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 our revenues.  OurAEP’s financial performance is tied to the health of the regional economies we serve.AEP serves.  The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities.the communities within the AEP System.

WeManagement cannot predict the outcome of the legal proceedings relating to ourAEP’s business activities. – Affecting each Registrant(Applies to all Registrants)

We areAEP is involved in legal proceedings, claims and litigation arising out of ourits business operations, the most significant of which are summarized in Note 6 of the Combined Notes to Consolidated Financial Statements entitled Commitments, Guarantees and Contingencies.  Adverse outcomes in these proceedings could require significant expenditures that could have a material adverse effect on our results of operations.reduce future net income and cash flows and negatively impact financial condition.


38


RISKS RELATING TO STATE RESTRUCTURING

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

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.  Through a short term agreement, AGR provides capacity and a decreasing portion of power to the Ohio customers that have not switched.  As customer switching in Ohio continues, it could reduce AGR’s future net income and cash flows and impact financial condition.

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 2013,2015, TCC’s largest REP accounted for 29%23% of its operating revenue and its second largest REP accounted for 16%22% of its operating revenue; TNC’s largest REP accounted for 12%11% of its operating revenues, and its second largest REP accounted for 7%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.


40


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 generation 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 andor additional substances become regulated.  If we retireAEP 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.  WeAEP typically recover ourrecovers expenditures for pollution control technologies, replacement generation, undepreciated plant balances and associated operating costs from customers through regulated rates in regulated jurisdictions.  Failure to recover these costs could reduce our future net income and cash flows and possibly harm our financial condition.   For our sales of energy from our competitiveAEP’s merchant generation units, there is no such cost-recovery mechanism.   As a result, weAEP may not recover our costs through the market and we may be forced to shut competitive units down.  The costs of compliance for ourAEP’s competitive units could reduce our future net income and cash flows and possibly harm our 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 CO2emissions 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.  Several groups have filed challenges to the endangerment finding and the Federal EPA’s subsequent rulemakings.  The Supreme Court has agreed to review whether EPA reasonably determined that establishing standards for new motor vehicles automatically triggered regulation of stationary sources through the prevention of significant deterioration and Title V permitting programs.

In 2012, the Federal EPA issued a proposed CO2 emissions standard for new power generation sources, with a CO2 limit equivalent to a natural gas unit.  In response to the comments submitted on this proposed rule, and in accordance with a directive from the President, EPA withdrew the April 2012 proposed rule and has issued a new proposal.  This proposed rule includes separate, but equivalent,final emission guidelines for existing fossil fuel fired electric generating units.  The standards for natural gas andnew coal-fired generating units are based on the use of partial carbon capture and storage at coal units.  We do not believe that carbon capture and storage has been adequately demonstrated, and intend to submit commentsstorage. The standards for natural gas combined cycle units are based on the proposed rule.use of efficient combined cycle generating technology. The President has also directed Federal EPAClean 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 issue standardsbe implemented pursuant to individual state plans beginning in 2022. In February 2016, the U.S. Supreme Court issued a stay on the final Clean Power Plan, including all of the deadlines for modified and reconstructed units, andsubmission of initial or final state plans. The stay will remain in effect until a guidelinefinal decision is issued by the U.S. Court of Appeals for the developmentDistrict of state implementation plans that would reduce carbon emissions from existing utility units by June 2014, to finalize those standards by June 2015,Columbia Circuit and to require states to submit implementation plans no later than June 2016.  Management believes some policy approaches being discussed would have significant and widespread negative consequencesthe U.S. Supreme Court considers any petition for review.All of the national economy and major U.S. industrial enterprises, including AEP and our customers.final requirements are currently the subject of litigation in the federal courts.


39


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.  Weits 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 recoverrecovers expenditures for pollution control technologies, replacement generation, undepreciated plant balances and associated operating costs of complying with new requirements such as the potential CO2 and other greenhouse gases emission standards from customers through regulated rates in regulated jurisdictions.  For our sales of energy based on market rate authority, however, there is no such recovery mechanism.  Failure to recover these costs should they arise, 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.


AEP’s financial performance may be adversely affected if the merchant generation fleet is not profitable or loses value. (Applies to AEP)
41
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 we receiveAEP receives from the results of PJM capacity auctions associated with our nonregulated generation assets could fail to adequately compensate us. – Affecting AEPAEP. (Applies to AEP)

At the end of last year, AGR acquired most of the generation formerly owned by OPCo.  Recovery ofFinancial returns on AGR’s generation capacity isare subject to the results of annual PJM capacity auctions.  Recent auctionAuction results indicate a great deal of volatility and the possibility of clearing prices substantially lower than the cost of such capacity.  We formed a coalition with other utility companies to address mutual concerns related toIf the auction process and PJM has made filings with the FERC seeking modification of that process.  Additional filings are expected.  We can give no assurance that the FERC will approve any modifications to the annual PJM capacity auctions.  If the annual PJM capacity auctions continue to result in clearing prices lower than the cost of ourAEP’s capacity, it could reduce our future net income and cash flows and impactharm 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 seeking damages based on allegations of federal and state common law nuisance in which we,AEP, among others, were defendants.  In general, the actions allege that CO2emissions 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.

Changes in technology and regulatory policies may cause ourlower the value of generating facilitiesfacilities. (Applies to be less competitive.  – Affecting each Registrantall Registrants)

WeAEP primarily generategenerates 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, windmillsand (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.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

40


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 our results of operations.

Our profitabilityFurther, 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 ourAEP’s continued authorization to sell power at market-based rates. – Affecting each Registrant(Applies to all Registrants)

FERC has granted AEGCo, AGR, APCo, I&M, KPCo, OPCo, PSO and SWEPCo authority to sell electricity at market-based rates (except in our balancing authority area of the SPP where our wholesale power transactions are cost-capped by FERC).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 our results of operations.

Our revenuesRevenues 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
42
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 and/or incentives.
Federal, state and foreign energy and environmental regulation and legislation and/or incentives.
RTO market structures.


41


Commodity trading and marketing activities are subject to inherent risks which can be reduced and controlled but not eliminated. – Affecting each Registrant(Applies to all Registrants)

We attempt to manage theThe exposure of orAEP’s power trading activities is 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 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.

We may not successfully manage the uncertainty involved with our power trading (including coal, natural gas and emission allowances trading and power marketing). – Affecting each Registrant

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

For example, the use of new technologies to recover natural gas from shale deposits has increased natural gas supply and reserves, placing further downward pressure on natural gas prices and has reduced the need for our coal-fired generation. Further, in the event that alternative generation resources, such as wind and solar, are mandated or otherwise subsidized or encouraged through climate legislation or regulation and added to the available generation supply, such resources could displace a higher marginal cost fossil plant, which could reduce the price at which
43
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 our financial condition, results of operations and cash flows, and could also result in an impairment of certain long-lived assets.

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

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.

44

ITEM 1B.   UNRESOLVED STAFF COMMENTS

None.

ITEM 2.   PROPERTIES

GENERATION FACILITIES

As of December 31, 2013, and after giving effect to the year-end affiliate disposition and acquisition of the former generation assets and related liabilities of OPCo,2015 the AEP System owned (or leased where indicated) generation 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:

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
  

(a)Rockport, Unit 2 is leased.
(b)The capacity and output of this plant is under contract to (and its financial impact is included with) AGR through 2017.

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 (b) 6 IN Natural Gas 1,186 2004
Total MWs       2,496  
           
(a)Rockport, Unit 2 is leased.
(b)The capacity and output of this plant is under contract to (and its financial impact is included with) AGR through 2017.
  
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 3 WV Steam - Coal 2,900 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       7,885   
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
  

(a)Clinch River Unit 3 was retired on May 31, 2015. Clinch River Units 1 and 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.


43
45


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
  

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.
(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 Unit 2Cook Plant
   Unit 1 Unit 2
Year Placed in Operation1975 19781975
 1978
Year of Expiration of NRC License2034 20372034
 2037
Nominal Net Electrical Rating in Kilowatts1,084,000 1,107,0001,084,000
 1,107,000
Annual Capacity Utilization      
201582.4% 89.7%
201482.7% 86.9%
201382.7% 86.9%96.9% 87.4%
201296.9% 87.4%
201181.3% 99.4%
201082.2% 80.8%

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
Mitchell (a) 2 WV Steam - Coal 780 1971
Total MWs       1,858  
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.  AGRWPCo 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.

PSO          
          Year Plant
        Net Maximum or First Unit
Plant Name Units State Fuel Type Capacity (MWs) Commissioned
Comanche 3 OK Natural Gas 266 1973
Riverside, Units 3 and 4 2 OK Natural Gas 151 2008
Southwestern, Units 4 and 5 2 OK Natural Gas 170 2008
Tulsa 2 OK Natural Gas 307 1956
Weleetka 3 OK Natural Gas 200 1975
Northeastern, Units 3 and 4 2 OK Steam - Coal 940 1979
Oklaunion (a) 1 TX Steam - Coal 101 1986
Northeastern, Units 1 and 2 2 OK Steam - Natural Gas 918 1961
Riverside, Units 1 and 2 2 OK Steam - Natural Gas 908 1974
Southwestern, Units 1, 2 and 3 3 OK Steam - Natural Gas 466 1952
Total MWs       4,427  
 
(a) Jointly-owned with TNC and non-affiliated entities.  Figures presented reflect only the portion owned by PSO.

46
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.

SWEPCo          
          Year Plant
        Net Maximum or First Unit
Plant Name Units State Fuel Type Capacity (MWs) Commissioned
Mattison 4 AR Natural Gas 313 2007
Stall 1 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 257 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 4 LA Steam - Natural Gas 242 1947
Lone Star 1 TX Steam - Natural Gas 50 1954
Wilkes 3 TX Steam - Natural Gas 838 1964
Total MWs       5,724  
           
(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 (formerly owned by OPCo)
          
         Year Plant
       Net Maximum or First Unit
AGR
          
Plant NamePlant Name Units State Fuel Type Capacity (MWs) Commissioned Units State Fuel Type 
Net Maximum
Capacity (MWs)
 
Year Plant
 or First Unit Commissioned
RacineRacine 2 OH Hydro 48 1982 2 OH Hydro 48
 1982
DarbyDarby 6 OH Natural Gas 507 2001 6 OH Natural Gas 510
 2001
WaterfordWaterford 4 OH Natural Gas 840 2003 4 OH Natural Gas 840
 2003
Beckjord (a) 1 OH Steam - Coal 53 1969
CardinalCardinal 1 OH Steam - Coal 595 1967 1 OH Steam - Coal 595
 1967
Conesville (a)Conesville (a) 3 OH Steam - Coal 1,139 1957 3 OH Steam - Coal 1,159
 1957
GavinGavin 2 OH Steam - Coal 2,640 1974 2 OH Steam - Coal 2,670
 1974
Kammer 3 WV Steam - Coal 630 1958
Mitchell (b)Mitchell (b) 2 WV Steam - Coal 780 1971 2 WV Steam - Coal —
 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)Stuart (a) 4 OH Steam - Coal 600 1971 4 OH Steam - Coal 600
 1971
Zimmer (a)Zimmer (a) 1 OH Steam - Coal 330 1991 1 OH Steam - Coal 330
 1991
Total MWs(c)
       10,002  
(a)Jointly-owned with nonaffiliated entities.  Figures presented reflect only the portion owned by AGR.
(b)AGR owns a 50% interest in the Mitchell Units.  KPCo owns the remaining 50%.
(c)AGR has contractual rights through 2017 to a natural gas-fired 1,186 MW generating unit located in Lawrenceburg, IN.
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          
        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  

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.

47


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.

Vertically Integrated Utilities Segment

 Total Overhead Circuit Miles of Transmission and Distribution Lines Circuit Miles of 765kV Lines
APCo51,594 731
I&M21,869 614
KGPCo1,404 -
KPCo11,159 257
PSO20,822 -
SWEPCo27,372 -
WPCo1,728 -
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 Circuit Miles of 765kV Lines
OPCo (a)45,530 508
TCC29,355 -
TNC17,046 -
    
(a)Includes 766 miles of 345,000 volt jointly owned lines.
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.

AEP 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
ETT1,3401,544
IMTCo1962
OHTCo47310
OKTCo217256
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.

48


SYSTEM TRANSMISSION LINES AND FACILITY SITING

Laws in the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Tennessee, Texas, 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 $3.8$5 billion of construction expenditures for 2014, excluding equity AFUDC 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.  For additional information on ourAEP’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 Expenditures for each Registrant.Expenditures.

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 ourAEP’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 6 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 6 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 AGR and KPCo, through its use oftheir interest in the Conner Run fly ash impoundment, isare subject to the provisions of the Mine Act.

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 and Conner Run under the Mine Act for the yearquarter ended December 31, 2013.2015.


48
49


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 14 to the consolidated financial statements entitled Financing Activities under the heading Dividend Restrictions in the 20132015 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 2013, 20122015, 2014 and 20112013 are incorporated by reference to the material under Statements of Changes in Common Shareholder’s Equity and Note 14 to the consolidated financial statements entitled Financing Activities under the heading Dividend Restrictions in the 20132015 Annual Reports.

During the quarter ended December 31, 2013,2015, 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 20132015 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 20132015 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 20132015 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 20132015 Annual Reports.


49


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 20132015 Annual Reports.

50


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 2013,2015, 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 Registrant 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, 2013,2015, 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.

The only changeThere 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 20132015 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting, relates to Ohio Power Company’s corporate separation.  On December 31, 2013, Ohio Power Company transferred its generation assets and related liabilities to AEP Generation Resources Inc, a subsidiary of AEP.  Certain of those generation assets and related liabilities were subsequently transferred to Appalachian Power Company and Kentucky Power Company.  In addition to the transfer of the generation assets and related liabilities, the Interconnection Agreement among AEP’s East zone public utility subsidiaries was terminated and replaced with a new Power Coordination Agreement among Appalachian Power Company, Kentucky Power Company and Indiana Michigan Power Company.  In connection with these activities, American Electric Power Company, Inc., Appalachian Power Company, Indiana Michigan Power Company and Ohio Power Company implemented or modified a number of business processes and controls.reporting.

Management assessed and reported on the effectiveness of its internal control over financial reporting as of December 31, 2013.2015.  As a result of that assessment, management determined that there were no material weaknesses as of December 31, 20132015 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 20132015 Annual Report of each Registrant.

ITEM 9B.   OTHER INFORMATION

None.

50
51



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 20142016 Annual Meeting of Shareholders (the 20142016 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 20142016 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 20142016 Annual Meeting including under the captions “Compensation Discussion and Analysis,” “Executive Compensation”, “Director Compensation” and “2013“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.


51
52



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 20142016 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, 2013:2015:

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 (a)
Equity Compensation Plans Approved by Security Holders 
-
—
 $NA 15,972,6999,975,626
Equity Compensation Plans Not Approved by Security Holders -—
  -—
 -—
Total -—
 $NA 15,972,6999,975,626

(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 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 2,687,883 higher if equity compensation that is paid in cash were not deducted from this column.
NANA    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 20142016 Annual Meeting under the captions “Transactions with Related Persons” and “Director Independence.”


52


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 20142016 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.”

53


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 20142016 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, 20132015 and 2012,2014, 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
 2013 2012 2013 2012 2013 2012APCo I&M OPCo
               2015 2014 2015 2014 2015 2014
Audit FeesAudit Fees $2,342,744 $2,026,590  $1,552,346 $1,447,948  $3,119,885 $2,459,868 $2,123,309
 $2,103,482
 $1,638,081
 $1,563,434
 $1,166,775
 $1,111,667
Audit-Related FeesAudit-Related Fees  104,923 57,556   51,488 47,022   128,535  60,901 125,961
 108,305
 70,341
 53,508
 94,931
 83,594
Tax FeesTax Fees  22,556  22,623   16,677  16,806   278,029  28,842 24,603
 26,915
 20,255
 21,117
 39,696
 15,719
TotalTotal $2,470,223 $2,106,769  $1,620,511 $1,511,776  $3,526,449 $2,549,611 $2,273,873
 $2,238,702
 $1,728,677
 $1,638,059
 $1,301,402
 $1,210,980

  PSO SWEPCo
  2013 2012 2013 2012
           
Audit Fees $641,720 $612,686  $1,131,155 $1,014,601 
Audit-Related Fees  21,920  25,125   102,633  778,130 
Tax Fees  7,100  7,177   12,505  11,413 
Total $670,740 $644,988  $1,246,293 $1,804,144 

  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
 

53
54


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, 2013, 2012 and 2011; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011; Consolidated Statements of Changes in Equity for the years ended December 31, 2013, 2012 and 2011; Consolidated Balance Sheets as of December 31, 2013 and 2012; Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011; Notes to Consolidated Financial Statements.
APCo, I&M and OPCo:
Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011; Consolidated Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2013, 2012 and 2011; Consolidated Balance Sheets as of December 31, 2013 and 2012; Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011; 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, 2013, 2012 and 2011; Statements of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011; Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2013, 2012 and 2011; Balance Sheets as of December 31, 2013 and 2012; Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011; 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, 2013, 2012 and 2011; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011; Consolidated Statements of Changes in Equity for the years ended December 31, 2013, 2012 and 2011; Consolidated Balance Sheets as of December 31, 2013 and 2012; Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011; 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

54
55


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 25, 201423, 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 and Director
 February 25, 201423, 2016
(Nicholas K. Akins)   
     
 
(ii)Principal Financial Officer:    
     
/s/   Brian X. Tierney Executive Vice President and Chief Financial Officer February 25, 201423, 2016
(Brian X. Tierney) Chief Financial Officer  
     
(iii)Principal Accounting Officer:    
     
/s/   Joseph M. Buonaiuto Senior Vice President, Controller and Chief Accounting Officer February 25, 201423, 2016
(Joseph M. Buonaiuto) Chief Accounting Officer  
     
(iv)           A Majority of the Directors:    
     
*Nicholas K. Akins    
*David J. Anderson    
*J. 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 25, 201423, 2016
                                          (Brian(Brian X. Tierney, Attorney-in-Fact)    


55
56


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 25, 201423, 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//s/   Nicholas K. Akins Chairman of the Board, Chief Executive Officer and Director February 25, 201423, 2016
(Nicholas K. Akins) Chief Executive Officer and Director  
     
(ii)Principal Financial Officer:    
     
              /s/
/s/   Brian X. Tierney Vice President,February 25, 2014
             (Brian X. Tierney)Chief Financial Officer and DirectorFebruary 23, 2016
(Brian X. Tierney)  
     
(iii) Principal Accounting Officer:    
     
/s/   Joseph M. Buonaiuto Controller and Chief Accounting Officer February 25, 201423, 2016
 (Joseph(Joseph M. Buonaiuto) Chief Accounting Officer  
     
(iv)A Majority of the Directors:    
     
 *Nicholas*Nicholas K. Akins    
 *Lisa*Lisa M. Barton    
              *David
*David M. Feinberg
              *Lana L. Hillebrand
    
 *Mark*Lana L. Hillebrand
*Mark C. McCullough    
 *Robert*Robert P. Powers    
 *Dennis E. WelchBrian X. Tierney    
     
*By:                                                                          ��         /s/   Brian X. Tierney   February 25, 201423, 2016
 (Brian X. Tierney, Attorney-in-Fact)    


56
57


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 25, 201423, 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 25, 201423, 2016
(Nicholas K. Akins) Chief Executive Officer and Director  
     
(ii)Principal Financial Officer:    
     
/s/   Brian X. Tierney Vice President, Chief Financial Officer and Director February 25, 201423, 2016
(Brian X. Tierney) Chief Financial Officer and Director  
     
(iii)Principal Accounting Officer:    
     
/s/   Joseph M. Buonaiuto Controller and Chief Accounting Officer February 25, 201423, 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    
*Thomas A. Kratt    
*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 25, 201423, 2016
 (Brian X. Tierney, Attorney-in-Fact)    


57
58


INDEX OF FINANCIAL STATEMENT SCHEDULES

 
Page
Number
Reports of Independent Registered Public Accounting Firm
S-2
  
The following financial statement schedules are included in this report on the pages indicated: 
  
American Electric Power Company, Inc. (Parent): 
Schedule I – Condensed Financial Information
S-3
Schedule I – Index of Condensed Notes to Condensed Financial Information
S-7
  
American Electric Power Company, Inc. and Subsidiary Companies: 
Schedule II – Valuation and Qualifying Accounts and Reserves
S-10
  
Appalachian Power Company and Subsidiaries: 
Schedule II – Valuation and Qualifying Accounts and Reserves
S-10
  
Indiana Michigan Power Company and Subsidiaries: 
Schedule II – Valuation and Qualifying Accounts and Reserves
S-10
  
Ohio Power Company and Subsidiaries: 
Schedule II – Valuation and Qualifying Accounts and Reserves
S-10
S-11
  
Public Service Company of Oklahoma: 
Schedule II – Valuation and Qualifying Accounts and Reserves
S-11
  
Southwestern Electric Power Company Consolidated: 
Schedule II – Valuation and Qualifying Accounts and Reserves
S-11


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, 20132015 and 2012,2014, and for each of the three years in the period ended December 31, 2013,2015, and the Company's internal control over financial reporting as of December 31, 2013,2015, and have issued our reports thereon dated February 25, 2014;23, 2016; such consolidated financial statements and reports are included in the Company’s 20132015 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 25, 201423, 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 subsidiaries, Public Service Company of Oklahoma, and Southwestern Electric Power Company Consolidated (collectively the “Companies”) as of December 31, 20132015 and 2012,2014, and for each of the three years in the period ended December 31, 2013,2015, and have issued our reports thereon dated February 25, 2014;23, 2016; such financial statements and reports are included in the Companies’ 20132015 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 25,23, 2016

S-2


SCHEDULE I
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)
  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

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


S-3
S-2


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

SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2013, 2012 and 2011
(in millions, except per-share and share amounts)
           
   Years Ended December 31,
  2013  2012  2011 
REVENUES         
Affiliated Revenues $ 4  $ 4  $ 5 
           
EXPENSES         
Other Operation   21    22    23 
          
OPERATING LOSS   (17)   (18)   (18)
          
Other Income (Expense):         
Interest Income   21    22    19 
Interest Expense   (17)   (90)   (42)
          
LOSS BEFORE INCOME TAX CREDIT AND         
 EQUITY EARNINGS   (13)   (86)   (41)
          
Income Tax Credit   -    -    2 
Equity Earnings of Unconsolidated Subsidiaries   1,493    1,345    1,980 
           
NET INCOME   1,480    1,259    1,941 
           
Other Comprehensive Income (Loss)   217    133    (89)
           
TOTAL COMPREHENSIVE INCOME $ 1,697  $ 1,392  $ 1,852 
           
WEIGHTED AVERAGE NUMBER OF BASIC AEP         
 COMMON SHARES OUTSTANDING   486,619,555    484,682,469    482,169,282 
           
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE         
 TO AEP COMMON SHAREHOLDERS $ 3.04  $ 2.60  $ 4.02 
           
WEIGHTED AVERAGE NUMBER OF DILUTED AEP         
 COMMON SHARES OUTSTANDING   487,040,956    485,084,694    482,460,328 
           
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE         
 TO AEP COMMON SHAREHOLDERS $ 3.04  $ 2.60  $ 4.02 
          
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
S-3


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

SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED BALANCE SHEETS
ASSETS
December 31, 2013 and 2012
(in millions)
 
        December 31,
  2013  2012 
CURRENT ASSETS      
Cash and Cash Equivalents $ 36  $ 166 
Other Temporary Investments   2    2 
Advances to Affiliates   539    650 
Accounts Receivable:      
 General   -    71 
 Affiliated Companies   11    36 
  Total Accounts Receivable   11    107 
Prepayments and Other Current Assets   6    5 
TOTAL CURRENT ASSETS   594    930 
       
PROPERTY, PLANT AND EQUIPMENT      
General   1    1 
Total Property, Plant and Equipment   1    1 
Accumulated Depreciation and Amortization   1    1 
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET   -    - 
       
OTHER NONCURRENT ASSETS      
Investments in Unconsolidated Subsidiaries   16,353    15,679 
Affiliated Notes Receivable   80    285 
Deferred Charges and Other Noncurrent Assets   57    54 
TOTAL OTHER NONCURRENT ASSETS   16,490    16,018 
       
TOTAL ASSETS $ 17,084  $ 16,948 
       
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-5
S-4


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

SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2013 and 2012
(dollars in millions)
 
        December 31,
  2013  2012 
CURRENT LIABILITIES  
Advances from Affiliates $ 41  $ - 
Accounts Payable:      
 General   -    1 
 Affiliated Companies   13    435 
Long-term Debt Due Within One Year   4    5 
Short-term Debt   57    321 
Other Current Liabilities   5    74 
TOTAL CURRENT LIABILITIES   120    836 
       
NONCURRENT LIABILITIES      
Long-term Debt   836    847 
Deferred Credits and Other Noncurrent Liabilities   43    28 
TOTAL NONCURRENT LIABILITIES   879    875 
       
TOTAL LIABILITIES   999    1,711 
       
       
COMMON SHAREHOLDERS' EQUITY      
Common Stock – Par Value – $6.50 Per Share:      
   2013  2012        
 Shares Authorized600,000,000  600,000,000        
 Shares Issued508,113,964  506,004,962        
(20,336,592 Shares were Held in Treasury as of December 31, 2013 and 2012)   3,303    3,289 
Paid-in Capital   6,131    6,049 
Retained Earnings   6,766    6,236 
Accumulated Other Comprehensive Income (Loss)   (115)   (337)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY   16,085    15,237 
       
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 17,084  $ 16,948 
         
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-6
S-5



SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2013, 2012 and 2011
(in millions)
             
     Years Ended December 31,
  2013  2012  2011 
OPERATING ACTIVITIES         
Net Income $  1,480  $  1,259  $  1,941 
Adjustments to Reconcile Net Income to Net Cash Flows         
 from Operating Activities:         
  Equity Earnings of Unconsolidated Subsidiaries   (1,493)   (1,345)   (1,980)
  Cash Dividends Received from Unconsolidated Subsidiaries   1,027    1,294    1,113 
  Change in Other Noncurrent Assets   2    13    2 
  Change in Other Noncurrent Liabilities   16    22    20 
  Changes in Certain Components of Working Capital:         
   Accounts Receivable, Net   96    (47)   72 
   Accounts Payable   (423)   (10)   (103)
   Other Current Liabilities   (73)   72    (3)
Net Cash Flows from Operating Activities   632    1,258    1,062 
          
INVESTING ACTIVITIES         
Purchases of Investment Securities   -    -    (69)
Sales of Investment Securities   -    -    166 
Change in Advances to Affiliates, Net   111    294    (388)
Capital Contributions to Unconsolidated Subsidiaries   (358)   (325)   (99)
Return of Capital Contributions from Unconsolidated Subsidiaries   375    -    - 
Repayments of Notes Receivable from Affiliated Companies   205    5    5 
Net Cash Flows from (Used for) Investing Activities   333    (26)   (385)
          
FINANCING ACTIVITIES         
Issuance of Common Stock, Net   84    83    92 
Issuance of Long-term Debt   199    843    - 
Commercial Paper and Credit Facility Borrowings   -    -    429 
Change in Short-term Debt, Net   (264)   (646)   769 
Retirement of Long-term Debt   (200)   (558)   - 
Change in Advances from Affiliates, Net   41    -    (295)
Commercial Paper and Credit Facility Repayments   -    -    (881)
Dividends Paid on Common Stock   (949)   (911)   (892)
Other Financing Activities   (6)   (4)   (3)
Net Cash Flows Used for Financing Activities   (1,095)   (1,193)   (781)
          
Net Increase (Decrease) in Cash and Cash Equivalents   (130)   39    (104)
Cash and Cash Equivalents at Beginning of Period   166    127    231 
Cash and Cash Equivalents at End of Period $  36  $  166  $  127 
          
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, 2013.2015.  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.  AEP System’s current consolidated federal income tax is allocated to 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 6 in the 20132015 Annual Reports.

3.  FINANCING ACTIVITIES

The following details long-term debt outstanding as of December 31, 20132015 and 2012:2014:

Long-term Debt
        
   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, 2013 2013  2012  2013  2012 
         (in millions)
 Senior Unsecured Notes            
  2017-2022 2.11% 1.65% - 2.95% 1.65% - 2.95% $ 850  $ 850 
               
 Fair Value of Interest Rate Hedges         (9)   3 
 Unamortized Discount, Net         (1)   (1)
 Total Long-term Debt Outstanding         840    852 
 Long-term Debt Due Within One Year         4    5 
 Long-term Debt       $ 836  $ 847 
Long-term Debt
  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, 20132015 is payable as follows:

          After  
2014  2015  2016  2017  2018  2018  Total2016 2017 2018 2019 2020 After 2020 Total
(in millions)(in millions)
Principal Amount$ 4  $ 1  $ (4) $ 540  $ -  $ 300  $ 841 $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                $ 840          
  
 $843.4


S-8
S-8



Short-term Debt

Short-term Debt
               
Parent's outstanding short-term debt was as follows:
               
    December 31,
    2013  2012 
    Outstanding Weighted Average Outstanding Weighted Average
 Type of DebtAmountInterest Rate AmountInterest Rate
   (in millions)    (in millions)   
 Commercial Paper $ 57   0.29 % $ 321   0.42 %
 Total Short-term Debt $ 57     $ 321    
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 $7 thousand, $11$2 million, $413 thousand and $199$7 thousand for the years ended December 31, 2013, 20122015, 2014 and 2011,2013, 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 $4 million, $5$4 million and $3$4 million for the years ended December 31, 2013, 20122015, 2014 and 2011,2013, 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 $15 million for the years ended December 31, 2015, 2014 and 2013, 2012 and 2011, respectively.

S-9


SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
AEP   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 $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    
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    
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

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

S-10
S-9



SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
 
AEP   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 millions)
Deducted from Assets:               
Accumulated Provision for Uncollectible               
  Accounts:               
  Year Ended December 31, 2013 $ 36  $ 51  $ 21  $ 48  $ 60 
  Year Ended December 31, 2012   32    53    3    52    36 
  Year Ended December 31, 2011   41    37    2    48    32 
                  
(a)Recoveries offset by reclasses to other liabilities.
(b)Uncollectible accounts written off.
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.
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, 2013 $ 6,087  $ 4,737  $ 1,768  $ 10,149  $ 2,443 
  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 
                  
(a)Recoveries offset by reclasses to other liabilities.
(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.
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, 2013 $ 229  $ (40)(c)$ -  $ 5  $ 184 
  Year Ended December 31, 2012   1,750    20    -    1,541    229 
  Year Ended December 31, 2011   1,692    151    -    93    1,750 
                  
(a)Recoveries offset by reclasses to other 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

OPCo   Additions    Distribution  
    Balance at Charged to Charged to    of OPCo Balance at
    Beginning Costs and Other    Generation End of
Description of Period Expenses Accounts (a) Deductions (b)  to Parent Period
  (in thousands)
Deducted from Assets:                  
Accumulated Provision for Uncollectible                  
  Accounts:                  
  Year Ended December 31, 2013 $ 129  $ 15,722  $ 19,191  $ 51  $ (7) $ 34,984 
  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 
                     
(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, 2013 $ 872  $ (122)(c) $ -  $ 288  $ 462 
  Year Ended December 31, 2012   777    95     -    -    872 
  Year Ended December 31, 2011   971    (194)(c)   -    -    777 
                   
(a)Recoveries on accounts previously written off.
(b)Uncollectible accounts written off.
(c)Recoveries on previous reserve balance.

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, 2013 $ 2,041  $ (143)(c) $ 2  $ 482  $ 1,418 
  Year Ended December 31, 2012   989    71     981    -    2,041 
  Year Ended December 31, 2011   588    149     376    124    989 
                   
(a)Recoveries on accounts previously written off.
(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.2012 Form 10-K, Ex 4(c)
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. 20122014 Form 10-K, Ex 4(d)4(b)
     
4(e)4(c) $11.75 Billion TermThird Amended and Restated Credit Agreement, dated as of July 17, 2013,November 10, 2014, among AEP, APCo, OPCo, AEP Generation Resources Inc., 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. Form 10Q, Ex 4, June 30, 2013
[10(a)Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, OPCo and I&M and with AEPSC, as amended.
Registration Statement No. 2-52910, Ex 5(a)
Registration Statement No. 2-61009, Ex 5(b)
19902014 Form 10-K, Ex 10(a)(3)]4(c)

     
*10(b)Restated and Amended Operating Agreement, among PSO, SWEPCo and AEPSC, effective as of March 1, 2014.
E-1
Exhibit
Designation
Nature of Exhibit
Previously Filed as Exhibit to:
*10(c)10(a) Transmission Agreement, effective November 2010, among APCo, CSPCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent. 2013 Form 10-K, Ex 10(c)
     
10(d)10(b) Transmission Coordination Agreement dated January 1, 1997, restated and amended by and among PSO, SWEPCo and AEPSC. 2009 FromForm 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, 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)
     
†10(l)(3)10(k)(1)(A) First Amendment to AEPSC Umbrella Trust for Executives. 
2008 Form 10-K, Ex10(l)(3)(A)
E-2
Exhibit
Designation
Nature of Exhibit
Previously Filed as Exhibit to:
     
†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 14, 2014.1, 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)
     
†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)
E-3
Exhibit
Designation
Nature of Exhibit
Previously Filed as Exhibit to:
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(w)10(v) AEP Executive Severance Plan Amended and Restated effective January 1, 2014.25, 2016. Form 8-K, Ex 10.1 dated January 15, 2014
     
*†10(x)10(w) Letter Agreement dated November 20, 2012 between AEPSC and Lana Hillebrand 2013 Form 10-K, Ex 10(s)
     
*12 Statement re: Computation of Ratios.  
     
*13 Copy of those portions of the AEP 20132015 Annual Report (for the fiscal year ended December 31, 2013)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
     
4(c)$1 Billion Term Credit Agreement, dated as of July 17, 2013, among AEP, APCo, OPCo, AEP Generation Resources Inc., the banks, financial institutions and other institutional lenders listed on the signature pages thereof, and Wells Fargo Bank, National Association, as Administrative Agent.Form 10Q, Ex 4, June 30, 2013
*10(a) Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010. 2013 Form 10-K, Ex 10(a)
     
[10(b)Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, OPCo and I&M 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(c) Transmission Agreement, effective November 2010, among APCo, CSPCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent. 2013 Form 10-K, Ex 10(c)
     
10(d)10(c) 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)
E-5
Exhibit
Designation
Nature of Exhibit
Previously Filed as Exhibit to:
     
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)
     
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, as modifiedmodified. 
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 20132015 Annual Report (for the fiscal year ended December 31, 2013)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  
E-6
Exhibit
Designation
Nature of Exhibit
Previously Filed as Exhibit to:
     
3(a) Composite of the Amended Articles of Acceptance of I&M, dated of March 7, 1997. 1996 Form 10-K, Ex 3(c)
     
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)
Registration Statement No. 333-207836, Ex 4(b)
     
4(b)Company Order and Officers Certificate to The Bank of New York Mellon dated March 18, 2013 of 3.20% Series J due 2023.Form 8-K, Ex 4(a) dated March 18, 2013
*10(a) Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010. 2013 Form 10-K, Ex 10(a)
     
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, effective November 2010, among APCo, CSPCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent. 2013 Form 10-K, Ex 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)
     
[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) Consent Decree with U.S. District Court, as modified. 
Form 8-K, Ex 10.1 dated October 9, 2007
Form 10-Q, Ex 10, June 30, 2013
     
10(g)10(f) 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


E-7
Exhibit
Designation
 
Nature of Exhibit
 
Previously Filed as Exhibit to:
   
*13 Copy of those portions of the I&M 20132015 Annual Report (for the fiscal year ended December 31, 2013)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  
     
2(a) Asset Contribution Agreement effective as of December 31, 2013 by and between Ohio Power Company and AEP Generation Resources Inc. Form 8-K, Ex 2.1 dated December 31, 2013
     
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
E-8
Exhibit
Designation
Nature of Exhibit
Previously Filed as Exhibit to:
     
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
     
4(i)$1 Billion Term Credit Agreement, dated as of July 17, 2013, among AEP, APCo, OPCo, AEP Generation Resources Inc., the banks, financial institutions and other institutional lenders listed on the signature pages thereof, and Wells Fargo Bank, National Association, as Administrative Agent.Form 10Q, Ex 4, June 30, 2013
*10(a)
 
 Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010. 
E-9
Exhibit
Designation
Nature of Exhibit
Previously Filed as Exhibit to:
2013 Form 10-K, Ex 10(a)
     
[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 1-3525]
*10(c) Transmission Agreement, effective November 2010, among APCo, CSPCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent. 2013 Form 10-K, Ex 10(a)
     
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)10(c) 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, as modified. 
Form 8-K, Item Ex 10.1 dated October 9, 2007
Form 10-Q, Ex 10, June 30, 2013
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), September 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)
     
*12 Statement re: Computation of Ratios.  
     
*13 Copy of those portions of the OPCo 20132015 Annual Report (for the fiscal year ended December 31, 2013)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.  
E-10
Exhibit
Designation
Nature of Exhibit
Previously Filed as Exhibit to:
     
*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)
     
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, effective as of March 1, 2014.
E-11
Exhibit
Designation
Nature of Exhibit
Previously Filed as Exhibit to:
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 20132015 Annual Report (for the fiscal year ended December 31, 2013)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.  
  

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.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.  
   
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)
E-12
Registration Statement No. 333-194991, Ex 4(b)(c)
Exhibit
Designation
Nature of Exhibit
Previously Filed as Exhibit to:Registration Statement No. 333-208535, 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, SWEPCo and AEPSC, effective as of March 1, 2014.
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 SWEPCo 20132015 Annual Report (for the fiscal year ended December 31, 2013)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.  
     
*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.  
E-13
Exhibit
Designation
Nature of Exhibit
Previously Filed as Exhibit to:
     
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