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

xTANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended December 31, 20102011

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.AMERICAN ELECTRIC POWER COMPANY, INC.  (A New York Corporation)
 13-4922640
 1-3457 
Appalachian Power Company (AAPPALACHIAN POWER COMPANY (A Virginia Corporation)
 54-0124790
 1-2680
Columbus Southern Power Company (An Ohio Corporation)
31-4154203
1-3570 
Indiana Michigan Power Company (AnINDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)
 35-0410455
 1-6543 
Ohio Power CompanyOHIO POWER COMPANY (An Ohio Corporation)
 31-4271000
 0-343 
Public Service Company ofPUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma (An Oklahoma Corporation)
 73-0410895
 1-3146 
Southwestern Electric Power Company (ASOUTHWESTERN 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 exchangeEach Exchange
on which registeredWhich Registered
American Electric Power Company, Inc. Common Stock, $6.50 par value New York Stock Exchange
Appalachian Power CompanyNone
Columbus Southern Power Company None  
Indiana Michigan Power Company None  
Ohio Power Company None  
Public Service Company of Oklahoma 6% Senior Notes, Series B, Due 2032 New York Stock Exchange
Southwestern Electric Power Company None  


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

RegistrantTitle of each class
American Electric Power Company, Inc.None
Appalachian Power Company4.50% Cumulative Preferred Stock, Voting, no par value
Columbus Southern Power CompanyNone
Indiana Michigan Power CompanyNone
Ohio Power Company4.50% Cumulative Preferred Stock, Voting, $100 par value
Public Service Company of OklahomaNone
Southwestern Electric Power Company4.28% Cumulative Preferred Stock, Voting, $100 par value
4.65% Cumulative Preferred Stock, Voting, $100 par value
5.00% Cumulative Preferred Stock, Voting, $100 par value

Indicate by check mark if the registrants American Electric Power Company, Inc., and Appalachian Power Company is each a well-known seasoned issuer, as defined in Rule 405 on the Securities Act.
Yes  xT
No.No  o
   
Indicate by check mark if the registrants Columbus Southern 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 on the Securities Act.
Yes  o
No.No  xT
   
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.No  xT
   
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  xT
No.No  o
   
Indicate by check mark whether American Electric Power Company, Inc. has, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern 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  xT
No.  o
Indicate by check mark whether Appalachian Power Company, Columbus Southern 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 registrants were required to submit and post such files).
Yes  o
No.No  o
Indicate by check mark if disclosure of delinquent filers with respect to Appalachian Power Company, Ohio Power Company, Public Service Company of Oklahoma or Southwestern Electric Power Company 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 registrant’sregistrants’ knowledge, in definitive proxy or information statements of Appalachian Power Company, Ohio Power Company, Public Service Company of Oklahoma or Southwestern Electric Power Company incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.xo 
   
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                                          xT
 
Accelerated filer                                  o
Non-accelerated filer                                           o (Do not check if a smaller reporting company)
Smaller reporting companyo
   
Indicate by check mark whether Appalachian Power Company, Columbus Southern 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 filer                                          o
 
Accelerated filer                                  o
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.No  xT


Columbus SouthernAppalachian Power Company, and 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, 2010, 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, 2010
 Aggregate Market Value of Voting and Non-Voting Common Equity Held by Non-Affiliates of the Registrants as of June 30, 2011, 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, 2011
American Electric Power Company, Inc. $15,530,071,139 480,807,156 $18,215,373,666 483,422,868
   ($6.50 par value)   ($6.50 par value)
Appalachian Power Company None 13,499,500 None 13,499,500
   (no par value)
Columbus Southern Power Company None 16,410,426
   (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, Columbus Southern 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 into which Document Isis Incorporated
  
Portions of Annual Reports of the following companies for
the fiscal year ended December 31, 2010:2011:
Part II
American Electric Power Company, Inc.
 
Appalachian Power Company
 
Columbus Southern 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 20112012 Annual Meeting of Shareholders.Part III
Portions of Information Statements of the following companies for 2011 Annual Meeting of Shareholders:Part III
Appalachian Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company


This combined Form 10-K is separately filed by American Electric Power Company, Inc., Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company.  Information contained herein relating to any individual registrant is filed by such registrant on its own behalf.  Except for American Electric Power Company, Inc., each registrant makes no representation as to information relating to the other registrants.

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



 
 
 

TABLE OF CONTENTS
Item
Number
Item
Number
 
Page
Number
Item
Number
 
Page
Number
Glossary of Termsi
Glossary of Termsi   
Forward-Looking Informationiv Forward-Looking Informationiv
PART I
1 Business 1Business 
 General1 General1
 Utility Operations11 Utility Operations10
 AEP River Operations23 Transmission Operations23
 Generation and Marketing23 AEP River Operations24
1ARisk Factors24
1BUnresolved Staff Comments36
Generation and Marketing24
Executive Officers of AEP25
1A1ARisk Factors26
1B1BUnresolved Staff Comments38
2 Properties362Properties38
 Generation Facilities36 Generation Facilities38
 Transmission and Distribution Facilities38 Transmission and Distribution Facilities42
 Titles38 Titles42
 System Transmission Lines and Facility Siting38 System Transmission Lines and Facility Siting42
 Construction Program39 Construction Program43
 Potential Uninsured Losses39 Potential Uninsured Losses43
3 Legal Proceedings403Legal Proceedings43
4 (Removed and Reserved)404Mine Safety Disclosure44
 Executive Officers of the Registrant40   
PART II
5 Market For Registrants’ Common Equity, Related Stockholder Matters And Issuer Purchases Of Equity Securities42
Market For Registrants’ Common Equity, Related Stockholder Matters
And Issuer Purchases Of Equity Securities
 
45
6 Selected Financial Data42Selected Financial Data45
7 Management’s Discussion And Analysis Of Financial Condition And Results Of Operations42Management’s Discussion And Analysis Of Financial Condition And Results Of Operations45
7AQuantitative And Qualitative Disclosures About Market Risk42
7AQuantitative And Qualitative Disclosures About Market Risk45
8 Financial Statements And Supplementary Data42Financial Statements And Supplementary Data46
9 Changes In And Disagreements With Accountants On Accounting And Financial Disclosure43Changes In And Disagreements With Accountants On Accounting And Financial Disclosure46
9AControls And Procedures43
9BOther Information43
9AControls And Procedures46
9BOther Information46
PART III
10 Directors, Executive Officers and Corporate Governance44Directors, Executive Officers and Corporate Governance47
11 Executive Compensation45Executive Compensation47
12 Security Ownership Of Certain Beneficial Owners and Management And Related Stockholder Matters45Security Ownership Of Certain Beneficial Owners and Management And Related Stockholder Matters48
13 Certain Relationships and Related Transactions, And Director Independence46Certain Relationships and Related Transactions and Director Independence48
14 Principal Accounting Fees And Services46Principal Accounting Fees And Services48
PART IV
15 Exhibits and Financial Statement Schedules48Exhibits and Financial Statement Schedules50
 Financial Statements48Financial Statements50
 Signatures49Signatures51
 Index to Financial Statement SchedulesS-1Index of Financial Statement SchedulesS-1
 Reports of Independent Registered Public Accounting FirmS-2Reports of Independent Registered Public Accounting FirmS-2
 Exhibit IndexE-1Exhibit IndexE-1


 
 
 

GLOSSARY OF TERMS

TheWhen the following terms and abbreviations or acronyms usedappear in the text of this Form 10-K are definedreport, they have the meanings indicated below:

Abbreviation or AcronymTerm DefinitionMeaning
AECC Arkansas Electric Cooperative Corporation, an unaffiliated corporationa nonaffiliated corporation.
AEGCo AEP Generating Company, an AEP electric utility subsidiary of AEPsubsidiary.
AEP or parentParent American Electric Power Company, Inc., a holding company.
AEP East companies APCo, CSPCo, I&M, KPCo and OPCoOPCo.
AEP Power Pool Members are APCo, CSPCo, I&M, KPCo and OPCo, as parties toOPCo.  The AEP Power Pool shares the Interconnection Agreementgeneration, cost of generation and resultant wholesale off-system sales of the member companies.
AEP River Operations AEP’s inland river transportation subsidiary, AEP River Operations LLC, (formerly AEP MEMCO LLC), operating primarily on the Ohio, Illinois and lower Mississippi riversrivers.
AEPSC American Electric Power Service Corporation, a service company subsidiary ofproviding management and professional services to AEP and its subsidiaries.
AEP System or the System The American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiariessubsidiaries.
AEP TranscoAEP Transmission Company, LLC, a subsidiary of AEP, an intermediate holding company for seven wholly-owned transmission companies.
AEP West companies PSO, SWEPCo, TCC and TNCTNC.
AEP Utilities AEP Utilities, Inc., a subsidiary of AEP, formerly, Central and South West CorporationCorporation.
AFUDC Allowance for funds used during construction (the net cost of borrowed funds, and a reasonable rate of return on other funds, used for construction under regulatory accounting)Funds Used During Construction.
ALJ Administrative law judgejudge.
APCo Appalachian Power Company, a publican AEP electric utility subsidiary of AEPsubsidiary.
APSC Arkansas Public Service CommissionCommission.
Buckeye Buckeye Power, Inc., an unaffiliated corporationa nonaffiliated corporation.
CAA Clean Air ActAct.
CAAA Clean Air Act Amendments of 19901990.
CCS Carbon capture and storage technologytechnology.
CCPCConesville Coal Preparation Company, a subsidiary of OPCo.
CERCLA Comprehensive Environmental Response, Compensation and Liability Act of 19801980.
CLECOCentral Louisiana Electric Company, a nonaffiliated utility company.
CO2
 Carbon dioxide and other greenhouse gasesgases.
Cook Plant The Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M, and located near Bridgman, Michigan&M.
CSPCo Columbus Southern Power Company, a publicthe AEP electric utility subsidiary of AEPthat was merged with and into OPCo effective December 31, 2011.
CSW Central and South West Corporation, a public utility holding company that merged withsubsidiary of AEP in June 2000.(Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Operating Agreement Agreement, dated January 1, 1997, as amended, originally by and among PSO, SWEPCo, TCC and TNC, currently by and between PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third party sales.  AEPSC acts as the agent for the parties.agent.
DHLCDolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
DOE United States Department of EnergyEnergy.
DP&L The Dayton Power and Light Company, an unaffiliateda nonaffiliated utility companycompany.
Duke Ohio Duke Energy Ohio, Inc.
EMF Electric and Magnetic Fields
EPAUnited States Environmental Protection AgencyFields.
EPACT The Energy Policy Act of 20052005.
ERCOT Electric Reliability Council of Texas regional transmission organization.
ESP Electric Security Plans, filed with the PUCO, pursuant to the Ohio AmendmentsAmendments.
ETEC East Texas Electric Cooperative
FERCFederal Energy Regulatory Commission
FPAFederal Power Act
I&MIndiana Michigan Power Company, a public utility subsidiary of AEP
IGCCIntegrated Gasification Combined CycleCooperative.
 

 
i
 

Abbreviation or AcronymTerm DefinitionMeaning
ETTElectric Transmission Texas, LLC, a joint venture established to construct, fund, own and operate electric transmission assets within ERCOT.
FERCFederal Energy Regulatory Commission.
Federal EPAUnited States Environmental Protection Agency.
FPAFederal Power Act.
GHGGreenhouse gases.
I&MIndiana Michigan Power Company, an AEP electric utility subsidiary.
IGCCIntegrated Gasification Combined Cycle.
Interconnection Agreement Agreement, dated July 6, 1951, as amended,An agreement by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plantsplants.
IURC Indiana Utility Regulatory CommissionCommission.
KgPCoKGPCo Kingsport Power Company, a publican AEP electric utility subsidiary of AEPsubsidiary.
KPCo Kentucky Power Company, a publican AEP electric utility subsidiary of AEPsubsidiary.
KPSC Kentucky Public Service CommissionCommission.
Lawrenceburg Plant A 1,146 MW gas-fired unit owned by AEGCo and located near Lawrenceburg, IndianaIndiana.
LLWPA Low-Level Waste Policy Act of 19801980.
LPSC Louisiana Public Service Commission
Commission.
MISO Midwest Independent Transmission System OperatorOperator.
Moody’s Moody’s Investors Service, Inc.
MW MegawattMegawatt.
MWHMegawatthour.
NOx
 Nitrogen oxideoxide.
Nonutility Money PoolAEP’s Nonutility Money Pool is the centralized funding mechanism AEP uses to meet the short term cash requirements of pool participants.
NPC National Power Cooperatives, Inc., an unaffiliated corporationa nonaffiliated corporation.
NRC Nuclear Regulatory CommissionCommission.
NSR Consent Decree The 2007 settlement with the Federal EPA, the United States Department of Justice, certain states and special interest groups that ended the litigation which had alleged that APCo, CSPCo, I&M and OPCo violated the new source review requirements of the CAA.
OASIS Open Access Same-time Information SystemSystem.
OATT Open Access Transmission Tariff, filed with FERCFERC.
OCC Corporation Commission of the State of OklahomaOklahoma.
Ohio Act Ohio electric restructuring legislationlegislation.
Ohio Amendments Amendments to the Ohio Act adopted in April 2008 which required electric utilities to adjust their rates by filing an ESP with the PUCOPUCO.
OHTCoAEP Ohio Transmission Company, Inc.
OKTCoAEP Oklahoma Transmission Company, Inc.
OPCo Ohio Power Company, a publican AEP electric utility subsidiary of AEPsubsidiary.
OSS Off-system salessales.
OVEC Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo together own ais 43.47% equity interestowned by AEP.
PJM PJM Interconnection, L.L.C., aPennsylvania – New Jersey – Maryland regional transmission organizationorganization.
PM Particulate Matter
Power PoolThe pooled generation resources of AEP East companies established under the Interconnection AgreementMatter.
PSO Public Service Company of Oklahoma, a publican AEP electric utility subsidiary of AEPsubsidiary.
PUCO Public Utilities Commission of OhioOhio.
PUCT Public Utility Commission of TexasTexas.
RCRA Resource Conservation and Recovery Act of 1976, as amendedamended.
REP Texas retail electricity providerprovider.
Rockport Plant A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned and partly leased by AEGCo and I&M (two 1,300 MW, coal-fired) located near Rockport, Indiana&M.
ROE Return on EquityEquity.
RTO Regional Transmission OrganizationOrganization.
SECSabine Securities and Exchange Commission
S&PStandard & Poor’s Ratings Service
SO2
Sulfur dioxide
SPPSouthwest Power Pool
SWEPCoSouthwestern Electric PowerSabine Mining Company, a public utility subsidiary of AEP
TATransmission Agreement dated April 1, 1984 by and among APCo, CSPCo, I&M, KPCo, KgPCo, OPCo and WPCo, which allocates costs and benefits in connection with the operation of transmission assetslignite mining company that is a consolidated variable interest entity.

 
ii
 

Abbreviation or AcronymTerm DefinitionMeaning
SECU.S. Securities and Exchange Commission.
S&PStandard & Poor’s Ratings Service.
SO2
Sulfur dioxide.
SPPSouthwest Power Pool regional transmission organization.
SWEPCoSouthwestern Electric Power Company, an AEP electric utility subsidiary.
TCA Transmission Coordination Agreement dated January 1, 1997, restated and amended, and as amended and approved by FERC in 2002,2011 by and among, PSO, SWEPCo TNC and AEPSC, in connection with the operation of the transmission assets of the threetwo public utility subsidiariessubsidiaries.
TCC AEP Texas Central Company, formerly Central Power and Light Company, a publican AEP electric utility subsidiary of AEPsubsidiary.
Texas Act Texas electric restructuring legislationlegislation.
TNC AEP Texas North Company, formerly West Texas Utilities Company, a publican AEP electric utility subsidiary of AEPsubsidiary.
TVA Tennessee Valley AuthorityAuthority.
VSCCUtility Money PoolAEP System’s Utility Money Pool is the centralized funding mechanism AEP uses to meet the short term cash requirements of pool participants.
Virginia SCC Virginia State Corporation CommissionCommission.
WPCo Wheeling Power Company, a publican AEP electric utility subsidiary of AEPsubsidiary.
WVPSC West Virginia Public Service Commission of West Virginia.

 
iii
 

FORWARD-LOOKING INFORMATION

This report made by the registrantsAEP and its registrant subsidiaries 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—7 – Management’s Financial Discussion and Analysis,” 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,”“continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties such as those below and as further described in our Risk Factors that could cause actual results to differ materially from those projected.  Forward-looking statements in this document speak onlyare presented as of the date of this document.  Except to the extent required by applicable law, we undertake 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 and growth in, or contraction within, our service territory and changes in market demand and demographic patterns.
·ŸInflationary or deflationary interest rate trends.
·ŸVolatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·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 retail competition, particularly in Ohio.Ohio due to the February 2012 PUCO rehearing order.
·ŸWeather conditions, including storms, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
·ŸAvailable sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·ŸAvailability of necessary generating capacity and the performance of our generating plants.
·ŸOur ability to resolve I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration and outage-related issues through warranty, insurance and the regulatory process.
·ŸOur ability to recover regulatory assets and stranded costs in connection with deregulation.
·ŸOur ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·ŸOur ability to build or acquire generating capacity, including the Turk Plant, and transmission linelines and facilities (including our 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.
·ŸNew legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants.plants and related assets.
·ŸA reduction in the federal statutory tax rate.
ŸTiming and resolution of pending and future rate cases, negotiations and other regulatory decisions, (includingincluding rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance).compliance.
·ŸResolution of litigation.
·ŸOur ability to constrain operation and maintenance costs.
·ŸOur ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.
·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.
·ŸVolatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities.

iv

·ŸChanges in utility regulation, including the implementation of ESPs and related regulationthe expected legal separation and transition to market for generation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.
·ŸAccounting pronouncements periodically issued by accounting standard-setting bodies.
iv
·ŸThe impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact on future funding requirements.
·ŸPrices and demand for power that we generate and sell at wholesale.
·ŸChanges in technology, particularly with respect to new, developing or alternative sources of generation.
·ŸOur ability to recover through rates or market prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.
ŸOur ability to successfully manage negotiations with stakeholders and obtain regulatory approval to terminate or amend the Interconnection Agreement and break up or modify the AEP Power Pool.
ŸEvolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
ŸOther risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

·Our abilityThe 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 subsidiaries expressly disclaim any obligation to recover through rates or pricesupdate any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.forward-looking information.


 
v
 


PART I

ITEM 1.   BUSINESS

GENERAL

OVERVIEW AND DESCRIPTION OF SUBSIDIARIESOverview and Description of Subsidiaries

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

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

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

At December 31, 2010,2011, the subsidiaries of AEP had a total of 18,71218,710 employees.  Because it is a holding company rather than an operating company, AEP has no employees.  The public utility subsidiaries of AEP are:

APCo (organized

Organized in Virginia in 1926)1926, APCo is engaged in the generation, transmission and distribution of electric power to approximately 957,000960,000 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.  At December 31, 2010,2011, APCo and its wholly owned subsidiaries had 2,1862,176 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 unaffiliatednonaffiliated utility companies: Carolina Power & Light Company, Duke Carolina and Virginia Electric and Power Company.  APCo has several points of interconnection with 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.

CSPCo (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, transmission and distribution of electric power to approximately 749,000 retail customers in Ohio, and in supplying and marketing electric power at wholesale to other electric utilities, municipalities and other market participants. At December 31, 2010, CSPCo had 1,082 employees. CSPCo’s service area is comprised of two areas in Ohio, which include portions of twenty-five counties. One area includes the City of Columbus and the other is a predominantly rural area in south central Ohio. Among the principal industries served are primary metals, chemicals and al lied products, health services and electronic machinery. In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for CSPCo to merge into OPCo, effective in October 2011.  Decisions are pending from the PUCO and the FERC.  In addition to its AEP System interconnections, CSPCo is interconnected with the following unaffiliated utility companies: Duke Ohio, DP&L and Ohio Edison Company.  CSPCo is a member of PJM.I&M

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I&M (organizedOrganized in Indiana in 1925)1907, I&M is engaged in the generation, transmission and distribution of electric power to approximately 582,000 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.  At December 31, 2010,2011, I&M had 2,7052,671 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.  Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana.  Subject to regulatory approval, I&M has agreed to purchase these assets.  In addition to its AEP System interconnections, I&M is interconnected with the following unaffiliatednonaffiliated utility companies: Central Illinois Public Service Company, Duke Ohio, Commonwealth Edison Company, Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, Duke Indiana and Richmond Power & Light Company.  I&M is a member of PJM.

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KPCo (organized

Organized in Kentucky in 1919)1919, KPCo is engaged in the generation, transmission and distribution of electric power to approximately 174,000173,000 retail customers in an area in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants.  At December 31, 2010,2011, KPCo had 417415 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 unaffiliatednonaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc.  KPCo is also interconnected wi thwith TVA.  KPCo is a member of PJM.

KgPCo (organizedKGPCo

Organized in Virginia in 1917)1917, KGPCo provides electric service to approximately 47,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee.  Kingsport Power CompanyKGPCo does not own any generating facilities and is a member of PJM.  It purchases electric power from APCo for distribution to its customers.  At December 31, 2010, Kingsport Power Company2011, KGPCo had 5250 employees.

OPCo (organized

Organized in Ohio in 1907 and re-incorporated in 1924)1924, OPCo is engaged in the generation, transmission and distribution of electric power to approximately 706,0001,460,000 retail customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants.  At December 31, 2010,2011, OPCo had 2,1003,256 employees.  Among the principal industries served by OPCo are primary metals, chemical manufacturing,chemicals and allied products, health services, electronic machinery, petroleum refining, and rubber and plastic products. In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for CSPCo to merge into OPCo, ef fective in October 2011.  Decisions are pending from the PUCO and the FERC.  In addition to its AEP System interconnections, OPCo is interconnected with the following unaffiliatednonaffiliated utility companies: Duke Ohio, The Cleveland Electric Illuminating Company, DP&L,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.

On December 31, 2011, CSPCo merged with and into OPCo with OPCo being the surviving entity.  For purposes of this Annual Report on Form 10-K, all prior reported amounts have been recast as if the merger occurred on the first day of the earliest reporting period.  All contracts, subsidiaries and operations of CSPCo are now reflected as part of OPCo.

PSO (organized

Organized in Oklahoma in 1913)1913, PSO is engaged in the generation, transmission and distribution of electric power to approximately 532,000 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.  At December 31, 2010,2011, PSO had 1,1501,131 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,processing.  In addition to its AEP System interconnections, PSO is interconnected with Empire Distric tDistrict Electric Company, Oklahoma Gas and Electric Company, Southwestern Public Service Company and Westar Energy, Inc.  PSO is a member of SPP.

SWEPCo (organized

Organized in Delaware in 1912)1912, SWEPCo is engaged in the generation, transmission and distribution of electric power to approximately 520,000521,000 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.  At December 31, 2010,2011, SWEPCo had 1,3821,462 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 mili tarymilitary installations, colleges and universities.
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SWEPCO  SWEPCo also owns and operates a lignite coal mining operation.  In addition to its AEP System interconnections, SWEPCo is interconnected with Cleco Corp.,CLECO, Empire District Electric Co.,Company, Entergy Corp. and Oklahoma Gas & Electric Co.Company.  SWEPCo is a member of SPP.

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TCC(organized

Organized in Texas in 1945)1945, TCC is engaged in the transmission and distribution of electric power to approximately 775,000787,000 retail customers through REPs in southern Texas.  TCC has sold all of its generation assets.  At December 31, 2010,2011, TCC had 1,006997 employees.  Among the principal industries served by TCC are chemical and petroleum refining, chemicals and allied products, oil and gas extraction, food processing, metal refining, plastics and machinery equipment.  In addition to its AEP System interconnections, TCC is a member of ERCOT.

TNC (organized

Organized in Texas in 1927)1927, TNC is engaged in the transmission and distribution of electric power to approximately 186,000 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.  At December 31, 2010,2011, TNC had 319 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.

WPCo(organized

Organized in West Virginia in 1883 and reincorporated in 1911)1911, WPCo provides electric service to approximately 41,000 retail customers in northern West Virginia.  WPCo does not own any generating facilities.  WPCo is a member of PJM.  It purchases electric power from OPCo for distribution to its customers.  At December 31, 2010,2011, WPCo had 52 employees.  In February 2012, WPCo filed an application with the FERC seeking authorization to merge with and into APCo.  The merger is expected to require the approval of the WVPSC and the Virginia SCC.

AEGCo (organized

Organized in Ohio in 1982)1982, AEGCo is an electric generating company.  AEGCo sells power at wholesale to OPCo, I&M CSPCo and KPCo.  AEGCo has no employees.

SERVICE COMPANY SUBSIDIARYService 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.  The executive officers of AEP and certain of its public utility subsidiaries are employees of AEPSC.  At December 31, 2010,2011, AEPSC had 5,1324,977 employees.

 
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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 year ended December 31, 20102011 are as follows:

Description AEP System (a)  APCo  CSPCo  I&M 
  (in thousands) 
UTILITY OPERATIONS:            
Retail Sales            
Residential Sales $5,125,000  $1,221,563  $883,766  $496,605 
Commercial Sales  3,406,000   559,718   751,724   364,908 
Industrial Sales  2,840,000   653,762   254,342   400,140 
PJM Net Charges  (42,000)  (14,008)  (7,852)  (7,998)
Provision for Rate Refund  (52,000)  4,147   (50,000)  - 
Other Retail Sales  207,000   74,331   7,053   6,610 
Total Retail  11,484,000   2,499,513   1,839,033   1,260,265 
Wholesale                
Off-System Sales  1,812,000   439,689   223,799   474,472 
Transmission  181,000   (20,518)  (14,399)  (139)
Total Wholesale  1,993,000   419,171   209,400   474,333 
Other Electric Revenues  145,000   31,499   14,822   740 
Other Operating Revenues  65,000   8,713   2,792   15,368 
Sales to Affiliates  -   316,207   82,994   445,021 
Total Utility Operating Revenues  13,687,000   3,275,103   2,149,041   2,195,727 
OTHER  740,000   -   -   - 
TOTAL REVENUES $14,427,000  $3,275,103  $2,149,041  $2,195,727 
Description AEP System (a) APCo I&M OPCo PSO SWEPCo
      (in thousands)
Utility Operations                  
 Retail Sales                  
  Residential Sales $ 5,207,000  $ 1,107,199  $ 503,554  $ 1,680,179  $ 572,404  $ 554,663 
  Commercial Sales   3,319,000    535,040    369,471    1,077,742    364,701    411,652 
  Industrial Sales   2,953,000    638,854    412,562    979,424    241,026    288,474 
  PJM Net Charges   (74,000)   (23,696)   (14,485)   (30,768)   -    - 
  Provision for Rate Refund   7,000    -    (461)   6,035    (158)   1,604 
  Other Retail Sales   205,000    64,741    6,693    17,714    78,722    8,118 
   Total Retail   11,617,000    2,322,138    1,277,334    3,730,326    1,256,695    1,264,511 
 Wholesale                  
  Off-System Sales   2,067,000    504,955    499,291    667,593    42,241    259,877 
  Transmission   187,000    (19,723)   (14,531)   (26,697)   31,903    47,782 
   Total Wholesale   2,254,000    485,232    484,760    640,896    74,144    307,659 
 Other Electric Revenues   161,000    29,649    8,353    36,008    14,713    22,022 
 Other Operating Revenues   59,000    9,942    15,086    18,395    3,644    2,019 
 Sales to Affiliates   -    358,264    429,237    1,005,486    14,192    57,615 
   Total Utility Operating Revenues   14,091,000    3,205,225    2,214,770    5,431,111    1,363,388    1,653,826 
Other   1,025,000    -    -    -    -    - 
Total Revenues $ 15,116,000  $ 3,205,225  $ 2,214,770  $ 5,431,111  $ 1,363,388  $ 1,653,826 

(a)Includes revenues of other subsidiaries not shown.  Intercompany transactions have been eliminated for the year ended December 31, 2010.2011.

Description OPCo  PSO  SWEPCo 
  (in thousands) 
UTILITY OPERATIONS:         
Retail Sales         
Residential Sales $735,551  $523,997  $496,454 
Commercial Sales  464,770   337,856   392,193 
Industrial Sales  660,952   222,087   275,229 
PJM Net Charges  (9,295)  -   - 
Provision for Rate Refund  -   (55)  (6,375)
Other Retail Sales  10,957   72,125   7,800 
Total Retail  1,862,935   1,156,010   1,165,301 
Wholesale            
Off-System Sales  311,246   46,364   240,935 
Transmission  (16,288)  30,039   44,336 
Total Wholesale  294,958   76,403   285,271 
Other Electric Revenues  1,313   14,503   18,942 
Other Operating Revenues  17,509   3,218   2,150 
Sales to Affiliates  1,046,992   23,528   51,870 
Total Utility Operating Revenues  3,223,707   1,273,662   1,523,534 
OTHER  -   -   - 
TOTAL REVENUES $3,223,707  $1,273,662  $1,523,534 
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FINANCING

General

Companies within the AEP System generally use short-term debt to finance working capital needs.  Short-term debt ismay 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'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 “Financial Condition” section Management’s Financial Discussion and Analysis,, included in the 2010 Annu al2011 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 and its significant subsidiaries, a $50 million cross-acceleration provision.  At December 31, 2010,2011, 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 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 Financial Discussion and Analysis,, included in the 20102011 Annual Reports, under the headi ngheading 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, leasing arrangements, including the leasing of coal transportation equipment and facilities.

 
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ENVIRONMENTAL AND OTHER MATTERS

General

AEP’s 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 believe are potentially material to the AEP system are outlined below.

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 our power plants are described below.  The states implement and administer many of these programs and could impose additional or more stringent requirements.

The Acid Rain Program: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.  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 continue to meet our 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 our facilities.  We have installed additional controls and taken other actions to achieve compliance with these programs.

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National Ambient Air Quality Standards: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 (PM 2 .52.5).  The PM 2.5 standard was remanded by the D.C. Circuit Court of Appeals, and a new standard is under development.  In 2009 the Obama Administration reconsidered theA new ozone standard is also under development and proposed a more stringent standard, which is expected to be finalized in 2011.2013.  The Federal EPA has also adopted a new short-term standard for SO2 in 2010,a lower standard for NO2, in 2010, and a lower standard for lead.lead in 2008.  The existing standard for carbon monoxide was retained in 2011.  The states will develop new SIPs for these standards, which could result in additional emission reductions being required from our facilities.

In 2005, the Federal EPA issued the Clean Air Interstate Rule (CAIR), which requires 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 Financial Discussion and Analysis under the headings entitled Environmental Matters—Matters – Clean Air Act Requirements.  In July 2010,August 2011, the Federal EPA issued a proposedfinal rule to replace CAIR (the Transport Rule)Cross State Air Pollution Rule (CSAPR)) that would impose new and more stringent requirements to control SO2 and NOx emissions from fossil fuel-fired electric generating units in 3127 states and the District of Columbia.  Petitions for review were filed with the U.S. Court of Appeals for the District of Columbia

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Circuit, and CSAPR was stayed.  CAIR remains in effect until further order from the court.  For additional information regarding the Transport Rule,CSAPR, see Management’s Financial Discussion and Analysis under the headings entitled Environmental Matters—Matters – Clean Air Act Requirements.

Hazardous Air Pollutants: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 2005,2011, the Federal EPA issued a Clean Air Mercury Rule (CAMR)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 mercury emissions from new and modified coal-fired power plants and requiring all states to issue new SIPs including mercury requirements for existing coal-fired power plants.  For additional information regarding CAMR,the Utility MACT, see Management’s Financial Discussion and Analysis under the headings entitled Environmental Matters—Matters – Clean Air Act Requirements.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.  For additional information regarding CAVR, see Management’s Financial Discussion and Anal ysis Analysis under the headings entitled Environmental Matters—Matters – Clean Air Act Requirements.

In January 2009,December 2011, the Federal EPA issued a determination that 37 states (including Indiana, Ohio,partial approval and partial disapproval of the Oklahoma Texas and Virginia) failed to submit SIP’s fulfilling theSIP for Regional Haze, program requirements by the deadline, and commencing a 2-year period for the development of a Federal Implementation Plan (FIP) in these states.  Oklahoma subsequently submitted a proposed SIP tofor the SO2 requirements that were disapproved.  The Federal EPA but anticipates that Federal EPA willhas also proposed to disapprove the plan and proposebest available retrofit technology determinations for the coal-fired power plants in Arkansas, but has not proposed a FIP in early 2011.for these units.  The requirements of the FIP that apply to our Oklahoma units impose significantly greater costs than would have been incurred under the Oklahoma SIP.  We are unable to predict if or how the remand of CAIR or the development ofwhether a FIP will be developed to satisfy CAVR in certain statesArkansas or how it may affect our compliance obligations for the Regional Haze programs.program.

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Greenhouse Gas Emissions:  

In the absence of comprehensive climate change legislation, the Federal EPA has taken action to regulate CO2 emissions under the existing requirements of the CAA.  Such actions are being legally challenged by numerous parties.  For additional information regarding the Federal EPA action taken to regulate CO2 emissions, see Management’s Financial Discussion and Analysis under the headings entitled Environmental Matters—Matters – Clean Air Act Requirements.

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

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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.  Certain states, including Ohio, Michigan, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements.  We are taking steps to comply with these requirements.requirements primarily through entering into power supply agreements giving us access to power generated by wind turbines.

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 2004,April 2011, the Federal EPA issued a finalproposed rule requiring all largesetting forth standards for existing power plants with once-through cooling water systems to meet certain standards tothat will reduce mortality of aquatic organisms pinned against thea plant’s cooling water intake screen (impingement) or entrained in the cooling water.  The proposed standards varied basedaffect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  We submitted comments on the water bodies from which the plants draw their cooling water.proposal in July and August 2011.

In July 2007, the Federal EPA suspended the 2004 rule, except foraffirmed the requirement that permitting agencies develop best professional judgment (BPJ) controls for existing facility cooling water intake structures that reflect the best technology available for minimizing adverse environmental impact.  The result is that the BPJ control standard for cooling water intake structures in effect prior to the 2004 rule is used as the applicable standard by permitting agencies pending finalization of revised rules by the Federal EPA.

In April 2009, the U.S. Supreme Court issued a decision that allows the Federal EPA the discretion to rely on cost-benefit analysis in setting national performance standards and in providing for cost-benefit variances from those standards as part of the regulations.  We cannot predict if or how the Federal EPA will apply this decision to any revision of the regulations or what effect it may have on similar requirements adopted by the states.  We expect the Federal EPA to issue revised rules in 2011.2012.

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 NPDESNational 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, but the Federal EPA has not yet proposed any specific requirements.  Until new standards are proposed, we cannot predict the outcome or impact of these rules on our operations.

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Coal Ash Regulation

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

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Global WarmingGreenhouse Gases – Position and Strategy

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 U.S.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 94 million metric tons during the 2003 to 20092010 period.  We expect our emissions to continue to decline over time as we diversify our generating sources and operate fewer coal units.  The projected de clinedecline in coal-fired generation is due to a number of factors including the ongoing cost of operating older units, increasing environmental regulations requiring significant capital investments and changing commodity market fundamentals.  Our strategy for this transformation is to protect the reliability of the electric system and reduce our emissions by pursuing multiple options.  These include diversifying our fuel portfolio and generating more electricity from natural gas, supporting incentives to invest in more nuclear generation, carbon capture and storage and other advanced coal technologies, increasing energy efficiency and investing in renewable resources, where there is regulatory support.  Meanwhile the U.S.Federal EPA began regulating CO2 emissions from large stationary sources such as power plants in 2011 by issuing a series of rules2012 under the NSR prevention of significant deterioration and Title V operating permit programs in the sta tes.programs.

For additional information on legislative and regulatory responses to global warming,greenhouse gases, including limitations on CO2 emissions, see Management’s Financial Discussion and Analysis under the headings entitled Environmental Matters – Global Warming.Warming.  Specific steps taken to reduce CO2 emissions include the following:

Carbon Capture and Storage

The 20 MW CCS Validation Project at the Mountaineer Plant in West Virginia successfully captured over 27,000 metric tons of CO2 between 2009 and 2010 and stored over 17,000 metric tons underground.  In January 2011, we began preliminary engineering and design work for a second, commercial-scale coal-derived CO2 capture and storage system at the Mountaineer Plant. We are also updating our estimates for the costs related to the commercial scale project.  We will evaluate the updated estimates before any decision is made to seek the necessary regulatory approvals to build the commercial scale project.  The project will be partially funded through the U.S. Departm ent of Energy’s Clean Coal Power Initiative. AEP was awarded federal grant funding of $334 million, which represents approximately half the expected cost of this project, exclusive of asset retirement obligations.
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Renewable Sources of Energy

Some of our states have laws or commission orders that establish requirements or goals for renewable and/or alternative energy (Louisiana, Ohio, Arkansas, Michigan, West Virginia, Texas, Indiana, Virginia and Oklahoma) and we are taking steps to comply with these rules in a timely fashion.  A key sustainability commitment we made iswas to increase renewable power by an additional 2,000 MW from 2007 levels by 2011, subject to regulatory approval.  By the end of 2010,2011, AEP secured only 1,500 MW of renewable power through power purchase agreements an additional 1,111 MW of renewable power.agreements.

End User Energy Efficiency

Energy efficiency is a high priority for AEP because it can be a cost-effective way to reduce energy demand and potentially delay the need for new power plants. We work collaboratively with regulators, technical experts, environmental groups and others to develop and implement efficiency and demand response programs.  From 2008 through 2010,2011, we have achieved approximately 321716 MW and 1,072,000 MWh1,972,000 MWH of demand and energy reductions, respectively.  We have a company 2012an internal goal to reduce 1,000 MW of demand and 2,250,000 MWhMWH of energy consumption.consumption by year-end 2012. We expect to surpass our energy reduction targetgoal subject to regulatory approvals, appropriate cost recovery, and continued customer demand for programs.  In 2010,2011, we invested over $70$115 million throughout most of our service territory in energy efficiency i nitiatives.and demand response initiatives.


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gridSMART®

AEP’s gridSMART ® initiative is designed to demonstrate the potential benefits of the smart grid by integrating advanced grid technologies into existing electric networks.  AEP is deploying smart grid technologies in several jurisdictions with regulatory support.

·  AEP Ohio is deploying a comprehensive suite of smart grid technologies in an innovative demonstration project with 110,000 customers.  The $150 million project is being funded through a $75 million federal grant, PUCO cost recovery support and vendor in-kind contributions.

·  AEP Texas is deploying a 970,000one million meter smart grid network, along with $1 million in energy use display devices for low income customers.  The $308 million project is targeted for completion by the end of 2013.  We are recovering the costs through an 11-year surcharge.

·  I&M has deployed a smart grid network to 10,000 customers.  The $7 million project is initially beingwas funded pursuant to a settlement agreement approved by the IURC.  Ongoing expenses will be considered in future rate cases.

·  With partial cost recovery support from the OCC, PSO is deploying a 15,000 smart meter network.network and grid management technologies to approximately 14,000 customers.  The project is being financed through an $8.75 million American Reinvestment and Recovery Act low-interest loan from the Oklahoma Department of Commerce with $2 million annual revenues for cost recovery approved by the Oklahoma Corporation Commission.

Current and Projected CO2 Emissions:Emission

Our total CO2 emissions in 20092010 (including our ownership in the Kyger Creek and Clifty Creek plants) were approximately 136140 million metric tons.  We estimate that our 2010Our 2011 emissions wereremained flat at approximately 140141 million metric tons.& #160; Emissions in 2011 and beyond will be affected by continued changes in our generation portfolio, market prices, the pace and scale of the economic recovery in our jurisdictions, available capital, weather, and other factors.  We expect overall increases in CO2 emissions during the next few years to be small, if at all realized,any, as our sales and generation rebound somewhat from recession lows in 2009.  However, over much of the remainder of the decade we expect emissions to decline as modest sales growth is offset by retirements of older, less efficient coal-fired units and increased utilization of natural gas.

Corporate Governance: In response to a shareholder proposal several years ago, our Board of Directors created an ad hoc committee to evaluate our actions to mitigate the economic impact from future policies to reduce CO2 and other emissions. Governance

Our Board of Directors continually reviews the risks posed by and our actions in response to environmental issues and in connection with its assessment of our strategic plan.  The Board of Directors is frequently informed of any new material environmental issues, including changes to regulations and proposed legislation.  The Board’s Committee on Directors and Corporate Governance oversees the com pany’scompany’s annual Corporate Accountability Report, which includes information on environmental issues. Environmental planning and policy leadership are criteria incorporated into our executive compensation plan.
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Other environmental issuesEnvironmental Issues and mattersMatters

·  
Litigation with the federal and/or certain state governments and certain special interest groups regarding regulated air emissions and/or whether emissions from coal-fired generating plants cause or contribute to global warming.  See Management’s Financial Discussion and Analysis under the heading entitled Litigation - – Environmental Litigation and Note 65 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies,, included in the 20102011 Annual Reports, for further information.

·  
CERCLA, which 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 65 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies,, included in the 20102011 Annual Reports, under the heading entitled The Comprehensive Environmental Response Compensation and Liability Act (Superfund) (Superfund) and State Remediation for further information.
information.

Environmental Investments

Investments related to improving AEP System plants’ environmental performance and compliance with air and water quality standards during 2008, 2009, 2010 and 20102011 and the current estimates for 2011, 2012, 2013 and 20132014 are shown below, in each case excluding equity AFUDC orand capitalized interest.  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
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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 generating plants for environmental quality controls.  Such future investments are needed in orde rorder to comply with air and water quality standards that have been adopted and have deadlines for compliance after 2011 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.  While we expect to recover our expenditures for pollution control technologies, replacement generation and associated operating costs from customers through regulated rates (in regulated jurisdictions) or market prices, without such recovery those costs could adversely affect future results of operations and cash flows, and possibly financial condition.  The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System.  See Management’s Financial Discussion and AnalysisunderAnalysis under the heading entitled Environmental Matters and Note 65 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies, included in the 20102011 Annual Reports, for more information regarding environmental expenditures in general.
Historical and Projected Environmental Investments
       
 200820092010201120122013
 ActualActualActualEstimateEstimateEstimate
(in thousands)
Total AEP System*$886,800$457,200$303,800$223,100$340,300$678,500
APCo361,200191,900202,700112,100125,700182,500
CSPCo162,80073,80052,10020,70018,80028,000
I&M22,40019,6008,1001,5007004,400
OPCo311,800151,00045,30050,30069,000193,700
PSO5,0001,0001,2007,4006,1005,100
SWEPCo**12,00010,700(10,500)10,30028,00089,200

*  Includes expenditures of the subsidiaries shown and other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies.  Excludes discontinued operations.
Historical and Projected Environmental Investments
                  
 2009 2010 2011 2012 2013 2014
 Actual Actual Actual Estimate Estimate Estimate
  (in thousands)
Total AEP System (a)$457,200 $303,800  $186,800 $510,700 $999,000 $1,100,000
APCo 191,900  202,700   68,900  77,600  77,700  80,300
I&M 19,600  8,100   5,900  89,800  148,200  148,000
OPCo 224,800  97,400   63,000  122,800  187,300  128,700
PSO 1,000  1,200   6,500  43,400  134,600  164,600
SWEPCo (b) 10,700  (10,500)  11,000  75,700  230,500  288,100

**  SWEPCo 2010 actual environmental cost includes reclassifications of project costs for suspended capital projects.
(a)Includes expenditures of the subsidiaries shown and other subsidiaries not shown.  The figures reflect construction expenditures, not equity investments in subsidiary companies.  Excludes discontinued operations.
(b)SWEPCo 2010 actual environmental cost includes reclassifications of project costs for suspended capital projects.
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Electric and Magnetic Fields

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 predict the ultimate impact of the question of EMF exposure and adverse health effects.  If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially adversely affected unless these costs can be recovered from customers.

UTILITY OPERATIONS

GENERAL

Utility operations constitute most of AEP’s business operations.  Utility operations include (i)(a) the generation, transmission and distribution of electric power to retail customers and (ii)(b) the supplying and marketing of electric power at wholesale (through the electric generation function) to other electric utility companies, municipalities and other market participants.  AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities.

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ELECTRIC GENERATION

Facilities

As of December 31, 2011, AEP’s public utility subsidiaries ownowned or leaseleased approximately 37,000 MW of domestic generation.  See Item 2 —– Properties for more information regarding AEP’s generation capacity.

AEP Power Pool

APCo, CSPCo, I&M, KPCo, OPCo and AEPSC are parties to the Interconnection Agreement, which was originally approved by the FERC in 1951 and subsequently amended in 1951, 1962, 1975, 1979 (twice) and 1980.  This agreement defines how the member companies share the costs and benefits associated with their generating plants.  This sharing is based upon each company’s “member load ratio.” The member load ratio is calculated monthly by dividing each company’s highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all member companies.  The member load ratio multiplied by the aggregate generation capacity of all the member companies determines each member company's capacity obligation.  The difference between each member company's obligation and its own generation capacity determines the capacity surplus or deficit of each member company.  The agreement requires the deficit companies to make monthly capacity equalization payments to the surplus companies based on the surplus companies' average fixed cost of generation.  Member companies that deliver energy to other member companies to meet their internal load requirements are reimbursed at average variable costs.  In addition, all member companies share off-system sales margins based upon each member company's member load ratio.  Consequently, the agreement provides a strong risk sharing and mitigation arrangement among the member companies.  As of December 31, 2010,2011, the member-load-ratios were as follows:

Peak
Demand
 Member-Load Ratio
Peak
Demand
(MW)
Member-Load
Ratio
(%)
(MWs) (%)
APCo7,62332.87,248 30.5
CSPCo4,28918.5
I&M4,47419.34,837 20.4
KPCo1,596  6.91,522 6.4
OPCo5,23522.510,148 42.7
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APCo, CSPCo, I&M, KPCo and OPCo are parties to the AEP System Interim Allowance Agreement (Allowance Agreement), which has been approved by the FERC and provides, among other things, for the transfer of SO2 emission allowances associated with transactions under the Interconnection Agreement.  The following table shows the net (credits) or charges allocated among the parties under the Interconnection Agreement during the years ended December 31, 2008, 20092011, 2010 and 2010:2009:

2008200920102011 2010 2009
(in thousands)(in thousands)
APCo$575,300$668,700$757,900$632,100  $757,900  $668,700 
CSPCo233,200257,600230,400
I&M(153,000)(100,900)(236,900) (183,700) (236,900) (100,900)
KPCo65,00031,60049,400 48,400  49,400  31,600 
OPCo(720,500)(857,000)(800,800) (496,800) (570,400) (599,400)


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Notification of Termination of the AEP Power Pool

Much hasThe regulatory landscape and business environment have changed extensively since the Interconnection Agreement was originally executed in 1951.  These changes include evolving environmental regulations; the introduction of “open access” to transmission facilities; the implementation of RTOs, including PJM, which is a robust generation power pool that has generating capacity of over 167,000 MWs, movement towards industry deregulation; increased competition in wholesale generation markets; and the effects of these changes on such things as costs, load and the array of supply and demand-side resources available to the AEP-East operating companies today.include:

·  Evolving environmental regulations.
·  The introduction of “open access” to transmission facilities.
·  The implementation of RTOs, including PJM, which is a robust generation power pool that has generating capacity of over 167,000 MWs.
·  Movement towards industry deregulation.
·  The planned separation of OPCo’s generation and power marketing businesses from its transmission and distribution businesses.
·  Increased competition in wholesale generation markets.
·  The effects of these changes on such things as costs, load and the array of supply and demand-side resources available to the AEP-East operating companies today.
Consequently, in December 2010, each AEP Power Pool member gave written notice to the other members, and AEPSC, the Pool’s agent, of its decision to terminate the Interconnection Agreement, effective January 1, 2014 or such other date as approved by FERC, subject to state regulatory input.  This decisionThe Pool Agreement members unanimously have agreed to terminate is subject to ongoing evaluation by AEP.waive the full three-year notice provision.  Because the Interconnection Agreement is a rate schedule on file at FERC, its termination will not be effective until accepted for filing by FERC.  The Interim Allowance Agreement would also be terminated on the same date.

By giving notice to terminate the Interconnection Agreement and the Interim Allowance Agreement, the Power Pool members are providing a timeline within which all Power Pool members will decide how they will respond to the impacts from modifying or terminating the Interconnection Agreement.  The result of this process might be a modified or different type of Pool. Final resolution could involve bilateral contracts or sales of generating assets from surplus members to deficit members. If

Additionally, the Power Pool members do not reach a consensus,AEP East companies have decided to terminate the Power Pool members could revoke their notices of termination and the Interconnection Agreement would remain in place.Allowance Agreement.

CSW Operating Agreement

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

The following table shows the net (credits) or charges allocated among the parties under the CSW Operating Agreement during the years ended December 31, 2008, 20092011, 2010 and 2010:
2009:

2008200920102011 2010 2009
(in thousands)(in thousands)
PSO$(57,000)$(22,762)$20,222$33,091  $20,222  $(22,762)
SWEPCo   59,900   22,762   (20,222) (33,091) (20,222) 22,762 

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Power generated by or allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any public utility subsidiary is primarily sold to customers by such public utility subsidiary at rates approved by the public utility commission in the jurisdiction of sale.  See Regulation —– Rates under Item 1, Utility Operations.Operations.

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

AEP’s System Integration Agreement provides for the integration and coordination of AEP’s East companies, PSO and SWEPCo.  This includes joint dispatch of generation within the AEP System and the distribution, between the two zones, of costs and benefits associated with the transfers of power between the two zones (including sales to

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third parties and risk management and trading activities).  It is designed to function as an umbrella agreement in addition to the Interconnection Agreement and the CSW Operating Agreement, each of which controls the distribution of costs and benefits for activities within each zone.

Risk Management and Trading

As agent for AEP’s public utility subsidiaries, AEPSC sells excess power into the market and engages in power, natural gas, coal and emissions allowances risk management and trading activities focused in regions in which AEP traditionally operates and in adjacent regions.  These activities primarily involve the purchase and sale of electricity (and to a lesser extent, natural gas, coal and emissions allowances) under physical forward contracts at fixed and variable prices.  These contracts include physical transactions, over-the-counter swaps and exchange-traded futures and options.  The majority of physical forward contracts are typically settled by netting into offsetting contracts.  These transactions are executed with numerous counterparties or on exchanges.  Counterpar tiesCounterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions.  As of December 31, 2010,2011, counterparties have posted approximately $28$16 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 had posted approximately $172$171 million with counterparties and exchanges).  Since open trading contracts are valued based on market prices of various commodities, exposures change daily.  See Management’s Financial Discussion and Analysis,, included in the 20102011 Annual Reports, under the heading entitled Quantitative and Qualitative Disclosures About Risk Management Activities fo rfor additional information.

Fuel Supply

The following table shows the sources of fuel used by the AEP System:

Years Ended December 31,
2008200920102011 2010 2009
Coal and Lignite86%88%82%78% 82% 88%
Natural Gas6% 8%11% 8% 6%
Nuclear8%5% 9%10% 9% 5%
Hydroelectric and other<1%1%<1%<1% <1% 1%

Price increases in one or more fuel sources relative to other fuels may result in increased use of other fuels.  Variations in theThe decreased generation of nuclear power arein 2009 is primarily related to a 2008 forced outage caused by a low pressure turbine blade failure event.  Theevent and the impacted unit returned to servicecoming back on line in December 2009.2010.

Coal and Lignite: AEP’s public utility subsidiaries 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.  Electric demand experienced a slight increase in 2010 which resulted in a slight increase in coal and lignite tons consumed.  In response to continued lower consumption rates at certain locations during 2010, AEP continued to work with coal suppliers to better match deliveries with consumption and minimize the impact on fuel inventory costs, carrying costs and cash. 0; System wide, inventory levels were reduced by 11 days in 2010.

AEP’s public utility subsidiaries 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 was in line with the projected fuel usage in 2011 and coal inventories ended 2011 near target levels.
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Management believes that AEP’s public utility subsidiaries 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 its public utility subsidiaries, as of December 31, 2011, AEP owns, leasesowned, leased or controlscontrolled more than 8,1007,600 railcars, 672634 barges, 1716 towboats and a coal handling terminal with 18 million tons of annual capacity to move and store coal for use in our generating facilities.  See AEP River Operations for a discussion of AEP’s for-profit coal and other dry-bulk commodity transportation operations that are not part of AEP’s Utility Operations segment.

During 2010, spot
Spot market prices for certain coals utilized by AEP fluctuated in a fairly narrow band throughout much of the year, but softened noticeably in the fourth quarter.  The general increase in spot coal generally increased throughoutprices seen over the year.  Among other things, these increases are due topast few years has been supported by higher international demand for U.S. coals, and increased mining costs related to regulatory and permitting issues.  Most of the coal purchased by AEP is procured through term contracts.  The price we paypaid under a number of these contracts is often lower than the spot market price for similar coal.  As term contracts expire they are replaced with new agreements, often at higher prices.  The price we paid for coal delivered in 2010 decreased2011 increased from the prior year, due in part to the expirationreflective of several high spot market contracts that were entered into in 2007 and 2008 for 2009 and the reopening of some contracts to current market prices.price trending.


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

 200820092010
Total coal delivered to AEP System plants (thousands of tons)77,05475,90964,614
Average price per ton of purchased coal$47.14$49.54$44.82
 Years Ended December 31,
 2011 2010 2009
Total Coal Delivered to AEP System Plants (thousands of tons) 62,956  64,614  75,909
Average Price per Ton of Purchased Coal$46.76 $44.82 $49.54

    The coal supplies at AEP System 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. At December 31, 2010, the System’s coal inventory was approximately 50The coal supplies at AEP System 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.  At December 31, 2011, the System’s coal inventory was approximately 39 days of full load burn.

In cases of emergency or shortage, AEP has developed programs to conserve coal supplies at its plants.  Such programs have been filed and reviewed with federally approved electric reliability organizations.  In some cases, the relevant state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agency.

The FERC has adopted regulations relating, among other things, to the circumstances under which, in the event of fuel emergencies or shortages, it might order electric utilities to generate and transmit electric power to other regions or systems experiencing fuel shortages, and to ratemaking principles by which such electric utilities would be compensated.  In addition, the federal government is authorized, under prescribed conditions, to reallocate coal and to require the transportation thereof, for the use at power plants or major fuel-burning installations experiencing fuel shortages.

Natural Gas:

Through its public utility subsidiaries, AEP consumed nearly 134167 billion cubic feet of natural gas during 20102011 for generating power.  This represents an increase of 25% from 2010 and continues a significant increase fromtrend that began in 2010 when AEP’s natural gas consumption increased 40% above the 2009 level.  The increased natural gas consumption is primarily due to the addition of the Stall natural gas combined cycle unit at SWEPCo in June 2010, along with increased operation of the Lawrenceburg and Waterford combined cycle units in the East.  APCo’s Dresden Plant, a new 580 MW combined-cycle natural gas generating unit in Ohio, was completed and placed in service in January 2012.  The efficient heat rates of these units coupled with sustained lower natural gas prices andhave supported the additionincreased operation of the 508 MW combined-cycle unit at SWEPCO’s J. Lamar Stall facility and the overall increasedAEP’s combined cycle natural gas demand throughout AEP’s system.units during 2011.  Increased production from shale gas development continues to place downward pressure on natural gas prices as a result of more abundant supplies, making power generated from these units more economic.  Many of the 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 long-term,term, monthly, seasonal firm and daily peaking purchase a ndand transportation agreements (that are entered into on a competitive basis and based on market prices) supplies natural gas requirements for each plant, as appropriate.
 
     Nuclear:
The following table shows the amount of natural gas delivered to the AEP System plants during the past three years and the average delivered price of natural gas purchased by AEP System companies:

 Years Ended December 31,
 2011 2010 2009
Total Natural Gas Delivered to AEP System Plants (BCFs) 166.8  133.6  95.7
Average Price per MMBtu of Purchased Natural Gas$4.48 $4.80 $4.17


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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 requirements.fuel.
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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 anticipates that the Cook Plant has sufficient storage capacity for its spent nuclear fuel to permit normal operations through 2013.  I&M has entered into an agreement to provide for onsite dry cask storage.  Initial loading of spent nuclear fuel into the dry casks is tentatively scheduled to begin in 2012.

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.  In 2009, when the most recent study was done, the estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant ranged from $831 million to $1.5 billion in 2009 non-discounted dollars.  At December 31, 2010,2011, the total decommissioning trust fund balance for the Cook Plant was approximately $1.2$1.3 billion.  The balance of funds available to decommission Cook Plant will differ based on contributions and investment returns.  The ultimate cost of retiring the Cook Plant may be materi allymaterially different from estimates and funding targets as a result of the:

·  Type of decommissioning plan selected;selected.

·  Escalation of various cost elements (including, but not limited to, general inflation and the cost of energy);.

·  Further development of regulatory requirements governing decommissioning;decommissioning.

·  Technology available at the time of decommissioning differing significantly from that assumed in studies;studies.

·  Availability of nuclear waste disposal facilities; andfacilities.

·  Availability of a DOE 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.  We will seek recovery from customers through our regulated rates if actual decommissioning costs exceed our projections.  See Note 65 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies under the heading Nuclear Contingencies,, included in the 20102011 Annual Reports, for information with respect to nuclear waste and decommissioning.

Low-Level Radioactive Waste:

The LLWPA 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, but Utah licenses a low-level radioactive waste disposal site which currently accepts low-level radioactive waste from Michigan.  I&M ships some of its low level waste to a facility in Utah.  There is currently no set date limiting I&M’s access to the Utah facility. 60;  I&M stores the remaining type of low-level waste onsite.  In order to have capacity for the duration of its licensed operation of Cook Plant for onsite storage of waste not shipped to Utah, I&M will have to modify its existing facilities sometime in the next ten to fifteen years.

Structured Arrangements Involving Capacity, Energy and Ancillary Services

In January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an agreement relating to the construction and operation of a 510 MW gas-fired electric generating peaking facility to be owned by NPC, called the Mone Plant.  OPCo is entitled to 100% of the power generated by the Mone Plant, and is responsible for the fuel and other costs of the facility through May 2012, as extended.  Following that, NPC and OPCo will be entitled to 80% and 20%, respectively, of the power of the Mone Plant, and both parties will generally be responsible for their allocable portion of the fuel and other costs of the facility.

 
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Certain Power Agreements

I&M:

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

Pursuant to an assignment between I&M and KPCo, and a unit power agreement between KPCo and AEGCo, 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.

CSPCo:OPCo

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

OVEC

OVEC: AEP and several unaffiliatednonaffiliated utility companies jointly own OVEC.  The aggregate equity participation of AEP in OVEC is 43.47%.  Until 2001, OVEC supplied from its generating capacity the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the DOE.  The sponsoring companies are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,200 MW) in proportion to their respective power participation ratios.  The aggregate power participation ratio of APCo, CSPCo, I& M&M and OPCo is 43.47%.  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, will expirewas extended by its terms in March 2026.  Negotiations are in process among the owners to extend this agreementin 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.  As of December 2010,  OVEC’s Board of Directors has authorized capital expenditures totaling approximately $1.35 billion in connection with the engineering and construction of flue gas desulfurization projects and the associated scrubber waste disposal landfills at its two generating plants.  OVEC has completed the financing of approximately $950 million$1.05 billion for these projects through debt issuances, including tax-advantaged debt issuances, and wo uldwould expect to finance the remaining cost by issuing additional debt.

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ELECTRIC TRANSMISSION AND DISTRIBUTION

General

AEP’s public utility subsidiaries (other than AEGCo) own and operate transmission and distribution lines and other facilities to deliver electric power.  See Item 2—2 – Properties for more information regarding the transmission and distribution lines.  Most of the transmission and distribution services are sold, in combination with electric power, to retail customers of AEP’s 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 1 –Utility– Utility Operations - Regulation—Rates.– Regulation – Rates.  The FERC regulates and approves the rates fo rfor wholesale transmission transactions.  See Item 1 –Utility– Utility Operations - Regulation—FERC.– Regulation – FERC.  As discussed below, some transmission services also are separately sold to non-affiliated companies.

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AEP’s public utility subsidiaries (other than AEGCo) 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.  For a discussion of competition in the sale of power, see Item 1 –Utility– Utility Operations - Competition.– Competition.

AEP Transmission Pool

Transmission Agreement: APCo, CSPCo, I&M, KPCoThe use and OPCo operate theirthe recovery of costs associated with the transmission lines as a single interconnected and coordinated system inassets of the AEP East transmission zonecompanies, including WPCo and KGPCo, are partiessubject to the Transmission Agreement (TA), defining how they share the costsrules, protocols and benefits associatedagreements in place with their relative ownership of the bulk transmission system (lines operated at 138kVPJM and above and stations containing extra high voltage equipment). The TA has beenas approved by the FERC. Sharing under the TA is based upon each company’s “member-load-ratio.”  The member-load-ratio is calculated monthly by dividing such company’s highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all east zone operating companies.  The respective peak demands and member-load-ratios as of December 31, 2010 are set forth above in the section titled ELECTRIC GENERATION – AEP Power Pool and CSW Operating Agreement.

In October 2010, the FERC approved our request to amend the TA effective November 1, 2010.  KgPCo and WPCo were added as parties to the TA.  In addition, the amendments generally provide for the allocation of PJM transmission costs on the basis of the TA parties’ 12-month coincident peak and reimburse transmission revenues based on individual cost of service instead of the member-load ratio method previously used.

The following table shows the net (credits) or charges allocated among the parties to the TA during the years ended December 31, 2008, 2009 and 2010:

 200820092010
 (in thousands)
APCo$(29,000)$(12,500)$(16,000)
CSPCo55,00051,30042,500
I&M(37,000)(38,400)(25,200)
KPCo(2,000)(8,800)(8,000)
OPCo13,0008,4006,700

Transmission Coordination Agreement, OATT, and ERCOT Protocols:Protocols

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

The following table shows the net (credits) or charges allocated pursuant to the TCA, SPP OATT and ERCOT protocols as described above duringfor the years ended December 31, 2008, 20092011, 2010 and 2010:2009:

Years Ended December 31,
2008200920102011 2010 2009
(in thousands)(in thousands)
PSO$8,200$11,000$10,500$9,000  $10,500  $11,000 
SWEPCo(8,200)(11,000)(10,500) (9,000) (10,500) (11,000)
TCC1,5001,7002,100 2,100  2,100  1,700 
TNC(1,500)(1,700)(2,100) (2,100) (2,100) (1,700)

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Transmission Services for Non-Affiliates:Non-Affiliates

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

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Coordination of East and West Zone Transmission:Transmission

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

·  The allocation of transmission costs and revenues andrevenues.

·  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

The AEP East Companies are members of PJM, and SWEPCo and PSO are members of the SPP (both FERC-approved RTOs).  RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.  The remaining AEP West companies (TCC and TNC) are members of ERCOT. See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2010 Annual Reports under the heading entitled Regional Transmission Rate Proceedings at the FERC for additional information regarding RTOs.

REGULATION

General

Except for transmission and/or retail generation sales in certain of its jurisdictions, AEP’s public utility subsidiaries’ retail rates and certain other matters are subject to traditional cost-based regulation by the state utility commissions.  AEP’s subsidiaries are also subject to regulation by the FERC under the FPA with respect to wholesale power and transmission service transactions as well as certain unbundled retail transmission rates mainly in Ohio.  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 public utility subsidiaries are also subject to the regulatory provisions of EPACT, much of which is administered by the FERC.  EPACT provides the FERC limited “ba ckstop”“backstop” transmission siting authority as well as increased utility merger oversight.

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 (i)(a) a utility’s adjusted revenues and expenses during a defined test period and (ii)(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 of time, a state utility commission can review and change rates on its own initiative.  Som eSome 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.
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Public utilities have traditionally financed capital investments until the new asset wasis 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 difficultvolatile capital markets, we are 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, securitization, formula rates and the inclusion of future test-year projections i ntointo rates.


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In many jurisdictions, the rates of AEP’s public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service).  In the ERCOT area of Texas, our utilities have exited the generation business and they currently charge unbundled cost-based rates for transmission and distribution service only.  In Ohio, rates for electric service are unbundled for generation, transmission and distribution service.  Historically, the state regulatory frameworks in the service area of the AEP System 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 recover yrecovery 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.  Several public utility subsidiaries operate in more than one jurisdiction.  See Note 43 to the consolidated financial statements, entitled Rate Matters,, included in the 20102011 Annual Reports, for more information regarding pending rate matters.

Indiana:

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

Ohio: CSPCo and

OPCo provideprovides “default” retail electric service to customers at unbundled rates pursuant to the Ohio Act.  CSPCo and OPCo exclusively provideprovides distribution and transmission services to retail customers within their service territories at cost-based rates approved by the PUCO.  Transmission services are provided at OATT rates based on rates established by the FERC.  CSPCo and
OPCo’s generation/supply rates are subject to their Electric Security Plansits ESP that the PUCO modified and approved in March 2009.  In December 2011, the PUCO approved a March 2009 order.   The order establishedmodified stipulation for a new ESP for the period January 2012 through May 2016 that includes a standard service offer rates in effect through 2011.  The order also provides(SSO) pricing for generation.  In February 2012, the PUCO issued an entry on rehearing which rejected the modified stipulation for a fuel adju stment clause for the three-year period of the ESP.  The order has been appealed by various partiesnew ESP and ordered a return to the Supreme Court of Ohio.  Although the Supreme Court of Ohio has rejected or dismissed a number of procedural and other challenges to the order, the order remains on appeal with that Court with oral arguments scheduled in February 2011.  In January 2011 CSPCo and OPCo filed an application with the FERC requesting approval for CSPCo to merge into OPCo, effective in October 2011.  Decisions are pending from the PUCO and the FERC.  Approval of the merger will not affect theirESP rates until such time as the PUCO approvesa new rates.rate plan is approved.

Oklahoma

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 a fuel adjustment factor to retail kilowatt-hour sales.  The factor is generally adjusted annually and is based upon forecasted fuel and purchased energy costs.  Over or under collections of fuel costs for prior periods are returned to or recovered from customers in the year following when new annual factors are established.

Texas:

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

 
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Virginia:

APCo currently provides retail electric service in Virginia at unbundled rates approved by the VSCC.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.  APCo is permitted to retain a minimum of 25% of the margins from its off-system sales with the remaining margins from such sales credited against its fuel adjustment clause factor with a true-up to actual.  In addition to base rates and fuel cost recovery, APCo is permitted to recover a variety of costs through rate adjustment c lauses.clauses.

West Virginia:

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

Other Jurisdictions: The public utility subsidiaries of AEP also provide service at cost based regulated bundled rates in Arkansas, Kentucky, Louisiana and Tennessee and regulated unbundled rates in Michigan.  These jurisdictions provide for the timely recovery of fuel costs through fuel adjustment clauses that true-up to actual expenses.

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

 
 
Jurisdiction
 
Percentage of
AEP System
Retail
Revenues (1)
 
Percentage of OSS Profits
Shared with Ratepayers
 
AEP Utility
Subsidiaries
Operating in
that Jurisdiction
 
Authorized
Return on
Equity (2)
 
 
 
      
 Ohio32%No sharing included in ESPsOPCo(3)
 CSPCo(3)
      
 Texas12%Not Applicable in ERCOTTCC (4)9.96%
 TNC (4)9.96%
 90% in SPPSWEPCo10.33%
      
 Virginia12%75%APCo10.53%
      
 West Virginia11%100%APCo10.50%
 WPCo10.50%
      
 Oklahoma10%75%PSO10.15%
      
 Indiana9%50% after certain level (5)I&M10.50%
      
 Kentucky5%60% below and above certain level (6)KPCo10.50%
      
 Louisiana4%50% to 100% after certain levels (7)SWEPCo10.57%
      
 Arkansas2%50% to 100% after certain levels (8)SWEPCo10.25%
      
 Michigan2%75%I&M10.35%
      
 Tennessee1%Not ApplicableKgPCo12.00%
Jurisdiction Percentage of AEP System Retail Revenues (a) Percentage of OSS Profits Shared with Ratepayers AEP Utility Subsidiaries Operating in that Jurisdiction Authorized Return on Equity (b)
         
Ohio 32% No sharing included in the ESP OPCo (c)
         
Texas 12% Not Applicable in ERCOT TCC 9.96%
   Not Applicable in ERCOT TNC 9.96%
   90% in SPP SWEPCo 10.33%
         
Oklahoma 11% 75% PSO 10.15%
         
West Virginia 11% 100% APCo 10.00%
   100% WPCo 10.00%
         
Virginia 10% 75% APCo 10.90%
         
Indiana 9% 50% after certain level (d) I&M 10.50%
         
Kentucky 5% 60% below and above certain level (e) KPCo 10.50%
         
Louisiana 5% 50% to 100% after certain levels (f) SWEPCo 10.57%
         
Arkansas 2% 50% to 100% after certain levels (g) SWEPCo 10.25%
         
Michigan 2% 80% I&M 10.20%
         
Tennessee 1% Not Applicable KGPCo 12.00%

(1)  (a)Represents the percentage of revenues from sales to retail customers from AEP utility companies operating in each state to the total AEP System revenues from sales to retail customers for the year ended December 31, 2010.2011.
(2)  (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.
(3)  (c)CSPCo’s and OPCo’s generation revenues are governed by its Electric Security Plans (ESPs) filed andPlan (ESP) as approved by the PUCO.  StartingPUCO in January 2009,March 2009.  Under the ESPs became effective whichESP, authorized rate increases during the ESP period were subject to caps that limit the annual rate increases for CSPCo to 7% in 2009 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% inthrough 2011.  Some rate components and increases are exempt from the cap limitations.  The ESPsESP also provided for a fuel adjustment clause for the three-year period of the ESP.clause.
(4)  Operating in the ERCOT region of Texas and consists of distribution and transmission functions.  Generation operations were divested in compliance with the Texas electric restructuring.
(5)  (d)There is an annual $37.5 million credit established for off-system sales in base rates.  If the off-system sales profits exceed the amount built into base rates, I&M reimburses ratepayers 50% of the excess.
(6)  (e)Starting in July 2010, thereThere is an annual $15.3 million credit established for off-system sales in base rates.  If the monthly off-system sales profits do not meet the monthly level built into base rates, ratepayers reimburse KPCo 60% of the shortfall.  If the monthly off-system sales profits exceed the monthly level built into base rates, KPCo reimburses ratepayers 60% of the excess.
(7)  
(f)
(g)
Below $874,000, 100% is shared with customers; fromgiven to customers.
From $874,001 to $1,314,000, 85% is shared with customers; abovegiven to customers.
Above $1,314,000, 50% is shared withgiven to customers.
(8)  Below $758,600, 100% is shared with customers; fromgiven to customers.
From $758,601 to $1,167,078, 85% is shared with customers; abovegiven to customers.
Above $1,167,078, 50% is shared withgiven to customers.

 
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FERC

Under the FPA, 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 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 (i)(a) approving contracts for wholesale sales to municipal and cooperative utilities and (ii)(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 controlbalancing area of the SPP, AEP has mark et-ratemarket-rate authority from the FERC, under which much of its wholesale marketing activity takes place.  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 OASIS, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees.

The FERC oversees RTOs, entities created to operate, plan and control utility transmission assets.  Order 2000 also prescribes certain characteristics and functions of acceptable RTO proposals.  The AEP East Companies are members of PJM.  SWEPCo and PSO are members of SPP.

The FERC has jurisdiction over the issuances of securities of most of our 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 limited “backstop” transmission siting authority as well as increased utility merger oversight.

COMPETITIONCompetition

Under current Ohio legislation, electric generation is sold in a competitive market in Ohio, and our native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service.  Competitive power suppliers are targeting retail customers by offering alternative generation service.  A growing number of CSPCo'sOPCo's commercial retail customers have switched to alternative generation providers while additional Ohio customers have provided notice of their intent to switch.  In 2010, CSPCo lost about 3%Currently, there are no limitations on the obligation of its total load dueOPCo to customer switching.provide below cost capacity rate pricing to alternative suppliers to support customers switching in Ohio.  These evolving market conditions will continue to impact CSPCo’sOPCo's results of operations.  To date, OPCo’s customer losses have been insignificant.   In February 2010, the PUCO granted aA retail supply subsidiary of AEP a certificate to operateoperates as a competitive retail electric service provider in Ohio.

The 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 foster competition in the wholesale market by creating a generation market with fewer barriers to entry and mandating 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), availability of capacity and power and reliability of service.

AEP’s public utility subsidiaries also compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil 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 generally maintain a favorable competitive position.  With respect to alternative sources of energy, the public utility subsidiaries of AEP believe that the reliability of their service and the limited ability of customers to substitute other cost-effective sources for electric power place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy.

 
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Significant changes in the global economy have led to increased price competition for 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, 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 public utility subsidiaries of AEP cooperate 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 negotiated with the customer, and then filed with the state commissions for approval.

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.

TRANSMISSION OPERATIONS

Wholly-owned Entities

AEP Transco, a subsidiary of AEP, has seven wholly-owned transmission companies, geographically aligned with our existing operating companies.  These transmission companies will develop and own new transmission assets that are physically connected to AEP’s system.  The transmission companies have been approved in Indiana, Michigan, Ohio and Oklahoma.  Applications for approval of the transmission companies have been filed with the APSC, the KPSC, the LPSC, the Virginia SCC and the WVPSC and are pending approval.

AEP Transco rates have been approved and will be regulated by the FERC, and are included in PJM’s and SPP’s OATT.  AEPSC and other AEP subsidiaries provide services to the transmission companies through service agreements.  Therefore, the transmission companies do not have any employees.

All of the transmission companies’ capital needs are provided by Parent, AEP Transco and/or the AEP Utility Money Pool.  The Utility Money Pool is used to meet the short-term borrowing needs of AEP regulated utility subsidiaries.  The Utility Money Pool operates in accordance with the terms and conditions approved in regulatory orders.  For the consolidated entities within our Transmission Operations segment, we forecast approximately $350 million, excluding AFUDC, of construction expenditures for 2012.

Joint Venture Initiatives

We have established joint ventures with other incumbent electric utility companies for the purpose of developing, building and owning Extra High Voltage (EHV) transmission lines to improve reliability and market efficiency and to access remote generation sources in North America.  Our joint ventures are invested in EHV projects at various stages of regulatory and RTO approval.

Our most significant joint venture, Electric Transmission Texas, LLC (ETT), was established to construct, fund, own and operate electric transmission assets within ERCOT, including transmission projects in the Competitive Renewable Energy Zone (CREZ). The PUCT has awarded approximately $1.5 billion of total CREZ investment to ETT.

Business services for the joint ventures are provided by AEPSC and the joint venture partner entity.  Therefore, the joint ventures do not have any employees. For the equity investments within our Transmission Operations segment, we forecast approximately $116 million of AEP equity contributions in 2012 to support construction expenditures and the payment of operating expenses.

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AEP RIVER OPERATIONS

Our AEP River Operations Segment transports coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi rivers.  Almost all of our customers are nonaffiliated third parties who obtain the transport of coal and dry bulk commodities for various uses.  We charge these customers market rates for the purpose of making a profit.  Depending on market conditions and other factors, including barge availability, we permit AEP utility subsidiary affiliates to use certain of our equipment at rates that reflect our cost.  Our affiliated utility customers procure the transport of coal for use as fuel in their respective generating plants.  We charge affiliated customers rates that reflect our costs.  AEP River Operations includes approximately 2,5812,600 barges, 45 towb oatstowboats and 2625 harbor boats that we own or lease.  These assets are separate from the barges and towboats dedicated exclusively to transporting coal for use as fuel in our own generating facilities discussed under the prior segment.  See Item 1 – Utility Operations -– Electric Generation —Fuel Supply—– 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), information timeliness and equipment..  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 a ndand 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.

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

GENERATION AND MARKETING

Our Generation and Marketing Segment consists of non-utilitynonutility generating assets and a competitive power supply and energy trading and marketing business.  We enter into short and long-term transactions to buy or sell capacity, energy and ancillary services primarily in the ERCOT market, and to a lesser extent Ohio in PJM and MISO.  As of December 31, 2010,2011, 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 377 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.  In 2006, TNC transferred
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its coal-fired generation capacity to comply with the separation requirements of the Texas Act.  The power obtained from the Oklaunion power station is marketed and sold in ERCOT.  We are regulated by the PUCT for transactions inside ERCOT and by the FERC for transactions outside of ERCOT.  While peak load in ERCOT typically occurs in the summer, we do not necessarily expect seasonal variation in our operations.  In 2010, we started operations of a retail energy business in the State of Ohio.  The purpose of this operation isOhio to sell competitive power supply to residential, commercial and industrial customers in the deregulated areas of Ohio.within or near AEP's traditional utility service areas.


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EXECUTIVE OFFICERS OF AEP as of February 28, 2012

The following persons are executive officers of AEP.  Their ages are given as of February 1, 2012.  The officers are appointed annually for a one-year term by the board of directors of AEP.

Nicholas K. Akins
President and Chief Executive Officer
Age 51
Chief Executive Officer since November 2011 and President since January 2011. Was Executive Vice President from August 2006 to December 2010.

Lisa M. Barton
Executive Vice President – Transmission
Age 46
Executive Vice President-Transmission of AEPSC since August 2011. Was Senior Vice President-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, Managing Director, Transmission of AEPSC from September 2007 to October 2007 and Director of Transmission Planning of AEPSC from December 2006 to September 2007.

David M. Feinberg
Senior Vice President, General Counsel and Secretary
Age 42
Senior Vice President, General Counsel and Secretary since January 2012.  Senior Vice President and General Counsel of AEPSC from May 2011. Previously served as Vice President, General Counsel and Secretary of Allegheny Energy, Inc. from 2006 to 2011.

Mark C. McCullough
Executive Vice President – Generation
Age 52
Executive Vice President-Generation of AEPSC since January 2011.  Was Senior Vice President-Fossil & Hydro Generation of AEPSC from February 2008 to December 2010 and Vice President-Baseload Generation of AEPSC from June 2005 to February 2008.

Robert P. Powers
Executive Vice President and Chief Operating Officer
Age 57
Executive Vice President and Chief Operating Officer since November 2011.  Was President-Utility Group from April 2009 to November 2011, President-AEP Utilities from January 2008 to April 2009 and Executive Vice President from 2004 to 2008.

Brian X. Tierney
Executive Vice President and Chief Financial Officer
Age 44
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 and Senior Vice President-Commercial Operations of AEPSC from 2005 to January 2008.

Dennis E. Welch
Executive Vice President and Chief Administrative Officer
Age 60
Executive Vice President and Chief Administrative Officer since October 2011.  Was Executive Vice President from January 2008 to September 2011 and Senior Vice President from August 2005 to December 2007.

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ITEM 1A.   RISK FACTORS

General Risks of Our Regulated OperationsGENERAL RISKS OF OUR REGULATED OPERATIONS
The regulatory environment in Ohio has recently become unpredictable and increasingly uncertain. – Affecting AEP and OPCo

For some time, our retail sales of electricity in Ohio have accounted for approximately 30% of our utilities segment revenue.  Due to a number of reasons, including commission turnover and a renewed emphasis on deregulation, the regulatory environment in Ohio has become increasingly unpredictable.  The current regulatory environment in Ohio could result in an extended period of uncertainty and cause our financial performance in Ohio to be volatile and difficult to project.

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

Our business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits, construction and/or acquisition of additional generation units and transmission facilities, modernizing existing infrastructure as well as other initiatives.  Our 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, we would not be able to recover the costs associated with our planned extensive investment.  This would cause our financial results to be diminished.  While we may seek to limit the impact of any denied recovery by attempting to reduce the scope of our capital investment, there can be no assurance as t oto the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.

We may not fully recover all of the investment in and expenses related to the Turk Plant.(Applies to AEP and SWEPCo)

SWEPCo is in the process of building the John W. Turk Plant (the “Turk Plant”) in southwest ArkansasRate and holds a 73% ownership interest in the planned 600MW coal-fired generating facility.  Its construction and anticipated operation has resulted in numerous legal challenges, including:

·  the validity of the air permit issued by the Arkansas Pollution Control and Ecology Commission in connection with the operation of the Turk Plant;
·  the validity of the wetlands permit issued by the U.S. Army Corps of Engineers in connection with the construction and operation of the Turk Plant;
·  the validity of the authority granted by the APSC to build three transmission lines and facilities needed to transmit power from the Turk Plant;
·  whether SWEPCo is required to obtain APSC approval to construct the Turk Plant without pursuing authority to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates; and
·  a complaint filed in the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of various federal and state laws.

If SWEPCo is unable to complete the Turk Plant construction and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.
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Our request for rateother recovery in Ohio for distribution service may not be approved in its entirety.(Applies toprovide full recovery of costs. – Affecting AEP CSPCo and OPCo)OPCo

In JanuaryFebruary 2011, CSPCo and OPCo filed a notice of intent with the PUCO to file for an annual increase in distribution rates of $34 million and $59 million, respectively, either as individual companies, or, if their proposed merger isrates.  In December 2011, a stipulation agreement was approved as a single merged entity.  The increase is based upon an 11.15% return on common equity to be effective January 2012. If the PUCO denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

Our request for rate recovery in Ohio for generation service may not be approved in its entirety.(Applies to AEP, CSPCo and OPCo)

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve the new ESP that includes a standard service offer pricing for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The requested increase in 2012 is $54 million and in 2013 is $106 million.  If the PUCO denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

Ohio may require us to refund revenue that we have collected. (Applies to AEP, CSPCo 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 rate adjustments result in significantly excessive earnings, the excess amount could be returned to customers.  In September 2010, CSPCo and OPCo filed their 2009 significantly excessive earnings filings with the PUCO.  In January 2011, the PUCO ruled that CSPCo generated approximately $43 million in significantly excessive earnings during 2009. The ruling is subject to rehearing by the PUCO and could be appealed inproviding recovery of certain distribution regulatory assets.  Due to a February 2012 PUCO ESP rehearing order, which rejected the courts.  If rehearing or a final appeal, if any, results in findings of additional significantly excessive earnings, then further amounts will be returned to customers. CSPCo and OPCo must file their 2010 significantly exc essive earnings filings with the PUCO. If the PUCO determines that CSPCo’s and/or OPCo’s 2010 earnings were significantly excessive, CSPCo and/or OPCo may be required to return a portion of their revenues to customers.
Ohio may require us to refund fuel costs that we have collected. (Applies to OPCo)

The PUCO selected an outside consultant to conduct an audit of recovery under the fuel adjustment clause for the period of January 2009 through December 2009.  The audit report included a recommendation that the PUCO should review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo’s under-recovery balance.  Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009 and $14 million reduced fuel expense in 2009 and 2010.  If the PUCO orders any portionESP modified stipulation, collection of the $58 million or other future adjustments be usedDistribution Investment Rider terminated.  If OPCo is not ultimately permitted to reduce the current year fuel adjustment clause deferral,fully recover its deferrals and costs, it would reduce future net income and cash flows and impact financial condition.

Rate recovery in Ohio for generation service may require us to refund rider revenue that we have collected. (Applies to CSPConot provide full recovery of costs. – Affecting AEP and OPCo)OPCo

TheIn January 2011, OPCo filed an application with the PUCO to approve a new ESP that included a standard service offer pricing for generation.  In December 2011, a modified stipulation agreement was approved by the PUCO which involved various issues pending before the PUCO, including generation rates and the recovery of fuel costs.  In February 2012, the PUCO issued an Economic Development Rider (EDR) by CSPCoentry on rehearing which rejected the ESP approved modified stipulation and ordered a return to the 2011 ESP rates until a new rate plan is approved.  Under the February 2012 rehearing order, OPCo has 30 days to notify the PUCO whether it plans to modify or withdraw its original application as filed in January 2011.  Management is currently evaluating its options and the potential financial and operational impacts on OPCo.  An intervenor in that proceeding has filed a notice of appeal of that award with the Supreme Court of Ohio.  As of December 31, 2010, CSPCo andIf OPCo have incurred $38 million and $30 million, respectively, in EDR costs including carrying costs.  If CSPCo and OPCo areis not ultimately permitted to fully recover their deferralsits costs, it would reduce future net income and cash flows and impact financial condition.

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Our request for rate recovery in West Virginia may not be approved in its entirety.(Applies to AEP and APCo)
Rate recovery approved in Ohio may have to be returned and/or may not provide full recovery of costs. – Affecting AEP and OPCo

In May 2010, APCoThe PUCO issued an order in March 2009 that modified and WPCo filedapproved the Electric Security Plan (ESP) which established rates through 2011.  The ESP order generally authorized rate increases during the ESP period, subject to caps that limit the rate increases, and also provides a requestfuel adjustment clause for the three-year period of the ESP.  The recovery under the fuel adjustment clause includes deferrals associated with the WVPSCOrmet interim arrangement and is subject to increase annual base rates by $156 million based on an 11.75% return on common equity to be effective March 2011.the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges.  In July 2011, OPCo filed its 2010 SEET filing with the PUCO.  If the WVPSC deniesPUCO and/or the Supreme Court of Ohio reverses all or part of the requested rate recovery or if deferred fuel costs are not fully recovered for other reasons, it could reduce future net income and cash flows.flows and impact financial condition.

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Oklahoma may require us to refund fuel costs that we have collected. (Applies to PSO)– Affecting PSO

In July 2009, the OCC initiated a proceeding to review PSO’s fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudence review of the related costs.  In March 2010, the Oklahoma Attorney General and an intervenor recommended the fuel clause adjustment rider be amended to decrease the shareholder’s portion of off-system sales margins from 25% to 10%.  That intervenor also recommended that the OCC conduct a comprehensive review of all affiliate fuel transactions during 2007 and 2008.  In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEP Energy Partners was filed.  Included in this testimony were unquantified refund recommendations relating to re-pricing of contract transactions.  If the OCC were t oto issue an unfavorable decision, it would reduce future net income and cash flows and impact financial condition.

Our future access to assets used to serve a major customer is in question.  (Applies to I&M)

Since 1975 I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expired on February 28, 2010.  As a result of a court-sponsored mediation process, I&M agreed to purchase the leased assets from Fort Wayne.  The agreement was signed in October 2010 and is subject to approval by the IURC.  If the IURC does not approve the agreement or the recovery of the costs resulting from the agreement or the lease, it could reduce future net income and cash flows.

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

Our 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, we 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 is 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.  In addition, if we have recorded any construction work or investments as a regulatory asset we m aymay need to impair that asset in the event the project is canceled.

Rate regulation may delay or deny full recovery of capital improvements, additions and other costs. (Applies to– Affecting each registrant.)Registrant

Our public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions.  These rates are generally regulated based on an analysis of the applicable utility’s expenses incurred in a test year.  Thus, commission-approved rates may or may not match a utility’s expenses at any given time.  There may also be a delay between the timing of when these costs are incurred and when these costs are recovered.  Traditionally, we have financed capital investments and improvements until the new asset was placed in service.  Provided the asset was found to be a prudent investment, the asset was then added to rate base and entitled to a return through rate recovery.  Long lead times in construction, the high costs of plant and equipment a nd difficultand volatile capital markets have heightened the risks involved in our capital investments 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.

 
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Certain of our revenues and results of operations are subject to risks that are beyond our control. (Applies to– Affecting each registrant.)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:including, but not limited to:

·    majorMajor facility or equipment failure;failure.
·    anAn environmental event such as a serious spill or release;release.
·    fires,Fires, floods, droughts, earthquakes, hurricanes or other natural disasters;disasters.
·    wars,Wars, terrorist acts (including cyber-terrorism) or threats and other catastrophic events;events.
·    significantSignificant health impairments or disease events, and;events.
·    otherOther serious operational problems.


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

Through I&M, we own the Cook Plant.  It consists of two nuclear generating units for a rated capacity of 2,191 MW, or 8-9% of the electricity we generate.generated by the AEP System.  We are, therefore, subject to the risks of nuclear generation, which include the following:

·    theThe 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;fuel.

·    limitationsLimitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations;operations.

·    uncertaintiesUncertainties with respect to contingencies and assessment amounts if insurance coverage is inadequate (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); and,.

·    uncertaintiesUncertainties 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.  In addition, although we have no reason to anticipate a serious nuclear incident at our plants, 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 an yany domestic nuclear unit.  Moreover, a major incident at any nuclear facility in the U.S. could require us to make material contributory payments.

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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.  Our ability to obtain adequate and timely recovery of costs associated with the Cook Plant is not assured.


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As a result of the nuclear plant situation in Japan following a March 2011 earthquake, the NRC has initiated a review of safety procedures and requirements for nuclear generating facilities.  This review could increase procedures and testing requirements, require physical modifications to the plant and increase future operating costs at the Cook Plant.  In addition to the review by the NRC, Congress could consider legislation tightening oversight of nuclear generating facilities.  We are unable to predict the impact of potential future regulation of nuclear facilities.

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

Our results 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 are unable to assess fully the impact that changes in these power markets may have on our business.

The amount we charged third parties for using our transmission facilities is subject to refund.  (Applies to AEP, APCo, CSPCo, I&M and OPCo.) – Affecting each Registrant

In July 2003, the FERC issued an order directing PJM and MISO to make compliance filings for their respective tariffs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within those RTOs.  To mitigate the impact of lost T&O revenues, the FERC approved temporary replacement seams elimination cost allocation (SECA) transition rates beginning in December 2004 and extending through March 2006.  Because intervenors objected to this decision, the SECA fees we collected ($220 million) are subject to refund.  Some claims for refund have been settled, and we have recorded a provision for estimated settlement refunds for the remaining unsettled $108 million of gross SECA revenues collected.  Any payments in excess of the reserve balance could harm our results of operationsreduce future net income and cash flows and impact financial position.condition.

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

As a result of EPACT, owners and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation and enforced by the FERC.  These standards, which previously were being applied on a voluntary basis, became mandatory in June 2007.  The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and isare guided by reliability and market interface principles.  Compliance with new reliability standards may subject us to higher operating costs and/or increased capital expenditures.  While we expect 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 we were f oundfound not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.

At times, demand for power could exceed our supply capacity. (Applies to– Affecting each registrant.)Registrant

We are currently obligated to supply power in parts of eleven states.  From time to time, because of unforeseen circumstances, the demand for power required to meet these obligations could exceed our available generation capacity.  If this occurs, we would have to buy power from the market.  This would increase the pressure on our short-term debt financing capacity in times of tight liquidity.  We may not always have the ability to pass these costs on to our customers, and the time lag between incurring costs and recovery can be long.  Since these situations most often occur during periods of peak demand, it is possible that the market price for power at that time would be very high.  Even if a supply shortage were brief, we could suffer substantial losses that could reduce our results of operations.

 
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Risks Related to Market, Economic or Financial VolatilityRISKS RELATED TO MARKET, ECONOMIC OR FINANCIAL VOLATILITY AND OTHER RISKS

Our financial performance may be adversely affected if we are unable to successfully operate our facilities or perform certain corporate functions. – Affecting each Registrant

Our performance 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 our 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 us 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, terrorism (including cyber-terrorism), floods or other similar occurrences.

We may be subject to disruptions or failures in our information technology systems and network infrastructures that could have a material adverse effect on us. – Affecting each Registrant

We maintain and rely extensively on information technology systems and network infrastructures for the effective operation of our business.  We also hold large amounts of data in various data center facilities which our business depends upon.  A disruption, infiltration or failure of our information technology systems or any of our data centers as a result of software or hardware malfunctions, computer viruses, cyber attacks, employee theft or misuse, power disruptions, natural disasters or accidents could cause breaches of data security and loss of critical data, which in turn could materially adversely affect our business.  Our security procedures, such as virus protection software, cyber security and our business continuity planning, such as our disaster recovery policies and back-up systems, may not be adequate or implemented properly to fully address the adverse effect of such events, which could adversely impact our operations.  In addition, our business could be adversely affected to the extent we do not make the appropriate level of investment in our technology systems as our technology systems become out-of-date or obsolete.

If we are unable to access capital markets on reasonable terms, it could have an adverse impact on our net income, cash flows and financial condition. (Applies to– Affecting each registrant)Registrant

We rely 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 our ability to raise capital and fund our capital needs, including construction costs and refinancing maturing indebtedness.  In addition, if capital is available only on less than reasonable terms or to borrowers whose creditworthiness is better than ours, capital costs could increase materially.  Restricted access to capital markets and/or increased borrowing costs could have an adverse impact on net income, cash flows and financial condition.

Downgrades in our credit ratings could negatively affect our ability to access capital and/or to operate our power trading businesses.  (Applies to – Affecting each registrant)Registrant

The credit ratings agencies periodically review our capital structure and the quality and stability of our earnings.  Any negative ratings actions could constrain the capital available to us and could limit our access to funding for our operations.  Our business is capital intensive, and we are dependent upon our ability to access capital at rates and on terms we determine to be attractive.  In periods of market turmoil, access to capital is difficult for all borrowers.  If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition could be harmed and future results of operations could be adversely affected.

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Our power trading business relies on the investment grade ratings of our individual public utility subsidiaries’ senior unsecured long-term debt.debt or on the investment grade ratings of AEP parent.  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, our ability to operate our power trading business profitably would be diminished because we would likely have to deposit cash or cash-related instruments which would reduce our profits.

Our pension plan willcould require additional significant contributions. (Applies to – Affecting each registrant.)Registrant

The performance of the capital markets affects the value of the assets that are held in trust to satisfy future obligations under our defined benefit pension plan.  The volatility of the capital markets in the past years has led to a decline inaffected the market value of these assets.  Also, a decline in interest rates on corporate bonds in 20102011 has impacted the benchmark discount rate in a way that results in a higher calculated pension liability.  Accordingly, our future required contributions to fund obligations under our defined benefit plan could increase significantly.be more than expected.

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

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

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

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 enter into.  In addition, we have 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 operations and harm our financial condition.  Conversely, unusually extreme weather conditions could increase AEP’ sAEP’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.

Failure to attract and retain an appropriately qualified workforce could harm our results of operations. (Applies to– Affecting each registrant.)Registrant

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 our business.  If we are unable to successfully attract and retain an appropriately qualified wor kforce,workforce, our results of operations could be negatively affected.

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

Our business plan calls for extensive investment in capital improvements 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, we 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.

Changes in commodity prices and the costs of transport may increase our cost of producing power or decrease the amount we receive from selling power, harming our financial performance.(Applies to – Affecting each registrant.)Registrant

We are exposed to changes in the price and availability of coal and the price and availability to transport coal because most of our generating capacity is coal-fired.  We have contracts of varying durations for the supply of coal for most of our existing generation capacity, but as these contracts end or otherwise are not honored, we may not be able to purchase coal on terms as favorable as the current contracts.  Similarly, we are exposed to changes in the price and availability of emission allowances.  We use emission allowances based on the amount of coal we use as fuel and the reductions achieved through emission controls and other measures.  According to our estimates,As long as current environmental programs remain in effect, we have procured sufficient emission allowances to cover nearly all of our projected needs for the next two years as well as a majority of our needs beyond that timeframe.  At some future point,If the Federal EPA’s replacement rule to reduce interstate transport were to take effect, additional costs may be incurred if forthcoming regulation changes requireto acquire supplemental allowances for compliance.compliance or to achieve further reductions in emissions.  If and when we obtain additional allowances those purchases may not be on as favorable terms as those currently obtained.  Our 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.
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We also own natural gas-fired facilities which increases our exposure to market prices of natural gas.  Natural gas prices tend to be more volatile than prices for other fuel sources.  Our 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-system sales prices, so the margins we realize from sales will be lower and, on occasion, we may need to curtail operation of marginal plants.  The availability of shale natural gas and issues related to its accessibility may have a long-term material effect on the price of natural gas.

Prices for coal, natural gas and emission allowances have shown material upward and downward swings in the recent 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 our financial results.  Since the prices we obtain for power may not change at the same rate as the change in coal, emission allowances or natural gas costs, we may be unable to pass on the changes in costs to our customers.

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.

Risks Relating
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RISKS RELATING TO STATE RESTRUCTURING

We are unable to State Restructuringfully predict the effects of legal separation in Ohio and becoming subject to market forces. – Affecting AEP and OPCo

In January 2012, the PUCO approved the corporate separation plan of OPCo’s generation assets to complete the transition to a fully competitive generation market by June 2015.  The corporate separation plan also would require approval by the FERC under provisions of the Federal Power Act.  Our customersIn February 2012, as part of the PUCO’s entry on rehearing which rejected the ESP approved modified stipulation, the PUCO revoked its approval of OPCo’s corporate separation plan.  Also, in February 2012, prior to the PUCO revoking OPCo’s corporate separation plan, an application was filed with the FERC seeking approval, among other things, to transfer OPCo’s generation assets to APCo, KPCo and a nonregulated AEP subsidiary.  If we can obtain regulatory approvals, our results of operations related to Ohio generation would be determined by our ability to sell power at a profit at rates determined by the prevailing market.  As a result of the February 2012 ESP rehearing order, we are in the process of withdrawing the PUCO and FERC applications.  We intend to file new FERC and PUCO applications related to corporate separation.  We can give no assurance that the PUCO or the FERC will not impose material adverse terms as a condition to approving our legal separation.  Additionally, certain of our generation units may no longer be cost effective and may be retired prior to the end of their anticipated useful life.  Because such generation assets are no longer subject to cost recovery regulation, this could result in material impairments.
We are unable to predict the consequences of terminating the Interconnection Agreement and breaking up the AEP Power Pool. – Affecting AEP, APCo, I&M and OPCo

The proposed corporate separation plans of OPCo’s generation assets will require us to either terminate or substantially alter the Interconnection Agreement.  The Interconnection Agreement establishes the AEP Power Pool which permits AEP East companies to share costs and benefits associated with their generating plants on a cost basis.  It is unknown at this time whether the AEP Power Pool will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bi-lateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.  If the AEP Power Pool is terminated without any subsequent agreements between some or all of the parties, surplus members will no longer automatically sell to deficit members, and they may not be able to otherwise sell that surplus in amounts or at rates equal to what they obtained under the Interconnection Agreement.  Conversely, deficit members will no longer automatically purchase from surplus members, and they may not be able to otherwise purchase in amounts or at rates equal to what they obtained under the Interconnection Agreement.  The possible loss of these sales by the surplus members and the potential increase in costs for the deficit members could reduce future net income and cash flows.  We have recently begunfiled with the FERC seeking approval of the termination of the Interconnection Agreement, the implementation of a power cost sharing agreement between APCo, I&M and KPCo, and to selecttransfer certain generation assets from OPCo to APCo, KPCo and a nonregulated AEP subsidiary.  As a result of the February 2012 ESP rehearing order, we are in the process of withdrawing the PUCO and FERC applications.  We intend to file new FERC and PUCO applications related to corporate separation.  We can give no assurance that the FERC or other state utility commissions will not impose material adverse terms as a condition to approving these arrangements and the termination of the Interconnection Agreement.

Customers are choosing alternative electric generation service providers, as allowed by Ohio legislation. (Applies tolaw and regulation. – Affecting AEP and CSPCo)OPCo

Under current Ohio legislation,law, electric generation is sold in a competitive market in Ohio and our native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service.  Competitive power suppliers are targeting retail customers by offering alternative generation service.  A growing number of CSPCo's commercial retail customers have switched to alternative generation providers while additional Ohio customers have provided notice of their intent to switch.  In 2010, CSPCo2011, we lost about 3%approximately 10% of its totalour Ohio load due to customer switching.  To date, OPCo’s losses have not been significant.Currently, there are no limitations on the obligation to provide below cost capacity rate pricing to alternative suppliers to support customers switching in Ohio.  These evolving market conditions will continue to impact CSPCo'sour results of operations.

There is uncertainty as to our recovery of stranded costs resulting from industry restructuring in Texas.(Applies to AEP.)

Restructuring legislation in Texas required utilities with stranded costs to use market-based methods to value certain generating assets for determining stranded costs.  We elected to use the sale of assets method to determine the market value of TCC’s generation assets for stranded cost purposes.  In general terms, the amount of stranded costs under this market valuation methodology is the amount by which the book value of generating assets, including regulatory assets and liabilities that were not securitized, exceeds the market value of the generation assets, as measured by the net proceeds from the sale of the assets.  In May 2005, TCC filed its stranded cost quantification application with the PUCT seeking recovery of $2.4 billion of net stranded generation costs and other recoverable true-up i tems.  A final order was issued in April 2006.  In the final order, the PUCT determined TCC’s net stranded generation costs and other recoverable true-up items to be approximately $1.475 billion.  We have appealed the PUCT’s final order seeking additional recovery consistent with the Texas Restructuring Legislation and related rules, other parties have appealed the PUCT’s final order as unwarranted or too large.  Management cannot predict the ultimate outcome of any future court appeals or any future remanded PUCT proceeding.
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Collection of our revenues in Texas is concentrated in a limited number of REPs.(Applies to AEP.) – Affecting AEP

Our revenues from the distribution of electricity in the ERCOT area of Texas are collected from REPs that supply the electricity we distribute to their customers.  Currently, we do business with approximately one hundred REPs.  In 2010,2011, TCC’s largest customer accounted for 25%22% of its operating revenue and its second largest customer accounted for 13%12% of its operating revenue; TNC’s largest customer (a non-utility affiliate) accounted for 29%28% of its operating revenues and its second largest customer accounted for 16%15% 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 depend on these RE PsREPs for timely remittance of payments.  Any delay or default in payment could adversely affect the timing and receipt of our cash flows and thereby have an adverse effect on our liquidity.

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Risks Related to Owning and Operating Generation Assets and Selling PowerRISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Our costs of compliance with existing environmental laws are significant.(Applies to – Affecting each registrant)Registrant

Our operations 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 systemSystem is produced by the combustion of fossil fuels.  Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generating plants are potentially subject to increased regulations, controls and mitigation expenses.  Compliance with these legal requirements requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at all of our facilities.facilities and could cause us to retire generating capacity prior to the end of its estimated useful life.  These expenditures have been significant in the past and we expect that they wi ll increasewill continue to be significant in order to comply with the future.current and proposed regulations.  Costs of compliance with environmental regulations could adversely affect our net income and financial position, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase.  If we retire generating plants prior to the end of their estimated useful life, there can be no assurance that we will recover the remaining costs associated with such plants.  While we expect to recover our expenditures for pollution control technologies, replacement generation and associated operating costs from customers through regulated rates (in regulated jurisdictions) or market prices, without such recovery those costs 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 us and our customers or cause some of our electric generating units to be uneconomical to operate or maintain.(Applies to – Affecting each registrant)Registrant

In June 2009, theThe U.S. House of Representatives passed the American Clean Energy Security Act (ACES).  ACES is a comprehensive energy and global warming bill that includes a number of provisions that would directly affect our business, including energy efficiency and renewable electricity standards, funding for carbon capture and sequestration demonstration projects,Congress has not taken any significant steps toward enacting legislation to control CO2emission standards, and an economy-wide cap and trade program for large sources of CO2 emissions that would reduce emissions by 17% in 2020 and just over 80 % by 2050 from 2005 levels.  Costs of compliance with the proposed legislation could adversely affect our net income and financial position.  This legislation did not become law.

Separately, insince 2009.  In December 2009, the Federal EPA issued a final endangerment finding under the CAA regarding emissions from motor vehicles.  The Federal EPA also finalized CO2 emission standards for new motor vehicles, and issued a rule that implements a permitting program for new and modified stationary sources of CO2 emissions in a phased manner through 2014.  Several groups have filed challenges to the endangerment finding.finding and the Federal EPA’s subsequent rulemakings.  The endangerment finding will leadFederal EPA has announced its intent to regulation ofpropose a CO2 and other gases under existing laws.emissions standard for new power generation sources during the next year.  Management believes some policy approaches being discussed would have significant and widespread negative consequences for the national economy and major U.S. industrialIndustrial enterprises, including us and our customers.

If CO2 and other emission standards are imposed, the standards could require significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units.  While we expect that costs of complying with new CO2 and other GHG emission standards will be treated like all other reasonable costs of serving customers and should be recoverable from customers as costs of doing business, without such recovery those costs could reduce our future net income and cash flows and harm our financial condition.

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Courts adjudicating nuisance and other similar claims against us may order us to pay damages or to limit or reduce our CO2 emissions.(Applies to – Affecting each registrant)Registrant

There are a number of pending cases seeking damages based on allegations of federal and state common law nuisance in which we, among others, are defendants.  In 2004, eight states andgeneral, the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority.  The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants.  The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming and sought injunctive reliefclimate change.  The plaintiffs in the formthese actions seek recovery of specific emission reduction commitments from the defendants.  The Second Circuit Courtdamages and other relief.  If these or other future actions are resolved against us, substantial modifications of Appeals reinstated this lawsuit on appeal after the lower court had dismissed it.  ; The U.S. Supreme Court has agreed to hear the defendants’ request for appeal.

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The trial court adjudicating the reinstated nuisance claims may order the defendants, including us,our existing coal-fired power plants could be required and we might be required to limit or reduce CO2 emissions.  This or similarSuch remedies could require us to purchase power from third parties to fulfill our commitments to supply power to our customers.  This could have a material impact on our costs.  While management believes such costs should be recoverable from customers as costs of doing business, without such recovery those costs could reduce our future net income and cash flows and harm our financial condition.

If these or other future actions are resolved against us, substantial modifications of our existing coal-fired power plants could be required.  In addition, we 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 our 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.

We may not fully recover the costs of repairing or replacing damaged equipment in Cook Plant Unit 1 and may be required to pay additional accidental outage insurance proceeds to ratepayers.(Applies to – Affecting AEP and I&M)&M

Cook Plant Unit 1 is a 1,084 MW nuclear generating unit located in Bridgman, Michigan.  In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator.  This equipment, located in the turbine building, is separate and isolated from the nuclear reactor.  The turbine rotors that caused the vibration were installed in 2006 and were within the vendor’s warranty period.  The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395$400 million.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M repaired Unit 1 and it1.  It resumed operations in December 2009 at slightly reduced power.power and a full-capacity blade was installed in 2011.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.

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Our revenues and results of operations from selling power are subject to market risks that are beyond our control.  (Applies to – Affecting each registrant.)Registrant

We sell power from our generation facilities into the spot market and other competitive power markets on a contractual basis.  We also enter into contracts to purchase and sell electricity, natural gas, emission allowances and coal as part of our power marketing and energy trading operations.  With respect to such transactions, the rate of return on our capital investments is not determined through mandated rates, and our revenues and results of operations are likely to depend, in large part, upon prevailing market prices for power in our regional markets and other competitive markets.  These market prices can fluctuate substantially over relatively short periods of time.  Trading margins may erode as markets mature and there may be diminished opportunities for gain should volatility decline. 60;  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 we 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.
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Volatility in market prices for fuel and power may result from:

·  weather conditions;Weather conditions.
·  Outages of major generation or transmission facilities.
·  outages of major generation or transmission facilities;Seasonality.
·  seasonality;Power usage.
·  power usage;Illiquid markets.
·  illiquid markets;Transmission or transportation constraints or inefficiencies.
·  Availability of competitively priced alternative energy sources.
·  Demand for energy commodities.
·  transmission or transportation constraints or inefficiencies;
·  availability of competitively priced alternative energy sources;
·  demand for energy commodities;
·  naturalNatural gas, crude oil and refined products and coal production levels;levels.
·  naturalNatural disasters, wars, embargoes and other catastrophic events; andevents.
·  federal,Federal, state and foreign energy and environmental regulation and legislation.

Our power trading (including coal, gas and emission allowances trading and power marketing) and risk management policies cannot eliminate the risk associated with these activities. (Applies to– Affecting each registrant.)Registrant

Our power trading (including coal, gas and emission allowances trading and power marketing) activities expose us to risks of commodity price movements.  We attempt to manage our exposure 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, we cannot predict the impact that our energy trading and risk management decisions may have on our business, operating results or financial position.

We routinely have open trading positions in the market, within guidelines we set, resulting from the management of our trading portfolio.  To the extent open trading positions exist, fluctuating commodity prices can improve or diminish our financial results and financial position.

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

Our financial performance may be adversely affected if we are unable to operate our electric generating facilities successfully.  (Applies to each registrant.)

Our performance is highly dependent on the successful operation of our electric generating facilities. Operating electric generating 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;
·  fuel supply interruptions caused by transportation constraints, adverse weather, non-performance by our suppliers and other factors; and
·  catastrophic events such as fires, earthquakes, explosions, hurricanes, terrorism, floods or other similar occurrences.

A decrease or elimination of revenues from power produced by our electric generating facilities or an increase in the cost of operating the facilities would adversely affect our results of operations.
 
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Parties with whom we have contracts may fail to perform their obligations, which could harm our results of operations.  (Applies to – Affecting each registrant.)Registrant

We are exposed to the risk that counterparties that owe us money or power could breach their obligations.  Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices that may exceed our contractual prices, which would cause our financial results to be diminished and we 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 rely on electric transmission facilities that we do not own or control.If these facilities do not provide us with adequate transmission capacity, we may not be able to deliver our wholesale electric power to the purchasers of our power.  (Applies to – Affecting each registrant.)Registrant

We depend on transmission facilities owned and operated by other unaffiliatednonaffiliated power companies to deliver the power we sell at wholesale.  This dependence exposes us to a variety of risks.  If transmission is disrupted, or transmission capacity is inadequate, we may not be able to sell and deliver our wholesale power.  If a region’s power transmission infrastructure is inadequate, our 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 transmis siontransmission infrastructure.

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

We do not fully hedge against price changes in commodities.  (Applies to – Affecting each registrant.)Registrant

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

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

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

In July 2010, federal legislation was enacted to reform financial markets that significantly alter how over-the-counter (OTC) derivatives are regulated.  The law increased regulatory oversight of OTC energy derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits.  The law gives the CFTC authority to exempt end users of energy commodities which could reduce, but not eliminate, the applicability of these measures to us and other end users.  These requirements could cause our OTC transactions to be more costly and have an adverse effect on our liquidity du edue 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.

 
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ITEM 1B.   UNRESOLVED STAFF COMMENTS

None.

ITEM 2.   PROPERTIES

GENERATION FACILITIES

UTILITY OPERATIONSUtility Operations

At December 31, 2010,2011, the AEP System owned (or leased where indicated) generating plants, all situated in the states in which our electric utilities serve retail customers, with net maximum power capabilities (winter rating) shown in the following table:tables:

Company Stations 
Coal
MW
  
Natural Gas
MW
  
Nuclear
MW
  
Lignite
MW
  
Hydro
MW
  
Oil
MW
  
Total
MW
 
AEGCo  2 (a)  1,310   1,186               2,496 
APCo  17 (b)(c)  5,093   516         677      6,286 
CSPCo  7 (d)  2,388   1,347             3   3,738 
I&M  9 (a)  2,305       2,191(e)     15       4,511 
KPCo  1    1,078                      1,078 
OPCo  8 (b)(c)  8,482              26       8,508 
PSO  8 (f)  1,026   3,554              25   4,605 
SWEPCo  11 (g)  1,848   2,668       850           5,366 
TNC  6 (f)(h)  377   262               8   647 
System Totals  69    23,907   9,533   2,191   850   718   36   37,235 
Percentage of System Totals       64.2   25.6   5.9   2.3   1.9   0.1     
AEGCo          
          Year Plant
        Net Maximum or First Unit
Plant Name Units State Fuel Type Capacity (MWs) Commissioned
Rockport (1&2(a), 50% of each) 2 IN Steam - Coal 1,310 1984
Lawrenceburg 6 IN Natural Gas 1,186 2004
Total MWs       2,496  
(a) Rockport Unit 2 is leased

(a)Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by I&M. Unit 2 of the Rockport Plant is leased one-half by AEGCo and one-half by I&M. The leases terminate in 2022 unless extended.
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
Smith Mountain 5 VA Pumped Storage 586 1965
Amos (1,2 &3) 3 WV Steam - Coal 1,600 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
Ceredo 6 WV Natural Gas 516 2001
Total MWs       5,977  

(b)Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by OPCo.

(c)APCo owns Units 1 and 3 and OPCo owns Units 2, 4 and 5 of Philip Sporn Plant, respectively.

(d)CSPCo owns generating units in common with Duke Ohio and DP&L. Its percentage ownership interest is reflected in this table.

(e)
Cook Unit 1 currently is not operating at the full capacity set forth here.  For further information, see Cook Nuclear Plant below.

(f)PSO and TNC, along with Oklahoma Municipal Power Authority and The Public Utilities Board of the City of Brownsville, Texas, are joint owners of the Oklaunion power station. PSO and TNC’s ownership interest is reflected in this portion of the table.  TNC has transferred its interest to a non-utility affiliate through 2027.

(g)SWEPCo owns generating units in common with Cleco Corporation and other unaffiliated parties. Only its ownership interest is reflected in this table.

(h)
TNC’s gas-fired and oil-fired generation has been deactivated.
 
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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 (1&2 (a), 50% of each) 2 IN Steam - Coal 1,310 1984
Tanners Creek 4 IN Steam - Coal 995 1951
Cook 2 MI Steam - Nuclear 2,191 1975
Total MWs       4,518  

(a) Rockport Unit 2 is leased

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

OPCo          
          Year Plant
        Net Maximum or First Unit
Plant Name Units State Fuel Type Capacity (MWs) Commissioned
Amos (3) 1 WV Steam - Coal 1,300 1973
Beckjord (a) 1 OH Steam - Coal 53 1969
Cardinal 1 OH Steam - Coal 595 1967
Conesville (a) 4 OH Steam - Coal 1,304 1957
Darby 6 OH Natural Gas 507 2001
Gavin 2 OH Steam - Coal 2,640 1974
Kammer 3 WV Steam - Coal 630 1958
Mitchell 2 WV Steam - Coal 1,560 1971
Muskingum River 5 OH Steam - Coal 1,440 1953
Picway 1 OH Steam - Coal 100 1926
Racine 2 OH Hydro 48 1982
Sporn 2 WV Steam - Coal 290 1950
Stuart (a) 4 OH Steam - Coal 608 1971
Stuart (a) 4 OH Oil 3 1970
Waterford 4 OH Natural Gas 840 2003
Zimmer (a) 1 OH Steam - Coal 330 1991
Total MWs       12,248  
 
(a) Jointly-owned with non-affiliated entities.  Figures presented reflect only the portion owned by OPCo.


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PSO          
          Year Plant
        Net Maximum or First Unit
Plant Name Units State Fuel Type Capacity (MWs) Commissioned
Riverside (1&2) 2 OK Steam - Natural Gas 909 1974
Riverside (3&4) 2 OK Natural Gas 160 2008
Riverside 1 OK Oil 3 1976
Northeastern (1&2) 4 OK Steam - Natural Gas 920 1961
Northeastern 1 OK Oil 3 1961
Southwestern (1-3) 3 OK Steam - Natural Gas 470 1952
Southwestern (4&5) 2 OK Natural Gas 170 2008
Southwestern 1 OK Oil 2 1962
Comanche 3 OK Natural Gas 260 1973
Comanche 2 OK Oil 4 1962
Weleetka 3 OK Natural Gas 200 1975
Weleetka 2 OK Oil 4 1963
Northeastern (3&4) 2 OK Steam - Coal 930 1979
Northeastern 1 OK Oil 1 1980
Oklaunion (a) 1 TX Steam - Coal 102 1986
Total MWs       4,138  
           
(a) Jointly-owned with TNC and non-affiliated entities.  Figures presented reflect only the portion owned by PSO.

SWEPCo           
          Year Plant 
       Net Maximum  or First Unit 
Plant Name Units StateFuel Type Capacity (MWs)  Commissioned 
Arsenal Hill  1 LASteam - Natural Gas  110   1960 
Lieberman  4 LASteam - Natural Gas  271   1947 
Knox Lee  4 TXSteam - Natural Gas  480   1950 
Wilkes  3 TXSteam - Natural Gas  856   1964 
Lone Star  1 TXSteam - Natural Gas  50   1954 
Stall  1 LANatural Gas  543   2010 
Mattison  4 ARNatural Gas  312   2007 
Welsh  3 TXSteam - Coal  1,584   1977 
Flint Creek  1 ARSteam - Coal  264   1978 
Pirkey  1 TXSteam - Lignite  580   1985 
Dolet Hills  1 LASteam - Lignite  262   1986 
Total MWs        5,312     
               
TNC              
               
        Net Maximum  Year Plant 
Plant Name Units StateFuel Type Capacity (MWs)  Commissioned 
Oklaunion (a)  1 TXSteam - Coal  377   1986 
               
(a) Jointly-owned with PSO and non-affiliated entities. Figures presented reflect only the portion owned by TNC. 


40


Domestic Independent Power (Generation and Marketing Segment)
 
           
        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  

The source of fuel in terms of total megawatts as well as a percentage of all of the generation units set forth in the tables above consists of the following:

Coal/Lignite (a)  24,302   67%
Natural Gas/Oil  8,780   24%
Nuclear  2,191   6%
Wind/Hydro/Pumped Storage  1,182   3%
Total MWs Generating Capacity  36,455   100%
         
(a) Does not include AEP’s 43% ownership of OVEC. 

Cook Nuclear Plant

The following table provides operating information relating to the Cook Plant.Plant:

Cook Plant Cook Plant
Unit 1 Unit 2 Unit 1 (a) Unit 2
Year Placed in Operation1975 1978Year Placed in Operation1975 1978
Year of Expiration of NRC License2034 2037Year of Expiration of NRC License2034 2037
Nominal Net Electrical Rating in Kilowatts1,084,000 1,107,000Nominal Net Electrical Rating in Kilowatts1,084,000 1,107,000
Net Capacity Factors   Net Capacity Factors   
2011201181.3% 99.4%
201082.2%(a) 80.8%201082.2% 80.8%
20092.8%(a) 83.1%20092.8% 83.1%
200859.2%(a) 96.6%200859.2% 96.6%
2007                 97.4% 83.8%
   Unit 1 Net Capacity Factor for 2008 through 2010 was impacted by a 2008 forced outage caused by a low pressure turbine blade failure event.  The reduced-capacity, repaired turbine was replaced with a full-capacity, new turbine in late 2011.
(a)

(a)   Unit 1 Net Capacity Factor for 2008 through 2010 was impacted by a 2008 forced outage caused by a low pressure turbine blade failure event. The reduced capacity repaired turbine is projected to be replaced with a full capacity turbine in late 2011.New Generation

New Generation

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in-service in the fourth quarter of 2012.  SWEPCo owns 73% of the Turk Plant and will operate the completed facility.  AEGCo is currently constructing theAPCo’s Dresden Plant, a new 580 MW combined-cycle natural gas generating unit in Ohio, which is expected to be in-servicewas completed and placed in 2012.  We resumed work on the Dresden Plantservice in the first quarter of 2011.January 2012.

GENERATION AND MARKETING

In addition to the generating facilities described above, AEP has ownership interests in other electrical generating facilities. Information concerning these facilities at December 31, 2010 is listed below.

Facility
FuelLocation
Capacity
Total MW
Desert Sky Wind FarmWindTexas161
Trent Wind FarmWindTexas150
Total311

 
3741
 
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:

Total Overhead Circuit Miles of
Transmission and Distribution Lines
 
Circuit Miles of
765kV Lines
 Total Overhead Circuit Miles of Transmission and Distribution Lines 
Circuit Miles of
765kV Lines
AEP System (a)224,703(b) 2,116 AEP System (a)224,475(b)2,116
APCo52,233  734 APCo52,312 734
CSPCo (a)15,697  — 
I&M22,005  615 I&M22,005 615
KgPCo1,358  — 
KGPCoKGPCo1,359 -
KPCo11,087  258 KPCo11,113 258
OPCo30,754  509 
OPCo (a)OPCo (a)46,413 509
PSO21,126  — PSO21,083 -
SWEPCo21,759  — SWEPCo21,883 -
TCC29,686  — TCC29,301 -
TNC17,289  — TNC17,212 -
WPCo1,708  — WPCo1,727 -
   
(a)Includes 766 miles of 345,000-volt jointly owned lines.
(b)Includes 73 miles of overhead transmission lines not identified with an operating company.

TRANSMISSION OPERATIONS

The following table sets forth the total overhead circuit miles of transmission lines of ETT, OHTCo and OKTCo:

(a)Includes 766 milesTotal Overhead Circuit Miles of 345,000-volt jointly owned lines.Transmission Lines
ETT445
OHTCo31
OKTCo36
(b)Includes 73 miles of overhead transmission lines not identified with an operating company.

TRANSMISSION INITIATIVES

We continue our pursuit of transmission opportunities throughout the U.S.  In 2009, we announced that our recently formed transmission company, AEP Transmission Company, LLC, will pursue new transmission investments within our retail service territories.  Through joint ventures with various other companies, we have existing and/or planned transmission projects and opportunities outside of our retail service territories.  We plan to invest approximately $273 million in these projects in 2011.  See Management’s Financial Discussion and Analysis included in the 2010 Annual Reports under the heading Transmission Initiatives, for more information.

TITLES

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 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.  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 legislation in Ohio and Virginia has restricted the right of eminent domain previously granted for power generation purposes.

SYSTEM TRANSMISSION LINES AND FACILITY SITING

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

 
3842
 
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 $2.5$3.1 billion of construction expenditures for 2011,2012, excluding the debt and equity components of AFUDC, capitalized interest and assets acquired under leases.  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, weather, legal reviews and the ability to access capital.

CONSTRUCTION EXPENDITURESConstruction Expenditures

The following table shows construction expenditures (including environmental expenditures) during 2008,2011, 2010 and 2009 and 2010 and a current estimate of 20112012 construction expenditures.  Actual amounts for 2008,2011, 2010 and 2009 and 2010budgeted amounts for 2012 exclude the equity component of AFUDC, capitalized interest and assets acquired under leases.  Budgeted amounts for 2011 exclude the debt and equity components of AFUDC and assets acquired under leases. 

  
2008
Actual
  
2009
Actual
  
2010
Actual
  
2011
Estimate (b)
 
  (in thousands) 
Total AEP System (a) $3,800,000  $2,792,000  $2,345,000  $2,506,000 
APCo  696,767   543,587   534,334   450,100 
CSPCo  433,014   302,699   235,901   186,900 
I&M  352,335   332,775   333,238   304,900 
OPCo  706,315   417,601   276,736   264,100 
PSO  285,826   175,122   194,896   169,200 
SWEPCo  692,162   596,581   420,485   441,500 

(a)  Includes expenditures of other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies.  Excludes discontinued operations.
      (b)Excludes Sabine Mining.
  2012 Estimate (b) 2011 Actual 2010 Actual 2009 Actual
  (in thousands)
Total AEP System (a) $3,064,700 $2,669,000 $2,345,000 $2,792,000
APCo  448,500  463,077  534,334  543,587
I&M  468,400  301,241  333,238  332,775
OPCo  569,400  460,125  512,637  720,300
PSO  204,100  140,326  194,896  175,122
SWEPCo (b)  475,400  551,163  420,485  596,581
                
(a) Includes expenditures of other subsidiaries not shown.  The figure reflects construction expenditures, not equity investments in subsidiary companies.
(b)Excludes Sabine.

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

POTENTIAL UNINSURED LOSSES

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to our generating plants and costs of replacement power.  Unless allowed to be recovered through rates, future losses or liabilities which are not completely insured could have a material adverse effect on results of operations and the financial condition of AEP and other AEP System companies.  For risks related to owning a nuclear generating unit, see Note 65 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies under the heading Nuclear Contingencies for information with respect to nuclear in cidentincident liability insurance.

39
ITEM 3.   LEGAL PROCEEDINGS

For a discussion of material legal proceedings, see Note 65 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies,, incorporated by reference in Item 8.

ITEM 4.                  REMOVED AND RESERVED

EXECUTIVE OFFICERS OF THE REGISTRANTS

AEP.  The following persons are, or may be deemed, executive officers of AEP.  Their ages are given as of February 1, 2011.

NameAgeOffice (a)
Michael G. Morris64Chairman of the Board and Chief Executive Officer
Nicholas K. Akins50President
Carl L. English64Vice Chairman
D. Michael Miller63Senior Vice President, General Counsel and Secretary
Robert P. Powers56President-AEP Utilities
Brian X. Tierney43Executive Vice President and Chief Financial Officer
Susan Tomasky57President – AEP Transmission

(a)  All of the executive officers have been employed by AEPSC or System companies in various capacities (AEP, as such, has no employees) for the past five years.  Mr. Akins became an executive officer of AEP in June 2006, Mr. English in August, 2004, Mr. Miller in July 2010, Mr. Powers in October 2001, Mr. Tierney in January 2008 and Ms. Tomasky in January 2000.  All of the above officers are appointed annually for a one-year term by the board of directors of AEP.

APCo, OPCo, PSO and SWEPCo.  The names of the executive officers of APCo, OPCo, PSO and SWEPCo, the positions they hold with these companies, their ages as of February 1, 2011, and a brief account of their business experience during the past five years appear below. The directors and executive officers of APCo, OPCo, PSO and SWEPCo are elected annually to serve a one-year term.

NameAgePositionPeriod
Michael G. Morris (a)(b)64Chairman of the Board, Chief Executive Officer and Director of AEP2004-Present
Chairman of the Board, Chief Executive Officer and Director of APCo, OPCo, PSO and SWEPCo2004-Present
Nicholas K. Akins (a)50
President of AEP
Executive Vice President of AEP, Vice President
2011-Present
and Director of APCo, OPCo, PSO and SWEPCo2006-Present
President and Chief Operating Officer of SWEPCo2004-2006
Carl L. English (a)64Vice Chairman2010 - Present
Chief Operating Officer2008-2010
President-AEP Utilities of AEP2004-2007
Director and Vice President of APCo, OPCo, PSO and SWEPCo2004-Present
D. Michael Miller (c)63
Senior Vice President, General Counsel and Secretary of AEP
Deputy General Counsel of AEPSC
Director of APCo, OPCo, PSO and SWEPCo
2010-Present
2002-2010
2010-Present
Robert P. Powers (a)56President-AEP Utilities of AEP2008-Present
Executive Vice President of AEP2004-2007
Director and Vice President of APCo and OPCo2001-Present
Director and Vice President of PSO and SWEPCo2008-Present
Brian X. Tierney (a)43Executive Vice President2008-Present
Chief Financial Officer2009-Present
Director and Vice President of APCo and OPCo2008-Present
 
4043
 
Director and Vice President of PSO and SWEPCo2009-Present
Senior Vice President—Commercial Operations of AEPSC2005-2007
Susan Tomasky (a)57President-AEP Transmission2008-Present
Executive Vice President of AEP2004-Present
Chief Financial Officer of AEP2001-2006
Vice President and Director of APCo, OPCo, PSO and SWEPCo2000-Present

ITEM 4.MINE SAFETY DISCLOSURE

(a)Messrs. Morris, Akins, English, Powers and Tierney and Ms. Tomasky are directors of CSPCo and I&M.
(b)Mr. Morris is a director of Alcoa, Inc. and The Hartford Financial Services Group, Inc.
(c)Mr. Miller is a director of CSPCo.
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 (DHLC) and OPCo, through its ownership of Conesville Coal Preparation Company (CCPC) and its use of the Conner Run fly ash impoundment, are subject to the provisions of the Mine Act.  OPCo is in the process of selling CCPC.

The persons listed below areDodd-Frank Wall Street Reform and Consumer Protection Act and the Presidents,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 therefore are also executive officers, of APCo, OPCo, PSOproposed assessments received by DHLC, CCPC and SWEPCo, respectively.Conner Run under the Mine Act for the year ended December 31, 2011.
APCo:
NameAgePositionPeriod
Charles R. Patton51President and Chief Operating Officer of APCo
2010-Present
Executive Vice President of AEP2009-2010
Senior Vice President-Regulatory and Public Policy of AEP
2008-2009
President and Chief Operating Officer of TCC and TNC2004-2008
Director and Vice President of PSO and SWEPCo2009-2010
OPCo:
NameAgePositionPeriod
Joseph Hamrock47President and Chief Operating Officer of CSPCo and OPCo2008-Present
Senior Vice President and Chief Information Officer of AEPSC2003-2007

PSO:
NameAgePositionPeriod
Stuart Solomon49 President and Chief Operating Officer of PSO 2004-Present

SWEPCo:
NameAgePositionPeriod
Venita McCellon-Allen  50 President and Chief Operating Officer of SWEPCo 2010-Present
 Executive Vice President of AEP 2008-2010
 Director and Vice President of APCo and OPCo 2009-2010
 Director and Vice President of PSO and SWEPCo 2008-2009
 President and Chief Operating Officer of SWEPCo 2006-2008
Senior Vice President-Shared Services of AEPSC 2004-2006
 Director of APCo, OPCo and SWEPCo 2004-2006
 
4144
 

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 1413 to the consolidated financial statements entitled Financing Activities under the heading Dividend Restrictions in the 20102011 Annual Report.

APCo, CSPCo, I&M, OPCo, PSO and SWEPCo. 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 2008,2011, 2010 and 2009 and 2010 are incorporated by reference to the material under Statements of Changes in Common Shareholder’s Equity and Comprehensive Income (Loss) and Note 1413 to the consolidated financial statements entitled Financing Activities under the heading Dividend Restrictions in the 20102011 Annual Reports.

During the quarter ended December 31, 2010,2011, 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

CSPCo and I&M.  Omitted pursuant to Instruction I(2)(a).

AEP, APCo, I&M, OPCo, PSO and SWEPCo.  The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 2010 Annual Reports.

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

CSPCo and I&M.  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 Financial Discussion and Analysis in the 20102011 Annual Reports.

AEP APCo, OPCo, PSO and SWEPCo.  

The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 2011 Annual Reports.

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

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 Financial Discussion and Analysis in the 20102011 Annual Reports.Reports.

ITEM 7A.                          QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISKAEP

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo. The information required by this item is incorporated herein by reference to the material under Management’s Financial Discussion and Analysis—Analysis in the 2011 Annual Reports.

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 Financial Discussion and Analysis – Quantitative and Qualitative Disclosures about Market and Credit Risk in the 20102011 Annual Reports.

45
ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ITEM 8.                      FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA

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

42
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo.       None.SWEPCo

None.

ITEM 9A.CONTROLS AND PROCEDURES

During 2010,2011, management, including the principal executive officer and principal financial officer of each of American Electric Power Company, Inc., Appalachian Power Company, Columbus Southern 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 Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the 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, 2010,2011, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.  The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

There have been no changes in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter of 20102011 that materially affected, or are reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

Management is required to assess and report on the effectiveness of its internal control over financial reporting as of December 31, 2010.2011.  As a result of that assessment, management determined that there were no material weaknesses as of December 31, 20102011 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 20102011 Annual Report of each Registrant.

ITEM 9B.   OTHER INFORMATION

None.

 
4346
 

PART III

ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS
AND CORPORATE GOVERNANCE

CSPCoAPCo, I&M, OPCo, PSO and I&M. SWEPCo

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

AEP:AEP

Directors, Director Nomination Process and Audit Committee.  Committee

Certain of the information called for in this Item 10, including the information relating to directors, is incorporated herein by reference to AEP's definitive proxy information statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to 20112012 Annual Meeting of Shareholders including under the captions “Election of Directors,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “AEP's Board of Directors and Committees,” “Directors,” "Involvement by Mr. Hoaglin in Certain Legal Proceedings" and “Shareholder Nominees for Directors.”

Executive Officers.Officers

Reference also is made to the information under the caption Executive Officers of the Registrants in Part I, Item 4 of this report.

Code of Ethics.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.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.Compliance

The information required by this item is incorporated herein by reference to information contained in the definitive proxy statement of AEP for the 20112012 annual meeting of shareholders.

APCo, OPCo, PSO and SWEPCo:

Directors and Executive Officers.   Certain of the information called for in this Item 10, including the information relating to directors, is incorporated herein by reference to the definitive information statement for each company (which will be filed with the SEC under the Exchange Act) relating to 2011 Annual Meeting of Shareholders under the captions “Election of Directors” and “Director Nomination Process.”

Audit Committee.  Each of APCo, OPCo, PSO and SWEPCo is a controlled subsidiary of AEP and does not have a separate audit committee.

Code of Ethics.  AEP’s Principles of Business Conduct is the code of ethics that applies to the Chief Executive Officer, Chief Financial Officer and principal accounting officer of  APCo, OPCo, PSO and SWEPCo The discussion of AEP’s Principles of Business Conduct above is incorporated herein by reference.  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 the Chief Executive Officer, Chief Financial Officer or principal accounting officer of APCo, OPCo, PSO and SWEPCo, as applicable, that company will disclose the nature of such amendment or waiver on AEP’s website, www.aep.com, or in a report on Form 8-K.
44
ITEM 11.EXECUTIVE COMPENSATION

CSPCoAPCo, I&M, OPCo, PSO and I&M.  SWEPCo

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

AEP.

The information called for by this Item 11 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 the 20112012 Annual Meeting including under the captions “Compensation Discussion and Analysis,” “Executive Compensation” and “Director Compensation”.  The information set forth under the subcaption “Human Resources 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 we specifically incorporate such report by reference therein.

47
APCo, OPCo, PSO and SWEPCO.  Certain of the information called for in this Item 11 is incorporated herein by reference to the definitive information statement for each company (which will be filed with the SEC under the Exchange Act) relating to 2011 Annual Meeting of Shareholders including under the captions “Compensation Discussion and Analysis,” “Executive Compensation” and “Director Compensation”. The information set forth under the subcaption “Human Resources Committee Report” should not be deemed filed nor should it be incorporated by reference in to any other filing under the Securities Act of 1933, as amended, or the Exchange Act except to the extent we specifically incorporate such report by reference therein.

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

CSPCoAPCo, I&M, OPCo, PSO and I&M. 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'sAEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to 20112012 Annual Meeting of Shareholders under the caption “Share Ownership of Certain Beneficial Owners and Management" and "Share Ownership of Directors and Executive Officers".

APCo, OPCo, PSO and SWEPCO. The information relating to Security Ownership of Certain Beneficial Owners is incorporated herein by reference to the definitive information statement for each company (which will be filed with the SEC under the Exchange Act) relating to the 2011 Annual Meeting under the caption “Share Ownership of Certain Beneficial Owners and Management" and "Share Ownership of Directors and Executive Officers".
45
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, 2010:2011:

 (Column A) (Column B) (Column C)
Plan Category
 
 
Number of securities to be issued upon exercise of outstanding options warrants and rights
(a)
 
 
Weighted average exercise price of outstanding options, warrants and rights
(b)
 
 
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))(2)
(c)
Plan Category Number of Securities to be Issued upon Exercise of Outstanding Options Warrants and Rights Weighted Average Exercise Price of Outstanding Options, Warrants and Rights 
Number of Securities Remaining
Available for Future Issuance under Equity Compensation Plans (Excluding Securities Reflected in Column A(b)
Equity compensation plans approved by security holders(1) 
 
1,557,813
 $32.88 18,836,851
Equity compensation plans not approved by security holders 0 0 0
Equity Compensation Plans Approved by Security Holders (a)Equity Compensation Plans Approved by Security Holders (a) 
 
320,880
 $29.35 18,444,311
Equity Compensation Plans Not Approved by Security HoldersEquity Compensation Plans Not Approved by Security Holders -  - -
Total 1,557,813 $32.88 18,836,851Total 320,880 $29.35 18,444,311
       
(a)Consists of shares to be issued upon exercise of outstanding options granted under the Amended and  Restated American
Electric Power System Long-Term Incentive Plan.
(b)
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 1,091,485 higher if equity compensation that is paid in cash were not deducted from this column.
 

(1) Consists of shares to be issued upon exercise of outstanding options granted under the Amended and  Restated American Electric Power System Long-Term Incentive Plan.
(2) 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 1,185,633 higher if equity compensation that is paid in cash were not deducted from this column.
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

CSPCoAPCo, I&M, OPCo, PSO and I&M:  SWEPCo

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

AEP:AEP

The information called for by this Item 13 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 the 20112012 Annual Meeting under the captions “Transactions with Related Persons” and “Director Independence.”

APCo, OPCo, PSO and SWEPCo:    Certain Relationships and Related Transactions.  There were no related person transactions involving APCo, OPCo, PSO or SWEPCo.  All of those companies' directors are not independent by virtue of being directors, officers or employees of AEP or  APCo, OPCo, PSO or SWEPCo.

ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES

AEP.  

The information called for by this Item 14 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 the 20112012 Annual Meeting under the captions “Audit and Non-Audit Fees,” "Audit Committee Report" and “Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Auditor.”

APCo, OPCo, PSO and SWEPCo.  The information called for by this Item 14 is incorporated herein by reference to the definitive information statement for each company (which will be filed with the SEC under the Exchange Act) relating to the 2011 Annual Meeting under the captions “Independent Registered Public Accounting Firm,” and “AEP's Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Auditor.”
 
4648
 
CSPCo
APCo, I&M, OPCo, PSO and I&M. 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 20112012 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, 20092011 and 2010, 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.

CSPCoI&MAPCo I&M OPCo 
20102009201020092011 2010 2011 2010 2011 2010 
Audit Fees$871,146$1,038,130$1,393,624$1,612,867 $2,241,610  $1,978,687  $1,610,206  $1,393,624  $2,849,269  $1,814,099 
Audit-Related Fees6,50025,9946,50037,851  6,900   6,500   6,900   6,500   6,900   6,500 
Tax Fees9,00025,53612,00039,304  9,000   9,000   12,000   12,000   18,000   9,000 
TOTAL$886,646$1,089,660$1,412,124$1,690,022
Total $2,257,510  $1,994,187  $1,629,106  $1,412,124  $2,874,169  $1,829,599 

 PSO SWEPCo 
 2011 2010 2011 2010 
Audit Fees $714,097  $645,180  $894,582  $975,827 
Audit-Related Fees  6,900   6,500   69,750   67,500 
Tax Fees  9,000   9,000   8,977   8,977 
Total $729,997  $660,680  $973,309  $1,052,304 


 
4749
 

PART IV

ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

Page
1.  Financial Statements:
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, 2011, 2010 2009 and 2008;2009; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2011, 2010 and 2009; Consolidated Statements of Changes in Equity for the years ended December 31, 2011, 2010 and 2009; Consolidated Balance Sheets as of December 31, 20102011 and 2009;2010; Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 2009 and 2008; Consolidated Statements of Changes in Equity and Comprehensive Income (Loss) for the years ended December 31, 2010, 2009 and 2008;2009; Notes to Consolidated Financial Statements. 
APCo CSPCo and I&M: 
Consolidated Statements of Income for the years ended December 31, 2011, 2010 2009 and 2008;2009; Consolidated Statements of Changes in Common Shareholder’s Equity and Comprehensive Income (Loss) for the years ended December 31, 2011, 2010 2009 and 2008;2009; Consolidated Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2011, 2010 and 2009; Consolidated Balance Sheets as of December 31, 20102011 and 2009;2010; Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 2009 and 2008;2009; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm.
 
OPCo and SWEPCo: 
Consolidated Statements of Income for the years ended December 31, 2011, 2010 2009 and 2008;2009; Consolidated Statements of Changes in Equity and Comprehensive Income (Loss) for the years ended December 31, 2011, 2010 2009 and 2008;2009; Consolidated Statements of Changes in Equity for the years ended December 31, 2011, 2010 and 2009; Consolidated Balance Sheets as of December 31, 20102011 and 2009;2010; Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 2009 and 2008;2009; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm. 
PSO: 
Statements of OperationsIncome for the years ended December 31, 2011, 2010 2009 and 2008;2009; Statements of Changes in Common Shareholder’s Equity and Comprehensive Income (Loss) for the years ended December 31, 2011, 2010 2009 and 2008;2009; Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2011, 2010 and 2009; Balance Sheets as of December 31, 20102011 and 2009;2010; Statements of Cash Flows for the years ended December 31, 2011, 2010 2009 and 2008;2009; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm. 
   2.   Financial Statement Schedules:
 
2.  FINANCIAL STATEMENT SCHEDULES:
Page
Number
Financial Statement Schedules are listed in the Index to Financial Statement SchedulesSchedules.  (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 FirmFirm.S-1
3.  Exhibits:EXHIBITS: 
Exhibits for AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by referencereference.E-1


 
4850
 

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, 201128, 2012

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/   Michael G. Morris
Chairman of the Board,February 25, 2011
(Michael G. Morris)s/   Nicholas K. Akins Chief Executive Officer, President and DirectorFebruary 28, 2012
(Nicholas K. Akins)  
     
     
(ii)           Principal Financial Officer:    
     
/s/   Brian X. Tierney
 Executive Vice President and February 25, 201128, 2012
(Brian X. Tierney) Chief Financial Officer  
     
(iii)           Principal Accounting Officer:    
     
/s/   Joseph M. Buonaiuto
 Senior Vice President, Controller and February 25, 201128, 2012
(Joseph M. Buonaiuto) Chief Accounting Officer  
     
(iv)           A Majority of the Directors:    
     
*E. R. Brooks
*Donald M. Carlton
* James F. Cordes
Nicholas K. Akins		    
*David J. Anderson
* James F. Cordes
* Ralph D. Crosby, Jr.    
*Linda A. Goodspeed
    
*ThomasThomas E. Hoaglin
Hoaglin		    
*Lester A. Hudson, Jr.
*Michael G. Morris
*Richard C. Notebaert    
*Lionel L. Nowell, III    
*Richard L. Sandor
*Kathryn D. Sullivan
    
*Sara Martinez Tucker    
*John F. Turner    
     
      
*By:
/s/   Brian X. Tierney
   February 25, 201128, 2012
 (Brian X. Tierney, Attorney-in-Fact)    

 
4951
 

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
 Columbus Southern 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, 201128, 2012

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/   Michael G. Morris
Chairman of the Board,February 25, 2011
(Michael G. Morris)s/   Nicholas K. Akins Chief Executive Officer, President and DirectorFebruary 28, 2012
(Nicholas K. Akins)  
     
(ii)           Principal Financial Officer:    
     
/s/   Brian X. Tierney
 Vice President, February 25, 201128, 2012
(Brian X. Tierney) Chief Financial Officer and Director  
     
(iii)           Principal Accounting Officer:    
     
/s/   Joseph M. Buonaiuto
 Controller and February 25, 201128, 2012
(Joseph M. Buonaiuto) Chief Accounting Officer  
     
(iv)           A Majority of the Directors:    
     
*Nicholas K. Akins    
*Carl L. EnglishLisa M. Barton    
*D. Michael MillerDavid M. Feinberg
*Mark C. McCullough    
*Robert P. Powers    
*Barbara D. Radous
*Susan Tomasky    
*Dennis E. Welch    
     
*By:
/s/   Brian X. Tierney
   February 25, 201128, 2012
 (Brian X. Tierney, Attorney-in-Fact)    

 
5052
 

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

Date: February 25, 201128, 2012

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/   Michael G. Morris
Chairman of the Board,February 25, 2011
(Michael G. Morris)s/   Nicholas K. Akins Chief Executive Officer, President and DirectorFebruary 28, 2012
(Nicholas K. Akins)  
     
(ii)           Principal Financial Officer:    
     
/s/   Brian X. Tierney
 Vice President, February 25, 201128, 2012
(Brian X. Tierney) Chief Financial Officer and Director  
     
(iii)           Principal Accounting Officer:    
     
/s/   Joseph M. Buonaiuto
 Controller and February 25, 201128, 2012
(Joseph M. Buonaiuto) Chief Accounting Officer  
     
(iv)           A Majority of the Directors:    
     
*Nicholas K. Akins    
*Lisa M. Barton
*Sarah L. Bodner    
*Paul Chodak, III    
*J. Edward Ehler    
*Carl L. English
*Allen R. Glassburn    
*scott m. krawecScott M. Krawec    
*Daniel V. Lee    
*Marc E. Lewis    
*Mark C. McCullough
*Robert P. Powers    
*Susan Tomasky    
     
*By:
/s/   Brian X. Tierney
   February 25, 201128, 2012
 (Brian X. Tierney, Attorney-in-Fact)    


 
5153
 


INDEX TOOF FINANCIAL STATEMENT SCHEDULES

 
Page
Number
Reports of Independent Registered Public Accounting Firm  S-2
 
REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS-2
  
The following financial statement schedules are included in this report on the pages indicated: 
  
AMERICAN ELECTRIC POWER COMPANY, INC.American Electric Power Company, Inc. (Parent)
:
Schedule I —– Condensed Financial Information
  S-3
Schedule I —– Condensed Notes to Condensed Financial InformationS-3  S-7
  
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
American Electric Power Company, Inc. and Subsidiary Companies:
Schedule II —– Valuation and Qualifying Accounts and Reserves
S-10
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Appalachian Power Company and Subsidiaries:
Schedule II —– Valuation and Qualifying Accounts and Reserves  S-10
 
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Indiana Michigan Power Company and Subsidiaries:
Schedule II —– Valuation and Qualifying Accounts and Reserves  S-10
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Ohio Power Company Consolidated:
Schedule II —– Valuation and Qualifying Accounts and Reserves  S-11
 
OHIO POWER COMPANY CONSOLIDATED
Public Service Company of Oklahoma:
Schedule II —– Valuation and Qualifying Accounts and Reserves  S-11
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
Southwestern Electric Power Company Consolidated:
Schedule II —– Valuation and Qualifying Accounts and Reserves 
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, 20102011 and 2009,2010, and for each of the three years in the period ended December 31, 2010,2011, and the Company's internal control over financial reporting as of December 31, 2010,2011, and have issued our reports thereon dated February 25, 201128, 2012 (which report on the consolidated financial statements expresses an unqualified opinion and includes an explanatory paragraph relating to the adoption of a new accounting pronouncementpronouncements in 2011 and 2010); such consolidated financial statements and our reports are included in the Company’s 20102011 Annual Report (filed as Exhibit 13 to the 20102011 Annual Report on Form 10-K of American Electric Power Company, Inc.) and are incorporated herein by reference.& #160;  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, 2011
28, 2012



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have audited the financial statements of Appalachian Power Company and subsidiaries, Columbus Southern Power Company and subsidiaries, Indiana Michigan Power Company and subsidiaries, Ohio Power Company Consolidated, Public Service Company of Oklahoma and Southwestern Electric Power Company Consolidated (collectively the “Companies”) as of December 31, 20102011 and 2009,2010, and for each of the three years in the period ended December 31, 2010,2011, and have issued our reports thereon dated February 25,28, 2012 (which reports on the financial statements of Appalachian Power Company and subsidiaries, Indiana Michigan Power Company and subsidiaries, Ohio Power Company Consolidated and Public Service Company of Oklahoma express an unqualified opinion and include an explanatory paragraph relating to the adoption of a new accounting pronouncement in 2011 (whichand which report on the financial statements of Southwestern Electric Power Company Consolidated expresses an unqualified opinion and includes an explanatory paragraph relating to the adoption of a new accounting pronouncementpronouncements in 2011 and 2010); such financial statements and our reports are included in the Companies' 2010 Ann ualCompanies’ 2011 Annual Reports (filed as Exhibit 13 to the 20102011 Annual Reports on Form 10-K of Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company) and are incorporated herein by reference.  Our audits also included the financial statement schedules 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, 2011
28, 2012

 
S-2
 


SCHEDULE ISCHEDULE I SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)AMERICAN ELECTRIC POWER COMPANY, INC. (Parent) AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATIONCONDENSED FINANCIAL INFORMATION CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF INCOMECONDENSED STATEMENTS OF INCOME CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2010, 2009 and 2008 
For the Years Ended December 31, 2011, 2010 and 2009For the Years Ended December 31, 2011, 2010 and 2009
(in millions, except per-share and share amounts)(in millions, except per-share and share amounts) (in millions, except per-share and share amounts)
          
         
 2010  2009  2008   2011  2010  2009 
REVENUES         REVENUES         
Affiliated Revenues $4  $2  $1 Affiliated Revenues $ 5  $ 4  $ 2 
                      
EXPENSES            EXPENSES         
Other Operation  54   18   15 Other Operation   23    54    18 
                      
OPERATING LOSS  (50)  (16)  (14)OPERATING LOSS   (18)   (50)   (16)
                      
Other Income (Expense):            Other Income (Expense):         
Interest Income  22   45   77 Interest Income   19    22    45 
Interest Expense  (52)  (84)  (112)Interest Expense   (42)   (52)   (84)
                      
LOSS BEFORE EQUITY EARNINGS  (80)  (55)  (49)
LOSS BEFORE INCOME TAX CREDIT ANDLOSS BEFORE INCOME TAX CREDIT AND         
            EQUITY EARNINGS   (41)   (80)   (55)
         
Income Tax CreditIncome Tax Credit   2    -    - 
Equity Earnings of Unconsolidated Subsidiaries  1,291   1,412   1,429 Equity Earnings of Unconsolidated Subsidiaries   1,980    1,291    1,412 
                      
NET INCOME $1,211  $1,357  $1,380 NET INCOME $ 1,941  $ 1,211  $ 1,357 
                      
WEIGHTED AVERAGE NUMBER OF BASIC AEP            WEIGHTED AVERAGE NUMBER OF BASIC AEP         
COMMON SHARES OUTSTANDING  479,373,306   458,677,534   402,083,847 
COMMON SHARES OUTSTANDING   482,169,282    479,373,306    458,677,534 
                      
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE            TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE         
TO AEP COMMON SHAREHOLDERS $2.53  $2.96  $3.43 
TO AEP COMMON SHAREHOLDERS $ 4.02  $ 2.53  $ 2.96 
                      
WEIGHTED AVERAGE NUMBER OF DILUTED AEP            WEIGHTED AVERAGE NUMBER OF DILUTED AEP         
COMMON SHARES OUTSTANDING  479,601,442   458,982,292   403,640,708 
COMMON SHARES OUTSTANDING   482,460,328    479,601,442    458,982,292 
                      
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE            TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE         
TO AEP COMMON SHAREHOLDERS $2.53  $2.96  $3.42 
            TO AEP COMMON SHAREHOLDERS $ 4.02  $ 2.53  $ 2.96 
See Condensed Notes to Condensed Financial Information. 
         
See Condensed Notes to Condensed Financial Information beginning on page S-7.See Condensed Notes to Condensed Financial Information beginning on page S-7.

 
S-3
 


SCHEDULE I 
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent) 
CONDENSED FINANCIAL INFORMATION 
CONDENSED BALANCE SHEETS 
ASSETS 
December 31, 2010 and 2009 
(in millions) 
  
  2010  2009 
CURRENT ASSETS      
Cash and Cash Equivalents $231  $233 
Other Temporary Investments  99   33 
Advances to Affiliates  556   257 
Accounts Receivable:        
   General  18   27 
   Affiliated Companies  113   11 
       Total Accounts Receivable  131   38 
Prepayments and Other Current Assets  7   7 
TOTAL CURRENT ASSETS  1,024   568 
         
PROPERTY, PLANT AND EQUIPMENT        
General  2   2 
Total Property, Plant and Equipment  2   2 
Accumulated Depreciation and Amortization  2   2 
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET  -   - 
         
OTHER NONCURRENT ASSETS        
Investments in Unconsolidated Subsidiaries  14,297   13,861 
Affiliated Notes Receivable  295   575 
Deferred Charges and Other Noncurrent Assets  70   70 
TOTAL OTHER NONCURRENT ASSETS  14,662   14,506 
         
TOTAL ASSETS $15,686  $15,074 
         
See Condensed Notes to Condensed Financial Information.        
 SCHEDULE I
 AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
 CONDENSED FINANCIAL INFORMATION
 CONDENSED BALANCE SHEETS
 ASSETS
 December 31, 2011 and 2010
 (in millions)
  
   2011  2010 
 CURRENT ASSETS      
 Cash and Cash Equivalents $ 127  $ 231 
 Other Temporary Investments   2    99 
 Advances to Affiliates   944    556 
 Accounts Receivable:      
  General   17    18 
  Affiliated Companies   43    113 
   Total Accounts Receivable   60    131 
 Prepayments and Other Current Assets   7    7 
 TOTAL CURRENT ASSETS   1,140    1,024 
        
 PROPERTY, PLANT AND EQUIPMENT      
 General   2    2 
 Total Property, Plant and Equipment   2    2 
 Accumulated Depreciation and Amortization   2    2 
 TOTAL PROPERTY, PLANT AND EQUIPMENT - NET   -    - 
        
 OTHER NONCURRENT ASSETS      
 Investments in Unconsolidated Subsidiaries   15,170    14,297 
 Affiliated Notes Receivable   290    295 
 Deferred Charges and Other Noncurrent Assets   59    70 
 TOTAL OTHER NONCURRENT ASSETS   15,519    14,662 
        
 TOTAL ASSETS $ 16,659  $ 15,686 
        
 
See Condensed Notes to Condensed Financial Information beginning on page S-7.
      

 
S-4
 


SCHEDULE I 
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent) 
CONDENSED FINANCIAL INFORMATION 
CONDENSED BALANCE SHEETS 
LIABILITIES AND EQUITY 
December 31, 2010 and 2009 
(dollars in millions) 
  
  2010  2009 
CURRENT LIABILITIES   
Advances from Affiliates $295  $289 
Accounts Payable:        
General  5   - 
Affiliated Companies  544   460 
Long-term Debt Due Within One Year  -   490 
Short Term Debt  650   119 
Accrued Interest  2   11 
Other Current Liabilities  2   4 
TOTAL CURRENT LIABILITIES  1,498   1,373 
         
NONCURRENT LIABILITIES        
Long-term Debt  552   544 
Deferred Credits and Other Noncurrent Liabilities  14   17 
TOTAL NONCURRENT LIABILITIES  566   561 
         
TOTAL LIABILITIES  2,064   1,934 
         
         
COMMON SHAREHOLDERS' EQUITY        
Common Stock – Par Value – $6.50 Per Share:        
  2010  2009         
Shares Authorized  600,000,000   600,000,000         
Shares Issued  501,114,881   498,333,265         
(20,307,725 shares and 20,278,858 shares were held in treasury at December 31, 2010        
    and 2009, respectively)  3,257   3,239 
Paid-in Capital  5,904   5,824 
Retained Earnings  4,842   4,451 
Accumulated Other Comprehensive Income (Loss)  (381)  (374)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY  13,622   13,140 
         
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $15,686  $15,074 
         
See Condensed Notes to Condensed Financial Information.        
 SCHEDULE I
 AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
 CONDENSED FINANCIAL INFORMATION
 CONDENSED BALANCE SHEETS
 LIABILITIES AND EQUITY
 December 31, 2011 and 2010
 (dollars in millions)
  
   2011  2010 
 CURRENT LIABILITIES  
 Advances from Affiliates $ -  $ 295 
 Accounts Payable:      
  General   1    5 
  Affiliated Companies   445    544 
 Long-term Debt Due Within One Year   1    - 
 Short Term Debt   967    650 
 Accrued Interest   2    2 
 Other Current Liabilities   5    2 
 TOTAL CURRENT LIABILITIES   1,421    1,498 
        
 NONCURRENT LIABILITIES      
 Long-term Debt   554    552 
 Deferred Credits and Other Noncurrent Liabilities   20    14 
 TOTAL NONCURRENT LIABILITIES   574    566 
        
 TOTAL LIABILITIES   1,995    2,064 
        
        
 COMMON SHAREHOLDERS' EQUITY      
 Common Stock – Par Value – $6.50 Per Share:      
    2011  2010        
  Shares Authorized600,000,000  600,000,000        
  Shares Issued503,759,460  501,114,881        
 (20,336,592 shares and 20,307,725 shares were held in treasury at December 31, 2011      
  and 2010, respectively)  3,274    3,257 
 Paid-in Capital   5,970    5,904 
 Retained Earnings   5,890    4,842 
 Accumulated Other Comprehensive Income (Loss)   (470)   (381)
 TOTAL AEP COMMON SHAREHOLDERS’ EQUITY   14,664    13,622 
        
 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 16,659  $ 15,686 
        
 See Condensed Notes to Condensed Financial Information beginning on page S-7.      

 
S-5
 


SCHEDULE I 
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent) 
CONDENSED FINANCIAL INFORMATION 
CONDENSED STATEMENTS OF CASH FLOWS 
For the Years Ended December 31, 2010, 2009 and 2008 
(in millions) 
          
  2010  2009  2008 
OPERATING ACTIVITIES         
Net Income $1,211  $1,357  $1,380 
Adjustments to Reconcile Net Income to Net Cash Flows            
   from Operating Activities:            
   Equity Earnings of Unconsolidated Subsidiaries  (1,291)  (1,412)  (1,429)
   Cash Dividend Received from Unconsolidated Subsidiaries  854   530   383 
   Change in Other Noncurrent Assets  -   5   (3)
   Change in Other Noncurrent Liabilities  14   6   44 
   Changes in Certain Components of Working Capital:            
     Accounts Receivable, Net  (93)  14   (20)
     Accounts Payable  89   29   1 
     Other Current Assets  -   -   2 
     Other Current Liabilities  (12)  (3)  (4)
Net Cash Flows from Operating Activities  772   526   354 
             
INVESTING ACTIVITIES            
Purchases of Investment Securities  (333)  (66)  (869)
Sales of Investment Securities  267   36   935 
Change in Advances to Affiliates, Net  (299)  1,441   (1,110)
Capital Contributions to Unconsolidated Subsidiaries  (6)  (1,154)  (481)
Issuance of Notes Receivable to Affiliated Companies  (20)  (25)  - 
Repayments of Notes Receivable from Affiliated Companies  300   5   5 
Other Investing Activities  -   1   - 
Net Cash Flows from (Used for) Investing Activities  (91)  238   (1,520)
             
FINANCING ACTIVITIES            
Issuance of Common Stock, Net  93   1,728   159 
Issuance of Long-term Debt  -   -   305 
Commercial Paper and Credit Facility Borrowings  466   -   1,969 
Change in Short-term Debt, Net  80   119   (659)
Retirement of Long-term Debt  (490)  -   - 
Change in Advances from Affiliates, Net  6   (3)  288 
Commercial Paper and Credit Facility Repayments  (15)  (1,969)  - 
Dividends Paid on Common Stock  (820)  (753)  (660)
Other Financing Activities  (3)  (4)  (1)
Net Cash Flows from (Used for) Financing Activities  (683)  (882)  1,401 
             
Net Increase (Decrease) in Cash and Cash Equivalents  (2)  (118)  235 
Cash and Cash Equivalents at Beginning of Period  233   351   116 
Cash and Cash Equivalents at End of Period $231  $233  $351 
             
See Condensed Notes to Condensed Financial Information.            
 SCHEDULE I
 AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
 CONDENSED FINANCIAL INFORMATION
 CONDENSED STATEMENTS OF CASH FLOWS
 For the Years Ended December 31, 2011, 2010 and 2009
 (in millions)
              
   2011  2010  2009 
 OPERATING ACTIVITIES         
 Net Income $ 1,941  $ 1,211  $ 1,357 
 Adjustments to Reconcile Net Income to Net Cash Flows         
  from Operating Activities:         
   Equity Earnings of Unconsolidated Subsidiaries   (1,980)   (1,291)   (1,412)
   Cash Dividends Received from Unconsolidated Subsidiaries   1,113    854    530 
   Change in Other Noncurrent Assets   2    -    5 
   Change in Other Noncurrent Liabilities   20    14    6 
   Changes in Certain Components of Working Capital:         
    Accounts Receivable, Net   72    (93)   14 
    Accounts Payable   (103)   89    29 
    Other Current Liabilities   (3)   (12)   (3)
 Net Cash Flows from Operating Activities   1,062    772    526 
           
 INVESTING ACTIVITIES         
 Purchases of Investment Securities   (69)   (333)   (66)
 Sales of Investment Securities   166    267    36 
 Change in Advances to Affiliates, Net   (388)   (299)   1,441 
 Capital Contributions to Unconsolidated Subsidiaries   (99)   (6)   (1,154)
 Issuance of Notes Receivable to Affiliated Companies   -    (20)   (25)
 Repayments of Notes Receivable from Affiliated Companies   5    300    5 
 Other Investing Activities   -    -    1 
 Net Cash Flows from (Used for) Investing Activities   (385)   (91)   238 
           
 FINANCING ACTIVITIES         
 Issuance of Common Stock, Net   92    93    1,728 
 Commercial Paper and Credit Facility Borrowings   429    466    - 
 Change in Short-term Debt, Net   769    80    119 
 Retirement of Long-term Debt   -    (490)   - 
 Change in Advances from Affiliates, Net   (295)   6    (3)
 Commercial Paper and Credit Facility Repayments   (881)   (15)   (1,969)
 Dividends Paid on Common Stock   (892)   (820)   (753)
 Other Financing Activities   (3)   (3)   (4)
 Net Cash Flows Used for Financing Activities   (781)   (683)   (882)
           
 Net Decrease in Cash and Cash Equivalents   (104)   (2)   (118)
 Cash and Cash Equivalents at Beginning of Period   231    233    351 
 Cash and Cash Equivalents at End of Period $ 127  $ 231  $ 233 
           
 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) is required as a result of the restricted net assets of consolidated subsidiaries exceeding 25% of consolidated net assets as of December 31, 2010.2011.  Parent is a public utility holding company that owns all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries, including joint ventures and equity investments.  The primary source of income for Parent is equity in its subsidiaries’ earnings.  Its major source of cash is dividends from the subsidiaries.  Parent borrows the funds for the money pool that is used by the subsidiaries for their short-term cash needs.

Income Taxes

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

Parent and its subsidiaries are parties to environmental and other legal matters.  For further discussion of commitments, guarantees and contingencies, see Note 65 in the 20102011 Annual Reports.

3.  FINANCING ACTIVITIES

Long-term Debt
       
  Interest Rate at   Outstanding at
  December 31, Interest Rate Ranges at December 31, December 31,
Type of Debt and Maturity 2010  2010  2009  2010  2009 
        (in millions)
Senior Unsecured Notes            
 2010-2015 5.25% 5.25% 5.25%-5.375% $ 243  $ 733 
              
Junior Subordinated Debentures            
 2063  8.75% 8.75% 8.75%   315    315 
                
Unamortized Discount (net)         (6)   (14)
Total Long-term Debt Outstanding         552    1,034 
Less Portion Due Within One Year         -    490 
Long-term Portion       $ 552  $ 544 
Long-term Debt
     
    Outstanding at
  Interest Rates at December 31, December 31,
Type of Debt and Maturity 2011  2010  2011  2010 
      (in millions)
Senior Unsecured Notes          
 2015  5.25% 5.25% $ 243  $ 243 
            
Junior Subordinated Debentures          
 2063  8.75% 8.75%   315    315 
              
Fair Value of Interest Rate Hedges       7    6 
Unamortized Discount, Net       (10)   (12)
Total Long-term Debt Outstanding       555    552 
Long-term Debt Due Within One Year       1    - 
Long-term Debt     $ 554  $ 552 

Long-term debt outstanding at December 31, 20102011 is payable as follows:

          After             After  
2011  2012  2013  2014  2015  2015  Total 2012  2013  2014  2015  2016  2016  Total
(in millions) (in millions)
Principal AmountPrincipal Amount$ -  $ -  $ -  $ -  $ 243  $ 315  $ 558 Principal Amount$ 1  $ 4  $ -  $ 245  $ -  $ 315  $ 565 
Unamortized Discount                  (6)
Unamortized Discount, NetUnamortized Discount, Net                  (10)
Total Long-term Debt OutstandingTotal Long-term Debt Outstanding              Total Long-term Debt Outstanding                $ 555 
at December 31, 2010                $ 552 


 
S-8
 
Short-term Debt
               
Parent's outstanding short-term debt was as follows:
               
    December 31,
    2010  2009 
    Outstanding Weighted Average Outstanding Weighted Average
 Type of DebtAmountInterest Rate AmountInterest Rate
   (in millions)    (in millions)   
 Commercial Paper $ 650   0.52 % $ 119   0.26 %
 Total Short-term Debt $ 650     $ 119    

Short-term Debt
Parent's outstanding short-term debt was as follows:
   December 31,
   2011  2010 
   Outstanding Weighted Average Outstanding Weighted Average
Type of DebtAmountInterest Rate AmountInterest Rate
  (in millions)    (in millions)   
Commercial Paper $ 967   0.51 % $ 650   0.52 %
Total Short-term Debt $ 967     $ 650    

4.  RELATED PARTY TRANSACTIONS

Payments on behalfBehalf 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 the 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 $199 thousand, $1 million $3 million and $9$3 million for the years ended December 31, 2011, 2010 2009 and 2008,2009, 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 $3 million, $2 million $11 million and $37$11 million for the years ended December 31, 2011, 2010 2009 and 2008,2009, 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 Statementsstatements of Income.income.  Parent earned interest income on loans to subsidiaries of $15 million, $18 million $29 million and $28$29 million for the years ended December 31, 2011, 2010 and 2009, and 2008, respectively.

 
S-9
 

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
AEPAEP   Additions    AEP   Additions    
   Balance at Charged to Charged to   Balance at   Balance at Charged to Charged to   Balance at
   Beginning Costs and Other   End of   Beginning Costs and Other   End of
DescriptionDescription of Period Expenses Accounts (a) Deductions (b) PeriodDescription of Period Expenses Accounts (a) Deductions (b) Period
 (in thousands)  (in thousands)
Deducted from Assets:Deducted from Assets:              Deducted from Assets:              
Accumulated Provision for UncollectibleAccumulated Provision for Uncollectible             Accumulated Provision for Uncollectible             
 Accounts:           Accounts:          
 Year Ended December 31, 2010 $ 37,399  $ 36,699  $ (1,036) $ 31,507  $ 41,555  Year Ended December 31, 2011 $ 41,555  $ 36,457  $ 1,994  $ 47,455  $ 32,551 
 Year Ended December 31, 2009  42,388    31,867    (2,850)   34,006   37,399  Year Ended December 31, 2010  37,399    36,699    (1,036)   31,507   41,555 
 Year Ended December 31, 2008   52,046    27,598    365    37,621   42,388  Year Ended December 31, 2009   42,388    31,867    (2,850)   34,006   37,399 
                                
(a)(a)Recoveries offset by reclasses to other liabilities.(a)Recoveries offset by reclasses to other liabilities.
(b)(b)Uncollectible accounts written off.(b)Uncollectible accounts written off.

APCoAPCo   Additions    APCo   Additions    
   Balance at Charged to Charged to   Balance at   Balance at Charged to Charged to   Balance at
   Beginning Costs and Other   End of   Beginning Costs and Other   End of
DescriptionDescription of Period Expenses Accounts (a) Deductions (b) PeriodDescription of Period Expenses Accounts (a) Deductions (b) Period
 (in thousands)  (in thousands)
Deducted from Assets:Deducted from Assets:              Deducted from Assets:              
Accumulated Provision for UncollectibleAccumulated Provision for Uncollectible             Accumulated Provision for Uncollectible             
 Accounts:           Accounts:          
 Year Ended December 31, 2010 $ 5,408  $ 6,573  $ 292  $ 5,606  $ 6,667  Year Ended December 31, 2011 $ 6,667  $ 6,041  $ 1,535  $ 8,954  $ 5,289 
 Year Ended December 31, 2009  6,176    4,198    (137)   4,829   5,408  Year Ended December 31, 2010  5,408    6,573    292    5,606   6,667 
 Year Ended December 31, 2008   13,948    3,477    289    11,538   6,176  Year Ended December 31, 2009   6,176    4,198    (137)   4,829   5,408 
                                
(a)(a)
Recoveries offset by reclasses to other liabilities.
(a)Recoveries offset by reclasses to other liabilities.
(b)(b)Uncollectible accounts written off.(b)Uncollectible accounts written off.

CSPCo   Additions    
I&MI&M   Additions    
   Balance at Charged to Charged to   Balance at   Balance at Charged to Charged to   Balance at
   Beginning Costs and Other   End of   Beginning Costs and Other   End of
DescriptionDescription of Period Expenses Accounts (a) Deductions (b) PeriodDescription of Period Expenses Accounts (a) Deductions (b) Period
 (in thousands)  (in thousands)
Deducted from Assets:Deducted from Assets:              Deducted from Assets:              
Accumulated Provision for UncollectibleAccumulated Provision for Uncollectible             Accumulated Provision for Uncollectible             
 Accounts:           Accounts:           
 Year Ended December 31, 2010 $ 3,481  $ 16  $ (404) $ 1,509  $ 1,584  Year Ended December 31, 2011 $ 1,692  $ 151  $ -  $ 93  $ 1,750 
 Year Ended December 31, 2009  2,895    1,362    (775)   1   3,481  Year Ended December 31, 2010  2,265    (139)(c)  (424)   10   1,692 
 Year Ended December 31, 2008   2,563    332    -    -   2,895  Year Ended December 31, 2009   3,310    78    (783)   340   2,265 
                                
(a)(a)
Recoveries offset by reclasses to other liabilities.
(a)Recoveries offset by reclasses to other liabilities.
(b)(b)Uncollectible accounts written off.(b)Uncollectible accounts written off.
(c)(c)Recoveries on previous reserve balance.

 
S-10
 
I&M   Additions    
OPCoOPCo   Additions    
   Balance at Charged to Charged to   Balance at   Balance at Charged to Charged to   Balance at
   Beginning Costs and Other   End of   Beginning Costs and Other   End of
DescriptionDescription of Period Expenses Accounts (a) Deductions (b) PeriodDescription of Period Expenses Accounts (a) Deductions (b) Period
 (in thousands)  (in thousands)
Deducted from Assets:Deducted from Assets:              Deducted from Assets:              
Accumulated Provision for UncollectibleAccumulated Provision for Uncollectible             Accumulated Provision for Uncollectible             
 Accounts:            Accounts:          
 Year Ended December 31, 2010 $ 2,265  $ (139)(c)$ (424) $ 10  $ 1,692  Year Ended December 31, 2011 $ 3,768  $ 59  $ (10) $ 254  $ 3,563 
 Year Ended December 31, 2009  3,310    78    (783)   340   2,265  Year Ended December 31, 2010  6,146    59    (928)   1,509   3,768 
 Year Ended December 31, 2008   2,711    599    -    -   3,310  Year Ended December 31, 2009   6,481    1,378    (1,708)   5   6,146 
                                
(a)(a)
Recoveries offset by reclasses to other liabilities.
(a)Recoveries offset by reclasses to other liabilities.
(b)(b)Uncollectible accounts written off.(b)Uncollectible accounts written off.
(c)Recoveries on previous reserve balance.

OPCo   Additions    
PSOPSO   Additions    
   Balance at Charged to Charged to   Balance at   Balance at Charged to Charged to   Balance at
   Beginning Costs and Other   End of   Beginning Costs and Other   End of
DescriptionDescription of Period Expenses Accounts (a) Deductions (b) PeriodDescription of Period Expenses Accounts (a) Deductions (b) Period
 (in thousands)  (in thousands)
Deducted from Assets:Deducted from Assets:              Deducted from Assets:              
Accumulated Provision for UncollectibleAccumulated Provision for Uncollectible             Accumulated Provision for Uncollectible             
 Accounts:           Accounts:           
 Year Ended December 31, 2010 $ 2,665  $ 43  $ (524) $ -  $ 2,184  Year Ended December 31, 2011 $ 971  $ (194)(c)$ -  $ -  $ 777 
 Year Ended December 31, 2009  3,586    16    (933)   4   2,665  Year Ended December 31, 2010  304    709    -    42   971 
 Year Ended December 31, 2008   3,396    191    -    1   3,586  Year Ended December 31, 2009   20    284    -    -   304 
                                
(a)(a)
Recoveries offset by reclasses to other liabilities.
(a)Recoveries on accounts previously written off.
(b)(b)Uncollectible accounts written off.(b)Uncollectible accounts written off.
(c)(c)Recoveries on previous reserve balance.

PSO   Additions    
SWEPCoSWEPCo   Additions    
   Balance at Charged to Charged to   Balance at   Balance at Charged to Charged to   Balance at
   Beginning Costs and Other   End of   Beginning Costs and Other   End of
DescriptionDescription of Period Expenses Accounts (a) Deductions (b) PeriodDescription of Period Expenses Accounts (a) Deductions (b) Period
 (in thousands)  (in thousands)
Deducted from Assets:Deducted from Assets:              Deducted from Assets:              
Accumulated Provision for UncollectibleAccumulated Provision for Uncollectible             Accumulated Provision for Uncollectible             
 Accounts:           Accounts:          
 Year Ended December 31, 2010 $ 304  $ 709  $ -  $ 42  $ 971  Year Ended December 31, 2011 $ 588  $ 149  $ 376  $ 124  $ 989 
 Year Ended December 31, 2009  20    284    -    -   304  Year Ended December 31, 2010  64    400    166    42   588 
 Year Ended December 31, 2008   -    20    -    -   20  Year Ended December 31, 2009   135    -    -    71   64 
                                
(a)(a)Recoveries on accounts previously written off.(a)Recoveries on accounts previously written off.
(b)(b)Uncollectible accounts written off.(b)Uncollectible accounts written off.

S-11
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, 2010 $ 64  $ 400  $ 166  $ 42  $ 588 
  Year Ended December 31, 2009   135    -    -    71    64 
  Year Ended December 31, 2008   143    -    -    8    135 
                  
(a)Recoveries on accounts previously written off.
(b)Uncollectible accounts written off.

 
S-12S-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:
REGISTRANT:
AEP‡File No. 1-3525
  
3(a) Composite of the Restated Certificate of Incorporation of AEP, dated April 28, 2009. 2009 Form 10-K, Ex 3(a)
*3(b) Composite By-Laws of AEP, as amended as of April 28, 2009.May 24, 2011. 2009 Form 10-K, Ex 3(b)
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)
4(b) Purchase Agreement dated as of March 8, 2005, between AEP and Merrill Lynch International. Form 10-Q, Ex 4(a), March 31, 2005
4(c)4(b) Junior Subordinated Indenture dated as of March 1, 2008 between AEP and The Bank of New York as Trustee. Registration Statement 333-156387, Ex 4(c)(d)
4(d) Second
4(c)Amended and Restated $1.5 Billion Credit Agreement, dated as of March 31, 2008,July 26, 2011, 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. Form 10-Q, Ex 10(a) September 30, 20084(d) July 29, 2011
4(e) Second Amended and Restated $1.5
4(d)$1.75 Billion Credit Agreement, dated as of March 31, 2008,July 26, 2011, among AEP, the banks, financial institutions and other institutional lenders listed on the signature pages thereof, and Barclays Bank plcPLC as Administrative Agent. Form 10-Q, Ex 10(b) September 30, 20084(e) July 29, 2011
4(f) $650 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent. Form 10-Q, Ex 10(c) September 30, 2008
4(g)Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex 10(d) September 30, 2008
4(h)$350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex 10 (e) September 30, 2008
4(i)Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex 10(f) September 30, 2008
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)
1990 Form 10-K, Ex 10(a)(3)
 
10(b) Restated and Amended Operating Agreement, amongForm 10-Q, Ex 10(b), March 31, 2006 

E-1


Exhibit Designation
Nature of Exhibit
Previously Filed as Exhibit to:
PSO, SWEPCo and AEPSC, Issued on February 10, 2006, Effective May 1, 2006.Form 10-Q, Ex 10(b), March 31, 2006
  
10(c) Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended. 
1985 Form 10-K, Ex 10(b)
1988 Form 10-K, Ex 10(b)(2)
��
10(d) Restated and Amended Transmission Coordination Agreement dated April 15, 2002,January 1, 1997, restated and amended, and as amended and approved by FERC in 2011 by and among, PSO, SWEPCo  TNC and AEPSC. 2009 Form 10-K, Ex 10(d)
10(e)(1) Amended and Restated Operating Agreement dated as of June 2, 1997, of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power CompanyKGPCo and Wheeling Power Company.WPCo. 2004 Form 10-K, Ex 10(e)(1)
E-1
Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
10(e)(2)(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)(3)(2) Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power CompanyKGPCo and Wheeling Power Company.WPCo. 2004 Form 10-K, Ex 10(e)(3)
10(f) 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) Consent Decree with U.S. District Court dated October 9, 2007. Form 8-K, Ex 10.1 dated October 9, 2007
†10(i) AEP Accident Coverage Insurance Plan for Directors. 1985 Form 10-K, Ex 10(g)
†10(j) 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) AEP Stock Unit Accumulation Plan for Non-Employee Directors, as amended. 2003 Form 10-K, Ex 10(k)(2)
†10(k)(1)(A) First Amendment to AEP Stock Unit Accumulation Plan for Non-Employee Directors dated as of February 9, 2007. 2006 Form 10-K, Ex 10(j)(2)(A)
†10(l) AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2008. 2008 Form 10-K, Ex 10(l)(1)(A)
†10(l)(1) Guaranty by AEP of AEPSC Excess Benefits Plan. 1990 Form 10-K, Ex 10(h)(1)(B)
     
*†10(l)(2) 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) AEPSC Umbrella Trust for Executives. 1993 Form 10-K, Ex 10(g)(3)
†10(l)(3)(A) First Amendment to AEPSC Umbrella Trust for Executives. 
2008 Form 10-K, Ex 10(l)(3)(A)
†10(m)(1) Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 15, 2003. 2003 Form 10-K, Ex 10(m)(1)
†10(m)(1)(A)Amendment to Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 9, 2008.2008 Form 10-K, Ex 10(m)(1)(A)
†10(m)(2)Memorandum of agreement between Susan Tomasky and AEPSC dated January 3, 2001.2000 Form 10-K, Ex 10(s)
†10(m)(3) Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers. 2002 Form 10-K, Ex 10(m)(4)
†10(m)(3)(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)
E-2
†10(m)(4)
Exhibit
Designation
 Letter Agreement dated June 9, 2004 between AEPSC and Carl English.Nature of Exhibit Form 10-Q, Ex 10(b), September 30, 2004Previously Filed as Exhibit to:
†10(n) 
AEP System Senior Officer Annual Incentive Compensation Plan, amended and restated effective December 13, 2006.
 Form 8-K, Ex 10.1 dated April 25, 2007
†10(o)(1) AEP System Survivor Benefit Plan, effective January 27, 1998. Form 10-Q, Ex 10, September 30, 1998

E-2

 Exhibit Designation 
Nature of Exhibit
 
Previously Filed as Exhibit to:
†10(o)(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)(1)(B)(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) AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008. 2008 Form 10-K, Ex 10(p)
*†10(p)(1)(A)First Amendment to AEP Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008.
†10(q) AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998. 2002 Form 10-K, Ex 10(r)
†10(r) Nuclear Key Contributor Retention Plan Amended and Restated as of January 1, 2008. 2008 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.
†10(s) AEP Change In Control Agreement, effective November 1, 2009. 2009 Form 10-K, Ex 10(s)
*
†10(t)(1) Amended and Restated AEP System Long-Term Incentive Plan. Form 10-Q, Ex 10, March 31,June 30, 2010
†10(t)(2) Form of
*†10(t)(1)(A)Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended. Form 10-Q, Ex 10(c), September 30, 2004
†10(t)(3) Form of
*†10(t)(2)(A)Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended. Form 10-Q, Ex 10(a), March 31, 2005
†10(t)(3)(A) Amendment to Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended. 2008 Form 10-K, Ex 10(t)(3)(A)
†10(u) AEP System Stock Ownership Requirement Plan Amended and Restated Effectiveeffective January 1, 2010. 2010 Form 10-K, Ex 10(u)
*†10(u)(1)(A)First Amendment to AEP System Stock Ownership Requirement Plan as Amended and Restated effective January 1, 2010.
†10(v) Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2009. 2008 Form 10-K, Ex 10(v)
E-3
Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
*12 Statement re: Computation of Ratios.
  
*13 Copy of those portions of the AEP 20102011 Annual Report (for the fiscal year ended December 31, 2010)2011) 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.  
*95Mine Safety Disclosure.
101.INS XBRL Instance Document.
  
101.SCH XBRL Taxonomy Extension SchemaSchema.
  
101.CAL XBRL Taxonomy Extension Calculation Linkbase.
  
101.DEF XBRL Taxonomy Extension Definition Linkbase.
  
101.LAB XBRL Taxonomy Extension LabelsLabel Linkbase.
  
101.PRE XBRL Taxonomy Extension Presentation Linkbase.  
REGISTRANT:
APCo‡File No. 1-3457
  
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)
E-4
4(a) 
Exhibit
Designation
 
Nature of Exhibit
Previously Filed as Exhibit to:
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)

E-3

Exhibit Designation
Nature of Exhibit
Previously Filed as Exhibit to:
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)
4(b) Company Order and Officer’s Certificate to The Bank of New York Mellon Trust Company, dated May 24, 2010 establishing terms of 3.40% Senior Notes due 2015. Form 8-K, Ex 4(a) dated May 24, 2010
4(c) $650 Million Credit Agreement,Company Order and Officer’s Certificate to The Bank of New York Mellon Trust Company, N.A., dated asMarch 25, 2011 establishing terms of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.4.60% Senior Notes due 2021. Form 10-Q, Ex10(c) September 30, 20088-K, Ex 4(a) dated March 25, 2011
4(d) Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent. Form 10-Q, Ex 10(d) September 30, 2008
4(e)$350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex 10(e) September 30, 2008
4(f)Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex 10(f) September 30, 2008
10(a)(1) Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended. 
Registration Statement No. 2-60015, Ex 5(a)
Registration Statement No. 2-63234, Ex 5(a)(1)(B) Registration Statement No 2-66301, Ex 5(a)(1)(C) Registration Statement No. 2-67728, Ex 5(a)(1)(D)
1989 Form 10-K, Ex 10(a)(1)(F)
1992 Form 10-K, Ex 10(a)(1)(B)
10(a)(2)(1) Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended March 13, 2006. 2005 Form 10-K, Ex 10(a)(2)
10(a)(3)(2) Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended. Registration Statement No. 2-60015, Ex 5(e)
10(b) 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, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended. 
1985 Form 10-K, Ex 10(b)
1988 Form 10-K, Ex 10(b)(2)
10(d)(1) Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power CompanyKGPCo and Wheeling Power Company.WPCo. 2004 Form 10-K, Ex 10(d)(1)
10(d)(2)(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)(3)(2) Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power CompanyKGPCo and Wheeling Power Company.WPCo. 2004 Form 10-K, Ex 10(d)(3)

 
E-4E-5
 

Exhibit
Designation
Nature of ExhibitPreviously Filed as Exhibit to:
10(e)Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
1996 Form 10-K, Ex 10(l), File No. 1-3525
10(f)Consent Decree with U.S. District Court. Form 8-K, Ex 10.1 dated October 9, 2007
*12Statement re: Computation of Ratios.
*13Copy of those portions of the APCo 2011 Annual Report (for the fiscal year ended December 31, 2011) which are incorporated by reference in this filing.
*23Consent of Deloitte & Touche LLP.
*24Power of Attorney.
*31(a)Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31(b)Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32(a)Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
*32(b)Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
101.INSXBRL Instance Document.
101.SCHXBRL Taxonomy Extension Schema.
101.CALXBRL Taxonomy Extension Calculation Linkbase.
101.DEFXBRL Taxonomy Extension Definition Linkbase.
101.LABXBRL Taxonomy Extension Label Linkbase.
101.PREXBRL Taxonomy Extension Presentation Linkbase.
I&M‡   File No. 1-3570
3(a)Composite of the Amended Articles of Acceptance of I&M, dated of March 7, 1997.1996 Form 10-K, Ex 3(c)
3(b)Composite By-Laws of I&M, amended as of February 26, 2008.2007 Form 10-K, Ex 3(b)
E-6
Exhibit
Designation
 
 
Nature of Exhibit
 
 
Previously Filed as Exhibit to:
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)
4(b)Company Order and Officer’s Certificate to The Bank of New York, dated January 15, 2009 establishing terms of 7.00% Senior Notes,  Series I due 2019.Form 8-K, Ex 4(a) dated January 15, 2009
10(a)Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended.
Registration Statement No. 2-60015, Ex 5(a)
Registration Statement No. 2-63234, Ex 5(a)(1)(B)
Registration Statement No. 2-66301, Ex 5(a)(1)(C)
Registration Statement No. 2-67728, Ex 5(a)(1)(D)
APCo 1989 Form 10-K, Ex 10(a)(1)(F), File No. 1-3457
APCo 1992 Form 10-K, Ex 10(a)(1)(B), File No. 1-3457
10(a)(1)Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended, March 13, 2006.2005 Form 10-K, Ex 10(a)(2)
10(a)(2)Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended.Registration Statement No. 2-60015, Ex 5(e)
10(a)(3)Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended.
Registration Statement No. 2-60015, Ex 5(c)
Registration Statement No. 2-67728, Ex 5(a)(3)(B)
APCo 1992 Form 10-K, Ex 10(a)(2)(B), File No. 1-3457
10(b)Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, I&M, and OPCo and with AEPSC, as amended.
Registration Statement No. 2-52910, Ex 5(a)
Registration Statement No. 2-61009, Ex 5(b)
1990 Form 10-K, Ex 10(a)(3), File No. 1-3525
10(b)(1)Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended.Registration Statement No. 33-32752, Ex 28(b)(1)(A)(B)
10(c)Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended.
1985 Form 10-K, Ex 10(b), File No. 1-3525
1988 Form 10-K, File No. 1-3525, Ex 10(b)(2)
10(d)Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo.2004 Form 10-K, Ex 10(d)(1)
10(d)(1)PJM West Reliability Assurance Agreement among Load Serving Entities in the PJM West service area.2004 Form 10-K, Ex 10(d)(2)
10(d)(2)Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo.2004 Form 10-K, Ex 10(d)(3)
E-7
Exhibit Designation
Nature of Exhibit
Previously Filed as Exhibit to:
10(e) Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC. 1996 Form 10-K, Ex 10(l), File No. 1-3525
10(f) Consent Decree with U.S. District Court. Form 8-K, Ex 10.1 dated October 9, 2007
†10(g) 
AEP System Senior Officer Annual Incentive Compensation Plan amended and restated effective December 13, 2006.
Form 8-K, Ex 10.1 dated  April 25, 2007
†10(h)(1)AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2008.2008 Form 10-K, Ex 10(h)(1)
*†10(h)(2)AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2011 (Non-Qualified).  
†10(h)(3)10(g) AEPSC UmbrellaLease Agreements, dated as of December 1, 1989, between I&M and Wilmington Trust for Executives.Company, as amended. 
Registration Statement No. 33-32753, Ex 28(a)(1-6)(C)
1993 Form 10-K, Ex 10(g)(3), File No. 1-352510(e)(1-6)(B)
†10(h)(3)(A)First Amendment to AEPSC Umbrella Trust for Executives.2008 Form 10-K, Ex 10(h)(3)(A)
†10(i)Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 15, 2003.2003 Form 10-K, Ex 10(m)(1)
†10(i)(A)Amendment to Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 9, 2008.2008 Form 10-K, Ex 10(i)(A)
†10(i)(2)Memorandum of Agreement between Susan Tomasky and AEPSC dated January 3, 2001.2000 Form 10-K, Ex 10(s), File No. 1-3525
†10(i)(3)Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers.2002 Form 10-K, Ex 10(m)(4)
†10(i)(3)(A)Amendment to Employment Agreement dated December 9, 2008 between AEPSC and Robert P. Powers.2008 Form 10-K, Ex 10(i)(4)(A)
†10(i)(4)Letter Agreement dated June 9, 2004 between AEPSC and Carl English.Form 10-Q, Ex 10(b), September 30, 2004
†10(j)AEP System Senior Officer Annual Incentive Compensation Plan, amended and restated effective December 13, 2006.Form 8-K, Ex 10.1 dated April 25, 2007
†10(k)(1)AEP System Survivor Benefit Plan, effective January 27, 1998.Form 10-Q, Ex 10, September 30, 1998
†10(k)(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(k)(1)(B)Second Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 1, 2008.2008 Form 10-K, Ex 10(k)(1)(B)
†10(l)AEP Change In Control Agreement, effective November 1, 2009.2009 10-K, Ex 10(l)
*†10(m)(1)Amended and Restated AEP System Long-Term Incentive Plan.Form 10-Q, Ex 10, March 31, 2010
†10(m)(2)Form of Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.Form 10-Q, Ex 10(c), November 5, 2004
†10(m)(3)Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.Form 10-Q, Ex 10(a), March 31, 2005
†10(m)(3)(A)Amendment to Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.2008 Form 10-K, Ex10(m)(3)(A)
†10(n)  AEP System Stock Ownership Requirement Plan Amended and Restated Effective January 1, 2010. 2009 Form 10-K, Ex 10(n)
†10(o)Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2009.2008 Form 10-K, Ex 10(n)
†10(p)AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008.2008 Form 10-K, Ex 10(o)
†10(q)AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998.2002 Form 10-K, Ex 10(r)
†10(r)Nuclear Key Contributor Retention Plan Amended and Restated as of January 1, 2008.2008 Form 10-K, Ex 10(q)
 *12*12 Statement re: Computation of Ratios.  

E-5
Exhibit Designation 
Nature of Exhibit
 
Previously Filed as Exhibit to:
*13 Copy of those portions of the APCo 2010I&M 2011 Annual Report (for the fiscal year ended December 31, 2010)2011) which are incorporated by reference in this filing.  
21 List of subsidiaries of APCo. 2006 Form 10-K, Ex 21, File No. 1-3525
*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.  
REGISTRANT:CSPCo‡
101.INSXBRL Instance Document.
101.SCHXBRL Taxonomy Extension Schema.
101.CALXBRL Taxonomy Extension Calculation Linkbase.
101.DEFXBRL Taxonomy Extension Definition Linkbase.
101.LABXBRL Taxonomy Extension Label Linkbase.
101.PREXBRL Taxonomy Extension Presentation Linkbase.
OPCo‡   File No. 1-2680No.1-6543
  
3(a) Composite of the Amended Articles of Incorporation of CSPCo,OPCo, dated May 19, 1994.June 3, 2002. 1994 Form 10-K,10-Q, Ex 3(c)3(e), June 30, 2002
3(b) Amended Code of Regulations of CSPCo.OPCo. Form 10-Q, Ex 3(b), June 30, 2008
E-8
Exhibit
Designation
Nature of Exhibit
Previously Filed as Exhibit to:
3(c)Agreement and Plan of Merger of Ohio Power Company and Columbus Southern Power Company entered into as of December 31, 2011.Form 8-K, Ex 2.1 dated January 6, 2012
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)
4(b)Company Order and Officer’s Certificate to Deutsche Bank Trust Company Americas, dated April 5, 2007, establishing terms of Floating Rate Notes, Series B.Form 8-K, Ex 4(a) dated April 5, 2007
4(c)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(d)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)
4(e)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(b)
4(f) 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(c) 
4(g)First Supplemental Indenture, dated as of December 31, 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(h)Third Supplemental Indenture, dated as of December 31, 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(i)CSPCo (predecessor in interest to OPCo) Company Order and Officer’s Certificate to Deutsche Bank Trust Company Americas, dated May 16, 2008, establishing terms of 6.05% Senior Notes, Series G, due 2018. Form 8-K, Ex 4(a), dated May 16, 2008
E-9
*4(d)
Exhibit
Designation
 
Nature of Exhibit
Previously Filed as Exhibit to:
4(j)CSPCo (predecessor in interest to OPCo) Company Order and Officer’s Certificate to Deutsche Bank Trust Company Americas, dated March 16, 2010 establishing terms of floating rate notes Series A due 2012. Form 8-K, Ex 4(a) dated March 16, 2010
4(e) $650 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex 10(c) September 30, 2008
4(f)Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex 10(d) September 30, 2008
4(g)
$350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
Form 10-Q, Ex 10(e) September 30, 2008
4(h)Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., asForm 10-Q, Ex 10(f) September 30, 2008

E-6

Exhibit Designation
Nature of Exhibit
Previously Filed as Exhibit to:
Administrative Agent.   
10(a)(1) Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended. 
Registration Statement No. 2-60015, Ex 5(a)
Registration Statement No. 2-63234, Ex 5(a)(1)(B)
Registration Statement No. 2-66301, Ex 5(a)(1)(C)
Registration Statement No. 2-67728, Ex 5(a)(1)(B)
APCo 1989 Form 10-K, Ex 10(a)(1)(F), File No. 1-3457
APCo 1992 Form 10-K, Ex 10(a)(1)(B), File No.1-3457
10(a)(2)(1)
 Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended March 13, 2006. 2005 Form 10-K, Ex 10(a)(2)
10(a)(3)(2) Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended. Registration Statement No. 2-60015, Ex 5(e)
10(b)(1)Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, OPCo and I&M and 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)(2)Unit Power Agreement, dated March 15, 2007 between AEGCo and CSPCo.2007 Form 10-K, Ex 10(b)(2)
10(c)Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo, and with AEPSC as agent, as amended.
1985 Form 10-K, Ex 10(b), File No. 1-3525
1988 Form 10-K, Ex 10(b)(2) File No. 1-3525
10(d)(1)Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.2004 Form 10-K, Ex 10(d)(1)
10(d)(2)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)(3)Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.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.Form 8-K, Ex 10.1 dated October 9, 2007
*12Statement re: Computation of Ratios.
*13Copy of those portions of the CSPCo 2010 Annual Report (for the fiscal year ended December 31, 2010) which are incorporated by reference in this filing.
21List of subsidiaries of CSPCo.2006 Form 10-K, Ex 21, File No. 1-3525
*23Consent of Deloitte & Touche LLP.
*24Power of Attorney.
*31(a)Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31(b)Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*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.
REGISTRANT:                                I&M‡           File No. 1-3570
3(a)Composite of the Amended Articles of Acceptance of I&M, dated of March 7, 1997.1996 Form 10-K, Ex 3(c)
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)

E-7

Nature of Exhibit
Previously Filed as Exhibit to:
4(b)Company Order and Officer’s Certificate to The Bank of New York, dated January 15, 2009 establishing terms of 7.00% Senior Notes,  Series I due 2019.Form 8-K, Ex 4(a) dated January 15, 2009
4(c)$650 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex.10(c) September 30, 2008
4(d)Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex.10(d) September 30, 2008
4(e)$350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex.10(e) September 30, 2008
4(f)Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex.10(f) September 30, 2008
10(a)(1)Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended.
Registration Statement No. 2-60015, Ex 5(a)
Registration Statement No. 2-63234, Ex 5(a)(1)(B)
Registration Statement No. 2-66301, Ex 5(a)(1)(C)
Registration Statement No. 2-67728, Ex 5(a)(1)(D)
APCo 1989 Form 10-K, Ex 10(a)(1)(F), File No. 1-3457
APCo 1992 Form 10-K, Ex 10(a)(1)(B), File No. 1-3457
10(a)(2)Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended, March 13, 2006.2005 Form 10-K, Ex 10(a)(2)
10(a)(3)Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended.Registration Statement No. 2-60015, Ex 5(e)
10(a)(4)Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended.
Registration Statement No. 2-60015, Ex 5(c)
Registration Statement No. 2-67728, Ex 5(a)(3)(B)
APCo 1992 Form 10-K, Ex 10(a)(2)(B), File No. 1-3457
10(b)(1)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)(2)Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended.Registration Statement No. 33-32752, Ex 28(b)(1)(A)(B)
10(c)
Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended.
1985 Form 10-K, Ex 10(b), File No. 1-3525
1988 Form 10-K, File No. 1-3525, Ex 10(b)(2)
10(d)(1)Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.2004 Form 10-K, Ex 10(d)(1)
10(d)(2)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)(3)Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo,2004 Form 10-K, Ex 10(d)(3)

E-8

Exhibit Designation
Nature of Exhibit
Previously Filed as Exhibit to:
   Kingsport Power Company and Wheeling Power Company. 
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.Form 8-K, Ex 10.1 dated October 9, 2007
10(g)Lease Agreements, dated as of December 1, 1989, between I&M and Wilmington Trust Company, as amended.
Registration Statement No. 33-32753, Ex 28(a)(1-6)(C)
1993 Form 10-K, Ex 10(e)(1-6)(B)
*12Statement re: Computation of Ratios.
*13Copy of those portions of the I&M 2010 Annual Report (for the fiscal year ended December 31, 2010) which are incorporated by reference in this filing.
21List of subsidiaries of I&M.2006 Form 10-K, Ex 21, File No. 1-3525
*23Consent of Deloitte & Touche LLP.
*24Power of Attorney.
*31(a)Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31(b)Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*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.
REGISTRANT:OPCo‡File No.1-6543
3(a)Composite of the Amended Articles of Incorporation of OPCo, dated June 3, 2002.Form 10-Q, Ex 3(e), June 30, 2002
3(b)Amended Code of Regulations of OPCo.Form 10-Q, Ex 3(b), June 30, 2008
4(a)
Indenture (for unsecured debt securities), dated as of September 1, 1997, between OPCo and Bankers Trust Company (now Deutsche Bank Trust Company Americas), as Trustee.
Registration Statement No. 333-49595, Ex 4(a)(b)(c)
Registration Statement No. 333-106242, Ex 4(b)(c)(d)
Registration Statement No. 333-75783, Ex 4(b)(c)
Registration Statement No. 333-127913, Ex 4(b)(c)
Registration Statement No. 333-139802, Ex 4(a)(b)(c)
Registration Statement No. 333-139802, Ex 4(b)(c)(d)
4(b)Company Order and Officer’s Certificate to Deutsche Bank Trust Company Americas, dated April 5, 2007, establishing terms of Floating Rate Notes, Series B.Form 8-K, Ex 4(a) dated April 5, 2007
4(c)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(d)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)
4(e)$650 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex 10(c) September 30, 2008
4(f)Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex 10(d) September 30, 2008
4(g)$350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M,Form 10-Q, Ex 10(e) September 30, 2008

E-9
Exhibit Designation
 Nature of Exhibit
Previously Filed as Exhibit to:
KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
4(h)Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex 10(f) September 30, 2008
10(a)(1)Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended.
Registration Statement No. 2-60015, Ex 5(a)
Registration Statement No. 2-63234, Ex 5(a)(1)(B)
Registration Statement No. 2-66301, Ex 5(a)(1)(C)
Registration Statement No. 2-67728, Ex 5(a)(1)(D)
APCo 1989 Form 10-K, Ex 10(a)(1)(F), File No. 1-3457
APCo 1992 Form 10-K, Ex 10(a)(1)(B), File No. 1-3457
10(a)(2)Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended, March 13, 2006.2005 Form 10-K, Ex 10(a)(2)
10(a)(3)Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended.Registration Statement No. 2-60015, Ex 5(e)
10(b) 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, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent. 
1985 Form 10-K, Ex 10(b), File No. 1-3525
1988 Form 10-K, Ex 10(b)(2), File No. 1-3525
10(d)(1)Unit Power Agreement, dated March 15, 2007 between AEGCo and CSPCo (predecessor in interest to OPCo).2007 Form 10-K, Ex 10(b)(2)
10(e) Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power CompanyKGPCo and Wheeling Power Company.WPCo. 2004 Form 10-K, Ex 10(d)(1)
10(d)(2)
10(f) 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)(3)
10(g) Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power CompanyKGPCo and Wheeling Power Company.WPCo. 2004 Form 10-K, Ex 10(d)(3)
10(e)
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(f)
10(i) Consent Decree with U.S. District Court. Form 8-K, Item Ex 10.1 dated October 9, 2007
E-10
10(g)Exhibit Designation
Nature of Exhibit
Previously Filed as Exhibit to:
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)
10(g)(2)
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(h)AEP System Senior Officer Annual Incentive Compensation Plan amended and restated effective December 13, 2006.Form 8-K, Ex 10.1 dated  April 25, 2007
†10(i)(1)AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2008.2008 Form 10-K, Ex 10(j)(1)
*†10(i)(2)AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2011. (Non-Qualified).  
†10(i)(3) AEPSC Umbrella Trust for Executives.1993 Form 10-K, Ex 10(g)(3), File No. 1-3525
†10(i)(3)(A)
First Amendment to AEPSC Umbrella Trust for
Executives.
2008 Form 10-K, Ex 10(j)(3)(A)

E-10

Exhibit Designation
Nature of Exhibit
Previously Filed as Exhibit to:
†10(j)(1)Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 15, 2003.2003 Form 10-K, Ex 10(m)(1)
†10(j)(1)(A)Amendment to Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 9, 2008.2008 Form 10-K, Ex 10(k)(1)(A )
†10(j)(2)Memorandum of agreement between Susan Tomasky and AEPSC dated January 3, 2001.2000 Form 10-K, Ex 10(s), File No. 1-3525
†10(j)(3)Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers.2002 Form 10-K, Ex 10(m)(4)
†10(j)(3)(A)Amendment to Employment Agreement dated December 9, 2008 between AEPSC and Robert P. Powers.2008 Form 10-K, Ex 10(k)(4)(A)
†10(j)(4)Letter Agreement dated June 9, 2004 between AEPSC and Carl English.Form 10-Q, Ex 10(b), September 30, 2004, File No. 1-3525
†10(k)AEP System Senior Officer Annual Incentive Compensation Plan, amended and restated effective December 13, 2006.Form 8-K, Ex 10.1 dated April 25, 2007
†10(l)(1)AEP System Survivor Benefit Plan, effective January 27, 1998.Form 10-Q, Ex 10, September 30, 1998
†10(l)(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(l)(1)(B)Second Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 1, 2008.2008 Form 10-K, Ex 10(m)(1)(B)
†10(m)AEP Change In Control Agreement, effective November 1, 2009.2009 Form 10-K, Ex 10(m)
*†10(n)(1)Amended and Restated AEP System Long-Term Incentive Plan.Form 10-Q, Ex 10, March 31, 2010
†10(o)Form of Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
Form 10-Q, Ex 10(c), November 5, 2004,
File No. 1-3525
†10(p)(1)Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.Form 10-Q, Ex 10(a), March 31, 2005
†10(p)(1)(A)Amendment to Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.2008 Form 10-K, Ex 10(q)(1)(A)
†10(q)
 AEP System Stock Ownership Requirement Plan Amended and Restated Effective January 1, 2010.
2009 Form 10-K, Ex 10(q)
†10(r)Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2009.2008 Form 10, Ex 10(s)
†10(s)AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008.2008 Form 10, Ex 10(t)
†10(t)AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998.2002 Form 10-K, Ex 10(r)
†10(u)Nuclear Key Contributor Retention Plan Amended and Restated as of January 1, 2008.2008 Form 10, Ex 10(v)
*12 Statement re: Computation of Ratios.
  
*13 Copy of those portions of the OPCo 20102011 Annual Report (for the fiscal year ended December 31, 2010)2011) which are incorporated by reference in this filing.  
21 List of subsidiaries of OPCo. 2006 Form 10-K, Ex 21, File No. 1-3525
*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.
*95Mine Safety Disclosure.
101.INSXBRL Instance Document.
101.SCHXBRL Taxonomy Extension Schema.
101.CALXBRL Taxonomy Extension Calculation Linkbase.
101.DEFXBRL Taxonomy Extension Definition Linkbase.
101.LABXBRL Taxonomy Extension Label Linkbase.
101.PREXBRL Taxonomy Extension Presentation Linkbase.  

 
E-11
 

Exhibit Designation
Nature of ExhibitDesignation
 
Nature of Exhibit
Previously Filed as Exhibit to:
REGISTRANT:                                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) $650 Million Credit Agreement,Ninth Supplemental Indenture, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo,January 19, 2011 between PSO and SWEPCo, the Initial Lenders named therein, the SwinglineThe Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank,of New York Mellon Trust Company, N.A., as Administrative Agent.Trustee, establishing terms of 4.40% Senior Notes, Series I, due 2021. Form 10-Q,8-K, Ex 10(c) September 30, 20084(a) dated January 20, 2011
4(d) Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent. Form 10-Q, Ex 10(d) September 30, 2008
4(e)$350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex 10(e) September 30, 2008
4(f)Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex 10(f) September 30, 2008
10(a) Restated and Amended Operating Agreement, among PSO, SWEPCo and AEPSC, Issued on February 10, 2006, Effective May 1, 2006. Form 10-Q, Ex 10(a), March 31, 2006
10(b) 
Restated and Amended Transmission Coordination Agreement dated April 15, 2002,January 1, 1997, restated and amended, and as amended and approved by FERC in 2011 by and among, PSO, SWEPCo TNC and AEPSC.
AEPSC, in connection with the operation of the transmission assets of the two public utility subsidiaries.		 2009 Form 10-K Ex 10(b)
†10(c)AEP System Senior Officer Annual Incentive Compensation Plan amended and restated effective December 13, 2006.Form 8-K, Ex 10.1 dated  April 25, 2007
†10(d)(1)AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2008.2008 Form 10-K, Ex 10(d)(1)
*†10(d)(2)AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2011 (Non-Qualified).  
†10(d)(3)AEPSC Umbrella Trust for Executives.1993 Form 10-K, Ex 10(g)(3), File No. 1-3525
†10(d)(3)(A)First Amendment to AEPSC Umbrella Trust for Executives.2008 Form 10-K, Ex 10(d)(3)(A)
 †10(e)(1)Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 15, 2003.2003 Form 10-K, Ex 10(m)(1)

E-12

Exhibit Designation
Nature of Exhibit
Previously Filed as Exhibit to:
†10(e)(1)(A)Amendment to Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 9, 2008.2008 Form 10-K, Ex 10(e)(A)
†10(e)(2)Memorandum of Agreement between Susan Tomasky and AEPSC dated January 3, 2001.2000 Form 10-K, Ex 10(s), File No. 1-3525
†10(e)(3)Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers.2002 Form 10-K, Ex 10(m)(4)
†10(e)(3)(A)Amendment to Employment Agreement dated December 9, 2008 between AEPSC and Robert P. Powers.2008 Form 10-K, Ex 10(e)(4)(A)
†10(e)(4)Letter Agreement dated June 9, 2004 between AEPSC and Carl English.Form 10-Q, Ex 10(b), September 30, 2004
†10(f)AEP System Senior Officer Annual Incentive Compensation Plan, amended and restated effective December 13, 2006.Form 8-K, Ex 10.1 dated April 25, 2007
†10(g)(1)AEP System Survivor Benefit Plan, effective January 27, 1998.Form 10-Q, Ex 10, September 30, 1998
†10(g)(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(g)(1)(B)  Second Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 1, 2008.2008 Form 10-K, Ex 10(g)(1)(B)
†10(h)AEP Change In Control Agreement, effective November 1, 2009.2009 Form 10-K, Ex 10(h)
*†10(i)(1)Amended and Restated AEP System Long-Term Incentive Plan.Form 10-Q, Ex 10, March 31, 2010
†10(i)(2)Form of Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.Form 10-Q, Ex 10(c), November 5, 2004
†10(i)(3)Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.Form 10-Q, Ex 10(a), March 31, 2005
†10(i)(3)(A)Amendment to Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.2008 Form 10-K, Ex 10(i)(3)(A)
†10(j)AEP System Stock Ownership Requirement Plan Amended and Restated Effective January 1, 2010.2009 Form 10-K, Ex 10(j)
†10(k)Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2009.2008 Form 10-K, Ex 10(j)
†10(l)AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008.2008 Form 10-K, Ex 10(k)
†10(m)AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998.2002 Form 10-K, Ex 10(p)
†10(n)Nuclear Key Contributor Retention Plan Amended and Restated as of January 1, 2008.2008 Form 10-K, Ex 10(m)
*12 Statement re: Computation of Ratios.
  
*13 Copy of those portions of the PSO 20102011 Annual Report (for the fiscal year ended December 31, 2010)2011) which are incorporated by reference in this filing.  
21List of subsidiaries of PSO.2006 Form 10-K, Ex 21, File No. 1-3525
*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-12
Exhibit
Designation
Nature of Exhibit
Previously 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.  

E-13

Exhibit Designation 
Nature of Exhibit
 
Previously Filed as Exhibit to:
REGISTRANT:    101.INSXBRL Instance Document.
101.SCHXBRL Taxonomy Extension Schema.
101.CALXBRL Taxonomy Extension Calculation Linkbase.
101.DEFXBRL Taxonomy Extension Definition Linkbase.
101.LABXBRL Taxonomy Extension Label Linkbase.
101.PREXBRL Taxonomy Extension Presentation Linkbase.
SWEPCo‡   File No. 1-3146
3(a) Composite of Amended Restated Certificate of Incorporation of SWEPCo. 2008 Form 10-K, Ex 3(a)
3(b) Composite By-Laws of SWEPCo amended as of February 26, 2008. 2007 Form 10-K, Ex 3(b)
4(a) 
Indenture (for unsecured debt securities), dated as of February 4, 2000, between SWEPCo and The Bank of New York, as Trustee.
 
 
 
Registration Statement No. 333-96213
Registration Statement No. 333-87834, Ex 4(a)(b)
Registration Statement No. 333-100632, Ex 4(b)
Registration Statement No. 333-108045, Ex 4(b)
Registration Statement No. 333-145669, Ex 4(c)(d)
Registration Statement No. 333-161539, Ex 4(b)(c)
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) $650 Million Credit Agreement,Ninth Supplemental Indenture dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo,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,&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent. due 2022. Form 10-Q,8-K, Ex 10(c) September 30, 20084(a), dated February 3, 2012
E-13
4(d)
Exhibit
Designation
 Amendment, dated asNature of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Exhibit Form 10-Q, Ex 10(d) September 30, 2008Previously Filed as Exhibit to:
4(e) $350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent. Form 10-Q, Ex 10(e) September 30, 2008
4(f)Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.Form 10-Q, Ex 10(f) September 30, 2008
10(a) Restated and Amended Operating Agreement, among PSO, TCC, TNC, SWEPCo and AEPSC, Issued on February 10, 2006, Effective May 1, 2006. Form 10-Q, Ex 10(a), March 31, 2006
10(b) Restated and Amended Transmission Coordination Agreement dated April 15, 2002,January 1, 1997, restated and amended, and as amended and approved by FERC in 2011 by and among, PSO, SWEPCo TNC and AEPSC.AEPSC, in connection with the operation of the transmission assets of the two public utility subsidiaries. Form 2009 10-K, Ex 10(b)
†10(c)AEP System Senior Officer Annual Incentive Compensation Plan amended and restated effective December 13, 2006.Form 8-K, Ex 10.1 dated  April 25, 2007
†10(d)(1)AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2008.2008 Form 10-K, Ex 10(d)(1)
*†10(d)(2)AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2011 (Non-Qualified).  
†10(d)(3)AEPSC Umbrella Trust for Executives.1993 Form 10-K, Ex 10(g)(3), File No. 1-3525
†10(d)(3)(A)First Amendment to AEPSC Umbrella Trust for Executives.2008 Form 10-K, Ex 10(d)(3)(A)
†10(e)(1)Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 15, 2003.2003 Form 10-K, Ex 10(m)(1)

E-14
  
Nature of Exhibit
Previously Filed as Exhibit to:
†10(e)(1)(A)Amendment to Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 9, 2008.2008 Form 10-K, Ex 10(e)(A)
†10(e)(2)Memorandum of Agreement between Susan Tomasky and AEPSC dated January 3, 2001.2000 Form 10-K, Ex 10(s), File No. 1-3525
†10(e)(3)Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers.2002 Form 10-K, Ex 10(m)(4)
†10(e)(3)(A)Amendment to Employment Agreement dated December 9, 2008 between AEPSC and Robert P. Powers.2008 Form 10-K, Ex 10(e)(4)(A)
†10(e)(4)Letter Agreement dated June 9, 2004 between AEPSC and Carl English.Form 10-Q, Ex 10(b), September 30, 2004
†10(f)AEP System Senior Officer Annual Incentive Compensation Plan, amended and restated effective December 13, 2006.Form 8-K, Ex 10.1 dated April 25, 2007
†10(g)(1)AEP System Survivor Benefit Plan, effective January 27, 1998.Form 10-Q, Ex 10, September 30, 1998
†10(g)(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(g)(1)(B) Second Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 1, 2008.2008 Form 10-K, Ex 10(g)(1)(B)
†10(h)AEP Change In Control Agreement, effective November 1, 2009.2009 Form 10-K, Ex 10(h)
*†10(i)(1)Amended and Restated AEP System Long-Term Incentive Plan.Form 10-Q, Ex 10, March 31, 2010
†10(i)(2)Form of Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.AEP Form 10-Q, Ex 10(c), November 5, 2004
†10(i)(3)Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.Form 10-Q, Ex 10(a), March 31, 2005
†10(i)(3)(A)Amendment to Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.2008 Form 10-K, Ex 10(i)(3)(A)
†10(j)AEP System Stock Ownership Requirement Plan Amended and Restated Effective January 1, 2010.2009 Form 10-K, Ex 10(j)
†10(k)Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2009.2008 Form 10-K, Ex 10(j)
†10(l)AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008.2008 Form 10-K, Ex 10(k)
†10(m)AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998.2002 Form 10-K, Ex 10(p)
†10(n)Nuclear Key Contributor Retention Plan Amended and Restated as of January 1, 2008.2008 Form 10-K, Ex 10(m)
*12 Statement re: Computation of Ratios.
  
*13 Copy of those portions of the SWEPCo 20102011 Annual Report (for the fiscal year ended December 31, 2010)2011) which are incorporated by reference in this filing.  
21 List of subsidiaries of SWEPCo. 2006 Form 10-K, Ex 21, File No. 1-3525
*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.  
*95Mine Safety Disclosure.
101.INSXBRL Instance Document.
101.SCHXBRL Taxonomy Extension Schema.
101.CALXBRL Taxonomy Extension Calculation Linkbase.
101.DEFXBRL Taxonomy Extension Definition Linkbase.
101.LABXBRL Taxonomy Extension Label Linkbase.
101.PREXBRL Taxonomy Extension Presentation Linkbase.
E-15

 ‡ 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-16E-14