Appalachian Power 10-Q 2012 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended March 31, 2012

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Transition Period from ____ to ____

Commission	Registrants; States of Incorporation;	I.R.S. Employer
File Number	Address and Telephone Number	Identification Nos.
1-3525	AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)	13-4922640
1-3457	APPALACHIAN POWER COMPANY (A Virginia Corporation)	54-0124790
1-3570	INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)	35-0410455
1-6543	OHIO POWER COMPANY (An Ohio Corporation)	31-4271000
0-343	PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)	73-0410895
1-3146	SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)	72-0323455
	1 Riverside Plaza, Columbus, Ohio 43215-2373
	Telephone (614) 716-1000

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	X	No

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate websites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).
Yes	X	No

Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer	X	Accelerated filer
Non-accelerated filer		Smaller reporting company

Indicate by check mark whether Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers or smaller reporting companies.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer		Accelerated filer
Non-accelerated filer	X	Smaller reporting company

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
Yes	No	X

Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

	Number of shares of common stock outstanding of the registrants at April 26, 2012
American Electric Power Company, Inc.	484,321,794
	($6.50 par value)
Appalachian Power Company	13,499,500
	(no par value)
Indiana Michigan Power Company	1,400,000
	(no par value)
Ohio Power Company	27,952,473
	(no par value)
Public Service Company of Oklahoma	9,013,000
	($15 par value)
Southwestern Electric Power Company	7,536,640
	($18 par value)

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF QUARTERLY REPORTS ON FORM 10-Q

March 31, 2012

		Page Number
Glossary of Terms		i
Forward-Looking Information		iv
Part I. FINANCIAL INFORMATION
Items 1, 2 and 3 - Financial Statements, Management’s Financial Discussion and Analysis and Quantitative and Qualitative Disclosures About Market Risk:
American Electric Power Company, Inc. and Subsidiary Companies:
	Management’s Financial Discussion and Analysis	1
	Condensed Consolidated Financial Statements	24
	Index of Condensed Notes to Condensed Consolidated Financial Statements	30
Appalachian Power Company and Subsidiaries:
	Management’s Narrative Financial Discussion and Analysis	70
	Condensed Consolidated Financial Statements	74
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	80
Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Financial Discussion and Analysis	82
	Condensed Consolidated Financial Statements	87
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	93
Ohio Power Company Consolidated:
	Management’s Narrative Financial Discussion and Analysis	95
	Condensed Consolidated Financial Statements	100
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	106
Public Service Company of Oklahoma:
	Management’s Narrative Financial Discussion and Analysis	108
	Condensed Financial Statements	110
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	116
Southwestern Electric Power Company Consolidated:
	Management’s Narrative Financial Discussion and Analysis	118
	Condensed Consolidated Financial Statements	121
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	127

Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	128
Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries	175
Item 4.               Controls and Procedures	180

Part II.  OTHER INFORMATION
	Item 1.	Legal Proceedings		181
	Item 1A.	Risk Factors		181
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		183
	Item 4.	Mine Safety Disclosures		183
	Item 5.	Other Information		183
	Item 6.	Exhibits:		183
			Exhibit 10
			Exhibit 12
			Exhibit 31(a)
			Exhibit 31(b)
			Exhibit 32(a)
			Exhibit 32(b)
			Exhibit 95
			Exhibit 101.INS
			Exhibit 101.SCH
			Exhibit 101.CAL
			Exhibit 101.DEF
			Exhibit 101.LAB
			Exhibit 101.PRE
SIGNATURE				184

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

GLOSSARY OF TERMS

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

Term	Meaning
AEGCo	AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent	American Electric Power Company, Inc., a utility holding company.
AEP Consolidated	AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit	AEP Credit, Inc., a subsidiary of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East companies	APCo, I&M, KPCo and OPCo.
AEP System	American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEPEP	AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, asset management and commercial and industrial sales in the deregulated Texas market.
AEPSC	American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC	Allowance for Funds Used During Construction.
AOCI	Accumulated Other Comprehensive Income.
APCo	Appalachian Power Company, an AEP electric utility subsidiary.
APSC	Arkansas Public Service Commission.
BlueStar	BlueStar Energy Holdings, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.
BOA	Bank of America Corporation.
CAA	Clean Air Act.
CLECO	Central Louisiana Electric Company, a nonaffiliated utility company.
CO2	Carbon dioxide and other greenhouse gases.
Cook Plant	Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CSPCo	Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
DCC Fuel	DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC and DCC Fuel IV LLC, variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC	Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
E&R	Environmental compliance and transmission and distribution system reliability.
EIS	Energy Insurance Services, Inc., a nonaffiliated captive insurance company.
ERCOT	Electric Reliability Council of Texas regional transmission organization.
ESP	Electric Security Plans, filed with the PUCO, pursuant to the Ohio Amendments.
ETT	Electric Transmission Texas, LLC, an equity interest joint venture between AEP and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FAC	Fuel Adjustment Clause.
FASB	Financial Accounting Standards Board.
Federal EPA	United States Environmental Protection Agency.
FERC	Federal Energy Regulatory Commission.
FGD	Flue Gas Desulfurization or scrubbers.
FTR	Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP	Accounting Principles Generally Accepted in the United States of America.

i

Term Meaning

I&M	Indiana Michigan Power Company, an AEP electric utility subsidiary.
IGCC	Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement	An agreement by and among APCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
IRS	Internal Revenue Service.
IURC	Indiana Utility Regulatory Commission.
KPCo	Kentucky Power Company, an AEP electric utility subsidiary.
KPSC	Kentucky Public Service Commission.
KWH	Kilowatthour.
LPSC	Louisiana Public Service Commission.
MISO	Midwest Independent Transmission System Operator.
MMBtu	Million British Thermal Units.
MPSC	Michigan Public Service Commission.
MTM	Mark-to-Market.
MW	Megawatt.
NEIL	Nuclear Electric Insurance Limited insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks.
NOx	Nitrogen oxide.
Nonutility Money Pool	Centralized funding mechanism AEP uses to meet the short term cash requirements of certain nonutility subsidiaries.
NSR	New Source Review.
OCC	Corporation Commission of the State of Oklahoma.
OPCo	Ohio Power Company, an AEP electric utility subsidiary.
OPEB	Other Postretirement Benefit Plans.
OTC	Over the counter.
PJM	Pennsylvania – New Jersey – Maryland regional transmission organization.
PM	Particulate Matter.
POLR	Provider of Last Resort revenues.
PSO	Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO	Public Utilities Commission of Ohio.
PUCT	Public Utility Commission of Texas.
Registrant Subsidiaries	AEP subsidiaries which are SEC registrants; APCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts	Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant	A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
RTO	Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine	Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC	U.S. Securities and Exchange Commission.
SEET	Significantly Excessive Earnings Test.
SIA	System Integration Agreement, effective June 15, 2000, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF	Spent Nuclear Fuel.
SO2	Sulfur dioxide.
SPP	Southwest Power Pool regional transmission organization.
SWEPCo	Southwestern Electric Power Company, an AEP electric utility subsidiary.

ii

Term Meaning

TCC	AEP Texas Central Company, an AEP electric utility subsidiary.
TNC	AEP Texas North Company, an AEP electric utility subsidiary.
Transition Funding	AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas restructuring law.
Turk Plant	John W. Turk, Jr. Plant, a 600 MW coal-fired plant under construction in Arkansas that is 73% owned by SWEPCo.
Utility Money Pool	Centralized funding mechanism AEP uses to meet the short term cash requirements of certain utility subsidiaries.
VIE	Variable Interest Entity.
Virginia SCC	Virginia State Corporation Commission.
WPCo	Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC	Public Service Commission of West Virginia.

iii

FORWARD-LOOKING INFORMATION

This report made by AEP 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 – Management’s Financial Discussion and Analysis” of the 2011 Annual Report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, we 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:

· The economic climate and growth in, or contraction within, our service territory and changes in market demand and demographic patterns.

· Inflationary or deflationary interest rate trends.

· Volatility 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.

· The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.

· Electric load, customer growth and the impact of retail competition, particularly in Ohio.

· Weather conditions, including storms, and our ability to recover significant storm restoration costs through applicable rate mechanisms.

· Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.

· Availability of necessary generating capacity and the performance of our generating plants.

· Our 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.

· Our ability to recover regulatory assets in connection with deregulation.

· Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.

· Our ability to build or acquire generating capacity, and transmission lines 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.

· New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants and related assets.

· A reduction in the federal statutory tax rate.

· Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.

· Resolution of litigation.

· Our ability to constrain operation and maintenance costs.

· Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.

· Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.

· Actions of rating agencies, including changes in the ratings of our debt.

· Volatility and changes in markets for electricity, natural gas and other energy-related commodities.

· Changes in utility regulation, including the implementation of ESPs and the transition to market and expected legal separation for generation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.

iv

· Accounting pronouncements periodically issued by accounting standard-setting bodies.

· The 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.

· Prices and demand for power that we generate and sell at wholesale.

· Changes in technology, particularly with respect to new, developing or alternative sources of generation.

· Our 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.

· Our ability to successfully manage negotiations with stakeholders and obtain regulatory approval to terminate or amend the Interconnection Agreement.

· Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.

· Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

The forward looking statements of AEP and its Registrant Subsidiaries speak only as of the date of this report or as of the date they are made.  AEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information.  For a more detailed discussion of these factors, see “Risk Factors” in the 2011 Annual Report and in Part II of this report.

v

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Proposed June 2012 – May 2015 Ohio ESP

In March 2012, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing.  The SSO rates would be effective from June 2012 through May 2015.  The ESP will transition OPCo to an auction-based SSO for capacity and energy by June 1, 2015.  The ESP also proposed to collect the Phase-In Recovery Rider from June 2013 through December 2018.  Further, the ESP proposed establishment of a non-bypassable Distribution Investment Rider through May 2015 to recover, with certain caps, post-August 2010 distribution investment.  The filing also seeks establishment of a new non-bypassable Retail Stability Rider (RSR) to recover lost generation revenues to provide financial certainty and stability during the ESP transition period.  The proposed RSR will be effective through May 2015.  Hearings are scheduled at the PUCO for May 2012 and oral arguments are scheduled for July 3, 2012, which would delay the proposed implementation of rates.  See “Ohio Electric Security Plan Filing” section of Note 2.

Ohio Customer Choice

In our Ohio service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service.  As a result, in comparison to the first quarter of 2011, we lost approximately $42 million of gross margin.  We are recovering a portion of lost margins through collection of capacity revenues from competitive CRES providers, off-system sales and new revenues from AEP Retail Energy Partners LLC, our CRES provider and member of our Generating and Marketing segment.  AEP Retail Energy Partners LLC targets retail customers in Ohio, both within and outside of our retail service territory.

In March 2012, AEP Retail Energy Partners LLC completed the acquisition of BlueStar Energy Holdings, Inc. (BlueStar) and its independent retail electric supplier BlueStar Energy Solutions.  BlueStar provides electric supply for retail customers in Ohio, Illinois and other deregulated electricity markets and also provides energy solutions throughout the United States, including demand response and energy efficiency services.  BlueStar has been in operation since 2002.

Ohio Capacity Rate

In March 2012, in response to OPCo’s motion for relief, the PUCO ordered that competitive retail electric service (CRES) providers not qualifying for the Reliability Pricing Model (RPM) price, which is substantially below OPCo’s current capacity cost of approximately $355/MW day, will pay a capacity billing rate of $255/MW day through May 2012, at which time the capacity billing rate will revert to the RPM price.  If the PUCO does not issue an order in the June 2012 – May 2015 ESP proceeding by May 31, 2012, OPCo will request an extension of the $255/MW day capacity rate.  See “Ohio Electric Security Plan Filing” section of Note 2.

Possible Corporate Separation and Termination of the Interconnection Agreement

In March 2012, we filed a corporate separation plan with the PUCO for OPCo’s generation assets.  Additional filings at the FERC and other state commissions related to corporate separation are expected to be filed in the future.  If all regulatory approvals are received, APCo and KPCo will seek recovery of associated costs from customers through their regulated rates.  Our results of operations related to generation in Ohio will be determined by our ability to sell power and capacity at a profit at rates determined by the prevailing market.  If we are unable to sell power and capacity at a profit, it could reduce future net income and cash flows and impact financial condition.

1

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC.  It is unknown at this time whether the Interconnection Agreement will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.  Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future.  If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

Customer Demand

In comparison to the first quarter of 2011, heating degree days in 2012 were down 32% and 50% in our eastern and western service territories, respectively.  Retail margins also decreased due to the loss of retail customers in Ohio.  See “Ohio Customer Choice” section above.  Our weather-normalized industrial sales increased 2% in 2012, primarily due to a significant increase in production from Ormet, a large aluminum company, and lesser increases from other metals and refinery customers.

Cost Reduction Initiatives

In April 2012, we initiated a process to identify employee repositioning opportunities and efficiencies that will result in sustainable cost savings.  The process will result in the redeployment of employees and involuntary severances.  The process is expected to be completed by the end of 2012.

Securitization

Texas Securitization

As part of the Texas restructuring appeals, in December 2011, the PUCT approved an unopposed stipulation allowing TCC to recover $800 million, including carrying charges.  We completed the securitization financing of $800 million in March 2012.

West Virginia Securitization

In March 2012, West Virginia passed securitization legislation, which allows the WVPSC to establish a regulatory framework to securitize certain deferred ENEC balances.  APCo and WPCo anticipate filing, in the second quarter of 2012, a request for a financing order with the WVPSC pursuant to the securitization legislation.  As of March 31, 2012, APCo’s ENEC under-recovery balance of $334 million was recorded in Regulatory Assets on the balance sheet.  See “APCo’s and WPCo’s Expanded Net Energy Charge (ENEC) Filing” section of Note 2.

Regulatory Activity

2009 Fuel Adjustment Clause Audit

The PUCO selected an outside consultant to conduct the audit of the FAC for OPCo for the period of January 2009 through December 2009.  In January 2012, the PUCO ordered that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance.  In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges.  OPCo expects to record the favorable effect of the rehearing order of approximately $30 million in the second quarter of 2012.

2

Significantly Excessive Earnings Test

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off of certain pretax earnings in 2010 and a subsequent refund to customers during 2011.  In May 2011, the Industrial Energy Users-Ohio and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO’s SEET decision.  The OEG’s appeal seeks the inclusion of off-system sales (OSS) in the calculation of SEET which, if ordered, could require an additional refund of $22 million based on the PUCO approved SEET calculation.  OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  In the fourth quarter of 2011, OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO ordered SEET refund.  OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis.  Management does not currently believe that there are significantly excessive earnings in 2011 for either CSPCo or OPCo.  See “Ohio Electric Security Plan Filing” section of Note 2.

Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on common equity of 11.15%.  The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.  Final hearings are currently scheduled for June 2012.  See “2011 Indiana Base Rate Case” section of Note 2.

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal generating unit in Arkansas, which is on target to be in service in the fourth quarter of 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  See “Turk Plant” section of Note 2.

Cook Plant

Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator.  Repair of the property damage and replacement of the turbine rotors and other equipment cost approximately $400 million.  Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process.  Due to the extensive lead time required to manufacture and install new turbine rotors, I&M repaired Unit 1 and it resumed operations in December 2009.  The installation of the new turbine rotors and other equipment occurred during the refueling outage of Unit 1 in the fall 2011.  If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it would reduce future net income and cash flows and impact financial condition.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 3.

Nuclear Regulatory Commission

As a result of the nuclear plant situation in Japan following a March 2011 earthquake, the Nuclear Regulatory Commission (NRC) 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.  The NRC is also looking into the fuel used at eleven reactors, including the units at the Cook Plant.  Their concern relates to fuel temperatures if abnormal conditions are experienced.  We continue to monitor this issue and respond to the NRC’s inquiry, as necessary.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.

3

Life Cycle Management Project

In April 2012, I&M filed a petition with the IURC for approval of the Cook Plant Life Cycle Management Project (LCM Project).  The LCM Project consists of a group of capital projects that extend the operating lives of Unit 1 and 2 to 2034 and 2037, respectively, which is consistent with the recent extension of their operating licenses.  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  I&M requested recovery of certain project costs, including interest, through a rider effective 2013.  I&M intends to file with the MPSC in the second quarter of 2012.  As of March 31, 2012, I&M has incurred $74 million related to the LCM Project.  If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

LITIGATION

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  We assess the probability of loss for each contingency and accrue a liability for cases that have a probable likelihood of loss if the loss can be estimated.  For details on our regulatory proceedings and pending litigation see Note 3 – Rate Matters, Note 5 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis” in the 2011 Annual Report.  Additionally, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies included herein.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements.  We will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants from fossil fuel-fired power plants, new proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.

We are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of our nuclear units.  We are also engaged in the development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change.  We, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court.  The U.S. House of Representatives passed legislation called the Transparency in Regulatory Analysis of Impacts on the Nation (the TRAIN Act) that would delay implementation of certain Federal EPA rules and facilitate a comprehensive analysis of their impacts.  The Senate is considering similar legislation.  We believe that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Financial Discussion and Analysis” in the 2011 Annual Report.  We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  We should be able to recover certain of these expenditures through market prices in deregulated jurisdictions.  If not, the costs of environmental compliance could reduce future net income and cash flows and impact financial condition.

4

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of March 31, 2012, the AEP System had a total generating capacity of nearly 37,080 MWs, of which 23,900 MWs are coal-fired.  We continue to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on our coal-fired generating facilities.  Based upon our estimates, investment to meet these proposed requirements ranges from approximately $6 billion to $7 billion between 2012 and 2020.  These amounts include investments to convert 1,055 MWs of coal generation to natural gas capacity.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules.  The cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on our units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.

Subject to the factors listed above and based upon our continuing evaluation, we have given notice to the applicable RTO of our intent to retire the following plants or units of plants before or during 2015:

		Generating
Company	Plant Name and Unit	Capacity
		(in MWs)
APCo	Clinch River Plant, Unit 3		235
APCo	Glen Lyn Plant		335
APCo	Kanawha River Plant		400
APCo/OPCo	Philip Sporn Plant, Units 1-4		600
I&M	Tanners Creek Plant, Units 1-3		495
KPCo	Big Sandy Plant, Unit 1		278
OPCo	Conesville Plant, Unit 3		165
OPCo	Kammer Plant		630
OPCo	Muskingum River Plant, Units 1-4		840
OPCo	Picway Plant		100
SWEPCo	Welsh Plant, Unit 2		528
Total			4,606

Duke Energy Corporation, the operator of W. C. Beckjord Generating Station, has announced its intent to close the facility in 2015.  OPCo owns 12.5% (54 MWs) of one unit at that station.

We are monitoring the potential impact that the proposed corporate separation of OPCo’s generation assets and the proposed termination of the Interconnection Agreement could have on the recoverability of OPCo's generation assets. 

In April 2012, we reached an agreement in principle with the Federal EPA, the State of Oklahoma and other parties to retire one coal-fired unit of PSO’s Northeastern Station no later than 2016, install emission controls on the second coal-fired Northeastern unit and retire the second unit no later than 2026.  These two coal-fired units have a combined generating capacity of 930 MWs.  The parties are working toward a final settlement agreement.

Plans for and the timing of conversion of some of our coal units to natural gas, installing emission control equipment on other units and closure of existing units will be impacted by changes in emission requirements and demand for power.  To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows.

5

Scrubber Applications

Rockport Plant

I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit its Rockport Plant.  As part of I&M’s compliance plan to address new environmental requirements, I&M needs to install FGD and selective catalytic reduction equipment on one unit of the Rockport Plant.  As a result of environmental requirements, I&M is evaluating options related to maturity of the lease for Rockport Plant Unit 2 in 2022.  If I&M receives approval of a CPCN, I&M will file for cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism.  An IURC decision is expected in the third quarter of 2012.

Big Sandy Unit 2 FGD System

KPCo filed an application with the KPSC seeking approval of a Certificate of Public Convenience and Necessity to retrofit Big Sandy Unit 2 with a dry FGD system and to commence site construction activities on or about July 1, 2013.  KPCo also filed for approval of its 2011 environmental compliance plan and related surcharge tariff for construction of certain facilities associated with the plan.  The projected capital costs of the Big Sandy Unit 2 dry FGD system are approximately $955 million including certain preconstruction study costs and approximately $101 million of AFUDC.  If approved, recovery of the Big Sandy Unit 2 dry FGD system would begin two months following the projected in-service date of July 2016.  As of March 31, 2012, KPCo has incurred $25 million related to the project including $15 million associated with a previously studied wet FGD system.  In March 2012, intervenors filed testimony which opposed the project.  A decision is expected in second quarter of 2012.  If KPCo is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

Flint Creek Plant

In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to go forward with the estimated $408 million FGD project at the Flint Creek Plant.  As a joint owner of the Flint Creek Plant, SWEPCo’s portion of the FGD project costs is estimated at $204 million.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions.  The states implement and administer many of these programs and could impose additional or more stringent requirements.

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas.  BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.  CAVR will be implemented through individual state implementation plans (SIPs) or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs).  The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas and Oklahoma.  The Federal EPA finalized a FIP for Oklahoma that contains more stringent control requirements for SO2 emissions from affected units in that state.  No action has been finalized in Arkansas.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for SO2, NOx and lead, and is currently reviewing the NAAQS for ozone and PM.  States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for our facilities as a result of those evaluations.  We cannot currently predict the nature, stringency or timing of those requirements.

Notable developments in significant CAA regulatory requirements affecting our operations are discussed in the following sections.

6

Cross-State Air Pollution Rule (CSAPR)

In August 2011, the Federal EPA issued CSAPR.  Certain revisions to the rule were finalized in March 2012.  CSAPR relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states.  Interstate trading of allowances is allowed on a restricted sub-regional basis beginning in 2012.  Arkansas and Louisiana are subject only to the seasonal NOx program in the rule.  Texas is subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program.  The annual SO2 allowance budgets in Indiana, Ohio and West Virginia have been reduced significantly in the rule.  Numerous affected entities, states and other parties filed petitions to review the CSAPR in the United States Court of Appeals for the District of Columbia Circuit.  Several of the petitioners filed motions to stay the implementation of the rule pending judicial review.  In December 2011, the court granted the motions for stay.  Oral argument was heard in April 2012.  A supplemental rule includes Oklahoma in the seasonal NOx program.  The supplemental rule was finalized in December 2011, with an increased NOx emission budget for the 2012 compliance year.  A separate appeal of the supplemental rule has been filed, but is being held in abeyance until the court issues a decision in the main CSAPR appeal.

The time frames and stringency of the required emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and our electric utility customers.  We cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In February 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  The effective date of the final rule was April 16, 2012 and compliance is required within three years.

The final rule contains a slightly less stringent PM limit than the original proposal and allows operators to exclude periods of startup and shutdown from the emissions averaging periods.  The compliance time frame remains a serious concern.  A one-year administrative extension may be available if the extension is necessary for the installation of controls or to avoid a serious reliability problem.  In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades.  We are concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines.  We are participating in petitions for review filed in the United States Court of Appeals for the District of Columbia Circuit by several organizations of which we are members.

Regional Haze

In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze SIP submitted by the State of Oklahoma through the Department of Environmental Quality.  The Federal EPA proposed to approve all of the NOx control measures in the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO.  The Federal EPA proposed a FIP that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP.  PSO submitted comments on the proposed action demonstrating that the cost-effectiveness calculations performed by the Federal EPA were unsound, challenging the period for compliance with the final rule and showing that the visibility improvements secured by the proposed SIP were significant and cost-effective.  The Federal EPA finalized the FIP in December 2011 that mirrored the proposed rule but established a five-year compliance schedule.  PSO filed a petition for review of the FIP in the Tenth Circuit Court of Appeals and engaged in settlement discussions with the Federal EPA, the State of Oklahoma and other parties.  In April 2012, we reached an agreement in principle that would provide for submission of a revised Regional Haze SIP requiring the retirement of one coal-fired unit of PSO’s Northeastern Station no later than 2016, installation of emission controls on the second coal-fired Northeastern unit and retirement of the second unit no later than 2026.  The parties are working toward finalizing a settlement agreement.

7

CO2 Regulation

In March 2012, the Federal EPA issued a proposal to regulate CO2 emissions from new fossil fuel-fired electricity generating units.  The proposed rule establishes a new source performance standard of 1,000 pounds of CO2 per megawatt hour of electricity generated, a rate that most natural gas combined cycle units can meet, but that is substantially below the emission rate of a new pulverized coal generator or an integrated gas combined cycle unit that uses coal for fuel.  As proposed, the rule does not apply to new gas-fired stationary combustion turbines used as peaking units, does not apply to existing, modified or reconstructed sources, and does not apply to units whose CO2 emission rate increases as a result of the addition of pollution control equipment to control criteria or HAPs.  The rule is not anticipated to have a significant immediate impact on the AEP System since it does not apply to existing units or units that have already commenced construction, like our Turk Plant.  Once the proposal is published in the Federal Register, the Federal EPA intends to solicit comments for 60 days.  We will be evaluating the proposal and preparing comments to submit to the Federal EPA.

Coal Combustion Residual Rule

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.  The rule contains two alternative proposals.  One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management.  Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule.  In October 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment.

Currently, approximately 40% of the coal ash and other residual products from our generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses.  Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes.  In addition, we currently use surface impoundments and landfills to manage these materials at our generating facilities and will incur significant costs to upgrade or close and replace these existing facilities under the proposed solid waste management alternative.  Regulation of these materials as hazardous wastes would significantly increase these costs.  As the rule is not final, we are unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

Clean Water Act Regulations

In April 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling.  Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority.  We are evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at our facilities.  We submitted comments on the proposal in July and August 2011.  A final rule is expected to be signed by the Federal EPA Administrator by the end of July 2012.  We are preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

8

Global Warming

National public policy makers and regulators in the 11 states we serve have conflicting views on global warming.  While comprehensive economy-wide regulation of CO2 emissions might be achieved through future legislation, Congress has yet to enact such legislation.  The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA.

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 of our states have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements, including Michigan, Ohio, Texas and Virginia.  We are taking steps to comply with these requirements.

Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others.  We have been named in pending lawsuits, which we are defending.  In March 2012, the court granted the defendants’ motion for dismissal of the suit in “Carbon Dioxide Public Nuisance Claims” on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations.  Plaintiffs appealed the decision to the Fifth Circuit Court of Appeals.  It is not possible to predict the outcome of these lawsuits or their impact on our operations or financial condition.  See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 3.

Future federal and state legislation or regulations that mandate limits on the emission of CO2 would result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force our utility subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets.  As a result, mandatory limits could reduce future net income and cash flows and impact financial condition.

For additional information on global warming, other environmental issues and the actions we are taking to address potential impacts, see Part I of the 2011 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters” and “Management’s Financial Discussion and Analysis.”

9

RESULTS OF OPERATIONS

SEGMENTS

Our primary business is the generation, transmission and distribution of electricity.  Within our Utility Operations segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

While our Utility Operations segment remains our primary business segment, the advancement of an area of our business prompted us to identify a new reportable segment.  Starting in the fourth quarter of 2011, we established our new Transmission Operations segment as described below:

Utility Operations

· Generation of electricity for sale to U.S. retail and wholesale customers.

· Transmission and distributionof electricity through assets owned and operated by our ten utility operating companies.

Transmission Operations

· Development, construction and operation of transmission facilities through investments in our wholly-owned transmission subsidiaries that were established in 2009 and our transmission joint ventures.  These investments have PUCT-approved or FERC-approved returns on equity.

· In April 2012, AEP and Great Plains Energy (Great Plains) formed Transource Energy LLC (Transource).  AEP and Great Plains own 86.5% and 13.5% of Transource, respectively.  Transource will initially pursue transmission projects in PJM, SPP and MISO.

AEP River Operations

· Commercial barging operations that transport coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.

Generation and Marketing

· Nonregulated generation in ERCOT.

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

The table below presents our consolidated Net Income by segment for the three months ended March 31, 2012 and 2011.  We reclassified prior year amounts to conform to the current year’s presentation.

	Three Months Ended March 31,
	2012			2011
	(in millions)
Utility Operations	$	384		$	374
Transmission Operations		9			4
AEP River Operations		9			7
Generation and Marketing		(1	)		1
All Other (a)		(11	)		(31	)
Net Income	$	390		$	355

(a)	While not considered a reportable segment, All Other includes:
	·	Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
	·	Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.  These contracts were financial derivatives which settled and expired in the fourth quarter of 2011.
	·	Revenue sharing related to the Plaquemine Cogeneration Facility which ended in the fourth quarter of 2011.

10

AEP CONSOLIDATED

First Quarter of 2012 Compared to First Quarter of 2011

Net Income increased from $355 million in 2011 to $390 million in 2012 primarily due to:

· A decrease in other operation and maintenance expenses as a result of reduced spending.

· The first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO’s February 2012 rejection of OPCo’s modified stipulation.

· Successful rate proceedings in our various jurisdictions.

· A first quarter 2011 settlement of litigation with BOA and Enron.

· An overall increase in net income from our Transmission Operations segment due to increased investments by ETT and our wholly-owned transmission subsidiaries.

These increases were partially offset by:

· A decrease in weather-related usage.

· The loss of retail customers in Ohio to various competitive retail electric service providers.

Average basic shares outstanding increased to 484 million in 2012 from 481 million in 2011.  Actual shares outstanding were 484 million as of March 31, 2012.

Our results of operations are discussed below by operating segment.

UTILITY OPERATIONS

We believe that a discussion of the results from our Utility Operations segment on a gross margin basis is most appropriate in order to further understand the key drivers of the segment.  Gross Margin represents total revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances and purchased power.  We reclassified prior year amounts to conform to the current year’s presentation.

	Three Months Ended
	March 31,
	2012			2011
	(in millions)
Revenues	$	3,385		$	3,524
Fuel and Purchased Power		1,269			1,297
Gross Margin		2,116			2,227
Other Operation and Maintenance		755			850
Depreciation and Amortization		412			393
Taxes Other Than Income Taxes		211			209
Operating Income		738			775
Interest and Investment Income		1			2
Carrying Costs Income		20			15
Allowance for Equity Funds Used During Construction		20			20
Interest Expense		(217	)		(232	)
Income Before Income Tax Expense and Equity Earnings		562			580
Equity Earnings of Unconsolidated Subsidiaries		1			1
Income Tax Expense		179			207
Net Income	$	384		$	374

11

Summary of KWH Energy Sales for Utility Operations
	Three Months Ended March 31,
	2012		2011
	(in millions of KWHs)
Retail:
Residential		14,799		16,949
Commercial		11,265		11,646
Industrial		14,647		14,329
Miscellaneous		721		723
Total Retail (a)		41,432		43,647
Wholesale		8,913		9,151
Total KWHs		50,345		52,798
(a) Includes energy delivered to customers served by TCC and TNC.

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.  In general, degree day changes in our eastern region have a larger effect on net income than changes in our western region due to the relative size of the two regions and the number of customers within each region.

Summary of Heating and Cooling Degree Days for Utility Operations
		Three Months Ended March 31,
		2012		2011
		(in degree days)
Eastern Region
Actual - Heating (a)			1,261		1,854
Normal - Heating (b)			1,751		1,739
Actual - Cooling (c)			28		3
Normal - Cooling (b)			3		3
Western Region
Actual - Heating (a)			347		692
Normal - Heating (b)			581		579
Actual - Cooling (d)			133		109
Normal - Cooling (b)			60		58
(a)	Eastern Region and Western Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Eastern Region cooling degree days are calculated on a 65 degree temperature base.
(d)	Western Region cooling degree days are calculated on a 65 degree temperature base for PSO/SWEPCo and a 70 degree temperature base for
	TCC/TNC.

12

First Quarter of 2012 Compared to First Quarter of 2011

Reconciliation of First Quarter of 2011 to First Quarter of 2012
Net Income from Utility Operations
(in millions)
First Quarter of 2011	$	374
Changes in Gross Margin:
Retail Margins		(98)
Off-system Sales		(2)
Transmission Revenues		13
Other Revenues		(24)
Total Change in Gross Margin		(111)
Changes in Expenses and Other:
Other Operation and Maintenance		95
Depreciation and Amortization		(19)
Taxes Other Than Income Taxes		(2)
Interest and Investment Income		(1)
Carrying Costs Income		5
Interest Expense		15
Total Change in Expenses and Other		93
Income Tax Expense		28
First Quarter of 2012	$	384

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail Margins decreased $98 million primarily due to the following:
	·	An $87 million decrease in weather-related usage primarily due to 32% and 50% decreases in heating degree days in our eastern and western service territories, respectively.
	·	A $54 million decrease attributable to Ohio customers switching to alternative competitive retail electric service (CRES) providers.
	·	A $39 million decrease due to the elimination of POLR charges, effective June 2011, in Ohio as a result of the October 2011 PUCO remand order.
	These decreases were partially offset by:
	·	Successful rate proceedings in our service territories which include:
		·	A $37 million rate increase for OPCo.
		·	A $22 million rate increase for APCo.
		·	A $16 million rate increase for I&M.
		·	For the rate increases described above, $20 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
·	Margins from Off-system Sales decreased $2 million primarily due to lower physical sales volumes and lower trading and marketing margins, partially offset by an increase in PJM capacity revenues.
·	Transmission Revenues increased $13 million primarily due to net rate increases in PJM and increased transmission revenues for Ohio customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers partially offsets lost revenues included in Retail Margins above.
·	Other Revenues decreased $24 million primarily due to an unfavorable regulatory order in Ohio and a decrease in gains on other miscellaneous sales.

13

Expenses and Other and Income Tax Expense changed between years as follows:

·	Other Operation and Maintenance expenses decreased $95 million primarily due to the following:
	·	A $41 million decrease due to the first quarter 2011 write-off of a portion of the West Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC in March 2011.
	·	A $35 million decrease due to the first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO’s February 2012 rejection of OPCo’s modified stipulation.
	·	A $34 million decrease in employee-related expenses.
	·	A $27 million decrease in plant outage and other plant operating and maintenance expenses.
	These decreases were partially offset by:
	·	A $33 million increase due to the first quarter 2011 deferral of 2009 costs related to storms and our 2010 cost reduction initiatives as allowed by the WVPSC in March 2011.
	·	An $11 million gain from the sale of land in January 2011.
·	Depreciation and Amortization expenses increased $19 millionprimarily due to the following:
	·	A $14 million increase due to shortened depreciable lives for certain OPCo generating plants effective December 2011.
	·	A $6 million increase due to increased amortization of TCC’s Securitized Transition Assets.  The increase in TCC’s securitization related amortizations are offset within Gross Margin.
	·	A $6 million increase in depreciation as a result of APCo’s increase in depreciation rates in Virginia effective February 1, 2012.
	·	A $5 million increase in amortization primarily due to APCo’s current year amortization as a result of the Virginia E&R surcharge and the Virginia Environmental Rate Adjustment Clause, both effective February 2012.
	·	Overall higher depreciable property balances.
	These increases were partially offset by:
	·	A $9 million decrease due to the amortization of a portion of an Ohio distribution depreciation reserve as approved by the PUCO in the 2011 Ohio Distribution Base Rate Case.
·	Carrying Costs Income increased $5 million primarily due to the following:
	·	An $8 million increase due to the recording of debt carrying costs prior to TCC’s issuance of securitization bonds in March 2012.
	·	A $3 million increase from carrying charges on APCo’s Dresden Plant resulting from the Virginia Generation Rate Adjustment Clause and the West Virginia Expanded Net Energy Charge.
	These increases were partially offset by:
	·	An $8 million decrease primarily due to OPCo’s collections of carrying costs in the first quarter 2012 on phase-in FAC deferrals and certain distribution regulatory assets.
·	Interest Expense decreased $15 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·	Income Tax Expense decreased $28 million primarily due to a decrease in pre-tax book income and audit settlements for previous years.

14

TRANSMISSION OPERATIONS

First Quarter of 2012 Compared to First Quarter of 2011

Net Income from our Transmission Operations segment increased from $4 million in 2011 to $9 million in 2012 primarily due to an increase in investments by ETT and our wholly-owned transmission subsidiaries.

AEP RIVER OPERATIONS

First Quarter of 2012 Compared to First Quarter of 2011

Net Income from our AEP River Operations segment increased from $7 million in 2011 to $9 million in 2012 primarily due to a reduction in expenses as a result of reduced spending.

GENERATION AND MARKETING

First Quarter of 2012 Compared to First Quarter of 2011

Net Income from our Generation and Marketing segment decreased from a gain of $1 million in 2011 to a loss of $1 million in 2012 primarily due to the expiration of production tax credits in 2011 partially offset by increased gross margins at the Oklaunion Plant.

ALL OTHER

First Quarter of 2012 Compared to First Quarter of 2011

Net Income from All Other increased from a loss of $31 million in 2011 to a loss of $11 million in 2012 primarily due to a loss incurred in February 2011 related to the settlement of litigation with BOA and Enron.

AEP SYSTEM INCOME TAXES

First Quarter of 2012 Compared to First Quarter of 2011

Income Tax Expense decreased $89 million primarily due to a decrease in pretax book income, the unrealized capital loss valuation allowance related to a deferred tax asset associated with the settlement of litigation with BOA and Enron and audit settlements for previous years.

FINANCIAL CONDITION

We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

	March 31, 2012				December 31, 2011
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	17,320	52.1	%	$	16,516	50.3	%
Short-term Debt		1,050	3.2			1,650	5.0
Total Debt		18,370	55.3			18,166	55.3
AEP Common Equity		14,856	44.7			14,664	44.7
Noncontrolling Interests		1	-			1	-
Total Debt and Equity Capitalization	$	33,227	100.0	%	$	32,831	100.0	%

Our ratio of debt-to-total capital was unchanged from December 31, 2011 to March 31, 2012 at 55.3%.  Long-term debt outstanding increased due to the March 2012 issuance of $800 million of securitization bonds.

15

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability.  We believe we have adequate liquidity under our existing credit facilities.  At March 31, 2012, we had $3.25 billion in aggregate credit facility commitments to support our operations.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  We are committed to maintaining adequate liquidity.  We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, sale-leaseback or leasing agreements or common stock.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At March 31, 2012, our available liquidity was approximately $3 billion as illustrated in the table below:

		Amount		Maturity
		(in millions)
Commercial Paper Backup:
	Revolving Credit Facility	$	1,500	June 2015
	Revolving Credit Facility		1,750	July 2016
Total			3,250
Cash and Cash Equivalents			286
Total Liquidity Sources			3,536
Less:	AEP Commercial Paper Outstanding		385
	Letters of Credit Issued		189
Net Available Liquidity		$	2,962

We have credit facilities totaling $3.25 billion to support our commercial paper program.  The credit facilities allow us to issue letters of credit in an amount up to $1.35 billion.

We use our commercial paper program to meet the short-term borrowing needs of our 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 maximum amount of commercial paper outstanding during the first three months of 2012 was $1.2 billion.  The weighted-average interest rate for our commercial paper during 2012 was 0.47%.

Securitized Accounts Receivables

In 2011, we renewed our receivables securitization agreement.  The agreement provides a commitment of $750 million from bank conduits to purchase receivables with an increase to $800 million for the months of July, August and September to accommodate seasonal demand.  A commitment of $375 million with the seasonal increase to $425 million for the months of July, August and September expires in June 2012 and the remaining commitment of $375 million expires in June 2014.  We intend to extend or replace the agreement expiring in June 2012 on or before its maturity.

Debt Covenants and Borrowing Limitations

Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually defined in our revolving credit agreements.  Debt as defined in the revolving credit agreements excludes junior subordinated debentures, securitization bonds and debt of AEP Credit.  At March 31, 2012,this contractually-defined percentage was 50.1%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  At March 31, 2012, we complied with all of the covenants contained in these

16

credit agreements.  In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements and in a majority of our non-exchange traded commodity contracts which would permit the lenders and counterparties to declare the outstanding amounts payable.  However, a default under our non-exchange traded commodity contracts does not cause an event of default under our revolving credit agreements.

The revolving credit facilities do not permit the lenders to refuse a draw on any facility if a material adverse change occurs.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  At March 31, 2012, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.47 per share in April 2012.  Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time.  Our income derives from our common stock equity in the earnings of our utility subsidiaries.  Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

We have the option to defer interest payments on the AEP Junior Subordinated Debentures for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.

We do not believe restrictions related to our various financing arrangements and regulatory requirements will have any significant impact on Parent’s ability to access cash to meet the payment of dividends on its common stock.

Credit Ratings

We do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but our access to the commercial paper market may depend on our credit ratings.  In addition, downgrades in our credit ratings by one of the rating agencies could increase our borrowing costs.  Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject us to additional collateral demands under adequate assurance clauses under our derivative and non-derivative energy contracts.

CASH FLOW

Managing our cash flows is a major factor in maintaining our liquidity strength.

	Three Months Ended
	March 31,
	2012				2011
	(in millions)
Cash and Cash Equivalents at Beginning of Period		$	221			$	294
Net Cash Flows from Operating Activities			876				830
Net Cash Flows Used for Investing Activities			(792	)			(613	)
Net Cash Flows from (Used for) Financing Activities			(19	)			114
Net Increase in Cash and Cash Equivalents			65				331
Cash and Cash Equivalents at End of Period		$	286			$	625

17

Cash from operations and short-term borrowings provides working capital and allows us to meet other short-term cash needs.

Operating Activities

	Three Months Ended
	March 31,
	2012			2011
	(in millions)
Net Income		$	390		$	355
Depreciation and Amortization			423			403
Other			63			72
Net Cash Flows from Operating Activities		$	876		$	830

Net Cash Flows from Operating Activities were $876 million in 2012 consisting primarily of Net Income of $390 million and $423 million of noncash Depreciation and Amortization.  Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  A significant change in other items includes the favorable impact of a decrease in accounts receivable and the unfavorable impact of an increase in fuel inventory due to the mild weather.  Deferred Income Taxes increased primarily due to provisions in the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Jobs Creation Act and an increase in tax versus book temporary differences from operations.

Net Cash Flows from Operating Activities were $830 million in 2011 consisting primarily of Net Income of $355 million and $403 million of noncash Depreciation and Amortization.  Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Significant changes in other items include the favorable impact of decreases in fuel inventory and receivables from customers and the unfavorable impact of reducing accounts payable.  Deferred Income Taxes increased primarily due to provisions in the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Jobs Creation Act, the settlement with BOA and Enron and an increase in tax versus book temporary differences from operations.  In February 2011, we paid $425 million to BOA.  $211 million of this payment was to settle litigation with BOA and Enron. The remaining $214 million to acquire cushion gas is discussed in Investing Activities below.

Investing Activities

	Three Months Ended
	March 31,
	2012				2011
	(in millions)
Construction Expenditures		$	(741	)		$	(540	)
Acquisitions of Nuclear Fuel			(11	)			(27	)
Acquisitions of Assets/Businesses			(85	)			(2	)
Acquisition of Cushion Gas from BOA			-				(214	)
Proceeds from Sales of Assets			8				69
Other			37				101
Net Cash Flows Used for Investing Activities		$	(792	)		$	(613	)

Net Cash Flows Used for Investing Activities were $792 million in 2012 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments.  Acquisitions of Assets/Businesses include our March 2012 purchase of BlueStar for $70 million.

Net Cash Flows Used for Investing Activities were $613 million in 2011 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments.  We paid $214 million to BOA for cushion gas as part of a litigation settlement.

18

Financing Activities

	Three Months Ended
	March 31,
	2012				2011
	(in millions)
Issuance of Common Stock, Net		$	31			$	31
Issuance of Debt, Net			193				324
Dividends Paid on Common Stock			(229	)			(223	)
Other			(14	)			(18	)
Net Cash Flows from (Used for) Financing Activities		$	(19	)		$	114

Net Cash Flows Used for Financing Activities in 2012 were $19 million.  Our net debt issuances were $193 million. The net issuances included issuances of $800 million securitization bonds, $275 million of senior unsecured notes and $67 million of notes payable offset by retirements of $191 million of senior unsecured and other debt notes, $50 million of pollution control bonds, $98 million of securitization bonds and a decrease in short-term borrowing of $600 million.  We paid common stock dividends of $229 million.  See Note 10 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows from Financing Activities in 2011 were $114 million.  Our net debt issuances were $324 million. The net issuances included $600 million senior unsecured notes, $421 million of pollution control bonds and an increase in short-term borrowing of $87 million offset by retirements of $214 million of senior unsecured and debt notes, $471 million of pollution control bonds and $92 million of securitization bonds.  We paid common stock dividends of $223 million.

In April 2012, I&M retired $26 million of Notes Payable related to DCC Fuel.

In April 2012, I&M issued $110 million of variable rate Notes Payable related to DCC Fuel.

OFF-BALANCE SHEET ARRANGEMENTS

In prior periods, under a limited set of circumstances, we entered into off-balance sheet arrangements for various reasons including reducing operational expenses and spreading risk of loss to third parties.  Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that we enter in the normal course of business.  The following identifies significant off-balance sheet arrangements:

	March 31,			December 31,
	2012			2011
	(in millions)
Rockport Plant Unit 2 Future Minimum Lease Payments		$	1,626		$	1,626
Railcars Maximum Potential Loss From Lease Agreement			25			25

For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis” in the 2011 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2011 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

19

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Financial Discussion and Analysis” in the 2011 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

ACCOUNTING PRONOUNCEMENTS

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes.  The FASB is currently working on several projects including revenue recognition, contingencies, financial instruments, leases, insurance, hedge accounting and consolidation policy.  We also expect to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP.  The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

Our Utility Operations segment is exposed to certain market risks as a major power producer and through its transactions in wholesale electricity, coal and emission allowance trading and marketing contracts.  These risks include commodity price risk, interest rate risk and credit risk.  In addition, we are exposed to foreign currency exchange risk because occasionally we procure various services and materials used in our energy business from foreign suppliers.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

Our Generation and Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM and MISO.  This segment is exposed to certain market risks as a marketer of wholesale and retail electricity.  These risks include commodity price risk, interest rate risk and credit risk.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

We employ risk management contracts including physical forward purchase and sale contracts and financial forward purchase and sale contracts.  We engage in risk management of power, coal and natural gas and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business.  As a result, we are subject to price risk.  The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.  Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures.  The CORC consists of our Chief Operating Officer, Chief Financial Officer, Senior Vice President of Commercial Operations and Chief Risk Officer.  When commercial activities exceed predetermined limits, we modify the positions to reduce the risk to be within the limits unless specifically approved by the CORC.

20

The following table summarizes the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2011:

MTM Risk Management Contract Net Assets (Liabilities)
Three Months Ended March 31, 2012
			Generation
	Utility		and
	Operations		Marketing			Total
	(in millions)
Total MTM Risk Management Contract Net Assets
at December 31, 2011	$	59	$	132		$	191
(Gain) Loss from Contracts Realized/Settled During the Period and
Entered in a Prior Period		2		(9	)		(7	)
Fair Value of New Contracts at Inception When Entered During the
Period (a)		4		4			8
Net Option Premiums Received for Unexercised or Unexpired
Option Contracts Entered During the Period		-		-			-
Changes in Fair Value Due to Market Fluctuations During the
Period (b)		3		3			6
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		4		-			4
Total MTM Risk Management Contract Net Assets
at March 31, 2012	$	72	$	130			202
Commodity Cash Flow HedgeContracts							(26	)
Interest Rate and Foreign Currency Cash Flow HedgeContracts							(15	)
Fair Value HedgeContracts							1
Collateral Deposits							85
Total MTM Derivative Contract Net Assets at March 31, 2012						$	247

(a)	Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  The contract prices are valued against market curves associated with the delivery location and delivery term.  A significant portion of the total volumetric position has been economically hedged.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)	Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets.

See Note 7 – Derivatives and Hedging and Note 8 – Fair Value Measurements for additional information related to our risk management contracts.  The following tables and discussion provide information on our credit risk and market volatility risk.

21

Credit Risk

We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  We use Moody’s Investors Service, Standard & Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

We have risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily.  As of March 31, 2012, our credit exposure net of collateral to sub investment grade counterparties was approximately 5.5%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).  As of March 31, 2012, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

		Exposure						Number of		Net Exposure
		Before						Counterparties		of
		Credit		Credit		Net		>10% of		Counterparties
Counterparty Credit Quality		Collateral		Collateral		Exposure		Net Exposure		>10%
		(in millions, except number of counterparties)
Investment Grade		$	637	$	4	$	633		2	$	240
Split Rating			-		-		-		-		-
Noninvestment Grade			11		-		11		1		11
No External Ratings:
	Internal Investment Grade		316		-		316		2		178
	Internal Noninvestment Grade		55		11		44		1		34
Total as of March 31, 2012		$	1,019	$	15	$	1,004		6	$	463
Total as of December 31, 2011		$	960	$	19	$	941		5	$	348

Value at Risk (VaR) Associated with Risk Management Contracts

We use a risk measurement model, which calculates VaR, to measure our commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, as of March 31, 2012, a near term typical change in commodity prices is not expected to have a material effect on our net income, cash flows or financial condition.

The following table shows the end, high, average and low market risk as measured by VaR for the trading portfolio for the periods indicated:

VaR Model

Three Months Ended								Twelve Months Ended
March 31, 2012								December 31, 2011
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	-	$	1	$	-	$	-	$	-	$	2	$	-	$	-

We back-test our VaR results against performance due to actual price movements.  Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

22

As our VaR calculation captures recent price movements, we also perform regular stress testing of the portfolio to understand our exposure to extreme price movements.  We employ a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which historical price movements translated into the largest potential MTM loss.  We then research the underlying positions, price movements and market events that created the most significant exposure and report the findings to the Risk Executive Committee or the CORC as appropriate.

Interest Rate Risk

We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which our interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on debt outstanding as of March 31, 2012 and December 31, 2011, the estimated EaR on our debt portfolio for the following twelve months was $24 million and $29 million, respectively.

23

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2012 and 2011
(in millions, except per-share and share amounts)
(Unaudited)
	2012			2011
REVENUES
Utility Operations	$	3,363		$	3,497
Other Revenues		262			233
TOTAL REVENUES		3,625			3,730
EXPENSES
Fuel and Other Consumables Used for Electric Generation		1,053			1,056
Purchased Electricity for Resale		260			275
Other Operation		656			686
Maintenance		262			265
Depreciation and Amortization		423			403
Taxes Other Than Income Taxes		217			213
TOTAL EXPENSES		2,871			2,898
OPERATING INCOME		754			832
Other Income (Expense):
Interest and Investment Income		2			2
Carrying Costs Income		20			15
Allowance for Equity Funds Used During Construction		23			20
Interest Expense		(229	)		(242	)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		570			627
Income Tax Expense		189			278
Equity Earnings of Unconsolidated Subsidiaries		9			6
NET INCOME		390			355
Net Income Attributable to Noncontrolling Interests		1			1
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS		389			354
Preferred Stock Dividend Requirements of Subsidiaries		-			1
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	389		$	353
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING		483,828,101			481,144,270
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
SHAREHOLDERS	$	0.80		$	0.73
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING		484,248,868			481,365,806
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
SHAREHOLDERS	$	0.80		$	0.73
CASH DIVIDENDS DECLARED PER SHARE	$	0.47		$	0.46
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 30.

24

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2012 and 2011
(in millions)
(Unaudited)
	2012			2011
NET INCOME	$	390		$	355
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $6 in 2012 and $1 in 2011		(11	)		1
Securities Available for Sale, Net of Tax of $1 in 2012 and $- in 2011		2			1
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $4 in 2012 and
$3 in 2011		7			6
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(2	)		8
TOTAL COMPREHENSIVE INCOME		388			363
Total Comprehensive Income Attributable to Noncontrolling Interests		1			1
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
SHAREHOLDERS		387			362
Preferred Stock Dividend Requirements of Subsidiaries		-			1
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
COMMON SHAREHOLDERS	$	387		$	361
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 30.

25

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Three Months Ended March 31, 2012 and 2011
(in millions)
(Unaudited)
		AEP Common Shareholders
		Common Stock								Accumulated
										Other
						Paid-in		Retained		Comprehensive		Noncontrolling
		Shares		Amount		Capital		Earnings		Income (Loss)		Interests		Total
TOTAL EQUITY – DECEMBER 31, 2010			501	$	3,257	$	5,904	$	4,842	$	(381)	$	-	$	13,622
Issuance of Common Stock			1		6		25								31
Common Stock Dividends									(222)				(1)		(223)
Preferred Stock Dividend Requirements of
	Subsidiaries								(1)						(1)
Other Changes in Equity							(13)								(13)
SUBTOTAL – EQUITY															13,416
NET INCOME									354				1		355
OTHER COMPREHENSIVE INCOME											8				8
TOTAL EQUITY – MARCH 31, 2011			502	$	3,263	$	5,916	$	4,973	$	(373)	$	-	$	13,779
TOTAL EQUITY – DECEMBER 31, 2011			504	$	3,274	$	5,970	$	5,890	$	(470)	$	1	$	14,665
Issuance of Common Stock			1		6		25								31
Common Stock Dividends									(228)				(1)		(229)
Other Changes in Equity							3		(1)						2
SUBTOTAL – EQUITY															14,469
NET INCOME									389				1		390
OTHER COMPREHENSIVE LOSS											(2)				(2)
TOTAL EQUITY – MARCH 31, 2012			505	$	3,280	$	5,998	$	6,050	$	(472)	$	1	$	14,857
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 30.

26

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2012 and December 31, 2011
(in millions)
(Unaudited)
			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	286	$	221
Other Temporary Investments
	(March 31, 2012 and December 31, 2011 amounts include $202 and $281, respectively, related to Transition Funding and EIS)			217		294
Accounts Receivable:
	Customers			616		690
	Accrued Unbilled Revenues			78		106
	Pledged Accounts Receivable – AEP Credit			896		920
	Miscellaneous			114		150
	Allowance for Uncollectible Accounts			(34)		(32)
		Total Accounts Receivable		1,670		1,834
Fuel				780		657
Materials and Supplies				638		635
Risk Management Assets				246		193
Accrued Tax Benefits				47		51
Regulatory Asset for Under-Recovered Fuel Costs				75		65
Margin Deposits				70		67
Prepayments and Other Current Assets				185		165
TOTAL CURRENT ASSETS				4,214		4,182
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			25,309		24,938
	Transmission			9,211		9,048
	Distribution			14,944		14,783
Other Property, Plant and Equipment (including nuclear fuel and coal mining)				3,836		3,780
Construction Work in Progress				2,923		3,121
Total Property, Plant and Equipment				56,223		55,670
Accumulated Depreciation and Amortization				18,791		18,699
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				37,432		36,971
OTHER NONCURRENT ASSETS
Regulatory Assets				5,291		6,026
Securitized Transition Assets				2,289		1,627
Spent Nuclear Fuel and Decommissioning Trusts				1,662		1,592
Goodwill				90		76
Long-term Risk Management Assets				425		403
Deferred Charges and Other Noncurrent Assets				1,499		1,346
TOTAL OTHER NONCURRENT ASSETS				11,256		11,070
TOTAL ASSETS			$	52,902	$	52,223
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 30.

27

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 2012 and December 31, 2011
(dollars in millions)
(Unaudited)
					2012		2011
CURRENT LIABILITIES
Accounts Payable					$	978	$	1,095
Short-term Debt:
	Securitized Debt for Receivables - AEP Credit					665		666
	Other Short-term Debt					385		984
		Total Short-term Debt				1,050		1,650
Long-term Debt Due Within One Year
	(March 31, 2012 and December 31, 2011 amounts include $316 and $293, respectively, related to Transition Funding, DCC Fuel and Sabine)					1,980		1,433
Risk Management Liabilities						185		150
Customer Deposits						301		289
Accrued Taxes						679		717
Accrued Interest						237		279
Regulatory Liability for Over-Recovered Fuel Costs						79		8
Other Current Liabilities						853		990
TOTAL CURRENT LIABILITIES						6,342		6,611
NONCURRENT LIABILITIES
Long-term Debt
	(March 31, 2012 and December 31, 2011 amounts include $2,382 and $1,674, respectively, related to Transition Funding, DCC Fuel and Sabine)					15,340		15,083
Long-term Risk Management Liabilities						239		195
Deferred Income Taxes						8,493		8,227
Regulatory Liabilities and Deferred Investment Tax Credits						3,469		3,195
Asset Retirement Obligations						1,500		1,472
Employee Benefits and Pension Obligations						1,739		1,801
Deferred Credits and Other Noncurrent Liabilities						923		974
TOTAL NONCURRENT LIABILITIES						31,703		30,947
TOTAL LIABILITIES						38,045		37,558
Rate Matters (Note 2)
Commitments and Contingencies (Note 3)
EQUITY
Common Stock – Par Value – $6.50 Per Share:
			2012	2011
	Shares Authorized		600,000,000	600,000,000
	Shares Issued		504,566,633	503,759,460
(20,336,592 shares were held in treasury at March 31, 2012 and December 31, 2011)						3,280		3,274
Paid-in Capital						5,998		5,970
Retained Earnings						6,050		5,890
Accumulated Other Comprehensive Income (Loss)						(472)		(470)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY						14,856		14,664
Noncontrolling Interests						1		1
TOTAL EQUITY						14,857		14,665
TOTAL LIABILITIES AND EQUITY					$	52,902	$	52,223
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 30.

28

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2012 and 2011
(in millions)
(Unaudited)
	2012			2011
OPERATING ACTIVITIES
Net Income	$	390		$	355
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		423			403
Deferred Income Taxes		261			330
Gain on Settlement with BOA and Enron		-			(51	)
Settlement of Litigation with BOA and Enron		-			(211	)
Carrying Costs Income		(20	)		(15	)
Allowance for Equity Funds Used During Construction		(23	)		(20	)
Mark-to-Market of Risk Management Contracts		10			42
Amortization of Nuclear Fuel		34			34
Property Taxes		(49	)		(52	)
Fuel Over/Under-Recovery, Net		112			(27	)
Change in Other Noncurrent Assets		(59	)		(3	)
Change in Other Noncurrent Liabilities		(47	)		77
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		207			181
Fuel, Materials and Supplies		(126	)		121
Accounts Payable		(26	)		(126	)
Accrued Taxes, Net		(30	)		(96	)
Other Current Assets		(15	)		2
Other Current Liabilities		(166	)		(114	)
Net Cash Flows from Operating Activities		876			830
INVESTING ACTIVITIES
Construction Expenditures		(741	)		(540	)
Change in Other Temporary Investments, Net		79			73
Purchases of Investment Securities		(353	)		(454	)
Sales of Investment Securities		334			484
Acquisitions of Nuclear Fuel		(11	)		(27	)
Acquisitions of Assets/Businesses		(85	)		(2	)
Acquisition of Cushion Gas from BOA		-			(214	)
Proceeds from Sales of Assets		8			69
Other Investing Activities		(23	)		(2	)
Net Cash Flows Used for Investing Activities		(792	)		(613	)
FINANCING ACTIVITIES
Issuance of Common Stock, Net		31			31
Issuance of Long-term Debt		1,132			1,014
Commercial Paper and Credit Facility Borrowings		21			318
Change in Short-term Debt, Net		(583	)		244
Retirement of Long-term Debt		(339	)		(777	)
Commercial Paper and Credit Facility Repayments		(38	)		(475	)
Principal Payments for Capital Lease Obligations		(18	)		(17	)
Dividends Paid on Common Stock		(229	)		(223	)
Dividends Paid on Cumulative Preferred Stock		-			(1	)
Other Financing Activities		4			-
Net Cash Flows from (Used for) Financing Activities		(19	)		114
Net Increase in Cash and Cash Equivalents		65			331
Cash and Cash Equivalents at Beginning of Period		221			294
Cash and Cash Equivalents at End of Period	$	286		$	625
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	265		$	250
Net Cash Paid (Received) for Income Taxes		(65	)		2
Noncash Acquisitions Under Capital Leases		20			24
Construction Expenditures Included in Current Liabilities at March 31,		250			220
Noncash Assumption of Liabilities Related to Acquisitions		56			-
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 30.

29

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.	Significant Accounting Matters
2.	Rate Matters
3.	Commitments, Guarantees and Contingencies
4.	Acquisition and Disposition
5.	Benefit Plans
6.	Business Segments
7.	Derivatives and Hedging
8.	Fair Value Measurements
9.	Income Taxes
10.	Financing Activities

30

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.  SIGNIFICANT ACCOUNTING MATTERS

General

The unaudited condensed consolidated financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC.  Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods.  Net income for the three months ended March 31, 2012 is not necessarily indicative of results that may be expected for the year ending December 31, 2012.  The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2011 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 28, 2012.

Variable Interest Entities

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE.  A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.  Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.”  In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE’s variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors.  We believe that significant assumptions and judgments were applied consistently.

We are the primary beneficiary of Sabine, DCC Fuel, AEP Credit, Transition Funding and a protected cell of EIS.  In addition, we have not provided material financial or other support to Sabine, DCC Fuel, Transition Funding, our protected cell of EIS and AEP Credit that was not previously contractually required.  We hold a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series).

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the three months ended March 31, 2012 and 2011 were $55 million and $33 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on our condensed balance sheets.

31

Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance.  EIS has multiple protected cells.  Neither AEP nor its subsidiaries have an equity investment in EIS.  The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance.  Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims.  Based on our control and the structure of the protected cell and EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate its assets and liabilities.  Our insurance premium expense to the protected cell for the three months ended March 31, 2012 and 2011 was $15 million and $30 million, respectively.  See the tables below for the classification of the protected cell’s assets and liabilities on our condensed balance sheets.  The amount reported as equity is the protected cell’s policy holders’ surplus.

I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC and DCC Fuel IV LLC (collectively DCC Fuel).  DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC and DCC Fuel IV LLC are separate legal entities from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the DCC Fuel LLC and DCC Fuel II LLC leases are made semi-annually and began in April 2010 and October 2010, respectively.  Payments on the DCC Fuel III LLC lease are made monthly and began in January 2011.  Payments on the DCC Fuel IV LLC lease are made quarterly and began in February 2012.  Payments on the leases for the three months ended March 31, 2012 and 2011 were $17 million and $6 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the 48, 54, 54 and 54 month lease term, respectively.  Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  See the tables below for the classification of DCC Fuel’s assets and liabilities on our condensed balance sheets.

AEP Credit is a wholly-owned subsidiary of AEP.  AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements.  AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings.  Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing.  Based on our control of AEP Credit, management has concluded that we are the primary beneficiary and are required to consolidate its assets and liabilities.  See the tables below for the classification of AEP Credit’s assets and liabilities on our condensed balance sheets.  See “Securitized Accounts Receivables – AEP Credit” section of Note 10.

Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.  Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant.  Therefore, TCC is required to consolidate Transition Funding.  The securitized bonds totaled $2.4 billion and $1.7 billion at March 31, 2012 and December 31, 2011, respectively, and are included in current and long-term debt on the condensed balance sheets.  Transition Funding has securitized transition assets of $2.3 billion and $1.6 billion at March 31, 2012 and December 31, 2011, respectively, which are presented separately on the face of the condensed balance sheets.  The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT.  The securitization bonds are payable only from and secured by the securitized transition assets.  The bondholders have no recourse to TCC or any other AEP entity.  TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs.  See the tables below for the classification of Transition Funding’s assets and liabilities on our condensed balance sheets.

32

The balances below represent the assets and liabilities of the VIEs that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
March 31, 2012
(in millions)
													TCC
	SWEPCo			I&M			Protected Cell						Transition
	Sabine			DCC Fuel			of EIS			AEP Credit			Funding
ASSETS
Current Assets		$	75		$	123		$	130		$	885		$	141
Net Property, Plant and Equipment			167			159			-			-			-
Other Noncurrent Assets			57			98			6			1			2,343
Total Assets		$	299		$	380		$	136		$	886		$	2,484
LIABILITIES AND EQUITY
Current Liabilities		$	48		$	92		$	51		$	840		$	248
Noncurrent Liabilities			251			288			67			1			2,218
Equity			-			-			18			45			18
Total Liabilities and Equity		$	299		$	380		$	136		$	886		$	2,484

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2011
(in millions)
													TCC
	SWEPCo			I&M			Protected Cell						Transition
	Sabine			DCC Fuel			of EIS			AEP Credit			Funding
ASSETS
Current Assets		$	48		$	118		$	121		$	910		$	220
Net Property, Plant and Equipment			154			188			-			-			-
Other Noncurrent Assets			42			118			6			1			1,580
Total Assets		$	244		$	424		$	127		$	911		$	1,800
LIABILITIES AND EQUITY
Current Liabilities		$	68		$	103		$	40		$	864		$	229
Noncurrent Liabilities			176			321			71			1			1,557
Equity			-			-			16			46			14
Total Liabilities and Equity		$	244		$	424		$	127		$	911		$	1,800

33

DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and voting rights equally.  Each entity guarantees 50% of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  SWEPCo’s total billings from DHLC for the three months ended March 31, 2012 and 2011 were $14 million and $13 million, respectively.  We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC.  Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on our condensed balance sheets.

Our investment in DHLC was:

	March 31, 2012						December 31, 2011
	As Reported on			Maximum			As Reported on			Maximum
	the Balance Sheet			Exposure			the Balance Sheet			Exposure
	(in millions)
Capital Contribution from SWEPCo		$	8		$	8		$	8		$	8
Retained Earnings			1			1			1			1
SWEPCo's Guarantee of Debt			-			54			-			52
Total Investment in DHLC		$	9		$	63		$	9		$	61

We and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH).  In February 2011, PJM directed that work on the PATH project be suspended.  PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region.  PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy.  Provisions exist within the PATH-WV agreement that make it a VIE.  The “Allegheny Series” is not considered a VIE.  We are not required to consolidate PATH-WV as we are not the primary beneficiary, although we hold a significant variable interest in PATH-WV.  Our equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on our condensed balance sheets.  We and FirstEnergy share the returns and losses equally in PATH-WV.  Our subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements.  As of March 31, 2012, PATH-WV had no debt outstanding.  However, if debt is issued, the debt to equity ratio in each series should be consistent with other regulated utilities.  The entities recover costs through regulated rates.

Given the structure of the entity, we may be required to provide future financial support to PATH-WV in the form of a capital call.  This would be considered an increase to our investment in the entity.  Our maximum exposure to loss is to the extent of our investment.  The likelihood of such a loss is remote since the FERC approved PATH-WV’s request for regulatory recovery of cost and a return on the equity invested.

Our investment in PATH-WV was:

	March 31, 2012						December 31, 2011
	As Reported on			Maximum			As Reported on			Maximum
	the Balance Sheet			Exposure			the Balance Sheet			Exposure
				(in millions)
Capital Contribution from AEP		$	19		$	19		$	19		$	19
Retained Earnings			11			11			10			10
Total Investment in PATH-WV		$	30		$	30		$	29		$	29

34

Earnings Per Share (EPS)

Basic earnings per common share is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period.  Diluted earnings per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.

The following tables present our basic and diluted EPS calculations included on our condensed statements of income:

	Three Months Ended March 31,
	2012					2011
	(in millions, except per share data)
			$/share					$/share
Earnings Attributable to AEP Common Shareholders	$	389				$	353
Weighted Average Number of Basic Shares Outstanding		483.8		$	0.80		481.1		$	0.73
Weighted Average Dilutive Effect of:
Stock Options		-			-		0.1			-
Restricted Stock Units		0.4			-		0.2			-
Weighted Average Number of Diluted Shares Outstanding		484.2		$	0.80		481.4		$	0.73

The assumed conversion of stock options does not affect net earnings for purposes of calculating diluted earnings per share.

Options to purchase 136,250 shares of common stock were outstanding at March 31, 2011 but were not included in the computation of diluted earnings per share attributable to AEP common shareholders.  Since the options’ exercise prices were greater than the average market price of the common shares, the effect would have been antidilutive.  There were no antidilutive shares outstanding at March 31, 2012.

2.  RATE MATTERS

As discussed in the 2011 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within our 2011 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition.  The following discusses ratemaking developments in 2012 and updates the 2011 Annual Report.

Regulatory Assets Not Yet Being Recovered

	March 31,		December 31,
	2012		2011
	(in millions)
Noncurrent Regulatory Assets (excluding fuel)
Regulatory assets not yet being recovered pending future proceedings
to determine the recovery method and timing:
Regulatory Assets Currently Earning a Return
Storm Related Costs	$	24	$	24
Economic Development Rider		13		13
Regulatory Assets Currently Not Earning a Return
Deferred Wind Power Costs		44		38
Environmental Rate Adjustment Clause		21		18
Mountaineer Carbon Capture and Storage Product Validation Facility		14		14
Special Rate Mechanism for Century Aluminum		13		13
Litigation Settlement		11		11
Storm Related Costs		2		10
Other Regulatory Assets Not Yet Being Recovered		19		14
Total Regulatory Assets Not Yet Being Recovered	$	161	$	155

35

OPCo Rate Matters

Ohio Electric Security Plan Filing

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011.  OPCo collected the 2009 annualized revenue increase over the last nine months of 2009.  The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018.  See the “January 2012 – May 2016 ESP as Rejected by the PUCO” section below.  The PUCO’s March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO.

In October 2011, the PUCO issued an order in the remand proceeding.  As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011.  In February 2012, the Ohio Consumers’ Counsel and the Industrial Energy Users-Ohio (IEU) filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which if ordered could total up to $698 million, excluding carrying costs.

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off of certain pretax earnings in 2010 and a subsequent refund to customers during 2011.  In May 2011, the IEU and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO’s SEET decision.  The OEG’s appeal seeks the inclusion of off-system sales (OSS) in the calculation of SEET which, if ordered, could require an additional refund of $22 million based on the PUCO approved SEET calculation.  The IEU’s appeal also sought the inclusion of OSS as well as other items in the determination of SEET, but did not quantify the amount.  Oral arguments were held in March 2012 and management is unable to predict the outcome of the appeals.  If the Supreme Court of Ohio ultimately determines that additional amounts should be refunded, it could reduce future net income and cash flows and impact financial condition.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings, which included OSS in the SEET calculation.  In December 2011, the PUCO staff filed testimony that recommended a $23 million refund of 2010 earnings.  In the fourth quarter of 2011, OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO ordered SEET refund.  OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis.  Management does not currently believe that there are significantly excessive earnings in 2011 for either CSPCo or OPCo.

Management is unable to predict the outcome of the unresolved litigation discussed above.  If these proceedings, including future SEET filings, result in adverse rulings, it could reduce future net income and cash flows and impact financial condition.

January 2012 – May 2016 ESP as Rejected by the PUCO

In December 2011, the PUCO approved a modified stipulation which established a new ESP that included a standard service offer (SSO) pricing for generation.  Various parties filed for rehearing with the PUCO requesting that the PUCO reconsider adoption of the modified stipulation.  In February 2012, the PUCO issued an entry on rehearing which rejected the modified stipulation and ordered a return to the 2011 ESP rates until a new rate plan is approved.

36

As directed by the February 2012 order, OPCo filed revised tariffs with the PUCO to implement the provisions of the 2011 ESP.  Included in the revised tariffs was the Phase-In Recovery Rider (PIRR) to recover deferred fuel costs as authorized under the 2009 – 2011 ESP order.  See the “2009 – 2011 ESP” section above.  In March 2012, the PUCO issued an order that directed OPCo to file new revised tariffs removing the PIRR and stated that its recovery would be addressed in a future proceeding.  OPCo implemented the new revised tariffs in March 2012.  In March 2012, OPCo resumed recording a weighted average cost of capital return on the PIRR deferral in accordance with the 2009 - 2011 ESP order.  In March 2012, OPCo filed a request for rehearing of the March 2012 order relating to the PIRR.  As of March 31, 2012, the net PIRR deferral was $499 million, excluding unrecognized equity carrying costs.  If OPCo is ultimately not permitted to fully recover its PIRR deferral, it would reduce future net income and cash flows and impact financial condition.

As a result of the PUCO’s rejection of the modified stipulation, in the first quarter of 2012, OPCo reversed a $35 million obligation to contribute to Partnership with Ohio and Ohio Growth Fund and an $8 million regulatory asset for 2011 storm damage, both originally recorded in the fourth quarter of 2011.

In March 2012, in response to OPCo’s motion for relief, the PUCO ordered that competitive retail electric service (CRES) providers not qualifying for the Reliability Pricing Model (RPM) price, which is substantially below OPCo’s current capacity cost of approximately $355/MW day, will pay a capacity billing rate of $255/MW day through May 2012, at which time the capacity billing rate will revert to the RPM price.  

Proposed June 2012 – May 2015 ESP

In March 2012, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing.  The SSO rates would be effective from June 2012 through May 2015.  The ESP will transition OPCo to an auction-based SSO for capacity and energy by June 1, 2015.  OPCo also filed an application with the PUCO for approval of the corporate separation of its generation assets including the transfer of generation assets to a nonregulated AEP subsidiary at net book value.  Contingent upon OPCo receiving final orders from the PUCO adopting the ESP as proposed and the corporate separation plan as filed, OPCo will conduct an energy-only auction for 5% of the SSO load with delivery beginning six months after the final orders and extending through December 2014.  In addition, a competitive bidding process would determine the price of energy for OPCo’s SSO load from January 2015 through May 2015.  The ESP proposed a two-tiered capacity pricing structure for CRES providers.  The first tier is priced at the RPM rate in effect in March 2012 of $146/MW day to serve approximately 21%, 31% and 41% of each customer class through December 2012, December 2013 and for the period January 2014 through May 2015, respectively.  All other capacity provided to CRES providers would be offered at $255/MW day.  In 2012, an additional amount of capacity may be made available at the $146/MW day rate to accommodate any community aggregation load above 21%, if applicable.

The resolution of the capacity rate is also the subject of separate proceedings before the PUCO and before the FERC.  In those proceedings, OPCo is seeking a wholesale cost-based capacity rate, currently at approximately $355/MW day.  Hearings on the capacity proceedings were held at the PUCO in April 2012.

The ESP also proposed to collect the PIRR from June 2013 through December 2018.  Further, the ESP proposed establishment of a non-bypassable Distribution Investment Rider through May 2015 to recover, with certain caps, post-August 2010 distribution investment.  The filing also seeks establishment of a new non-bypassable Retail Stability Rider (RSR) to recover lost generation revenues to provide financial certainty and stability during the ESP transition period.  The proposed RSR will be effective through May 2015.

Hearings on the June 2012 – May 2015 ESP are scheduled at the PUCO for May 2012 and oral arguments are scheduled for July 3, 2012, which would delay the proposed implementation of rates.

2011 Ohio Distribution Base Rate Case

In February 2011, OPCo filed with the PUCO for an annual increase in distribution rates of $94 million based upon an 11.15% return on common equity to be effective January 2012.  In December 2011, a stipulation was approved by the PUCO which provided for no change in distribution rates and a new rider for a $15 million annual credit to residential ratepayers due principally to the inclusion of the rate base distribution investment in the Distribution Investment Rider (DIR).

37

Due to the February 2012 PUCO order which rejected the modified stipulation, collection of the DIR terminated.  In March 2012, OPCo filed an application with the PUCO to approve an ESP for the period June 2012 through May 2015, which includes a request for a new DIR.  See the “Proposed June 2012 – May 2015 ESP” section above.  The June 2012 – May 2015 ESP proceeding is currently pending.  In March 2012, the PUCO issued an order clarifying that OPCo has the right to file a new distribution base rate case.  If OPCo is not ultimately permitted to fully recover its costs, it would reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

The PUCO selected an outside consultant to conduct the audit of the FAC for OPCo for the period of January 2009 through December 2009.  In May 2010, the outside consultant provided its audit report to the PUCO.  In January 2012, the PUCO ordered that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance.  Further, the January 2012 PUCO order stated that a consultant be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.  Management is unable to predict the outcome of the consultant’s recommendation.  In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges.  OPCo expects to record the favorable effect of the rehearing order of approximately $30 million in the second quarter of 2012.  If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultants’ review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

2010 and 2011 Fuel Adjustment Clause Audits

In May 2011, the PUCO-selected outside consultant issued its results of the 2010 FAC audit.  The audit report included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes.  The 2011 FAC audit is in progress and an audit report is expected to be issued in the second quarter of 2012.  As of March 31, 2012, the amount of OPCo’s carrying costs that could potentially be at risk due to the 2010 and 2011 audits is estimated to be approximately $32 million, including $17 million of unrecognized equity carrying costs.  Decisions from the PUCO are pending.  Management is unable to predict the outcome of these proceedings.  If PUCO orders result in a reduction in the carrying charges related to the FAC deferrals, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet.  This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009.  In March 2009, the PUCO approved a FAC in the ESP filing and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio.  The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record a regulatory asset for the difference between the approved market price and the rate paid by Ormet.  Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs.  In November 2009, OPCo requested that the PUCO approve recovery of the deferral under the interim agreement plus a weighted average cost of capital carrying charge.  The deferral amount is included in OPCo’s FAC phase-in deferral balance.  In the ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related regulatory asset and requested that the PUCO prevent OPCo from collecting the Ormet-related revenues in the future.  The PUCO did not take any action on this request in the 2009-2011 ESP proceeding.  The intervenors raised the issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.  This issue remains pending before the PUCO.  If OPCo is not ultimately permitted to fully recover its requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

38

Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  Through March 31, 2012, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order and has incurred pre-construction costs.  Intervenors have filed motions with the PUCO requesting all collected pre-construction costs be refunded to Ohio ratepayers with interest.

Management cannot predict the outcome of these proceedings concerning the Ohio IGCC plant or what effect, if any, these proceedings would have on future net income and cash flows.  However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is on target to be in service in the fourth quarter of 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.8 billion, excluding AFUDC, plus an additional $122 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $122 million for transmission, excluding AFUDC.  As of March 31, 2012, excluding costs attributable to its joint owners and a $49 million provision for a Texas capital costs cap, SWEPCo has capitalized approximately $1.5 billion of expenditures (including AFUDC and capitalized interest of $243 million for generation and related transmission costs of $110 million).  As of March 31, 2012, the joint owners and SWEPCo have contractual construction obligations of approximately $90 million (including related transmission costs of $6 million).  SWEPCo’s share of the contractual construction obligations is $67 million.

The PUCT approved a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers.  SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful.  The Texas Industrial Energy Consumers (TIEC) filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers.  In February 2010, the Texas District Court affirmed the PUCT’s order in all respects.  In November 2011, the Texas Court of Appeals affirmed the PUCT’s order in all respects.  Motions for rehearing at the Texas Court of Appeals were denied in January 2012.  In April 2012, SWEPCo and TIEC filed petitions for review at the Supreme Court of Texas.

If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.

APCo and WPCo Rate Matters

Virginia Fuel Filing

In April 2012, APCo filed an application with the Virginia SCC for an annual increase in fuel revenues of $117 million to be effective June 2012.  The filing included forecasted costs for the 15-month period ended August 2013 and requested recovery of APCo's anticipated unrecovered fuel balance as of May 2012 over a two-year period commencing in June 2012.  The non-incremental portion of APCo's forecasted and deferred wind purchased power costs are reflected in APCo's filing.  As of March 31, 2012, APCo’s under-recovered fuel balance and non-incremental wind purchased power costs of $84 million were recorded in Regulatory Assets on the balance sheet.  If the Virginia SCC were to disallow a portion of APCo’s deferred fuel costs, including any deferred wind purchased power costs, it would reduce future net income and cash flows.

39

Environmental Rate Adjustment Clause (RAC)

In November 2011, the Virginia SCC issued an order which approved APCo’s environmental RAC recovery of $30 million to be collected over one year beginning in February 2012 but denied recovery of certain environmental costs.  As a result, in the fourth quarter of 2011, APCo recorded a pretax write-off of $31 million on the statement of income related to environmental compliance costs incurred from January 2009 through December 2010.  In December 2011, APCo filed a notice of appeal with the Supreme Court of Virginia regarding the Virginia SCC’s environmental RAC decision.  If the Supreme Court of Virginia were to issue a favorable decision, it could increase future net income and cash flows.

APCo’s Filings for an IGCC Plant

Through March 31, 2012, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction.  APCo will not start construction of the IGCC plant until sufficient assurance of full cost recovery exists in Virginia and West Virginia.  If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs.  If the costs are not recoverable, it would reduce future net income and cash flows and impact financial condition.

APCo’s and WPCo’s Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation, which allows the WVPSC to establish a regulatory framework to securitize certain deferred ENEC balances.  Also in March 2012, APCo and WPCo filed their fourth year ENEC application with the WVPSC which requested no change in ENEC rates if the WVPSC issues a financing order allowing securitization of the under-recovered ENEC deferral.  The proposed rates consist of a Dresden Plant surcharge of $32 million and an increase in the construction surcharge of $2 million, offset by a reduction of $34 million in current ENEC rates.  APCo and WPCo anticipate filing, in the second quarter of 2012, a request for a financing order with the WVPSC pursuant to the securitization legislation.  If the financing order is not issued, APCo and WPCo requested recovery of these costs in current rates.  As of March 31, 2012, APCo’s ENEC under-recovery balance of $334 million was recorded in Regulatory Assets on the balance sheet, excluding $7 million of unrecognized equity carrying costs.  If the WVPSC were to disallow a portion of APCo’s and WPCo’s deferred ENEC costs, it could reduce future net income and cash flows and impact financial condition.

PSO Rate Matters

PSO 2008 Fuel and Purchased Power

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 the Oklahoma Industrial Energy Consumers (OIEC) recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of off-system sales margins decrease from 25% to 10%.  The OIEC 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 AEPEP was filed.  The testimony included unquantified refund recommendations relating to re-pricing of those ERCOT trading contracts.  Hearings were held in June 2011.  If the OCC were to issue an unfavorable decision, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

2011 Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on common equity of 11.15%.  The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.  Final hearings are currently scheduled for June 2012.

40

Life Cycle Management Project

In April 2012, I&M filed a petition with the IURC for approval of the Cook Plant Life Cycle Management Project (LCM Project).  The LCM Project consists of a group of capital projects that extend the operating lives of Unit 1 and 2 to 2034 and 2037, respectively, which is consistent with the recent extension of their operating licenses.  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  I&M requested recovery of certain project costs, including interest, through a rider effective 2013.  As of March 31, 2012, I&M has incurred $74 million related to the LCM Project.  If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

KPCo Rate Matters

Big Sandy Unit 2 FGD System

KPCo filed an application with the KPSC seeking approval of a Certificate of Public Convenience and Necessity to retrofit Big Sandy Unit 2 with a dry FGD system and to commence site construction activities on or about July 1, 2013.  KPCo also filed for approval of its 2011 environmental compliance plan and related surcharge tariff for construction of certain facilities associated with the plan.  The projected capital costs of the Big Sandy Unit 2 dry FGD system are approximately $955 million including certain preconstruction study costs and approximately $101 million of AFUDC.  If approved, recovery of the Big Sandy Unit 2 dry FGD system would begin two months following the projected in-service date of July 2016.  As of March 31, 2012, KPCo has incurred $25 million related to the project including $15 million associated with a previously studied wet FGD system.  In March 2012, intervenors filed testimony which opposed the project.  The Kentucky Industrial Utility Customers also opposed recovery of the costs associated with the wet FGD system study.  A decision is expected in second quarter of 2012.  If KPCo is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund

In 2004, AEP eliminated transaction-based through-and-out transmission service charges and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA through March 2006.  Intervenors objected and the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund.  The AEP East companies recognized gross SECA revenues of $220 million.  In 2006, a FERC Administrative Law Judge issued an initial decision finding that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.

AEP filed briefs jointly with other affected companies asking the FERC to reverse the decision.  In May 2010, the FERC issued an order that generally supported AEP’s position and required a compliance filing.  In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC.  If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million.  The AEP East companies could also potentially receive payments up to approximately $10 million including estimated interest of $3 million.  A decision is pending from the FERC.

The FERC has approved settlements applicable to $112 million of SECA revenue.  The AEP East companies provided reserves for net refunds for SECA settlements applicable to the remaining $108 million of SECA revenues collected.  Based on the analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the compliance filing be made final.  Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.

41

Possible Termination of the Interconnection Agreement

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC.  It is unknown at this time whether the Interconnection Agreement will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers, or if each company will choose to operate independently.  Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future.  If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

3.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

We are subject to certain claims and legal actions arising in our ordinary course of business.  In addition, our business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation against us cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on our financial statements.  The Commitments, Guarantees and Contingencies note within our 2011 Annual Report should be read in conjunction with this report.

GUARANTEES

We record liabilities for guarantees in accordance with the accounting guidance for “Guarantees.”  There is no collateral held in relation to any guarantees.  In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters of Credit

We enter into standby letters of credit with third parties.  As Parent, we issue all of these letters of credit in our ordinary course of business on behalf of our subsidiaries.  These letters of credit cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

We have two credit facilities totaling $3.25 billion, under which we may issue up to $1.35 billion as letters of credit.  As of March 31, 2012, the maximum future payments for letters of credit issued under the credit facilities were $189 million with maturities ranging from April 2012 to April 2013.

We have $402 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $407 million.  The letters of credit have maturities ranging from March 2013 to July 2014.

Guarantees of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $100 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  As of March 31, 2012, SWEPCo has collected approximately $54 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Other Current Liabilities and $38 million is recorded in Asset Retirement Obligations on our condensed balance sheets.

Sabine charges SWEPCo, its only customer, all of its costs.  SWEPCo passes these costs to customers through its fuel clause.

42

Indemnifications and Other Guarantees

Contracts

We enter into several types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, our exposure generally does not exceed the sale price.  The status of certain sale agreements is discussed in the 2011 Annual Report “Dispositions” section of Note 6.  As of March 31, 2012, there were no material liabilities recorded for any indemnifications.

Master Lease Agreements

We lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, we are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.  At March 31, 2012, the maximum potential loss for these lease agreements was approximately $15 million assuming the fair value of the equipment is zero at the end of the lease term.

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignments are accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $16 million and $18 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2012.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 84% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  The maximum potential losses related to the guarantee are approximately $12 million and $13 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, we believe that the fair value would produce a sufficient sales price to avoid any loss.

43

ENVIRONMENTAL CONTINGENCIES

Carbon Dioxide Public Nuisance Claims

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing.  An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision.  The petition was denied in January 2011.  Plaintiffs refiled their complaint in federal district court.  The court ordered all defendants to respond to the refiled complaints in October 2011.  In March 2012, the court granted the defendants’ motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations.  Plaintiffs appealed the decision to the Fifth Circuit Court of Appeals.  We will continue to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Alaskan Villages’ Claims

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  The plaintiffs appealed the decision.  The court heard oral argument in November 2011.  We believe the action is without merit and intend to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, our generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials.  We currently incur costs to dispose of these substances safely.

In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M started remediation work in accordance with a plan approved by MDEQ.  I&M’s provision is approximately $10 million.  As the remediation work is completed, I&M’s cost may continue to increase as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ.  We cannot predict the amount of additional cost, if any.

44

NUCLEAR CONTINGENCIES

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission.  We have a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S.  Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

Cook Plant Unit 1 Fire and Shutdown

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 are 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 cost approximately $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.  Due to the extensive lead time required to manufacture and install new turbine rotors, I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The installation of the new turbine rotors and other equipment occurred as planned during the fall 2011 refueling outage of Unit 1.

I&M maintains insurance through NEIL.  As of March 31, 2012, we recorded $64 million in Prepayments and Other Current Assets on our condensed balance sheets representing amounts under NEIL insurance policies.  Through March 31, 2012, I&M received payments from NEIL of $203 million for the cost incurred to date to repair the property damage and $185 million under an accidental outage policy.

The claims process with NEIL continues and includes a review of claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies, the timing of the unit’s return to service and whether the return should have occurred earlier reducing the amount received under the accidental outage policy.  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 reduce future net income and cash flows and impact financial condition.

OPERATIONAL CONTINGENCIES

Natural Gas Markets Lawsuits

In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity.  AEP was dismissed from the case.  A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies.  AEP (or a subsidiary) was among the companies named as defendants in some of these cases.  We settled, received summary judgment or were dismissed from all of these cases.  The plaintiffs appealed the dismissal of several cases involving AEP companies in Nevada to the Ninth Circuit Court of Appeals.  We will continue to defend the cases on appeal.  We believe the provision we have is adequate.  We believe the remaining exposure is immaterial.

45

4.  ACQUISITION AND DISPOSITION

ACQUISITION

2012

BlueStar Energy (Generation and Marketing segment)

In March 2012, we completed the acquisition of BlueStar Energy Holdings, Inc. (BlueStar) and its independent retail electric supplier BlueStar Energy Solutions for $70 million, subject to potential working capital adjustments.  This transaction also included goodwill of $14 million, intangible assets associated with sales contracts and customer accounts of $59 million and liabilities associated with supply contracts of $25 million.  These amounts are subject to revision once further evaluations are complete.  BlueStar provides electric supply for retail customers in Ohio, Illinois and other deregulated electricity markets and also provides energy solutions throughout the United States, including demand response and energy efficiency services.  BlueStar has been in operation since 2002 and has approximately 23,000 customer accounts.

DISPOSITION

2011

Electric Transmission Texas LLC (ETT) (Utility Operations segment)

During the three months ended March 31, 2011, TCC sold $5 million of transmission facilities to ETT.  There were no gains or losses recorded on these sale transactions.

5.  BENEFIT PLANS

Components of Net Periodic Benefit Cost

The following table provides the components of our net periodic benefit cost for the plans for the three months ended March 31, 2012 and 2011:

									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended March 31,								Three Months Ended March 31,
	2012				2011				2012				2011
	(in millions)
Service Cost		$	19			$	18			$	12			$	11
Interest Cost			56				59				26				27
Expected Return on Plan Assets			(80	)			(79	)			(25	)			(27	)
Amortization of Prior Service Credit			-				-				(5	)			-
Amortization of Net Actuarial Loss			37				30				14				7
Net Periodic Benefit Cost		$	32			$	28			$	22			$	18

46

6.  BUSINESS SEGMENTS

As outlined in our 2011 Annual Report, our primary business is the generation, transmission and distribution of electricity.  Within our Utility Operations segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

While our Utility Operations segment remains our primary business segment, the advancement of an area of our business prompted us to identify a new reportable segment.  Starting in the fourth quarter of 2011, we established our new Transmission Operations segment as described below:

Utility Operations

·   Generation of electricity for sale to U.S. retail and wholesale customers.

·   Transmission and distribution of electricity through assets owned and operated by our ten utility operating companies.

Transmission Operations

·   Development, construction and operation of transmission facilities through investments in our wholly-owned transmission subsidiaries that were established in 2009 and our transmission joint ventures.  These investments have PUCT-approved or FERC-approved returns on equity.

·   In April 2012, AEP and Great Plains Energy (Great Plains) formed Transource Energy LLC (Transource).  AEP and Great Plains own 86.5% and 13.5% of Transource, respectively.  Transource will initially pursue transmission power projects in PJM, SPP and MISO.

AEP River Operations

·   Commercial barging operations that transport coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.

Generation and Marketing

·   Nonregulated generation in ERCOT.

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

The remainder of our activities is presented as All Other.  While not considered a reportable segment, All Other includes:

·   Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

·   Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.  These contracts were financial derivatives which settled and expired in the fourth quarter of 2011.

·   Revenue sharing related to the Plaquemine Cogeneration Facility which ended in the fourth quarter of 2011.

47

The tables below present our reportable segment information for the three months ended March 31, 2012 and 2011 and balance sheet information as of March 31, 2012 and December 31, 2011.  These amounts include certain estimates and allocations where necessary.  We reclassified prior year amounts to conform to the current year’s presentation.

						Nonutility Operations
								Generation
		Utility		Transmission		AEP River		and		All Other		Reconciling
		Operations		Operations		Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Three Months Ended March 31, 2012
Revenues from:
	External Customers	$	3,362	$	1	$	172	$	85	$	5	$	-	$	3,625
	Other Operating Segments		23		2		7		-		2		(34)		-
Total Revenues		$	3,385	$	3	$	179	$	85	$	7	$	(34)	$	3,625
Net Income (Loss)		$	384	$	9	$	9	$	(1)	$	(11)	$	-	$	390

						Nonutility Operations
								Generation
		Utility		Transmission		AEP River		and		All Other		Reconciling
		Operations		Operations		Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Three Months Ended March 31, 2011
Revenues from:
	External Customers	$	3,497	$	-	$	167	$	62	$	4	$	-	$	3,730
	Other Operating Segments		27		-		5		1		1		(34)		-
Total Revenues		$	3,524	$	-	$	172	$	63	$	5	$	(34)	$	3,730
Net Income (Loss)		$	374	$	4	$	7	$	1	$	(31)	$	-	$	355

						Nonutility Operations
								Generation				Reconciling
		Utility		Transmission		AEP River		and		All Other		Adjustments
		Operations		Operations		Operations		Marketing		(a)		(b)			Consolidated
		(in millions)
March 31, 2012
Total Property, Plant and Equipment		$	54,839	$	410	$	612	$	617	$	11	$	(266)		$	56,223
Accumulated Depreciation and
	Amortization		18,474		1		143		225		10		(62)			18,791
Total Property, Plant and Equipment - Net		$	36,365	$	409	$	469	$	392	$	1	$	(204)		$	37,432
Total Assets		$	50,581	$	727	$	657	$	1,012	$	16,397	$	(16,472)	(c)	$	52,902

48

						Nonutility Operations
								Generation				Reconciling
		Utility		Transmission		AEP River		and		All Other		Adjustments
		Operations		Operations		Operations		Marketing		(a)		(b)			Consolidated
		(in millions)
December 31, 2011
Total Property, Plant and Equipment		$	54,396	$	323	$	608	$	590	$	11	$	(258)		$	55,670
Accumulated Depreciation and
	Amortization		18,393		-		136		219		10		(59)			18,699
Total Property, Plant and Equipment - Net		$	36,003	$	323	$	472	$	371	$	1	$	(199)		$	36,971
Total Assets		$	50,093	$	594	$	659	$	868	$	16,751	$	(16,742)	(c)	$	52,223

(a) All Other includes:

·   Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

·   Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.  These contracts were financial derivatives which settled and expired in the fourth quarter of 2011.

·   Revenue sharing related to the Plaquemine Cogeneration Facilitywhich ended in the fourth quarter of 2011.

(b) Includes eliminations due to an intercompany capital lease.

(c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies.

7.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

We are exposed to certain market risks as a major power producer and marketer of wholesale electricity, coal and emission allowances.  These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.  We manage these risks using derivative instruments.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Trading Strategies

Our strategy surrounding the use of derivative instruments for trading purposes focuses on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact.

Risk Management Strategies

Our strategy surrounding the use of derivative instruments focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  To accomplish our objectives, we primarily employ risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments.  Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.”  Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

We enter into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business.  We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio.  For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities.  We also engage in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies.  For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.”  The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.

49

The following table represents the gross notional volume of our outstanding derivative contracts as of March 31, 2012 and December 31, 2011:

Notional Volume of Derivative Instruments
	Volume
	March 31,			December 31,			Unit of
	2012			2011			Measure
Primary Risk Exposure	(in millions)
Commodity:
Power			524			609	MWHs
Coal			19			21	Tons
Natural Gas			113			100	MMBtus
Heating Oil and Gasoline			4			6	Gallons
Interest Rate		$	202		$	226	USD
Interest Rate and Foreign Currency		$	803		$	907	USD

Fair Value Hedging Strategies

We enter into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt.  Certain interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate.  Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.

Cash Flow Hedging Strategies

We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities.  We monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases.  We do not hedge all commodity price risk.

Our vehicle fleet and barge operations are exposed to gasoline and diesel fuel price volatility.  We enter into financial heating oil and gasoline derivative contracts in order to mitigate price risk of our future fuel purchases.  For disclosure purposes, these contracts are included with other hedging activities as “Commodity.”  We do not hedge all fuel price risk.

We enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure.  Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate.  We also enter into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt.  Our forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures.  We do not hedge all interest rate exposure.

At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers.  In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar.  We do not hedge all foreign currency exposure.

50

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheets at fair value.  The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes.  If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions.  In order to determine the relevant fair values of our derivative instruments, we also apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due.  Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions.  Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts.  Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles.  Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with our estimates of current market consensus for forward prices in the current period.  This is particularly true for longer term contracts.  Cash flows may vary based on market conditions, margin requirements and the timing of settlement of our risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the March 31, 2012 and December 31, 2011 balance sheets, we netted $24 million and $26 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $109 million and $133 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

51

The following tables represent the gross fair value impact of our derivative activity on our condensed balance sheets as of March 31, 2012 and December 31, 2011:

Fair Value of Derivative Instruments
March 31, 2012
	Risk Management
	Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location	Commodity (a)		Commodity (a)			Currency (a)			Other (b)			Total
	(in millions)
Current Risk Management Assets	$	1,298	$	41		$	1		$	(1,094	)	$	246
Long-term Risk Management Assets		758		21			-			(354	)		425
Total Assets		2,056		62			1			(1,448	)		671
Current Risk Management Liabilities		1,275		63			13			(1,166	)		185
Long-term Risk Management Liabilities		604		25			2			(392	)		239
Total Liabilities		1,879		88			15			(1,558	)		424
Total MTM Derivative Contract Net Assets
(Liabilities)	$	177	$	(26	)	$	(14	)	$	110		$	247

Fair Value of Derivative Instruments
December 31, 2011
	Risk Management
	Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location	Commodity (a)		Commodity (a)			Currency (a)			Other (b)			Total
	(in millions)
Current Risk Management Assets	$	852	$	24		$	-		$	(683	)	$	193
Long-term Risk Management Assets		641		15			-			(253	)		403
Total Assets		1,493		39			-			(936	)		596
Current Risk Management Liabilities		847		29			20			(746	)		150
Long-term Risk Management Liabilities		483		15			22			(325	)		195
Total Liabilities		1,330		44			42			(1,071	)		345
Total MTM Derivative Contract Net Assets
(Liabilities)	$	163	$	(5	)	$	(42	)	$	135		$	251

(a) Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."

(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."  Amounts also include de-designated risk management contracts.

52

The tables below present our activity of derivative risk management contracts for the three months ended March 31, 2012 and 2011:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended March 31, 2012 and 2011
Location of Gain (Loss)	2012			2011
	(in millions)
Utility Operations Revenues	$	10		$	20
Other Revenues		3			2
Regulatory Assets (a)		(21	)		2
Regulatory Liabilities (a)		14			8
Total Gain on Risk Management Contracts	$	6		$	32

(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.”  Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis.

Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship.  Depending on the exposure, we designate a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes.  Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income.  Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances.  However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

Accounting for Fair Value Hedging Strategies

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change.

We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our condensed statements of income.  During the three months ended March 31, 2012 and 2011, we recognized gains of $1 million and $4 million, respectively, on our hedging instruments and offsetting losses of $1 million and $4 million, respectively,on our long-term debt.  During the three months ended March 31, 2012 and 2011, hedge ineffectiveness was immaterial.

53

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets until the period the hedged item affects Net Income.  We recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on our condensed balance sheets, depending on the specific nature of the risk being hedged.  During the three months ended March 31, 2012 and 2011, we designated power, coal and natural gas derivatives as cash flow hedges.

We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our condensed statements of income.  During the three months ended March 31, 2012 and 2011, we designated heating oil and gasoline derivatives as cash flow hedges.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Interest Expense on our condensed statements of income in those periods in which hedged interest payments occur.  During the three months ended March 31, 2012 and 2011, we designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Depreciation and Amortization expense on our condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.  During the three months ended March 31, 2012 and 2011, we designated foreign currency derivatives as cash flow hedges.

During the three months ended March 31, 2012 and 2011, hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies disclosed above.

54

The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets and the reasons for changes in cash flow hedges for the three months ended March 31, 2012 and 2011.  All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended March 31, 2012
				Interest Rate
				and Foreign
	Commodity			Currency			Total
	(in millions)
Balance in AOCI as of December 31, 2011	$	(3	)	$	(20	)	$	(23	)
Changes in Fair Value Recognized in AOCI		(20	)		1			(19	)
Amount of (Gain) or Loss Reclassified from AOCI
to Statement of Income/within Balance Sheet:
Utility Operations Revenues		-			-			-
Other Revenues		(1	)		-			(1	)
Purchased Electricity for Resale		7			-			7
Interest Expense		-			1			1
Regulatory Assets (a)		1			-			1
Regulatory Liabilities (a)		-			-			-
Balance in AOCI as of March 31, 2012	$	(16	)	$	(18	)	$	(34	)

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended March 31, 2011
				Interest Rate
				and Foreign
	Commodity			Currency			Total
	(in millions)
Balance in AOCI as of December 31, 2010	$	7		$	4		$	11
Changes in Fair Value Recognized in AOCI		2			(1	)		1
Amount of (Gain) or Loss Reclassified from AOCI
to Statement of Income/within Balance Sheet:
Utility Operations Revenues		-			-			-
Other Revenues		(1	)		-			(1	)
Purchased Electricity for Resale		-			-			-
Interest Expense		-			1			1
Regulatory Assets (a)		-			-			-
Regulatory Liabilities (a)		-			-			-
Balance in AOCI as of March 31, 2011	$	8		$	4		$	12

(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.

55

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets at March 31, 2012 and December 31, 2011 were:

Impact of Cash Flow Hedges on the Condensed Balance Sheet
March 31, 2012
				Interest Rate
				and Foreign
	Commodity			Currency			Total
	(in millions)
Hedging Assets (a)	$	29		$	-		$	29
Hedging Liabilities (a)		55			15			70
AOCI Gain (Loss) Net of Tax		(16	)		(18	)		(34	)
Portion Expected to be Reclassified to Net
Income During the Next Twelve Months		(14	)		(3	)		(17	)

Impact of Cash Flow Hedges on the Condensed Balance Sheet
December 31, 2011
				Interest Rate
				and Foreign
	Commodity			Currency			Total
	(in millions)
Hedging Assets (a)	$	20		$	-		$	20
Hedging Liabilities (a)		25			42			67
AOCI Gain (Loss) Net of Tax		(3	)		(20	)		(23	)
Portion Expected to be Reclassified to Net
Income During the Next Twelve Months		(3	)		(2	)		(5	)

(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.

The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.  As of March 31, 2012, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions is 42 months.

Credit Risk

We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  We use Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

We use standardized master agreements which may include collateral requirements.  These master agreements facilitate the netting of cash flows associated with a single counterparty.  Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk.  The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold.  The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy.  In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.

56

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, we are obligated to post an additional amount of collateral if our credit ratings decline below investment grade.The amount of collateral required fluctuates based on market prices and our total exposure.  On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts.  AEP and its subsidiaries have not experienced a downgrade below investment grade.  The following table represents: (a) our aggregate fair value of such derivative contracts, (b) the amount of collateral we would have been required to post for all derivative and non-derivative contracts if our credit ratings had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of March 31, 2012 and December 31, 2011:

		March 31,		December 31,
		2012		2011
		(in millions)
Liabilities for Derivative Contracts with Credit Downgrade Triggers		$	21	$	32
Amount of Collateral AEP Subsidiaries Would Have Been
	Required to Post		50		39
Amount Attributable to RTO and ISO Activities			48		38

In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million.  On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts.  The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of March 31, 2012 and December 31, 2011:

	March 31,		December 31,
	2012		2011
	(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual
Netting Arrangements	$	716	$	515
Amount of Cash Collateral Posted		2		56
Additional Settlement Liability if Cross Default Provision is Triggered		354		291

8.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

57

For our commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated.  We typically obtain multiple broker quotes, which are non-binding in nature, but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, we average the quoted bid and ask prices.  In certain circumstances, we may discard a broker quote if it is a clear outlier.  We use a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated, we include these locations within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.  The main driver of our contracts being classified as Level 3 is the inability to substantiate our energy price curves in the market.   To a lesser extent, these contracts could be sensitive to volumetric estimates for some structured transactions.  However, a significant portion of our Level 3 volumetric contractual positions have been economically hedged which greatly limits potential earnings volatility.

We utilize our trustee’s external pricing service in our estimate of the fair value of the underlying investments held in the nuclear trusts.  Our investment managers review and validate the prices utilized by the trustee to determine fair value.  We perform our own valuation testing to verify the fair values of the securities.  We receive audit reports of our trustee’s operating controls and valuation processes.  The trustee uses multiple pricing vendors for the assets held in the trusts.

Assets in the nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds.  Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

Fair Value Measurements of Long-term Debt

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange.

The book values and fair values of Long-term Debt as of March 31, 2012 and December 31, 2011 are summarized in the following table:

	March 31, 2012				December 31, 2011
	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
Long-term Debt	$	17,320	$	19,533	$	16,516	$	19,259

58

Fair Value Measurements of Other Temporary Investments

Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds, marketable securities that we intend to hold for less than one year and investments by our protected cell of EIS.

The following is a summary of Other Temporary Investments:

			March 31, 2012
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
Other Temporary Investments			Cost		Gains		Losses		Value
			(in millions)
Restricted Cash (a)			$	137	$	-	$	-	$	137
Fixed Income Securities:
	Mutual Funds			64		-		-		64
Equity Securities - Mutual Funds				11		5		-		16
Total Other Temporary Investments			$	212	$	5	$	-	$	217
			December 31, 2011
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
Other Temporary Investments			Cost		Gains		Losses		Value
			(in millions)
Restricted Cash (a)			$	216	$	-	$	-	$	216
Fixed Income Securities:
	Mutual Funds			64		-		-		64
Equity Securities - Mutual Funds				11		3		-		14
Total Other Temporary Investments			$	291	$	3	$	-	$	294
(a)		Primarily represents amounts held for the repayment of debt.

The following table provides the activity for our debt and equity securities within Other Temporary Investments for the three months ended March 31, 2012 and 2011:

	Three Months Ended March 31,
	2012			2011
	(in millions)
Proceeds from Investment Sales		$	-		$	196
Purchases of Investments			-			148
Gross Realized Gains on Investment Sales			-			-
Gross Realized Losses on Investment Sales			-			-

At March 31, 2012 and December 31, 2011, we had no Other Temporary Investments with an unrealized loss position.  At March 31, 2012, fixed income securities are primarily debt based mutual funds with short and intermediate maturities.  Mutual funds may be sold and do not contain maturity dates.

59

The following table provides details of Other Temporary Investments included in Accumulated Other Comprehensive Income (Loss) on our balance sheet and the reasons for changes for the three months ended March 31, 2012.  All amounts in the following table are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Other Temporary Investments
Three Months Ended March 31, 2012
	(in millions)
Balance in AOCI as of December 31, 2011		$	2
Changes in Fair Value Recognized in AOCI			2
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income:
Interest Income			-
Balance in AOCI as of March 31, 2012		$	4

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

·   Acceptable investments (rated investment grade or above when purchased).

·   Maximum percentage invested in a specific type of investment.

·   Prohibition of investment in obligations of AEP or its affiliates.

·   Withdrawals permitted only for payment of decommissioning costs and trust expenses.

We maintain trust records for each regulatory jurisdiction.  These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities.  The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value.  I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose.  Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the equity and debt investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized gains and other-than-temporary impairments from securities in the trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.  The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities.  Regulatory approval is required to withdraw decommissioning funds.

60

The following is a summary of nuclear trust fund investments at March 31, 2012 and December 31, 2011:

		March 31, 2012						December 31, 2011
		Estimated		Gross		Other-Than-		Estimated		Gross		Other-Than-
		Fair		Unrealized		Temporary		Fair		Unrealized		Temporary
		Value		Gains		Impairments		Value		Gains		Impairments
		(in millions)
Cash and Cash Equivalents		$	19	$	-	$	-	$	18	$	-	$	-
Fixed Income Securities:
	United States Government		548		49		(1)		544		61		(1)
	Corporate Debt		52		5		(1)		54		5		(2)
	State and Local Government		323		-		(1)		330		-		(2)
	Subtotal Fixed Income Securities		923		54		(3)		928		66		(5)
Equity Securities - Domestic			720		286		(80)		646		215		(80)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,662	$	340	$	(83)	$	1,592	$	281	$	(85)

The following table provides the securities activity within the decommissioning and SNF trusts for the three months ended March 31, 2012 and 2011:

	Three Months Ended March 31,
	2012		2011
	(in millions)
Proceeds from Investment Sales	$	334	$	288
Purchases of Investments		353		306
Gross Realized Gains on Investment Sales		2		5
Gross Realized Losses on Investment Sales		1		5

The adjusted cost of debt securities was $869 million and $862 million as of March 31, 2012 and December 31, 2011, respectively.  The adjusted cost of equity securities was $434 million and $431 million as of March 31, 2012 and December 31, 2011, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at March 31, 2012 was as follows:

	Fair Value
	of Debt
	Securities
	(in millions)
Within 1 year		$	39
1 year – 5 years			322
5 years – 10 years			341
After 10 years			221
Total		$	923

61

Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 and December 31, 2011.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in our valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2012
			Level 1		Level 2		Level 3		Other		Total
Assets:			(in millions)
Cash and Cash Equivalents (a)			$	24	$	-	$	-	$	262	$	286
Other Temporary Investments
Restricted Cash (a)				109		-		-		28		137
Fixed Income Securities:
	Mutual Funds			64		-		-		-		64
Equity Securities - Mutual Funds (b)				16		-		-		-		16
Total Other Temporary Investments				189		-		-		28		217
Risk Management Assets
Risk Management Commodity Contracts (c) (f)				61		1,821		169		(1,435)		616
Cash Flow Hedges:
	Commodity Hedges (c)			17		43		1		(32)		29
Fair Value Hedges				-		1		-		-		1
De-designated Risk Management Contracts (d)				-		-		-		25		25
Total Risk Management Assets				78		1,865		170		(1,442)		671
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)				-		10		-		9		19
Fixed Income Securities:
	United States Government			-		548		-		-		548
	Corporate Debt			-		52		-		-		52
	State and Local Government			-		323		-		-		323
		Subtotal Fixed Income Securities		-		923		-		-		923
Equity Securities - Domestic (b)				720		-		-		-		720
Total Spent Nuclear Fuel and Decommissioning Trusts				720		933		-		9		1,662
Total Assets			$	1,011	$	2,798	$	170	$	(1,143)	$	2,836
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)			$	53	$	1,743	$	78	$	(1,520)	$	354
Cash Flow Hedges:
	Commodity Hedges (c)			-		87		-		(32)		55
	Interest Rate/Foreign Currency Hedges			-		15		-		-		15
Total Risk Management Liabilities			$	53	$	1,845	$	78	$	(1,552)	$	424

62

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2011
			Level 1		Level 2		Level 3		Other		Total
Assets:			(in millions)
Cash and Cash Equivalents (a)			$	6	$	-	$	-	$	215	$	221
Other Temporary Investments
Restricted Cash (a)				191		-		-		25		216
Fixed Income Securities:
	Mutual Funds			64		-		-		-		64
Equity Securities - Mutual Funds (b)				14		-		-		-		14
Total Other Temporary Investments				269		-		-		25		294
Risk Management Assets
Risk Management Commodity Contracts (c) (g)				47		1,299		147		(945)		548
Cash Flow Hedges:
	Commodity Hedges (c)			15		23		-		(18)		20
De-designated Risk Management Contracts (d)				-		-		-		28		28
Total Risk Management Assets				62		1,322		147		(935)		596
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)				-		5		-		13		18
Fixed Income Securities:
	United States Government			-		544		-		-		544
	Corporate Debt			-		54		-		-		54
	State and Local Government			-		330		-		-		330
		Subtotal Fixed Income Securities		-		928		-		-		928
Equity Securities - Domestic (b)				646		-		-		-		646
Total Spent Nuclear Fuel and Decommissioning Trusts				646		933		-		13		1,592
Total Assets			$	983	$	2,255	$	147	$	(682)	$	2,703
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)			$	43	$	1,209	$	78	$	(1,052)	$	278
Cash Flow Hedges:
	Commodity Hedges (c)			-		43		-		(18)		25
	Interest Rate/Foreign Currency Hedges			-		42		-		-		42
Total Risk Management Liabilities			$	43	$	1,294	$	78	$	(1,070)	$	345

(a) Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties.  Level 1 amounts primarily represent investments in money market funds.

(b) Amounts represent publicly traded equity securities and equity-based mutual funds.

(c) Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.''

(d) Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for ''Derivatives and Hedging.''  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This MTM value will be amortized into revenues over the remaining life of the contracts.

(e) Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions.  Level 2 amounts primarily represent investments in money market funds.

(f) The March 31, 2012 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $3 million in 2012, $12 million in periods 2013-2015 and ($7) million in periods 2016-2018;  Level 2 matures $4 million in 2012, $49 million in periods 2013-2015, $18 million in periods 2016-2017 and $7 million in periods 2018-2030;  Level 3 matures $3 million in 2012, $46 million in periods 2013-2015, $18 million in periods 2016-2017 and $24 million in periods 2018-2030.  Risk management commodity contracts are substantially comprised of power contracts.

63

(g) The December 31, 2011 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $3 million in 2012, $7 million in periods 2013-2015 and ($6) million in periods 2016-2018;  Level 2 matures $21 million in 2012, $50 million in periods 2013-2015, $11 million in periods 2016-2017 and $8 million in periods 2018-2030;  Level 3 matures ($19) million in 2012, $44 million in periods 2013-2015, $18 million in periods 2016-2017 and $26 million in periods 2018-2030.  Risk management commodity contracts are substantially comprised of power contracts.

There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2012 and 2011.

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as Level 3 in the fair value hierarchy:

		Net Risk Management
Three Months Ended March 31, 2012		Assets (Liabilities)
		(in millions)
Balance as of December 31, 2011		$	69
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)			(12)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		3
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			1
Purchases, Issuances and Settlements (c)			16
Transfers into Level 3 (d) (f)			17
Transfers out of Level 3 (e) (f)			(12)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			10
Balance as of March 31, 2012		$	92

		Net Risk Management
Three Months Ended March 31, 2011		Assets (Liabilities)
		(in millions)
Balance as of December 31, 2010		$	85
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)			(2)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		(4)
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			-
Purchases, Issuances and Settlements (c)			(8)
Transfers into Level 3 (d) (f)			-
Transfers out of Level 3 (e) (f)			(8)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			10
Balance as of March 31, 2011		$	73

(a) Included in revenues on our condensed statements of income.

(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.

(c) Represents the settlement of risk management commodity contracts for the reporting period.

(d) Represents existing assets or liabilities that were previously categorized as Level 2.

(e) Represents existing assets or liabilities that were previously categorized as Level 3.

(f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

(g) Relates to the net gains (losses) of those contracts that are not reflected on our condensed statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets.

64

9.  INCOME TAXES

AEP System Tax Allocation Agreement

We, along with our subsidiaries, file a consolidated federal income tax return.  The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense.  The tax benefit of the Parent is allocated to our subsidiaries with taxable income.  With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Federal and State Income Tax Audit Status

We are no longer subject to U.S. federal examination for years before 2009.  We completed the examination of the years 2007 and 2008 in April 2011 and settled all outstanding issues on appeal for the years 2001 through 2006 in October 2011.  The settlements did not have a material impact on net income, cash flows or financial condition.  The IRS examination of years 2009 and 2010 started in October 2011.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, we accrue interest on these uncertain tax positions.  We are not aware of any issues for open tax years that upon final resolution are expected to impact net income.

We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions.  These taxing authorities routinely examine our tax returns and we are currently under examination in several state and local jurisdictions.  We believe that we have filed tax returns with positions that may be challenged by these tax authorities.  Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and the ultimate resolution of these audits will not materially impact net income.  With few exceptions, we are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2000.  In March 2012, AEP settled all outstanding franchise tax issues with the state of Ohio for the years 2000 through 2009.  The settlements did not have a material impact on net income, cash flows or financial condition.

10.  FINANCING ACTIVITIES

Long-term Debt

Type of Debt	March 31, 2012		December 31, 2011
	(in millions)
Senior Unsecured Notes	$	11,862	$	11,737
Pollution Control Bonds		2,062		2,112
Notes Payable		428		402
Securitization Bonds		2,389		1,688
Junior Subordinated Debentures		315		315
Spent Nuclear Fuel Obligation (a)		265		265
Other Long-term Debt		31		29
Fair Value of Interest Rate Hedges		7		7
Unamortized Discount, Net		(39)		(39)
Total Long-term Debt Outstanding		17,320		16,516
Long-term Debt Due Within One Year		1,980		1,433
Long-term Debt	$	15,340	$	15,083

(a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal.  The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983.  Trust fund assets related to this obligation were $308 million at both March 31, 2012 and December 31, 2011 and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets.

65

Long-term debt and other securities issued, retired and principal payments made during the first three months of 2012 are shown in the tables below:

			Principal			Interest
Company	Type of Debt		Amount			Rate	Due Date
Issuances:		(in millions)				(%)
PSO	Notes Payable		$	2		3.00	2027
SWEPCo	Senior Unsecured Notes			275		3.55	2022
SWEPCo	Notes Payable			65		4.58	2032
Non-Registrant:
TCC	Securitization Bonds			312		2.845	2024
TCC	Securitization Bonds			308		0.88	2017
TCC	Securitization Bonds			180		1.976	2020
Total Issuances			$	1,142	(a)

(a) Amount indicated on the statement of cash flows of $1,132 million is net of issuance costs and premium or discount.

				Principal		Interest
Company		Type of Debt		Amount Paid		Rate		Due Date
Retirements and			(in millions)			(%)
	Principal Payments:						��
APCo		Pollution Control Bonds		$	30	6.05		2024
APCo		Pollution Control Bonds			20	5.00		2021
I&M		Notes Payable			6	Variable		2016
I&M		Notes Payable			4	2.12		2016
I&M		Notes Payable			6	Variable		2015
OPCo		Senior Unsecured Notes			150	Variable		2012
SWEPCo		Notes Payable			20	7.03		2012
Non-Registrant:
AEP Subsidiaries		Notes Payable			4	Variable		2017
AEP Subsidiaries		Notes Payable			1	7.59-8.03		2026
TCC		Securitization Bonds			63	4.98		2013
TCC		Securitization Bonds			35	5.96		2013
Total Retirements and
	Principal Payments			$	339

In April 2012, I&M retired $26 million of Notes Payable and issued $110 million of variable rate Notes Payable related to DCC Fuel.

In April 2012, AEGCo retired $4 million of 6.33% Senior Unsecured Notes due in 2037.

As of March 31, 2012, trustees held, on our behalf, $478 million of our reacquired Pollution Control Bonds.

Dividend Restrictions

Parent Restrictions

The holders of our common stock are entitled to receive the dividends declared by our Board of Directors provided funds are legally available for such dividends.  Our income derives from our common stock equity in the earnings of our utility subsidiaries.

66

Pursuant to the leverage restrictions in our credit agreements, we must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.  The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend.  The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements.  None of AEP’s retained earnings were restricted for the purpose of the payment of dividends.

We have issued $315 million of Junior Subordinated Debentures.  The debentures will mature on March 1, 2063, subject to extensions to no later than March 1, 2068, and are callable at par any time on or after March 1, 2013.  We have the option to defer interest payments on the debentures for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire our common stock.  We do not anticipate any deferral of those interest payments in the foreseeable future.

Utility Subsidiaries’ Restrictions

Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.  Specifically, several of our public utility subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%.

The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.”  The term “capital account” is not defined in the Federal Power Act or its regulations.  Management understands “capital account” to mean the value of the common stock.  This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings.

Short-term Debt

Our outstanding short-term debt was as follows:

	March 31, 2012				December 31, 2011
	Outstanding		Interest		Outstanding		Interest
Type of Debt	Amount		Rate (a)		Amount		Rate (a)
	(in millions)				(in millions)
Securitized Debt for Receivables (b)	$	665	0.26	%	$	666	0.27	%
Commercial Paper		385	0.46	%		967	0.51	%
Line of Credit – Sabine (c)		-	-	%		17	1.79	%
Total Short-term Debt	$	1,050			$	1,650

(a) Weighted average rate.

(b) Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance.

(c) This line of credit does not reduce available liquidity under AEP's credit facilities.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 3.

Securitized Accounts Receivable – AEP Credit

AEP Credit has a receivables securitization agreement with bank conduits.  Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries.  AEP Credit continues to service the receivables.  These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables and accelerate AEP Credit’s cash collections.

67

Accounts receivable information for AEP Credit is as follows:

	Three Months Ended
	March 31,
	2012			2011
	(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable		0.26	%		0.31	%
Net Uncollectible Accounts Receivable Written Off	$	8		$	11

		March 31,		December 31,
		2012		2011
		(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
	Less Uncollectible Accounts	$	877	$	902
Total Principal Outstanding			665		666
Delinquent Securitized Accounts Receivable			36		38
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable			19		18
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable			323		370

Customer accounts receivable retained and securitized for our operating companies are managed by AEP Credit.  AEP Credit’s delinquent customer accounts receivable represents accounts greater than 30 days past due.

68

APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

69

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Possible Termination of the Interconnection Agreement

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC.  It is unknown at this time whether the Interconnection Agreement will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.  Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future.  If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

Regulatory Activity

West Virginia Regulatory Activity

In March 2012, West Virginia passed securitization legislation, which allows the WVPSC to establish a regulatory framework to securitize certain deferred ENEC balances.  APCo and WPCo anticipate filing, in the second quarter of 2012, a request for a financing order with the WVPSC pursuant to the securitization legislation.  As of March 31, 2012, APCo’s ENEC under-recovery balance of $334 million was recorded in Regulatory Assets on the balance sheet.  See “APCo’s Expanded Net Energy Charge (ENEC) Filing” section of Note 2.

In a November 2009 proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division.  The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources.  Merger approvals from the WVPSC, the Virginia SCC and the FERC are required.  In December 2011 and February 2012, APCo and WPCo filed merger applications with the WVPSC and the FERC, respectively.  In February 2012, APCo and WPCo withdrew their merger application with the FERC.  In March 2012, the WVPSC granted APCo’s and WPCo’s request to hold the pending merger docket open for ninety days to enable filings before other commissions to proceed.  Management intends to refile with the FERC and also file with the Virginia SCC in the future.  See “WPCo Merger with APCo” section of Note 2.

Litigation and Environmental Issues

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report.  Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 128.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 175 for additional discussion of relevant factors.

70

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales
		Three Months Ended March 31,
		2012		2011
		(in millions of KWHs)
Retail:
	Residential		3,450		3,959
	Commercial		1,626		1,698
	Industrial		2,604		2,619
	Miscellaneous		202		210
Total Retail			7,882		8,486
Wholesale			1,381		1,827
Total KWHs			9,263		10,313

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

Summary of Heating and Cooling Degree Days
		Three Months Ended March 31,
		2012		2011
		(in degree days)
Actual - Heating (a)			921		1,330
Normal - Heating (b)			1,343		1,337
Actual - Cooling (c)			26		6
Normal - Cooling (b)			6		6
(a)	Eastern Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Eastern Region cooling degree days are calculated on a 65 degree temperature base.

71

First Quarter of 2012 Compared to First Quarter of 2011

Reconciliation of First Quarter of 2011 to First Quarter of 2012
Net Income
(in millions)
First Quarter of 2011	$	39
Changes in Gross Margin:
Retail Margins		42
Off-system Sales		(3)
Transmission Revenues		2
Other Revenues		(2)
Total Change in Gross Margin		39
Changes in Expenses and Other:
Other Operation and Maintenance		25
Depreciation and Amortization		(11)
Carrying Costs Income		3
Interest Expense		2
Total Change in Expenses and Other		19
Income Tax Expense		(22)
First Quarter of 2012	$	75

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail Margins increased $42 million primarily due to the following:
	·	A $25 million increase due to lower capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia.
	·	A $22 million increase due to higher base rates in Virginia and West Virginia.
	·	A $15 million increase in other variable electric generation expenses.
	These increases were partially offset by:
	·	A $17 million decrease in residential and commercial margins primarily due to lower non-weather related usage.
	·	A $13 million decrease in weather-related usage primarily due to a 33% decrease in heating degree days.
·	Margins from Off-system Sales decreased $3 million primarily due to lower physical sales volumes and lower trading and marketing margins.

72

Expenses and Other and Income Tax Expense changed between years as follows:

·	Other Operation and Maintenance expenses decreased$25 million primarily due to the following:
	·	A $41 million decrease due to the first quarter 2011 write-off of a portion of the West Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC in March 2011.
	·	An $8 million decrease due to recording an increase in under-recovery of transmission costs for the Virginia Transmission Rate Adjustment Clause.
	These decreases were partially offset by:
	·	A $32 million increase due to the first quarter 2011 deferral of 2009 costs related to storms and the 2010 cost reduction initiatives as allowed by the WVPSC in 2011.
·	Depreciation and Amortization expenses increased $11 million primarily due to:
	·	A $6 million increase in depreciation as a result of an increase in depreciation rates in Virginia effective February 1, 2012.
	·	A $5 million increase in amortization mainly due to current year amortization as a result of the Virginia E&R surcharge and the Virginia Environmental Rate Adjustment Clause, both effective February 2012.
·	Carrying Costs Income increased $3 million primarily due to carrying charges on the Dresden Plant resulting from the Virginia Generation Rate Adjustment Clause and the West Virginia Expanded Net Energy Charge.
·	Income Tax Expense increased $22 million primarily due to an increase in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2011 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 175 for a discussion of accounting pronouncements.

73

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
	2012		2011
REVENUES
Electric Generation, Transmission and Distribution	$	738,599	$	751,012
Sales to AEP Affiliates		64,301		78,691
Other Revenues		2,576		2,117
TOTAL REVENUES		805,476		831,820
EXPENSES
Fuel and Other Consumables Used for Electric Generation		186,884		180,581
Purchased Electricity for Resale		65,356		69,218
Purchased Electricity from AEP Affiliates		156,017		224,189
Other Operation		74,319		113,276
Maintenance		46,335		32,293
Depreciation and Amortization		80,413		69,099
Taxes Other Than Income Taxes		26,962		27,103
TOTAL EXPENSES		636,286		715,759
OPERATING INCOME		169,190		116,061
Other Income (Expense):
Interest Income		343		320
Carrying Costs Income		7,785		3,439
Allowance for Equity Funds Used During Construction		513		883
Interest Expense		(51,307)		(52,939)
INCOME BEFORE INCOME TAX EXPENSE		126,524		67,764
Income Tax Expense		51,213		28,784
NET INCOME		75,311		38,980
Preferred Stock Dividend Requirements Including Capital Stock Expense		-		200
EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	75,311	$	38,780
The common stock of APCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

74

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
	2012				2011
NET INCOME	$	75,311		$	38,980
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $290 in 2012 and $275 in 2011		(539	)		511
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $484 in 2012
and $418 in 2011		900			777
TOTAL OTHER COMPREHENSIVE INCOME		361			1,288
TOTAL COMPREHENSIVE INCOME	$	75,672		$	40,268
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

75

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
									Accumulated
									Other
			Common		Paid-in		Retained		Comprehensive
			Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S EQUITY –
	DECEMBER 31, 2010		$	260,458	$	1,475,496	$	1,133,748	$	(48,023)	$	2,821,679
Common Stock Dividends								(37,500)				(37,500)
Preferred Stock Dividends								(200)				(200)
Capital Stock Expense						3						3
SUBTOTAL – COMMON
		SHAREHOLDER'S EQUITY										2,783,982
NET INCOME								38,980				38,980
OTHER COMPREHENSIVE INCOME										1,288		1,288
TOTAL COMMON SHAREHOLDER'S EQUITY –
	MARCH 31, 2011		$	260,458	$	1,475,499	$	1,135,028	$	(46,735)	$	2,824,250
TOTAL COMMON SHAREHOLDER'S EQUITY –
	DECEMBER 31, 2011		$	260,458	$	1,573,752	$	1,160,747	$	(58,543)	$	2,936,414
Common Stock Dividends								(50,000)				(50,000)
SUBTOTAL – COMMON
		SHAREHOLDER'S EQUITY										2,886,414
NET INCOME								75,311				75,311
OTHER COMPREHENSIVE INCOME										361		361
TOTAL COMMON SHAREHOLDER'S EQUITY –
	MARCH 31, 2012		$	260,458	$	1,573,752	$	1,186,058	$	(58,182)	$	2,962,086
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

76

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2012 and December 31, 2011
(in thousands)
(Unaudited)
			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	1,803	$	2,317
Advances to Affiliates				22,406		22,008
Accounts Receivable:
	Customers			147,909		158,382
	Affiliated Companies			71,831		136,194
	Accrued Unbilled Revenues			45,808		68,427
	Miscellaneous			2,654		5,505
	Allowance for Uncollectible Accounts			(5,568)		(5,289)
		Total Accounts Receivable		262,634		363,219
Fuel				188,148		143,931
Materials and Supplies				102,644		101,724
Risk Management Assets				49,520		39,645
Accrued Tax Benefits				2,025		7,715
Regulatory Asset for Under-Recovered Fuel Costs				43,773		41,105
Prepayments and Other Current Assets				21,707		21,745
TOTAL CURRENT ASSETS				694,660		743,409
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			5,547,165		5,194,967
	Transmission			2,002,348		1,943,969
	Distribution			2,868,847		2,845,405
Other Property, Plant and Equipment				368,030		357,326
Construction Work in Progress				193,637		565,841
Total Property, Plant and Equipment				10,980,027		10,907,508
Accumulated Depreciation and Amortization				3,048,168		2,994,016
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				7,931,859		7,913,492
OTHER NONCURRENT ASSETS
Regulatory Assets				1,458,032		1,481,193
Long-term Risk Management Assets				46,049		39,226
Deferred Charges and Other Noncurrent Assets				124,349		122,187
TOTAL OTHER NONCURRENT ASSETS				1,628,430		1,642,606
TOTAL ASSETS			$	10,254,949	$	10,299,507
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

77

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
March 31, 2012 and December 31, 2011
(Unaudited)
	2012		2011
		(in thousands)
CURRENT LIABILITIES
Advances from Affiliates	$	184,040	$	198,248
Accounts Payable:
General		173,411		186,612
Affiliated Companies		92,497		137,376
Long-term Debt Due Within One Year – Nonaffiliated		545,026		594,525
Risk Management Liabilities		33,047		26,606
Customer Deposits		62,044		61,690
Deferred Income Taxes		20,757		14,255
Accrued Taxes		79,294		63,422
Accrued Interest		60,611		57,230
Other Current Liabilities		81,997		105,646
TOTAL CURRENT LIABILITIES		1,332,724		1,445,610
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		3,131,908		3,131,726
Long-term Risk Management Liabilities		21,971		12,923
Deferred Income Taxes		1,759,245		1,736,180
Regulatory Liabilities and Deferred Investment Tax Credits		590,453		576,792
Employee Benefits and Pension Obligations		298,177		302,182
Deferred Credits and Other Noncurrent Liabilities		158,385		157,680
TOTAL NONCURRENT LIABILITIES		5,960,139		5,917,483
TOTAL LIABILITIES		7,292,863		7,363,093
Rate Matters (Note 2)
Commitments and Contingencies (Note 3)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 30,000,000 Shares
Outstanding  – 13,499,500 Shares		260,458		260,458
Paid-in Capital		1,573,752		1,573,752
Retained Earnings		1,186,058		1,160,747
Accumulated Other Comprehensive Income (Loss)		(58,182)		(58,543)
TOTAL COMMON SHAREHOLDER’S EQUITY		2,962,086		2,936,414
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY	$	10,254,949	$	10,299,507
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

78

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
	2012			2011
OPERATING ACTIVITIES
Net Income	$	75,311		$	38,980
Adjustments to Reconcile Net Income to Net Cash Flows from
Operating Activities:
Depreciation and Amortization		80,413			69,099
Deferred Income Taxes		27,343			60,802
Carrying Costs Income		(7,785	)		(3,439	)
Allowance for Equity Funds Used During Construction		(513	)		(883	)
Mark-to-Market of Risk Management Contracts		(2,426	)		(1,553	)
Fuel Over/Under-Recovery, Net		24,741			(9,857	)
Change in Other Noncurrent Assets		(11,020	)		10,237
Change in Other Noncurrent Liabilities		8,866			12,013
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		100,202			109,662
Fuel, Materials and Supplies		(45,137	)		61,846
Accounts Payable		(24,787	)		(71,056	)
Accrued Taxes, Net		22,142			(32,472	)
Other Current Assets		(269	)		6,505
Other Current Liabilities		(16,921	)		957
Net Cash Flows from Operating Activities		230,160			250,841
INVESTING ACTIVITIES
Construction Expenditures		(117,359	)		(113,132	)
Change in Advances to Affiliates, Net		(398	)		(383,537	)
Other Investing Activities		2,295			4,047
Net Cash Flows Used for Investing Activities		(115,462	)		(492,622	)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated		-			640,770
Change in Advances from Affiliates, Net		(14,208	)		(128,331	)
Retirement of Long-term Debt – Nonaffiliated		(49,506	)		(229,655	)
Retirement of Cumulative Preferred Stock		-			(8	)
Principal Payments for Capital Lease Obligations		(1,637	)		(1,876	)
Dividends Paid on Common Stock		(50,000	)		(37,500	)
Dividends Paid on Cumulative Preferred Stock		-			(200	)
Other Financing Activities		139			14
Net Cash Flows from (Used for) Financing Activities		(115,212	)		243,214
Net Increase (Decrease) in Cash and Cash Equivalents		(514	)		1,433
Cash and Cash Equivalents at Beginning of Period		2,317			951
Cash and Cash Equivalents at End of Period	$	1,803		$	2,384
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	46,159		$	36,992
Net Cash Paid (Received) for Income Taxes		(2,984	)		629
Noncash Acquisitions Under Capital Leases		1,037			368
Government Grants Included in Accounts Receivable at March 31,		-			572
Construction Expenditures Included in Current Liabilities at March 31,		30,998			38,071
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

79

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to APCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to APCo.  The footnotes begin on page 128.

	Footnote Reference
Significant Accounting Matters	Note 1
Rate Matters	Note 2
Commitments, Guarantees and Contingencies	Note 3
Benefit Plans	Note 4
Business Segments	Note 5
Derivatives and Hedging	Note 6
Fair Value Measurements	Note 7
Income Taxes	Note 8
Financing Activities	Note 9

80

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

81

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Possible Termination of the Interconnection Agreement

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC.  It is unknown at this time whether the Interconnection Agreement will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.  Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future.  If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

Regulatory Activity

Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on equity of 11.15%.  The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.  Final hearings are currently scheduled for June 2012.  See “2011 Indiana Base Rate Case” section of Note 2.

Cook Plant

Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator.  Repair of the property damage and replacement of the turbine rotors and other equipment cost approximately $400 million.  Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process.  Due to the extensive lead time required to manufacture and install new turbine rotors, I&M repaired Unit 1 and it resumed operations in December 2009.  The installation of the new turbine rotors and other equipment occurred during the refueling outage of Unit 1 in the fall of 2011.  If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it would reduce future net income and cash flows and impact financial condition.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 3.

Nuclear Regulatory Commission

As a result of the nuclear plant situation in Japan following a March 2011 earthquake, the Nuclear Regulatory Commission (NRC) 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.  The NRC is also looking into the fuel used at eleven reactors, including the units at the Cook Plant.  Their concern relates to fuel temperatures if abnormal conditions are experienced.  Management continues to monitor this issue and responds to the NRC’s inquiry, as necessary.In addition to the review by the NRC, Congress could consider legislation tightening oversight of nuclear generating facilities.  Management is unable to predict the impact of potential future regulation of nuclear facilities.

82

Life Cycle Management Project

In April 2012, I&M filed a petition with the IURC for approval of the Cook Plant Life Cycle Management Project (LCM Project).  The LCM Project consists of a group of capital projects that extend the operating lives of Unit 1 and 2 to 2034 and 2037, respectively, which is consistent with the recent extension of their operating licenses.  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  I&M requested recovery of certain project costs, including interest, through a rider effective 2013.  I&M intends to file with the MPSC in the second quarter of 2012.  As of March 31, 2012, I&M has incurred $74 million related to the LCM Project.  If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

Litigation and Environmental Issues

In the ordinary course of business, I&M is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report.  Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 128.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 175 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales
		Three Months Ended March 31,
		2012		2011
		(in millions of KWHs)
Retail:
	Residential		1,569		1,836
	Commercial		1,165		1,263
	Industrial		1,833		1,844
	Miscellaneous		23		23
Total Retail			4,590		4,966
Wholesale			1,961		2,096
Total KWHs			6,551		7,062

83

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

Summary of Heating and Cooling Degree Days
		Three Months Ended March 31,
		2012		2011
		(in degree days)
Actual - Heating (a)			1,622		2,392
Normal - Heating (b)			2,184		2,175
Actual - Cooling (c)			29		-
Normal - Cooling (b)			1		1
(a)	Eastern Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Eastern Region cooling degree days are calculated on a 65 degree temperature base.

84

First Quarter of 2012 Compared to First Quarter of 2011

Reconciliation of First Quarter of 2011 to First Quarter of 2012
Net Income
(in millions)
First Quarter of 2011	$	45
Changes in Gross Margin:
Retail Margins		(31)
FERC Municipals and Cooperatives		1
Off-system Sales		(4)
Transmission Revenues		1
Other Revenues		7
Total Change in Gross Margin		(26)
Changes in Expenses and Other:
Other Operation and Maintenance		7
Total Change in Expenses and Other		7
Income Tax Expense		13
First Quarter of 2012	$	39

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail Margins decreased $31 million primarily due to the following:
	·	A $28 million decrease in weather-related usage primarily due to a 32% decrease in heating degree days.
	·	A $16 million decrease in capacity settlement revenues under the Interconnection Agreement.
	These decreases were partially offset by:
	·	A $16 million increase due to rate relief driven mainly by higher PJM rider revenue, interim Michigan base rate increases and higher Indiana Demand Side Management (DSM) revenue.  DSM and PJM revenues have corresponding increases to riders/trackers recognized in expense items.
·	Margins from Off-System Sales decreased $4 million primarily due to lower physical sales volumes and lower trading and marketing margins.
·	Other Revenues increased $7 million primarily due to I&M’s River Transportation Division (RTD) revenues from barging activities.  The increase in RTD revenue was offset by a corresponding increase in Other Operation and Maintenance expenses from barging activities as discussed below.

Expenses and Other and Income Tax Expense changed between years as follows:

·	Other Operation and Maintenance expenses decreased $7 million primarily due to the following:
	·	An $8 million decrease due to lower steam maintenance.
	·	A $4 million decrease in distribution primarily due to decreased overhead line expenses.
	These decreases were partially offset by:
	·	A $5 million increase in RTD expenses from barging activities.  The increase in RTD expense was offset by a corresponding increase in Other Revenues from barging activities as discussed above.
·	Income Tax Expense decreased $13 million primarily due to a decrease in pretax book income, the regulatory accounting treatment of state income taxes and federal income tax adjustments recorded in 2011 related to prior year tax returns.

85

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2011 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 175 for a discussion of accounting pronouncements.

86

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
	2012		2011
REVENUES
Electric Generation, Transmission and Distribution	$	436,027	$	456,862
Sales to AEP Affiliates		75,915		74,868
Other Revenues - Affiliated		30,711		24,331
Other Revenues - Nonaffiliated		3,554		4,431
TOTAL REVENUES		546,207		560,492
EXPENSES
Fuel and Other Consumables Used for Electric Generation		112,370		115,062
Purchased Electricity for Resale		35,910		29,292
Purchased Electricity from AEP Affiliates		87,953		79,584
Other Operation		135,216		133,211
Maintenance		42,265		51,000
Depreciation and Amortization		33,979		34,087
Taxes Other Than Income Taxes		22,189		22,262
TOTAL EXPENSES		469,882		464,498
OPERATING INCOME		76,325		95,994
Other Income (Expense):
Interest Income		1,251		696
Allowance for Equity Funds Used During Construction		3,011		3,199
Interest Expense		(25,053)		(25,191)
INCOME BEFORE INCOME TAX EXPENSE		55,534		74,698
Income Tax Expense		16,313		29,271
NET INCOME		39,221		45,427
Preferred Stock Dividend Requirements		-		85
EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	39,221	$	45,342
The common stock of I&M is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

87

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
		2012		2011
NET INCOME		$	39,221	$	45,427
OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $1,322 in 2012 and $286 in 2011			2,456		531
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $150 in 2012
	and $128 in 2011		279		237
TOTAL OTHER COMPREHENSIVE INCOME			2,735		768
TOTAL COMPREHENSIVE INCOME		$	41,956	$	46,195
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

88

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive
	Stock		Capital		Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2010	$	56,584	$	981,294	$	677,360		$	(20,889	)	$	1,694,349
Common Stock Dividends						(18,750	)					(18,750	)
Preferred Stock Dividends						(85	)					(85	)
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												1,675,514
NET INCOME						45,427						45,427
OTHER COMPREHENSIVE INCOME									768			768
TOTAL COMMON SHAREHOLDER'S
EQUITY – MARCH 31, 2011	$	56,584	$	981,294	$	703,952		$	(20,121	)	$	1,721,709
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2011	$	56,584	$	980,896	$	751,721		$	(28,221	)	$	1,760,980
Common Stock Dividends						(12,500	)					(12,500	)
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												1,748,480
NET INCOME						39,221						39,221
OTHER COMPREHENSIVE INCOME									2,735			2,735
TOTAL COMMON SHAREHOLDER'S
EQUITY – MARCH 31, 2012	$	56,584	$	980,896	$	778,442		$	(25,486	)	$	1,790,436
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

89

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2012 and December 31, 2011
(in thousands)
(Unaudited)
			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	643	$	1,020
Advances to Affiliates				143,962		95,714
Accounts Receivable:
	Customers			60,784		72,461
	Affiliated Companies			57,309		90,980
	Accrued Unbilled Revenues			15,570		14,780
	Miscellaneous			37,302		22,685
	Allowance for Uncollectible Accounts			(1,948)		(1,750)
		Total Accounts Receivable		169,017		199,156
Fuel				71,800		52,979
Materials and Supplies				170,993		175,924
Risk Management Assets				45,019		32,152
Accrued Tax Benefits				21,318		38,425
Deferred Cook Plant Fire Costs				64,291		63,809
Prepayments and Other Current Assets				45,137		35,395
TOTAL CURRENT ASSETS				732,180		694,574
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			3,922,767		3,932,472
	Transmission			1,233,154		1,224,786
	Distribution			1,494,192		1,481,608
Other Property, Plant and Equipment (including nuclear fuel and coal mining)				693,440		709,558
Construction Work in Progress				253,831		236,096
Total Property, Plant and Equipment				7,597,384		7,584,520
Accumulated Depreciation, Depletion and Amortization				3,201,638		3,179,920
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				4,395,746		4,404,600
OTHER NONCURRENT ASSETS
Regulatory Assets				600,515		602,979
Spent Nuclear Fuel and Decommissioning Trusts				1,661,580		1,591,732
Long-term Risk Management Assets				34,563		29,362
Deferred Charges and Other Noncurrent Assets				75,171		69,309
TOTAL OTHER NONCURRENT ASSETS				2,371,829		2,293,382
TOTAL ASSETS			$	7,499,755	$	7,392,556
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

90

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
March 31, 2012 and December 31, 2011
(dollars in thousands)
(Unaudited)
		2012		2011
CURRENT LIABILITIES
Accounts Payable:
	General	$	108,485	$	113,063
	Affiliated Companies		64,902		81,102
Long-term Debt Due Within One Year – Nonaffiliated
	(March 31, 2012 and December 31, 2011 amounts include $99,783 and
	$101,620, respectively, related to DCC Fuel)		277,284		279,075
Risk Management Liabilities			29,265		16,980
Customer Deposits			30,715		30,696
Accrued Taxes			78,911		65,233
Accrued Interest			22,578		27,798
Other Current Liabilities			102,405		117,879
TOTAL CURRENT LIABILITIES			714,545		731,826
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			1,764,457		1,778,600
Long-term Risk Management Liabilities			15,455		18,871
Deferred Income Taxes			952,319		925,712
Regulatory Liabilities and Deferred Investment Tax Credits			946,896		875,202
Asset Retirement Obligations			1,026,191		1,013,122
Deferred Credits and Other Noncurrent Liabilities			289,456		288,243
TOTAL NONCURRENT LIABILITIES			4,994,774		4,899,750
TOTAL LIABILITIES			5,709,319		5,631,576
Rate Matters (Note 2)
Commitments and Contingencies (Note 3)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
	Authorized – 2,500,000 Shares
	Outstanding  – 1,400,000 Shares		56,584		56,584
Paid-in Capital			980,896		980,896
Retained Earnings			778,442		751,721
Accumulated Other Comprehensive Income (Loss)			(25,486)		(28,221)
TOTAL COMMON SHAREHOLDER’S EQUITY			1,790,436		1,760,980
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	7,499,755	$	7,392,556
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

91

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
			2012		2011
OPERATING ACTIVITIES
Net Income			$	39,221	$	45,427
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			33,979		34,087
	Deferred Income Taxes			26,638		25,087
	Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net			(4,878)		11,616
	Allowance for Equity Funds Used During Construction			(3,011)		(3,199)
	Mark-to-Market of Risk Management Contracts			(5,624)		(658)
	Amortization of Nuclear Fuel			33,585		34,240
	Fuel Over/Under-Recovery, Net			(3,493)		4,156
	Change in Other Noncurrent Assets			(9,931)		(6,066)
	Change in Other Noncurrent Liabilities			32,710		13,327
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		49,885		97,575
		Fuel, Materials and Supplies		(13,890)		8,343
		Accounts Payable		(4,269)		(71,206)
		Accrued Taxes, Net		30,624		14,479
		Other Current Assets		(6,197)		(1,475)
		Other Current Liabilities		(23,279)		3,865
Net Cash Flows from Operating Activities				172,070		209,598
INVESTING ACTIVITIES
Construction Expenditures				(72,867)		(54,733)
Change in Advances to Affiliates, Net				(48,248)		(56,813)
Purchases of Investment Securities				(352,877)		(305,945)
Sales of Investment Securities				334,400		287,761
Acquisitions of Nuclear Fuel				(10,936)		(27,132)
Other Investing Activities				8,745		17,029
Net Cash Flows Used for Investing Activities				(141,783)		(139,833)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated				-		76,864
Change in Advances from Affiliates, Net				-		(42,769)
Retirement of Long-term Debt – Nonaffiliated				(16,074)		(82,354)
Principal Payments for Capital Lease Obligations				(1,890)		(2,128)
Dividends Paid on Common Stock				(12,500)		(18,750)
Dividends Paid on Cumulative Preferred Stock				-		(85)
Other Financing Activities				(200)		8
Net Cash Flows Used for Financing Activities				(30,664)		(69,214)
Net Increase (Decrease) in Cash and Cash Equivalents				(377)		551
Cash and Cash Equivalents at Beginning of Period				1,020		361
Cash and Cash Equivalents at End of Period			$	643	$	912
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	29,398	$	28,542
Net Cash Paid (Received) for Income Taxes				(23,095)		(1,033)
Noncash Acquisitions Under Capital Leases				2,009		693
Construction Expenditures Included in Current Liabilities at March 31,				26,957		21,651
Acquisition of Nuclear Fuel Included in Current Liabilities at March 31,				-		377
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

92

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to I&M’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to I&M.  The footnotes begin on page 128.

	Footnote Reference
Significant Accounting Matters	Note 1
Rate Matters	Note 2
Commitments, Guarantees and Contingencies	Note 3
Benefit Plans	Note 4
Business Segments	Note 5
Derivatives and Hedging	Note 6
Fair Value Measurements	Note 7
Income Taxes	Note 8
Financing Activities	Note 9

93

OHIO POWER COMPANY CONSOLIDATED

94

OHIO POWER COMPANY CONSOLIDATED

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Proposed June 2012 – May 2015 Ohio ESP

In March 2012, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing.  The SSO rates would be effective from June 2012 through May 2015.  The ESP will transition OPCo to auction-based SSO for capacity and energy by June 1, 2015.  The ESP also proposed to collect the Phase-In Recovery Rider from June 2013 through December 2018.  Further, the ESP proposed establishment of a non-bypassable Distribution Investment Rider through May 2015 to recover, with certain caps, post-August 2010 distribution investment.  The filing also seeks establishment of a new non-bypassable Retail Stability Rider (RSR) to recover lost generation revenues to provide financial certainty and stability during the ESP transition period.  The proposed RSR will be effective through May 2015.  Hearings are scheduled at the PUCO for May 2012 and oral arguments are scheduled for July 3, 2012, which would delay the proposed implementation of rates.  See “Ohio Electric Security Plan Filing” section of Note 2.

Ohio Customer Choice

In OPCo’s service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service.  As a result, in comparison to the first three months of 2011, OPCo lost approximately $49 million of gross margin.  OPCo is recovering a portion of lost margins through collection of capacity revenues from competitive CRES providers and off-system sales.

Ohio Capacity Rate

In March 2012, in response to OPCo’s motion for relief, the PUCO ordered that competitive retail electric service (CRES) providers not qualifying for the Reliability Pricing Model (RPM) price, which is substantially below OPCo’s current capacity cost of approximately $355/MW day, will pay a capacity billing rate of $255/MW day through May 2012, at which time the capacity billing rate will revert to the RPM price.  If the PUCO does not issue an order in the June 2012 – May 2015 ESP proceeding by May 31, 2012, OPCo will request an extension of the $255/MW day capacity rate.  See “Ohio Electric Security Plan Filing” section of Note 2.

Possible Corporate Separation and Termination of the Interconnection Agreement

In March 2012, OPCo filed a corporate separation plan with the PUCO for its generation assets.  Additional filings at the FERC and other state commissions related to corporate separation are expected to be filed in the future.  If corporate separation is not approved, OPCo’s results of operations related to generation will be determined by its ability to sell power and capacity at a profit at rates determined by the prevailing market.  If OPCo is unable to sell power and capacity at a profit, it could reduce future net income and cash flows and impact financial condition.

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC.  It is unknown at this time whether the Interconnection Agreement will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.  Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future.  If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

95

Regulatory Activity

2009 Fuel Adjustment Clause Audit

The PUCO selected an outside consultant to conduct the audit of the FAC for OPCo for the period of January 2009 through December 2009.  In January 2012, the PUCO ordered that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance.  In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges.  OPCo expects to record the favorable effect of the rehearing order of approximately $30 million in the second quarter of 2012.

Significantly Excessive Earnings Test

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in  a write-off of certain pretax earnings in 2010 and a subsequent refund to customers during 2011.  In May 2011, the IEU and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO’s decision.  The OEG’s appeal seeks the inclusion of off-system sales (OSS) in the calculation of SEET, which, if ordered, could require an additional refund of $22 million based on the PUCO approved SEET calculation.  OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  In the fourth quarter of 2011, OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO ordered SEET refund.  OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis.  Management does not currently believe that there are significantly excessive earnings in 2011 for either CSPCo or OPCo.  See “Ohio Electric Security Plan Filing” section of Note 2.

Ohio Distribution Base Rate Case

In December 2011, a stipulation was approved by the PUCO which provided for no change in distribution rates and a new rider for a $15 million annual credit to residential ratepayers due principally to the inclusion of the rate base distribution investment in the Distribution Investment Rider (DIR).  Due to the February 2012 PUCO order which rejected the modified stipulation, collection of the DIR terminated.  In March 2012, OPCo filed an application with the PUCO to approve an ESP for the period June 2012 through May 2015, which includes a request for a new DIR.  The June 2012 – May 2015 ESP proceeding is currently pending.  In March 2012, the PUCO issued an order clarifying that OPCo has the right to file a new distribution base rate case.  See “2011 Ohio Distribution Base Rate Case” section of Note 2.

Litigation and Environmental Issues

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report.  Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 128.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 175 for additional discussion of relevant factors.

CSPCo-OPCo Merger

On December 31, 2011, CSPCo merged into OPCo with OPCo being the surviving entity.  All prior reported amounts have been recast as if the merger occurred on the first day of the earliest reporting period.   All contracts and operations of CSPCo and its subsidiary are now part of OPCo.

96

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales
		Three Months Ended March 31,
		2012		2011
		(in millions of KWHs)
Retail:
	Residential		3,879		4,451
	Commercial		3,236		3,389
	Industrial		4,721		4,540
	Miscellaneous		31		35
Total Retail (a)			11,867		12,415
Wholesale			2,506		2,770
Total KWHs			14,373		15,185
(a) Includes energy delivered to customers served by OPCo.

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

Summary of Heating and Cooling Degree Days
		Three Months Ended March 31,
		2012		2011
		(in degree days)
Actual - Heating (a)			1,397		2,073
Normal - Heating (b)			1,918		1,903
Actual - Cooling (c)			28		1
Normal - Cooling (b)			2		2
(a)	Eastern Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Eastern Region cooling degree days are calculated on a 65 degree temperature base.

97

First Quarter of 2012 Compared to First Quarter of 2011

Reconciliation of First Quarter of 2011 to First Quarter of 2012
Net Income
(in millions)
First Quarter of 2011	$	166
Changes in Gross Margin:
Retail Margins		(103)
Off-system Sales		7
Transmission Revenues		7
Other Revenues		7
Total Change in Gross Margin		(82)
Changes in Expenses and Other:
Other Operation and Maintenance		53
Depreciation and Amortization		(1)
Carrying Costs Income		(8)
Other Income		1
Interest Expense		3
Total Change in Expenses and Other		48
Income Tax Expense		19
First Quarter of 2012	$	151

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail Margins decreased $103 million primarily due to the following:
	·	A $54 million decrease attributable to customers switching to alternative competitive retail electric service (CRES) providers.
	·	A $40 million decrease in capacity settlements under the Interconnection Agreement.
	·	A $39 million decrease due to the elimination of POLR charges, effective June 2011, as a result of the October 2011 PUCO remand order.
	·	A $23 million decrease in weather-related usage primarily due to a 33% decrease in heating degree days.
	These decreases were partially offset by:
	·	A $37 million increase in rate relief.  Of these increases, $8 million relates to riders/trackers which have corresponding increases in other expense items below.
·	Margins from Off-system Sales increased $7 million primarily due to an increase in PJM capacity revenues.
·	Transmission Revenues increased $7 million primarily due to net rate increases in PJM and increased transmission revenues for customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers partially offsets lost revenues included in Retail Margins above.
·	Other Revenues increased $7 million primarily due to sales to Buckeye Power, Inc. to provide backup energy under the Cardinal Station Agreement and revenues from Cook Coal Terminal.

98

Expenses and Other and Income Tax Expense changed between years as follows:

·	Other Operation and Maintenance expenses decreased $53 million primarily due to the following:
	·	A $35 million decrease due to the first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of OPCo's modified stipulation.
	·	A $12 million decrease in plant maintenance expenses at various plants.
	·	A $7 million decrease in employee-related expenses.
	These decreases were partially offset by:
	·	An $11 million gain from the sale of land in January 2011.
·	Depreciation and Amortization expenses increased $1 millionprimarily due to the following:
	·	A $14 million increase due to shortened depreciable lives for certain generating plants effective December 2011.
	This increase was partially offset by:
	·	A $9 million decrease due to the amortization of a portion of a distribution depreciation reserve as approved by the PUCO in the 2011 Ohio Distribution Base Rate Case.
	·	A $5 million decrease in depreciation due to the third quarter 2011 plant impairment of Sporn Unit 5.
·	Carrying Costs Income decreased $8 million primarily due to collections of carrying costs in first quarter 2012 on phase-in FAC deferrals and certain distribution regulatory assets.
·	Income Tax Expense decreased $19 million primarily due to a decrease in pretax book income and audit settlements for previous years.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2011 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 175 for a discussion of accounting pronouncements.

99

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
	2012		2011
REVENUES
Electric Generation, Transmission and Distribution	$	1,040,831	$	1,130,177
Sales to AEP Affiliates		181,757		252,534
Other Revenues – Affiliated		9,111		7,018
Other Revenues – Nonaffiliated		5,524		4,461
TOTAL REVENUES		1,237,223		1,394,190
EXPENSES
Fuel and Other Consumables Used for Electric Generation		369,993		407,396
Purchased Electricity for Resale		58,134		68,414
Purchased Electricity from AEP Affiliates		88,683		116,451
Other Operation		130,342		170,399
Maintenance		80,604		93,412
Depreciation and Amortization		134,430		133,412
Taxes Other Than Income Taxes		105,418		105,310
TOTAL EXPENSES		967,604		1,094,794
OPERATING INCOME		269,619		299,396
Other Income (Expense):
Interest Income		1,098		458
Carrying Costs Income		2,758		10,731
Allowance for Equity Funds Used During Construction		1,123		1,203
Interest Expense		(54,261)		(57,020)
INCOME BEFORE INCOME TAX EXPENSE		220,337		254,768
Income Tax Expense		69,507		88,798
NET INCOME		150,830		165,970
Preferred Stock Dividend Requirements Including Capital Stock Expense		-		208
EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	150,830	$	165,762
The common stock of OPCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

100

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
		2012		2011
NET INCOME		$	150,830	$	165,970
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $937 in 2012 and $158 in 2011			(1,741)		293
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,745 in 2012
	and $1,422 in 2011		3,241		2,641
TOTAL OTHER COMPREHENSIVE INCOME			1,500		2,934
TOTAL COMPREHENSIVE INCOME		$	152,330	$	168,904
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

101

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
								Accumulated
								Other
		Common		Paid-in		Retained		Comprehensive
		Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2010	$	321,201	$	1,744,991	$	2,768,602	$	(180,155)	$	4,654,639
Common Stock Dividends							(162,500)				(162,500)
Preferred Stock Dividends							(183)				(183)
Capital Stock Expense					25		(25)				-
SUBTOTAL – COMMON
	SHAREHOLDER'S EQUITY										4,491,956
NET INCOME							165,970				165,970
OTHER COMPREHENSIVE INCOME									2,934		2,934
TOTAL COMMON SHAREHOLDER'S
	EQUITY –  MARCH 31, 2011	$	321,201	$	1,745,016	$	2,771,864	$	(177,221)	$	4,660,860
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2011	$	321,201	$	1,744,099	$	2,582,600	$	(197,722)	$	4,450,178
Common Stock Dividends							(75,000)				(75,000)
SUBTOTAL – COMMON
	SHAREHOLDER'S EQUITY										4,375,178
NET INCOME							150,830				150,830
OTHER COMPREHENSIVE INCOME									1,500		1,500
TOTAL COMMON SHAREHOLDER'S
	EQUITY –  MARCH 31, 2012	$	321,201	$	1,744,099	$	2,658,430	$	(196,222)	$	4,527,508
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

102

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2012 and December 31, 2011
(in thousands)
(Unaudited)
			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	1,709	$	2,095
Advances to Affiliates				89,840		219,458
Accounts Receivable:
	Customers			87,635		146,432
	Affiliated Companies			146,616		162,830
	Accrued Unbilled Revenues			3,095		19,012
	Miscellaneous			12,811		16,994
	Allowance for Uncollectible Accounts			(3,526)		(3,563)
		Total Accounts Receivable		246,631		341,705
Fuel				311,773		262,886
Materials and Supplies				193,333		201,325
Risk Management Assets				73,775		54,293
Accrued Tax Benefits				6,095		11,975
Prepayments and Other Current Assets				42,862		41,560
TOTAL CURRENT ASSETS				966,018		1,135,297
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			9,528,532		9,502,614
	Transmission			1,958,930		1,948,329
	Distribution			3,582,480		3,545,574
Other Property, Plant and Equipment				556,737		546,642
Construction Work in Progress				364,474		354,465
Total Property, Plant and Equipment				15,991,153		15,897,624
Accumulated Depreciation and Amortization				5,692,825		5,742,561
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				10,298,328		10,155,063
OTHER NONCURRENT ASSETS
Regulatory Assets				1,356,371		1,370,504
Long-term Risk Management Assets				68,264		53,614
Deferred Charges and Other Noncurrent Assets				250,748		309,775
TOTAL OTHER NONCURRENT ASSETS				1,675,383		1,733,893
TOTAL ASSETS			$	12,939,729	$	13,024,253
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

103

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
March 31, 2012 and December 31, 2011
(Unaudited)
		2012		2011
			(in thousands)
CURRENT LIABILITIES
Accounts Payable:
	General	$	229,329	$	293,730
	Affiliated Companies		115,182		183,898
Long-term Debt Due Within One Year – Nonaffiliated			594,500		244,500
Risk Management Liabilities			49,460		36,561
Accrued Taxes			365,340		450,570
Accrued Interest			68,100		66,441
Other Current Liabilities			246,062		238,275
TOTAL CURRENT LIABILITIES			1,667,973		1,513,975
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			3,109,846		3,609,648
Long-term Debt – Affiliated			200,000		200,000
Long-term Risk Management Liabilities			32,662		17,890
Deferred Income Taxes			2,286,013		2,245,380
Regulatory Liabilities and Deferred Investment Tax Credits			467,993		301,124
Employee Benefits and Pension Obligations			321,980		335,029
Deferred Credits and Other Noncurrent Liabilities			325,754		351,029
TOTAL NONCURRENT LIABILITIES			6,744,248		7,060,100
TOTAL LIABILITIES			8,412,221		8,574,075
Rate Matters (Note 2)
Commitments and Contingencies (Note 3)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
	Authorized – 40,000,000 Shares
	Outstanding  – 27,952,473 Shares		321,201		321,201
Paid-in Capital			1,744,099		1,744,099
Retained Earnings			2,658,430		2,582,600
Accumulated Other Comprehensive Income (Loss)			(196,222)		(197,722)
TOTAL COMMON SHAREHOLDER’S EQUITY			4,527,508		4,450,178
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	12,939,729	$	13,024,253
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

104

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
			2012		2011
OPERATING ACTIVITIES
Net Income			$	150,830	$	165,970
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			134,430		133,412
	Deferred Income Taxes			47,668		60,940
	Carrying Costs Income			(2,758)		(10,731)
	Allowance for Equity Funds Used During Construction			(1,123)		(1,203)
	Mark-to-Market of Risk Management Contracts			(8,566)		(1,487)
	Property Taxes			53,973		52,233
	Fuel Over/Under-Recovery, Net			21,222		(21,197)
	Change in Other Noncurrent Assets			(1,649)		(17,314)
	Change in Other Noncurrent Liabilities			(20,486)		16,371
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		98,001		79,087
		Fuel, Materials and Supplies		(40,200)		57,075
		Accounts Payable		(98,502)		(76,834)
		Accrued Taxes, Net		(76,603)		(70,876)
		Other Current Assets		(2,041)		3,098
		Other Current Liabilities		(10,538)		(34,157)
Net Cash Flows from Operating Activities				243,658		334,387
INVESTING ACTIVITIES
Construction Expenditures				(148,956)		(94,592)
Change in Advances to Affiliates, Net				129,618		8,312
Acquisitions of Assets				(23)		(1,489)
Proceeds from Sales of Assets				2,827		23,895
Other Investing Activities				-		12,178
Net Cash Flows Used for Investing Activities				(16,534)		(51,696)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated				-		49,917
Retirement of Long-term Debt – Nonaffiliated				(150,000)		(165,000)
Principal Payments for Capital Lease Obligations				(2,619)		(3,123)
Dividends Paid on Common Stock				(75,000)		(162,500)
Dividends Paid on Cumulative Preferred Stock				-		(183)
Other Financing Activities				109		(162)
Net Cash Flows Used for Financing Activities				(227,510)		(281,051)
Net Increase (Decrease) in Cash and Cash Equivalents				(386)		1,640
Cash and Cash Equivalents at Beginning of Period				2,095		949
Cash and Cash Equivalents at End of Period			$	1,709	$	2,589
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	52,150	$	53,332
Net Cash Paid (Received) for Income Taxes				(7,359)		1,273
Noncash Acquisitions Under Capital Leases				819		469
Government Grants Included in Accounts Receivable at March 31,				2,052		1,938
Construction Expenditures Included in Current Liabilities at March 31,				28,330		24,131
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

105

OHIO POWER COMPANY CONSOLIDATED

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to OPCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to OPCo.  The footnotes begin on page 128.

	Footnote Reference
Significant Accounting Matters	Note 1
Rate Matters	Note 2
Commitments, Guarantees and Contingencies	Note 3
Benefit Plans	Note 4
Business Segments	Note 5
Derivatives and Hedging	Note 6
Fair Value Measurements	Note 7
Income Taxes	Note 8
Financing Activities	Note 9

106

PUBLIC SERVICE COMPANY OF OKLAHOMA

107

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Litigation and Environmental Issues

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report.  Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 128.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 175 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales
		Three Months Ended March 31,
		2012		2011
		(in millions of KWHs)
Retail:
	Residential		1,337		1,540
	Commercial		1,101		1,130
	Industrial		1,193		1,123
	Miscellaneous		300		279
Total Retail			3,931		4,072
Wholesale			545		234
Total KWHs			4,476		4,306

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

Summary of Heating and Cooling Degree Days
		Three Months Ended March 31,
		2012		2011
		(in degree days)
Actual - Heating (a)			676		1,257
Normal - Heating (b)			1,066		1,058
Actual - Cooling (c)			64		33
Normal - Cooling (b)			13		13
(a)	Western Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Western Region cooling degree days are calculated on a 65 degree temperature base.

108

First Quarter of 2012 Compared to First Quarter of 2011

Reconciliation of First Quarter of 2011 to First Quarter of 2012
Net Income
(in millions)
First Quarter of 2011		$	15
Changes in Gross Margin:
Retail Margins (a)			7
Transmission Revenues			(2)
Total Change in Gross Margin			5
Changes in Expenses and Other:
Other Operation and Maintenance			(10)
Other Income			1
Interest Expense			1
Total Change in Expenses and Other			(8)
Income Tax Expense			1
First Quarter of 2012		$	13
(a)	Includes firm wholesale sales to municipals and cooperatives.

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail Margins increased $7 million primarily due to the following:
	·	A $4 million increase primarily due to revenue increases from rate riders.  This increase in retail margins had corresponding increases to riders/trackers recognized in other expense items.
	·	A $4 million increase in industrial margins primarily due to increased usage.
	·	A $3 million increase primarily due to decreased capacity and fuel costs.
	These increases were partially offset by:
	·	A $4 million decrease in weather-related usage primarily due to a 52% decrease in heating degree days.

Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $­­­10 million primarily due to the following:
	·	A $6 million increase in plant operations primarily due to the 2011 deferral of generation maintenance expenses as a result of an order in PSO’s base rate case and an increase in generation plant maintenance.
	·	A $5 million increase in transmission expenses primarily due to increased SPP transmission services.
	These increases were partially offset by:
	·	A $2 million decrease in operation expenses due to lower employee-related expenses.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2011 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 175 for a discussion of accounting pronouncements.

109

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
	2012		2011
REVENUES
Electric Generation, Transmission and Distribution	$	292,522	$	284,587
Sales to AEP Affiliates		7,105		2,796
Other Revenues		904		620
TOTAL REVENUES		300,531		288,003
EXPENSES
Fuel and Other Consumables Used for Electric Generation		125,425		91,748
Purchased Electricity for Resale		25,442		41,179
Purchased Electricity from AEP Affiliates		6,198		16,611
Other Operation		46,979		44,404
Maintenance		28,325		20,721
Depreciation and Amortization		23,533		23,863
Taxes Other Than Income Taxes		11,139		10,596
TOTAL EXPENSES		267,041		249,122
OPERATING INCOME		33,490		38,881
Other Income (Expense):
Interest Income		935		52
Carrying Costs Income		613		647
Allowance for Equity Funds Used During Construction		422		366
Interest Expense		(14,711)		(15,938)
INCOME BEFORE INCOME TAX EXPENSE		20,749		24,008
Income Tax Expense		8,101		8,619
NET INCOME		12,648		15,389
Preferred Stock Dividend Requirements		-		49
EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	12,648	$	15,340
The common stock of PSO is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

110

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
	2012		2011
NET INCOME	$	12,648	$	15,389
OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $29 in 2012 and $239 in 2011		(53)		(443)
TOTAL COMPREHENSIVE INCOME	$	12,595	$	14,946
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

111

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
								Accumulated
								Other
		Common		Paid-in		Retained		Comprehensive
		Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2010	$	157,230	$	364,307	$	312,441	$	8,494	$	842,472
Common Stock Dividends							(16,250)				(16,250)
Preferred Stock Dividends							(49)				(49)
SUBTOTAL – COMMON
	SHAREHOLDER'S EQUITY										826,173
NET INCOME							15,389				15,389
OTHER COMPREHENSIVE LOSS									(443)		(443)
TOTAL COMMON SHAREHOLDER'S
	EQUITY – MARCH 31, 2011	$	157,230	$	364,307	$	311,531	$	8,051	$	841,119
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2011	$	157,230	$	364,037	$	364,389	$	7,149	$	892,805
Common Stock Dividends							(15,000)				(15,000)
SUBTOTAL – COMMON
	SHAREHOLDER'S EQUITY										877,805
NET INCOME							12,648				12,648
OTHER COMPREHENSIVE LOSS									(53)		(53)
TOTAL COMMON SHAREHOLDER'S
	EQUITY – MARCH 31, 2012	$	157,230	$	364,037	$	362,037	$	7,096	$	890,400
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

112

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
March 31, 2012 and December 31, 2011
(in thousands)
(Unaudited)
			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	788	$	1,413
Advances to Affiliates				29,136		39,876
Accounts Receivable:
	Customers			35,939		39,977
	Affiliated Companies			44,613		23,079
	Miscellaneous			7,342		8,993
	Allowance for Uncollectible Accounts			(771)		(777)
		Total Accounts Receivable		87,123		71,272
Fuel				19,661		20,854
Materials and Supplies				50,429		50,347
Risk Management Assets				860		565
Deferred Income Tax Benefits				10,528		7,013
Accrued Tax Benefits				9,116		6,733
Regulatory Asset for Under-Recovered Fuel Costs				-		4,313
Prepayments and Other Current Assets				6,777		6,440
TOTAL CURRENT ASSETS				214,418		208,826
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			1,316,411		1,317,948
	Transmission			696,741		692,644
	Distribution			1,786,250		1,762,110
Other Property, Plant and Equipment				217,335		214,626
Construction Work in Progress				66,030		70,371
Total Property, Plant and Equipment				4,082,767		4,057,699
Accumulated Depreciation and Amortization				1,265,681		1,266,816
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				2,817,086		2,790,883
OTHER NONCURRENT ASSETS
Regulatory Assets				264,738		266,545
Long-term Risk Management Assets				255		314
Deferred Charges and Other Noncurrent Assets				42,229		13,536
TOTAL OTHER NONCURRENT ASSETS				307,222		280,395
TOTAL ASSETS			$	3,338,726	$	3,280,104
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

113

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
March 31, 2012 and December 31, 2011
(Unaudited)
		2012		2011
			(in thousands)
CURRENT LIABILITIES
Accounts Payable:
	General	$	53,661	$	76,607
	Affiliated Companies		39,071		45,029
Long-term Debt Due Within One Year – Nonaffiliated			429		311
Risk Management Liabilities			4,059		1,280
Customer Deposits			46,737		47,493
Accrued Taxes			40,255		21,660
Accrued Interest			14,970		12,637
Regulatory Liability for Over-Recovered Fuel Costs			57,762		-
Other Current Liabilities			37,043		43,586
TOTAL CURRENT LIABILITIES			293,987		248,603
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			948,964		947,053
Long-term Risk Management Liabilities			3,410		1,330
Deferred Income Taxes			736,567		726,463
Regulatory Liabilities and Deferred Investment Tax Credits			340,564		334,812
Employee Benefits and Pension Obligations			82,990		84,548
Deferred Credits and Other Noncurrent Liabilities			41,844		44,490
TOTAL NONCURRENT LIABILITIES			2,154,339		2,138,696
TOTAL LIABILITIES			2,448,326		2,387,299
Rate Matters (Note 2)
Commitments and Contingencies (Note 3)
COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
	Authorized – 11,000,000 Shares
	Issued – 10,482,000 Shares
	Outstanding – 9,013,000 Shares		157,230		157,230
Paid-in Capital			364,037		364,037
Retained Earnings			362,037		364,389
Accumulated Other Comprehensive Income (Loss)			7,096		7,149
TOTAL COMMON SHAREHOLDER’S EQUITY			890,400		892,805
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	3,338,726	$	3,280,104
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

114

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
				2012		2011
OPERATING ACTIVITIES
Net Income				$	12,648	$	15,389
Adjustments to Reconcile Net Income to Net Cash Flows from Operating
	Activities:
		Depreciation and Amortization			23,533		23,863
		Deferred Income Taxes			9,307		15,364
		Carrying Costs Income			(613)		(647)
		Allowance for Equity Funds Used During Construction			(422)		(366)
		Mark-to-Market of Risk Management Contracts			4,818		397
		Property Taxes			(29,020)		(28,113)
		Fuel Over/Under-Recovery, Net			62,075		5,863
		Change in Other Noncurrent Assets			(3,567)		(770)
		Change in Other Noncurrent Liabilities			(372)		20,617
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		(15,757)		29,450
			Fuel, Materials and Supplies		1,111		(665)
			Accounts Payable		(10,655)		4,103
			Accrued Taxes, Net		15,852		11,392
			Other Current Assets		(564)		(2,025)
			Other Current Liabilities		(3,542)		4,378
Net Cash Flows from Operating Activities					64,832		98,230
INVESTING ACTIVITIES
Construction Expenditures					(62,696)		(32,876)
Change in Advances to Affiliates, Net					10,740		(3,093)
Other Investing Activities					290		367
Net Cash Flows Used for Investing Activities					(51,666)		(35,602)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated					1,944		246,376
Change in Advances from Affiliates, Net					-		(91,382)
Retirement of Long-term Debt – Nonaffiliated					-		(200,000)
Principal Payments for Capital Lease Obligations					(841)		(1,039)
Dividends Paid on Common Stock					(15,000)		(16,250)
Dividends Paid on Cumulative Preferred Stock					-		(49)
Other Financing Activities					106		-
Net Cash Flows Used for Financing Activities					(13,791)		(62,344)
Net Increase (Decrease) in Cash and Cash Equivalents					(625)		284
Cash and Cash Equivalents at Beginning of Period					1,413		470
Cash and Cash Equivalents at End of Period				$	788	$	754
SUPPLEMENTARY INFORMATION
Cash Paid (Received) for Interest, Net of Capitalized Amounts				$	10,795	$	(5,337)
Net Cash Paid for Income Taxes					4,873		286
Noncash Acquisitions Under Capital Leases					437		384
Construction Expenditures Included in Current Liabilities at March 31,					9,861		5,048
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

115

PUBLIC SERVICE COMPANY OF OKLAHOMA

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to PSO’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to PSO.  The footnotes begin on page 128.

	Footnote Reference
Significant Accounting Matters	Note 1
Rate Matters	Note 2
Commitments, Guarantees and Contingencies	Note 3
Benefit Plans	Note 4
Business Segments	Note 5
Derivatives and Hedging	Note 6
Fair Value Measurements	Note 7
Income Taxes	Note 8
Financing Activities	Note 9

116

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

117

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Regulatory Activity

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal generating unit in Arkansas, which is on target to be in service in the fourth quarter of 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  See “Turk Plant” section of Note 2.

Litigation and Environmental Issues

In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report.  Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 128.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 175 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales
		Three Months Ended March 31,
		2012		2011
		(in millions of KWHs)
Retail:
	Residential		1,382		1,604
	Commercial		1,311		1,366
	Industrial		1,318		1,252
	Miscellaneous		20		20
Total Retail			4,031		4,242
Wholesale			2,272		1,877
Total KWHs			6,303		6,119

118

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

Summary of Heating and Cooling Degree Days
		Three Months Ended March 31,
		2012		2011
		(in degree days)
Actual - Heating (a)			423		849
Normal - Heating (b)			746		745
Actual - Cooling (c)			114		51
Normal - Cooling (b)			30		31
(a)	Western Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Western Region cooling degree days are calculated on a 65 degree temperature base.

119

First Quarter of 2012 Compared to First Quarter of 2011

Reconciliation of First Quarter of 2011 to First Quarter of 2012
Net Income
(in millions)
First Quarter of 2011		$	30
Changes in Gross Margin:
Retail Margins (a)			(10)
Other Revenues			1
Total Change in Gross Margin			(9)
Changes in Expenses and Other:
Other Operation and Maintenance			11
Depreciation and Amortization			(1)
Other Income			4
Total Change in Expenses and Other			14
Income Tax Expense			1
First Quarter of 2012		$	36
(a)	Includes firm wholesale sales to municipals and cooperatives.

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail Margins decreased $10 million primarily due to:
	·	A $14 million decrease primarily due to adjustments to capacity and fuel costs.
	·	A $5 million decrease in weather-related usage primarily due to a 50% decrease in heating degree days.
	These decreases were partially offset by:
	·	A $9 million increase in municipal and cooperative revenues due to formula rate adjustments and higher rates.

Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses decreased $11 million primarily due to:

· A $6 million decrease in generation maintenance expenses primarily due to the timing of planned plant outages.

· A $2 million decrease in distribution maintenance expenses primarily due to decreased vegetation management and storm-related expenses.

· A $2 million decrease in operation expenses primarily due to lower employee-related expenses.

· Other Income increased $4 million primarily due to an increase in AFUDC as a result of construction at the Turk Plant.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2011 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 175 for a discussion of accounting pronouncements.

120

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
	2012		2011
REVENUES
Electric Generation, Transmission and Distribution	$	339,703	$	347,067
Sales to AEP Affiliates		8,957		15,579
Other Revenues		326		309
TOTAL REVENUES		348,986		362,955
EXPENSES
Fuel and Other Consumables Used for Electric Generation		128,234		134,012
Purchased Electricity for Resale		35,467		38,589
Purchased Electricity from AEP Affiliates		6,255		2,111
Other Operation		51,593		54,068
Maintenance		21,262		29,391
Depreciation and Amortization		34,021		33,290
Taxes Other Than Income Taxes		16,786		16,966
TOTAL EXPENSES		293,618		308,427
OPERATING INCOME		55,368		54,528
Other Income (Expense):
Other Income		14,894		10,540
Interest Expense		(22,002)		(22,425)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		48,260		42,643
Income Tax Expense		12,472		13,396
Equity Earnings of Unconsolidated Subsidiary		607		580
NET INCOME		36,395		29,827
Net Income Attributable to Noncontrolling Interest		1,083		1,082
NET INCOME ATTRIBUTABLE TO SWEPCo SHAREHOLDERS		35,312		28,745
Preferred Stock Dividend Requirements		-		57
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	35,312	$	28,688
The common stock of SWEPCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

121

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
		2012		2011
NET INCOME		$	36,395	$	29,827
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $956 in 2012 and $202 in 2011			(1,775)		376
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $89 in 2012
	and $69 in 2011		165		128
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			(1,610)		504
TOTAL COMPREHENSIVE INCOME			34,785		30,331
Total Comprehensive Income Attributable to Noncontrolling Interest			1,083		1,082
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo
	SHAREHOLDERS	$	33,702	$	29,249
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

122

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
	SWEPCo Common Shareholder
							Accumulated
							Other
	Common		Paid-in		Retained		Comprehensive		Noncontrolling
	Stock		Capital		Earnings		Income (Loss)		Interest		Total
TOTAL EQUITY – DECEMBER 31, 2010	$	135,660	$	674,979	$	868,840	$	(12,491)	$	361	$	1,667,349
Common Stock Dividends – Nonaffiliated										(1,077)		(1,077)
Preferred Stock Dividends						(57)						(57)
SUBTOTAL – EQUITY												1,666,215
NET INCOME						28,745				1,082		29,827
OTHER COMPREHENSIVE INCOME								504				504
TOTAL EQUITY – MARCH 31, 2011	$	135,660	$	674,979	$	897,528	$	(11,987)	$	366	$	1,696,546
TOTAL EQUITY – DECEMBER 31, 2011	$	135,660	$	674,606	$	1,029,915	$	(26,815)	$	391	$	1,813,757
Common Stock Dividends – Nonaffiliated										(1,092)		(1,092)
SUBTOTAL – EQUITY												1,812,665
NET INCOME						35,312				1,083		36,395
OTHER COMPREHENSIVE LOSS								(1,610)				(1,610)
TOTAL EQUITY – MARCH 31, 2012	$	135,660	$	674,606	$	1,065,227	$	(28,425)	$	382	$	1,847,450
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

123

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2012 and December 31, 2011
(in thousands)
(Unaudited)
			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents
		(March 31, 2012 amount includes $17,358 related to Sabine)	$	18,032	$	801
Advances to Affiliates				27,651		-
Accounts Receivable:
	Customers			33,442		35,054
	Affiliated Companies			23,569		23,730
	Miscellaneous			15,439		19,370
	Allowance for Uncollectible Accounts			(991)		(989)
		Total Accounts Receivable		71,459		77,165
Fuel
	(March 31, 2012 and December 31, 2011 amounts include $23,351 and
	$32,651, respectively, related to Sabine)			93,461		102,015
Materials and Supplies				64,062		55,325
Risk Management Assets				1,197		445
Deferred Income Tax Benefits				4,745		8,195
Accrued Tax Benefits				56,523		1,541
Regulatory Asset for Under-Recovered Fuel Costs				18,676		10,843
Prepayments and Other Current Assets				25,321		16,827
TOTAL CURRENT ASSETS				381,127		273,157
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			2,326,828		2,326,102
	Transmission			1,020,686		988,534
	Distribution			1,695,881		1,675,764
Other Property, Plant and Equipment
	(March 31, 2012 and December 31, 2011 amounts include $237,393 and
	$232,948, respectively, related to Sabine)			650,122		637,019
Construction Work in Progress				1,499,757		1,443,569
Total Property, Plant and Equipment				7,193,274		7,070,988
Accumulated Depreciation and Amortization
	(March 31, 2012 and December 31, 2011 amounts include $106,736 and
	$103,586, respectively, related to Sabine)			2,230,300		2,211,912
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				4,962,974		4,859,076
OTHER NONCURRENT ASSETS
Regulatory Assets				415,221		394,276
Long-term Risk Management Assets				423		282
Deferred Charges and Other Noncurrent Assets				108,070		74,992
TOTAL OTHER NONCURRENT ASSETS				523,714		469,550
TOTAL ASSETS			$	5,867,815	$	5,601,783
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

124

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 2012 and December 31, 2011
(Unaudited)
		2012		2011
			(in thousands)
CURRENT LIABILITIES
Advances from Affiliates		$	-	$	132,473
Accounts Payable:
	General		149,441		181,268
	Affiliated Companies		69,234		59,201
Short-term Debt – Nonaffiliated			-		17,016
Long-term Debt Due Within One Year – Nonaffiliated			3,250		20,000
Risk Management Liabilities			10,733		24,359
Customer Deposits			63,501		52,095
Accrued Taxes			57,079		44,404
Accrued Interest			18,854		39,629
Obligations Under Capital Leases			16,200		15,058
Regulatory Liability for Over-Recovered Fuel Costs			-		5,032
Other Current Liabilities			67,385		64,413
TOTAL CURRENT LIABILITIES			455,677		654,948
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			2,044,337		1,708,637
Long-term Risk Management Liabilities			309		221
Deferred Income Taxes			759,358		665,668
Regulatory Liabilities and Deferred Investment Tax Credits			438,882		428,571
Asset Retirement Obligations			74,647		65,673
Employee Benefits and Pension Obligations			92,794		87,159
Obligations Under Capital Leases			116,184		112,802
Deferred Credits and Other Noncurrent Liabilities			38,177		64,347
TOTAL NONCURRENT LIABILITIES			3,564,688		3,133,078
TOTAL LIABILITIES			4,020,365		3,788,026
Rate Matters (Note 2)
Commitments and Contingencies (Note 3)
EQUITY
Common Stock – Par Value – $18 Per Share:
	Authorized –  7,600,000 Shares
	Outstanding  – 7,536,640 Shares		135,660		135,660
Paid-in Capital			674,606		674,606
Retained Earnings			1,065,227		1,029,915
Accumulated Other Comprehensive Income (Loss)			(28,425)		(26,815)
TOTAL COMMON SHAREHOLDER’S EQUITY			1,847,068		1,813,366
Noncontrolling Interest			382		391
TOTAL EQUITY			1,847,450		1,813,757
TOTAL LIABILITIES AND EQUITY		$	5,867,815	$	5,601,783
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

125

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2012 and 2011
(in thousands)
(Unaudited)
				2012		2011
OPERATING ACTIVITIES
Net Income				$	36,395	$	29,827
Adjustments to Reconcile Net Income to Net Cash Flows from
	Operating Activities:
		Depreciation and Amortization			34,021		33,290
		Deferred Income Taxes			82,540		15,440
		Allowance for Equity Funds Used During Construction			(13,774)		(10,597)
		Mark-to-Market of Risk Management Contracts			4,896		(1,348)
		Property Taxes			(29,686)		(30,534)
		Fuel Over/Under-Recovery, Net			(12,865)		(7,074)
		Change in Other Noncurrent Assets			(4,400)		13,210
		Change in Other Noncurrent Liabilities			(10,862)		20,206
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		5,732		2,162
			Fuel, Materials and Supplies		(183)		4,488
			Accounts Payable		(7,399)		(11,429)
			Accrued Taxes, Net		(42,370)		29,884
			Accrued Interest		(20,801)		(22,192)
			Other Current Assets		(8,557)		(940)
			Other Current Liabilities		(127)		(12,285)
Net Cash Flows from Operating Activities					12,560		52,108
INVESTING ACTIVITIES
Construction Expenditures					(130,344)		(114,351)
Change in Advances to Affiliates, Net					(27,651)		76,855
Other Investing Activities					(1,096)		(1,515)
Net Cash Flows Used for Investing Activities					(159,091)		(39,011)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated					336,664		-
Credit Facility Borrowings					20,701		18,478
Change in Advances from Affiliates, Net					(132,473)		-
Retirement of Long-term Debt – Nonaffiliated					(20,000)		-
Credit Facility Repayments					(37,717)		(24,695)
Principal Payments for Capital Lease Obligations					(3,726)		(3,186)
Dividends Paid on Common Stock – Nonaffiliated					(1,092)		(1,077)
Dividends Paid on Cumulative Preferred Stock					-		(57)
Other Financing Activities					1,405		-
Net Cash Flows from (Used for) Financing Activities					163,762		(10,537)
Net Increase in Cash and Cash Equivalents					17,231		2,560
Cash and Cash Equivalents at Beginning of Period					801		1,514
Cash and Cash Equivalents at End of Period				$	18,032	$	4,074
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	39,581	$	41,646
Net Cash Paid for Income Taxes					1,168		698
Noncash Acquisitions Under Capital Leases					8,396		4,286
Construction Expenditures Included in Current Liabilities at March 31,					95,570		94,536
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 128.

126

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to SWEPCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to SWEPCo.  The footnotes begin on page 128.

	Footnote Reference
Significant Accounting Matters	Note 1
Rate Matters	Note 2
Commitments, Guarantees and Contingencies	Note 3
Benefit Plans	Note 4
Business Segments	Note 5
Derivatives and Hedging	Note 6
Fair Value Measurements	Note 7
Income Taxes	Note 8
Financing Activities	Note 9

127

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to condensed financial statements that follow are a combined presentation for the Registrant Subsidiaries.  The following list indicates the registrants to which the footnotes apply:
1.	Significant Accounting Matters	APCo, I&M, OPCo, PSO, SWEPCo
2.	Rate Matters	APCo, I&M, OPCo, PSO, SWEPCo
3.	Commitments, Guarantees and Contingencies	APCo, I&M, OPCo, PSO, SWEPCo
4.	Benefit Plans	APCo, I&M, OPCo, PSO, SWEPCo
5.	Business Segments	APCo, I&M, OPCo, PSO, SWEPCo
6.	Derivatives and Hedging	APCo, I&M, OPCo, PSO, SWEPCo
7.	Fair Value Measurements	APCo, I&M, OPCo, PSO, SWEPCo
8.	Income Taxes	APCo, I&M, OPCo, PSO, SWEPCo
9.	Financing Activities	APCo, I&M, OPCo, PSO, SWEPCo

128

1.  SIGNIFICANT ACCOUNTING MATTERS

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC.  Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary.  Net income for the three months ended March 31, 2012 is not necessarily indicative of results that may be expected for the year ending December 31, 2012.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2011 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2011 as filed with the SEC on February 28, 2012.

Variable Interest Entities

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE.  A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.  Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.”  In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors.  Management believes that significant assumptions and judgments were applied consistently.  There have been no changes to the reporting of VIEs in the financial statements where it is concluded that a Registrant Subsidiary is the primary beneficiary.  In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.

SWEPCo is the primary beneficiary of Sabine.  I&M is the primary beneficiary of DCC Fuel.  APCo, I&M, OPCo, PSO and SWEPCo each hold a significant variable interest in AEPSC.  I&M and OPCo each hold a significant variable interest in AEGCo.  SWEPCo holds a significant variable interest in DHLC.

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the three months ended March 31, 2012 and 2011 were $55 million and $33 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets.

129

The balances below represent the assets and liabilities of Sabine that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
March 31, 2012 and December 31, 2011
(in millions)
	Sabine
ASSETS	2012		2011
Current Assets	$	75	$	48
Net Property, Plant and Equipment		167		154
Other Noncurrent Assets		57		42
Total Assets	$	299	$	244
LIABILITIES AND EQUITY
Current Liabilities	$	48	$	68
Noncurrent Liabilities		251		176
Equity		-		-
Total Liabilities and Equity	$	299	$	244

I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC and DCC Fuel IV LLC (collectively DCC Fuel).  DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC and DCC Fuel IV LLC are separate legal entities from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on DCC Fuel LLC and DCC Fuel II LLC leases are made semi-annually and began in April 2010 and October 2010, respectively.  Payments on the DCC Fuel III LLC lease are made monthly and began in January 2011.  Payments on the DCC Fuel IV LLC lease are made quarterly and began in February 2012.  Payments on the leases for the three months ended March 31, 2012 and 2011 were $17 million and $6 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the 48, 54, 54 and 54 month lease term, respectively.  Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s condensed balance sheets.

The balances below represent the assets and liabilities of DCC Fuel that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
March 31, 2012 and December 31, 2011
(in millions)
	DCC Fuel
ASSETS	2012		2011
Current Assets	$	123	$	118
Net Property, Plant and Equipment		159		188
Other Noncurrent Assets		98		118
Total Assets	$	380	$	424
LIABILITIES AND EQUITY
Current Liabilities	$	92	$	103
Noncurrent Liabilities		288		321
Equity		-		-
Total Liabilities and Equity	$	380	$	424

130

DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and voting rights equally.  Each entity guarantees 50% of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  SWEPCo’s total billings from DHLC for the three months ended March 31, 2012 and 2011 were $14 million and $13 million, respectively.  SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC.  SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheets.

SWEPCo’s investment in DHLC was:

	March 31, 2012				December 31, 2011
	As Reported on		Maximum		As Reported on		Maximum
	the Balance Sheet		Exposure		the Balance Sheet		Exposure
	(in millions)
Capital Contribution from SWEPCo	$	8	$	8	$	8	$	8
Retained Earnings		1		1		1		1
SWEPCo's Guarantee of Debt		-		54		-		52
Total Investment in DHLC	$	9	$	63	$	9	$	61

AEPSC provides certain managerial and professional services to AEP’s subsidiaries.  AEP is the sole equity owner of AEPSC.  AEP management controls the activities of AEPSC.  The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost.  AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered.  AEPSC finances its operations through cost reimbursement from other AEP subsidiaries.  There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business.  AEPSC and its billings are subject to regulation by the FERC.  AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations.  AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure.  However, AEP subsidiaries do not have control over AEPSC.  AEPSC is consolidated by AEP.  In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

Total AEPSC billings to the Registrant Subsidiaries were as follows:

	Three Months Ended March 31,
Company	2012		2011
	(in thousands)
APCo	$	38,546	$	44,941
I&M		26,107		31,827
OPCo		53,445		63,877
PSO		17,596		19,418
SWEPCo		26,720		29,833

The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:

	March 31, 2012				December 31, 2011
	As Reported on the		Maximum		As Reported on the		Maximum
Company	Balance Sheet		Exposure		Balance Sheet		Exposure
	(in thousands)
APCo	$	11,634	$	11,634	$	20,812	$	20,812
I&M		8,226		8,226		13,741		13,741
OPCo		23,565		23,565		29,823		29,823
PSO		5,315		5,315		9,280		9,280
SWEPCo		7,944		7,944		14,699		14,699

131

AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP.  AEGCo owns a 50% ownership interest in Rockport Plant Unit 1, leases a 50% interest in Rockport Plant Unit 2 and owns 100% of the Lawrenceburg Generating Station.  AEGCo sells all the output from the Rockport Plant to I&M and KPCo.   AEGCo leases the Lawrenceburg Generating Station to OPCo.  AEP guarantees all the debt obligations of AEGCo.  I&M and OPCo are considered to have a significant interest in AEGCo due to these transactions.  I&M and OPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations.  In the event AEGCo would require financing or other support outside the billings to I&M, OPCo and KPCo, this financing would be provided by AEP.  For additional information regarding AEGCo’s lease, see the “Rockport Lease” section of Note 12 in the 2011 Annual Report.

Total billings from AEGCo were as follows:

	Three Months Ended March 31,
Company	2012		2011
	(in thousands)
I&M	$	58,822	$	52,821
OPCo		58,417		51,034

The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows:

	March 31, 2012				December 31, 2011
	As Reported on		Maximum		As Reported on		Maximum
Company	the Balance Sheet		Exposure		the Balance Sheet		Exposure
	(in thousands)
I&M	$	15,527	$	15,527	$	25,731	$	25,731
OPCo		17,492		17,492		22,139		22,139

CSPCo-OPCo Merger

On December 31, 2011, CSPCo merged into OPCo with OPCo being the surviving entity.  All prior reported amounts have been recast as if the merger occurred on the first day of the earliest reporting period.   All contracts and operations of CSPCo and its subsidiary are now part of OPCo.

132

2.  RATE MATTERS

As discussed in the 2011 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within the 2011 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition.  The following discusses ratemaking developments in 2012 and updates the 2011 Annual Report.

Regulatory Assets Not Yet Being Recovered

			APCo				I&M
			March 31,		December 31,		March 31,		December 31,
			2012		2011		2012		2011
Noncurrent Regulatory Assets (excluding fuel)			(in thousands)				(in thousands)
Regulatory assets not yet being recovered
	pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Not Earning a Return
	Deferred Wind Power Costs		$	43,642	$	38,192	$	-	$	-
	Virginia Environmental Rate Adjustment Clause			21,412		17,950		-		-
	Mountaineer Carbon Capture and Storage
		Product Validation Facility		14,155		14,155		-		-
	Special Rate Mechanism for Century Aluminum			12,880		12,811		-		-
	Dresden Operating Costs			2,737		-		-		-
	Transmission Agreement Phase-In			2,218		1,925		-		-
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility		1,329		1,335		1,432		1,680
	Litigation Settlement			-		-		10,880		10,803
	Other Regulatory Assets Not Yet Being Recovered			1,439		1,010		-		-
Total Regulatory Assets Not Yet Being Recovered			$	99,812	$	87,378	$	12,312	$	12,483
			OPCo
			March 31,		December 31,
			2012		2011
Noncurrent Regulatory Assets (excluding fuel)			(in thousands)
Regulatory assets not yet being recovered
	pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Earning a Return
	Economic Development Rider		$	12,732	$	12,572
Regulatory Assets Currently Not Earning a Return
	Storm Related Costs			-		8,375
Total Regulatory Assets Not Yet Being Recovered			$	12,732	$	20,947
			PSO				SWEPCo
			March 31,		December 31,		March 31,		December 31,
			2012		2011		2012		2011
Noncurrent Regulatory Assets (excluding fuel)			(in thousands)				(in thousands)
Regulatory assets not yet being recovered
	pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Not Earning a Return
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility	$	-	$	-	$	2,369	$	2,380
	Rate Case Expenses			-		-		1,701		-
	Other Regulatory Assets Not Yet Being Recovered			-		-		1,928		1,699
Total Regulatory Assets Not Yet Being Recovered			$	-	$	-	$	5,998	$	4,079

133

OPCo Rate Matters

Ohio Electric Security Plan Filing

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011.  OPCo collected the 2009 annualized revenue increase over the last nine months of 2009.  The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018.  See the “January 2012 – May 2016 ESP as Rejected by the PUCO” section below.  The PUCO’s March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO.

In October 2011, the PUCO issued an order in the remand proceeding.  As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011.  In February 2012, the Ohio Consumers’ Counsel and the Industrial Energy Users-Ohio (IEU) filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which if ordered could total up to $698 million, excluding carrying costs.

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off of certain pretax earnings in 2010 and a subsequent refund to customers during 2011.  In May 2011, the IEU and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO’s SEET decision.  The OEG’s appeal seeks the inclusion of off-system sales (OSS) in the calculation of SEET which, if ordered, could require an additional refund of $22 million based on the PUCO approved SEET calculation.  The IEU’s appeal also sought the inclusion of OSS as well as other items in the determination of SEET, but did not quantify the amount.  Oral arguments were held in March 2012 and management is unable to predict the outcome of the appeals.  If the Supreme Court of Ohio ultimately determines that additional amounts should be refunded, it could reduce future net income and cash flows and impact financial condition.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order.  Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings, which included OSS in the SEET calculation.  In December 2011, the PUCO staff filed testimony that recommended a $23 million refund of 2010 earnings.  In the fourth quarter of 2011, OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO ordered SEET refund.  OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis.  Management does not currently believe that there are significantly excessive earnings in 2011 for either CSPCo or OPCo.

Management is unable to predict the outcome of the unresolved litigation discussed above.  If these proceedings, including future SEET filings, result in adverse rulings, it could reduce future net income and cash flows and impact financial condition.

January 2012 – May 2016 ESP as Rejected by the PUCO

In December 2011, the PUCO approved a modified stipulation which established a new ESP that included a standard service offer (SSO) pricing for generation.  Various parties filed for rehearing with the PUCO requesting that the PUCO reconsider adoption of the modified stipulation.  In February 2012, the PUCO issued an entry on rehearing which rejected the modified stipulation and ordered a return to the 2011 ESP rates until a new rate plan is approved.

As directed by the February 2012 order, OPCo filed revised tariffs with the PUCO to implement the provisions of the 2011 ESP.  Included in the revised tariffs was the Phase-In Recovery Rider (PIRR) to recover deferred fuel costs as authorized under the 2009 – 2011 ESP order.  See the “2009 – 2011 ESP” section above.  In March 2012, the PUCO issued an order that directed OPCo to file new revised tariffs removing the PIRR and stated that its recovery would be addressed in a future proceeding.  OPCo implemented the new revised tariffs in March 2012.  In March

134

2012, OPCo resumed recording a weighted average cost of capital return on the PIRR deferral in accordance with the 2009 - 2011 ESP order.  In March 2012, OPCo filed a request for rehearing of the March 2012 order relating to the PIRR.  As of March 31, 2012, the net PIRR deferral was $499 million, excluding unrecognized equity carrying costs.  If OPCo is ultimately not permitted to fully recover its PIRR deferral, it would reduce future net income and cash flows and impact financial condition.

As a result of the PUCO’s rejection of the modified stipulation, in the first quarter of 2012, OPCo reversed a $35 million obligation to contribute to Partnership with Ohio and Ohio Growth Fund and an $8 million regulatory asset for 2011 storm damage, both originally recorded in the fourth quarter of 2011.

In March 2012, in response to OPCo’s motion for relief, the PUCO ordered that competitive retail electric service (CRES) providers not qualifying for the Reliability Pricing Model (RPM) price, which is substantially below OPCo’s current capacity cost of approximately $355/MW day, will pay a capacity billing rate of $255/MW day through May 2012, at which time the capacity billing rate will revert to the RPM price.

Proposed June 2012 – May 2015 ESP

In March 2012, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing.  The SSO rates would be effective from June 2012 through May 2015.  The ESP will transition OPCo to an auction-based SSO for capacity and energy by June 1, 2015.  OPCo also filed an application with the PUCO for approval of the corporate separation of its generation assets including the transfer of generation assets to a nonregulated AEP subsidiary at net book value.  Contingent upon OPCo receiving final orders from the PUCO adopting the ESP as proposed and the corporate separation plan as filed, OPCo will conduct an energy-only auction for 5% of the SSO load with delivery beginning six months after the final orders and extending through December 2014.  In addition, a competitive bidding process would determine the price of energy for OPCo’s SSO load from January 2015 through May 2015.  The ESP proposed a two-tiered capacity pricing structure for CRES providers.  The first tier is priced at the RPM rate in effect in March 2012 of $146/MW day to serve approximately 21%, 31% and 41% of each customer class through December 2012, December 2013 and for the period January 2014 through May 2015, respectively.  All other capacity provided to CRES providers would be offered at $255/MW day.  In 2012, an additional amount of capacity may be made available at the $146/MW day rate to accommodate any community aggregation load above 21%, if applicable.

The resolution of the capacity rate is also the subject of separate proceedings before the PUCO and before the FERC.  In those proceedings, OPCo is seeking a wholesale cost-based capacity rate, currently at approximately $355/MW day.  Hearings on the capacity proceedings were held at the PUCO in April 2012.

The ESP also proposed to collect the PIRR from June 2013 through December 2018.  Further, the ESP proposed establishment of a non-bypassable Distribution Investment Rider through May 2015 to recover, with certain caps, post-August 2010 distribution investment.  The filing also seeks establishment of a new non-bypassable Retail Stability Rider (RSR) to recover lost generation revenues to provide financial certainty and stability during the ESP transition period.  The proposed RSR will be effective through May 2015.

Hearings on the June 2012 – May 2015 ESP are scheduled at the PUCO for May 2012 and oral arguments are scheduled for July 3, 2012, which would delay the proposed implementation of rates.  

2011 Ohio Distribution Base Rate Case

In February 2011, OPCo filed with the PUCO for an annual increase in distribution rates of $94 million based upon an 11.15% return on common equity to be effective January 2012.  In December 2011, a stipulation was approved by the PUCO which provided for no change in distribution rates and a new rider for a $15 million annual credit to residential ratepayers due principally to the inclusion of the rate base distribution investment in the Distribution Investment Rider (DIR).

135

Due to the February 2012 PUCO order which rejected the modified stipulation, collection of the DIR terminated.  In March 2012, OPCo filed an application with the PUCO to approve an ESP for the period June 2012 through May 2015, which includes a request for a new DIR.  See the “Proposed June 2012 – May 2015 ESP” section above.  The June 2012 – May 2015 ESP proceeding is currently pending.  In March 2012, the PUCO issued an order clarifying that OPCo has the right to file a new distribution base rate case.  If OPCo is not ultimately permitted to fully recover its costs, it would reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

The PUCO selected an outside consultant to conduct the audit of the FAC for OPCo for the period of January 2009 through December 2009.  In May 2010, the outside consultant provided its audit report to the PUCO.  In January 2012, the PUCO ordered that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance.  Further, the January 2012 PUCO order stated that a consultant be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.  Management is unable to predict the outcome of the consultant’s recommendation.  In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges.  OPCo expects to record the favorable effect of the rehearing order of approximately $30 million in the second quarter of 2012.  If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultants’ review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

2010 and 2011 Fuel Adjustment Clause Audits

In May 2011, the PUCO-selected outside consultant issued its results of the 2010 FAC audit.  The audit report included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes.  The 2011 FAC audit is in progress and an audit report is expected to be issued in the second quarter of 2012.  As of March 31, 2012, the amount of OPCo’s carrying costs that could potentially be at risk due to the 2010 and 2011 audits is estimated to be approximately $32 million, including $17 million of unrecognized equity carrying costs.  Decisions from the PUCO are pending.  Management is unable to predict the outcome of these proceedings.  If PUCO orders result in a reduction in the carrying charges related to the FAC deferrals, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet.  This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009.  In March 2009, the PUCO approved a FAC in the ESP filing and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio.  The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record a regulatory asset for the difference between the approved market price and the rate paid by Ormet.  Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs.  In November 2009, OPCo requested that the PUCO approve recovery of the deferral under the interim agreement plus a weighted average cost of capital carrying charge.  The deferral amount is included in OPCo’s FAC phase-in deferral balance.  In the ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related regulatory asset and requested that the PUCO prevent OPCo from collecting the Ormet-related revenues in the future.  The PUCO did not take any action on this request in the 2009-2011 ESP proceeding.  The intervenors raised the issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.  This issue remains pending before the PUCO.  If OPCo is not ultimately permitted to fully recover its requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

136

Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  Through March 31, 2012, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order and has incurred pre-construction costs.  Intervenors have filed motions with the PUCO requesting all collected pre-construction costs be refunded to Ohio ratepayers with interest.

Management cannot predict the outcome of these proceedings concerning the Ohio IGCC plant or what effect, if any, these proceedings would have on future net income and cash flows.  However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is on target to be in service in the fourth quarter of 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.8 billion, excluding AFUDC, plus an additional $122 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $122 million for transmission, excluding AFUDC.  As of March 31, 2012, excluding costs attributable to its joint owners and a $49 million provision for a Texas capital costs cap, SWEPCo has capitalized approximately $1.5 billion of expenditures (including AFUDC and capitalized interest of $243 million for generation and related transmission costs of $110 million).  As of March 31, 2012, the joint owners and SWEPCo have contractual construction obligations of approximately $90 million (including related transmission costs of $6 million).  SWEPCo’s share of the contractual construction obligations is $67 million.

The PUCT approved a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers.  SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful.  The Texas Industrial Energy Consumers (TIEC) filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers.  In February 2010, the Texas District Court affirmed the PUCT’s order in all respects.  In November 2011, the Texas Court of Appeals affirmed the PUCT’s order in all respects.  Motions for rehearing at the Texas Court of Appeals were denied in January 2012.  In April 2012, SWEPCo and TIEC filed petitions for review at the Supreme Court of Texas.

If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.

Louisiana 2010 Formula Rate Filing

In April 2010, SWEPCo filed its third formula rate plan (FRP) which decreased annual Louisiana retail rates by $3 million effective August 2010, subject to refund.  In October 2010 and September 2011, consultants for the LPSC filed testimony objecting to certain components of SWEPCo’s FRP calculations.  Hearings are scheduled for May 2012.  If the LPSC orders a refund, it would reduce future net income and cash flows.

137

APCo Rate Matters

Virginia Fuel Filing

In April 2012, APCo filed an application with the Virginia SCC for an annual increase in fuel revenues of $117 million to be effective June 2012.  The filing included forecasted costs for the 15-month period ended August 2013 and requested recovery of APCo's anticipated unrecovered fuel balance as of May 2012 over a two-year period commencing in June 2012.  The non-incremental portion of APCo's forecasted and deferred wind purchased power costs are reflected in APCo's filing.  As of March 31, 2012, APCo’s under-recovered fuel balance and non-incremental wind purchased power costs of $84 million were recorded in Regulatory Assets on the balance sheet.  If the Virginia SCC were to disallow a portion of APCo’s deferred fuel costs, including any deferred wind purchased power costs, it would reduce future net income and cash flows.

Environmental Rate Adjustment Clause (RAC)

In November 2011, the Virginia SCC issued an order which approved APCo’s environmental RAC recovery of $30 million to be collected over one year beginning in February 2012 but denied recovery of certain environmental costs.  As a result, in the fourth quarter of 2011, APCo recorded a pretax write-off of $31 million on the statement of income related to environmental compliance costs incurred from January 2009 through December 2010.  In December 2011, APCo filed a notice of appeal with the Supreme Court of Virginia regarding the Virginia SCC’s environmental RAC decision.  If the Supreme Court of Virginia were to issue a favorable decision, it could increase future net income and cash flows.

APCo’s Filings for an IGCC Plant

Through March 31, 2012, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction.  APCo will not start construction of the IGCC plant until sufficient assurance of full cost recovery exists in Virginia and West Virginia.  If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs.  If the costs are not recoverable, it would reduce future net income and cash flows and impact financial condition.

APCo’s Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation, which allows the WVPSC to establish a regulatory framework to securitize certain deferred ENEC balances.  Also in March 2012, APCo filed its fourth year ENEC application with the WVPSC which requested no change in ENEC rates if the WVPSC issues a financing order allowing securitization of the under-recovered ENEC deferral.  The proposed rates consist of a Dresden Plant surcharge of $29 million and an increase in the construction surcharge of $2 million, offset by a reduction of $31 million in current ENEC rates.  APCo anticipates filing, in the second quarter of 2012, a request for a financing order with the WVPSC pursuant to the securitization legislation.  If the financing order is not issued, APCo requested recovery of these costs in current rates.  As of March 31, 2012, APCo’s ENEC under-recovery balance of $334 million was recorded in Regulatory Assets on the balance sheet, excluding $7 million of unrecognized equity carrying costs.  If the WVPSC were to disallow a portion of APCo’s deferred ENEC costs, it could reduce future net income and cash flows and impact financial condition.

WPCo Merger with APCo

In a November 2009 proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division.  The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources.  Merger approvals from the WVPSC, the Virginia SCC and the FERC are required.  In December 2011 and February 2012, APCo and WPCo filed merger applications with the WVPSC and the FERC, respectively.  In February 2012, APCo and WPCo withdrew their merger application with the FERC.  In March 2012, the WVPSC granted APCo’s and WPCo’s request to hold the pending merger docket open for ninety days to enable filings before other commissions to proceed.  Management intends to refile with the FERC and also file with the Virginia SCC in the future.

138

PSO Rate Matters

PSO 2008 Fuel and Purchased Power

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 the Oklahoma Industrial Energy Consumers (OIEC) recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of off-system sales margins decrease from 25% to 10%.  The OIEC 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 AEPEP was filed.  The testimony included unquantified refund recommendations relating to re-pricing of those ERCOT trading contracts.  Hearings were held in June 2011.  If the OCC were to issue an unfavorable decision, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

2011 Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on common equity of 11.15%.  The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.  Final hearings are currently scheduled for June 2012.

Life Cycle Management Project

In April 2012, I&M filed a petition with the IURC for approval of the Cook Plant Life Cycle Management Project (LCM Project).  The LCM Project consists of a group of capital projects that extend the operating lives of Unit 1 and 2 to 2034 and 2037, respectively, which is consistent with the recent extension of their operating licenses.  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  I&M requested recovery of certain project costs, including interest, through a rider effective 2013.  As of March 31, 2012, I&M has incurred $74 million related to the LCM Project.  If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund – Affecting APCo, I&M and OPCo

In 2004, AEP eliminated transaction-based through-and-out transmission service charges and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA through March 2006.  Intervenors objected and the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund.  The AEP East companies recognized gross SECA revenues of $220 million.  APCo’s, I&M’s and OPCo’s portions of recognized gross SECA revenues are as follows:

Company	(in millions)
APCo	$	70.2
I&M		41.3
OPCo		92.1

In 2006, a FERC Administrative Law Judge issued an initial decision finding that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.

AEP filed briefs jointly with other affected companies asking the FERC to reverse the decision.  In May 2010, the FERC issued an order that generally supported AEP’s position and required a compliance filing.

139

The AEP East companies provided reserves for net refunds for SECA settlements totaling $44 million applicable to the $220 million of SECA revenues collected.  APCo’s, I&M’s and OPCo’s portions of the provision are as follows:

Company	(in millions)
APCo	$	14.1
I&M		8.3
OPCo		18.5

Settlements approved by the FERC consumed $10 million of the reserve for refunds applicable to $112 million of SECA revenue.  In December 2010, the FERC issued an order approving a settlement agreement resulting in the collection of $2 million of previously deemed uncollectible SECA revenue.  Therefore, the AEP East companies reduced their reserves for net refunds for SECA settlements by $2 million.  The balance in the reserve for future settlements as of March 31, 2012 was $32 million.  APCo’s, I&M’s and OPCo’s reserve balances as of March 31, 2012 were:

Company	March 31, 2012
	(in millions)
APCo		$	10.0
I&M			5.9
OPCo			13.2

In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC.  If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million.  The AEP East companies could also potentially receive payments up to approximately $10 million including estimated interest of $3 million.  A decision is pending from the FERC.  APCo’s, I&M’s and OPCo’s portions of potential refund payments and potential payments to be received are as follows:

	Potential			Potential
	Refund			Payments to
Company	Payments			be Received
	(in millions)
APCo		$	6.4		$	3.2
I&M			3.7			1.9
OPCo			8.3			4.2

Based on the analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the compliance filing be made final.  Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.

Possible Termination of the Interconnection Agreement – Affecting APCo, I&M and OPCo

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC.  It is unknown at this time whether the Interconnection Agreement will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers, or if each company will choose to operate independently.  Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future.  If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

140

3.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business.  In addition, their business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements.  The Commitments, Guarantees and Contingencies note within the 2011 Annual Report should be read in conjunction with this report.

GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.”  There is no collateral held in relation to any guarantees.  In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters of Credit – Affecting APCo, I&M, OPCo and SWEPCo

Certain Registrant Subsidiaries enter into standby letters of credit with third parties.  These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves.

AEP has two credit facilities totaling $3.25 billion, under which up to $1.35 billion may be issued as letters of credit.  As of March 31, 2012, the maximum future payments for letters of credit issued under the credit facilities were as follows:

Company	Amount		Maturity
	(in thousands)
I&M	$	150	March 2013
SWEPCo		4,448	March 2013

The Registrant Subsidiaries have $357 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $361 million as follows:

				Bilateral			Maturity of
	Pollution			Letters			Bilateral Letters
Company	Control Bonds			of Credit			of Credit
	(in thousands)
APCo		$	229,650		$	232,293	March 2013 to March 2014
I&M			77,000			77,886	March 2013
OPCo			50,000			50,575	March 2013

Guarantees of Third-Party Obligations – Affecting SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $100 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  As of March 31, 2012, SWEPCo has collected approximately $54 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Other Current Liabilities and $38 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed balance sheets.

Sabine charges SWEPCo, its only customer, all of its costs.  SWEPCo passes these costs to customers through its fuel clause.

141

Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of March 31, 2012, there were no material liabilities recorded for any indemnifications.

APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies related to power purchase and sale activity pursuant to the SIA.  PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.

Master Lease Agreements

The Registrant Subsidiaries lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.  At March 31, 2012, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:

	Maximum
Company	Potential Loss
	(in thousands)
APCo	$	2,295
I&M		2,197
OPCo		2,870
PSO		898
SWEPCo		2,242

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignments are accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $16 million and $18 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2012.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 84% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  The maximum potential losses related to the guarantee are approximately $12 million and $13 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, management believes that the fair value would produce a sufficient sales price to avoid any loss.

142

ENVIRONMENTAL CONTINGENCIES

Carbon Dioxide Public Nuisance Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing.  An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place.  Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision.  The petition was denied in January 2011.  Plaintiffs refiled their complaint in federal district court.  The court ordered all defendants to respond to the refiled complaints in October 2011.  In March 2012, the court granted the defendants’ motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations.  Plaintiffs appealed the decision to the Fifth Circuit Court of Appeals.  Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Alaskan Villages’ Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  The plaintiffs appealed the decision.  The court heard oral argument in November 2011.  Management believes the action is without merit and intends to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, the generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials.  The Registrant Subsidiaries currently incur costs to dispose of these substances safely.

In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M started remediation work in accordance with a plan approved by MDEQ.  I&M’s provision is approximately $10 million.  As the remediation work is completed, I&M’s cost may continue to increase as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ.  Management cannot predict the amount of additional cost, if any.

143

NUCLEAR CONTINGENCIES – AFFECTING I&M

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission.  I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S.  Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

Cook Plant Unit 1 Fire and Shutdown

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 are 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 cost approximately $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.  Due to the extensive lead time required to manufacture and install new turbine rotors, I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The installation of the new turbine rotors and other equipment occurred as planned during the fall 2011 refueling outage of Unit 1.

I&M maintains insurance through NEIL.  As of March 31, 2012, I&M recorded $64 million on its condensed balance sheet representing amounts under NEIL insurance policies.  Through March 31, 2012, I&M received payments from NEIL of $203 million for the cost incurred to date to repair the property damage and $185 million under an accidental outage policy.

The claims process with NEIL continues and includes a review of claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies, the timing of the unit’s return to service and whether the return should have occurred earlier reducing the amount received under the accidental outage policy.  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 reduce future net income and cash flows and impact financial condition.

4.  BENEFIT PLANS

The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans.  Substantially all employees are covered by the qualified plan or both the qualified plan and a nonqualified pension plan.  The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide medical and life insurance benefits for retired employees.

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost by Registrant Subsidiary for the plans for the three months ended March 31, 2012 and 2011:

APCo									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended March 31,								Three Months Ended March 31,
	2012				2011				2012				2011
	(in thousands)
Service Cost		$	1,891			$	1,800			$	1,347			$	1,246
Interest Cost			7,553				8,070				4,616				4,867
Expected Return on Plan Assets			(10,486	)			(10,458	)			(4,188	)			(4,496	)
Amortization of Transition Obligation			-				-				200				286
Amortization of Prior Service Cost (Credit)			119				229				(716	)			(43	)
Amortization of Net Actuarial Loss			5,085				4,141				2,631				1,455
Net Periodic Benefit Cost		$	4,162			$	3,782			$	3,890			$	3,315

144

I&M									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended March 31,								Three Months Ended March 31,
	2012				2011				2012				2011
	(in thousands)
Service Cost		$	2,477			$	2,358			$	1,655			$	1,530
Interest Cost			6,561				6,929				3,196				3,403
Expected Return on Plan Assets			(9,391	)			(9,214	)			(3,211	)			(3,472	)
Amortization of Transition Obligation			-				-				33				47
Amortization of Prior Service Cost (Credit)			102				186				(596	)			(59	)
Amortization of Net Actuarial Loss			4,392				3,534				1,762				891
Net Periodic Benefit Cost		$	4,141			$	3,793			$	2,839			$	2,340

OPCo									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended March 31,								Three Months Ended March 31,
	2012				2011				2012				2011
	(in thousands)
Service Cost		$	2,751			$	2,557			$	2,187			$	1,957
Interest Cost			11,298				12,078				6,047				6,375
Expected Return on Plan Assets			(17,100	)			(16,366	)			(5,639	)			(6,129	)
Amortization of Transition Obligation			-				-				26				37
Amortization of Prior Service Cost (Credit)			186				368				(968	)			(53	)
Amortization of Net Actuarial Loss			7,610				6,200				3,417				1,804
Net Periodic Benefit Cost		$	4,745			$	4,837			$	5,070			$	3,991

PSO									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended March 31,								Three Months Ended March 31,
	2012				2011				2012				2011
	(in thousands)
Service Cost		$	1,488			$	1,438			$	709			$	655
Interest Cost			3,075				3,305				1,449				1,512
Expected Return on Plan Assets			(4,504	)			(4,366	)			(1,480	)			(1,566	)
Amortization of Transition Obligation			-				-				-				-
Amortization of Prior Service Credit			(237	)			(236	)			(270	)			(19	)
Amortization of Net Actuarial Loss			2,052				1,678				797				388
Net Periodic Benefit Cost		$	1,874			$	1,819			$	1,205			$	970

SWEPCo									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended March 31,								Three Months Ended March 31,
	2012				2011				2012				2011
	(in thousands)
Service Cost		$	1,775			$	1,642			$	831			$	757
Interest Cost			3,134				3,318				1,668				1,742
Expected Return on Plan Assets			(4,717	)			(4,595	)			(1,699	)			(1,800	)
Amortization of Transition Obligation			-				-				-				-
Amortization of Prior Service Cost (Credit)			(198	)			(198	)			(233	)			65
Amortization of Net Actuarial Loss			2,083				1,680				915				446
Net Periodic Benefit Cost		$	2,077			$	1,847			$	1,482			$	1,210

145

5.  BUSINESS SEGMENTS

The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business.  The Registrant Subsidiaries’ other activities are insignificant.  The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

6.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances.  These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk.  These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates.  AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Trading Strategies

The strategy surrounding the use of derivative instruments for trading purposes focuses on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries.

Risk Management Strategies

The strategy surrounding the use of derivative instruments focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments.  Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.”  Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business.  AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio.   For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities.  AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies.  For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.”  The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors.

146

The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of March 31, 2012 and December 31, 2011:

Notional Volume of Derivative Instruments
March 31, 2012
Primary Risk	Unit of
Exposure	Measure	APCo			I&M			OPCo			PSO			SWEPCo
		(in thousands)
Commodity:
Power	MWHs			133,928			94,735			197,496			41			51
Coal	Tons			3,196			2,251			6,623			2,686			3,449
Natural Gas	MMBtus			12,247			8,613			18,058			102			129
Heating Oil and
Gasoline	Gallons			765			387			916			448			425
Interest Rate	USD		$	22,555		$	15,865		$	33,261		$	-		$	-
Interest Rate and
Foreign Currency	USD		$	-		$	200,000		$	-		$	-		$	69
Notional Volume of Derivative Instruments
December 31, 2011
Primary Risk	Unit of
Exposure	Measure	APCo			I&M			OPCo			PSO			SWEPCo
		(in thousands)
Commodity:
Power	MWHs			169,459			109,326			229,468			39			49
Coal	Tons			3,714			1,920			8,337			3,574			2,974
Natural Gas	MMBtus			7,923			5,081			10,728			115			145
Heating Oil and
Gasoline	Gallons			1,057			525			1,254			618			569
Interest Rate	USD		$	31,029		$	19,890		$	42,093		$	175		$	203
Interest Rate and
Foreign Currency	USD		$	-		$	200,000		$	-		$	-		$	200,069

Fair Value Hedging Strategies

AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt.  Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate.  Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.

Cash Flow Hedging Strategies

AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities.  Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases.  The Registrant Subsidiaries do not hedge all commodity price risk.

The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility.  AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases.  For disclosure purposes, these contracts are included with other hedging activities as “Commodity.”  The Registrant Subsidiaries do not hedge all fuel price risk.

147

AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure.  Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate.  AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt.  The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures.  The Registrant Subsidiaries do not hedge all interest rate exposure.

At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers.  In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar.  The Registrant Subsidiaries do not hedge all foreign currency exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheet at fair value.  The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes.  If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions.  In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due.  Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions.  Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts.  Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles.  Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period.  This is particularly true for longer term contracts.  Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the March 31, 2012 and December 31, 2011 balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

	March 31, 2012						December 31, 2011
	Cash Collateral			Cash Collateral			Cash Collateral			Cash Collateral
	Received			Paid			Received			Paid
	Netted Against			Netted Against			Netted Against			Netted Against
	Risk Management			Risk Management			Risk Management			Risk Management
Company	Assets			Liabilities			Assets			Liabilities
	(in thousands)
APCo		$	2,564		$	23,891		$	4,291		$	28,964
I&M			1,803			16,804			2,752			18,547
OPCo			3,781			35,231			5,810			39,183
PSO			56			15			53			130
SWEPCo			71			19			66			124

148

The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of March 31, 2012 and December 31, 2011:

Fair Value of Derivative Instruments
March 31, 2012
APCo
	Risk
	Management
	Contracts			Hedging Contracts
								Interest Rate
								and Foreign
Balance Sheet Location	Commodity (a)			Commodity (a)				Currency (a)			Other (b)				Total
	(in thousands)
Current Risk Management Assets		$	344,011		$	1,441			$	-		$	(295,932	)		$	49,520
Long-term Risk Management Assets			125,333			257				-			(79,541	)			46,049
Total Assets			469,344			1,698				-			(375,473	)			95,569
Current Risk Management Liabilities			340,686			4,445				-			(312,084	)			33,047
Long-term Risk Management Liabilities			107,485			456				-			(85,970	)			21,971
Total Liabilities			448,171			4,901				-			(398,054	)			55,018
Total MTM Derivative Contract Net
Assets (Liabilities)		$	21,173		$	(3,203	)		$	-		$	22,581			$	40,551
Fair Value of Derivative Instruments
December 31, 2011
APCo
	Risk
	Management
	Contracts			Hedging Contracts
								Interest Rate
								and Foreign
Balance Sheet Location	Commodity (a)			Commodity (a)				Currency (a)			Other (b)				Total
	(in thousands)
Current Risk Management Assets		$	232,784		$	1,040			$	-		$	(194,179	)		$	39,645
Long-term Risk Management Assets			99,751			90				-			(60,615	)			39,226
Total Assets			332,535			1,130				-			(254,794	)			78,871
Current Risk Management Liabilities			235,354			2,767				-			(211,515	)			26,606
Long-term Risk Management Liabilities			82,058			350				-			(69,485	)			12,923
Total Liabilities			317,412			3,117				-			(281,000	)			39,529
Total MTM Derivative Contract Net
Assets (Liabilities)		$	15,123		$	(1,987	)		$	-		$	26,206			$	39,342

149

Fair Value of Derivative Instruments
March 31, 2012
I&M
	Risk
	Management
	Contracts			Hedging Contracts
								Interest Rate
								and Foreign
Balance Sheet Location	Commodity (a)			Commodity (a)				Currency (a)				Other (b)				Total
	(in thousands)
Current Risk Management Assets		$	252,201		$	985			$	-			$	(208,167	)		$	45,019
Long-term Risk Management Assets			90,330			181				-				(55,948	)			34,563
Total Assets			342,531			1,166				-				(264,115	)			79,582
Current Risk Management Liabilities			239,641			3,126				6,026				(219,528	)			29,265
Long-term Risk Management Liabilities			75,604			321				-				(60,470	)			15,455
Total Liabilities			315,245			3,447				6,026				(279,998	)			44,720
Total MTM Derivative Contract Net
Assets (Liabilities)		$	27,286		$	(2,281	)		$	(6,026	)		$	15,883			$	34,862

Fair Value of Derivative Instruments
December 31, 2011
I&M
	Risk
	Management
	Contracts			Hedging Contracts
								Interest Rate
								and Foreign
Balance Sheet Location	Commodity (a)			Commodity (a)				Currency (a)				Other (b)				Total
	(in thousands)
Current Risk Management Assets		$	154,628		$	667			$	-			$	(123,143	)		$	32,152
Long-term Risk Management Assets			68,047			58				-				(38,743	)			29,362
Total Assets			222,675			725				-				(161,886	)			61,514
Current Risk Management Liabilities			149,466			1,747				-				(134,233	)			16,980
Long-term Risk Management Liabilities			52,441			224				10,637				(44,431	)			18,871
Total Liabilities			201,907			1,971				10,637				(178,664	)			35,851
Total MTM Derivative Contract Net
Assets (Liabilities)		$	20,768		$	(1,246	)		$	(10,637	)		$	16,778			$	25,663

150

Fair Value of Derivative Instruments
March 31, 2012
OPCo
	Risk
	Management
	Contracts			Hedging Contracts
								Interest Rate
								and Foreign
Balance Sheet Location	Commodity (a)			Commodity (a)				Currency (a)			Other (b)				Total
	(in thousands)
Current Risk Management Assets		$	519,383		$	2,092			$	-		$	(447,700	)		$	73,775
Long-term Risk Management Assets			185,883			379				-			(117,998	)			68,264
Total Assets			705,266			2,471				-			(565,698	)			142,039
Current Risk Management Liabilities			514,421			6,557				-			(471,518	)			49,460
Long-term Risk Management Liabilities			159,468			674				-			(127,480	)			32,662
Total Liabilities			673,889			7,231				-			(598,998	)			82,122
Total MTM Derivative Contract Net
Assets (Liabilities)		$	31,377		$	(4,760	)		$	-		$	33,300			$	59,917

Fair Value of Derivative Instruments
December 31, 2011
OPCo
	Risk
	Management
	Contracts			Hedging Contracts
								Interest Rate
								and Foreign
Balance Sheet Location	Commodity (a)			Commodity (a)				Currency (a)			Other (b)				Total
	(in thousands)
Current Risk Management Assets		$	325,904		$	1,409			$	-		$	(273,020	)		$	54,293
Long-term Risk Management Assets			136,519			122				-			(83,027	)			53,614
Total Assets			462,423			1,531				-			(356,047	)			107,907
Current Risk Management Liabilities			329,307			3,712				-			(296,458	)			36,561
Long-term Risk Management Liabilities			112,454			474				-			(95,038	)			17,890
Total Liabilities			441,761			4,186				-			(391,496	)			54,451
Total MTM Derivative Contract Net
Assets (Liabilities)		$	20,662		$	(2,655	)		$	-		$	35,449			$	53,456

151

Fair Value of Derivative Instruments
March 31, 2012
PSO
	Risk
	Management
	Contracts				Hedging Contracts
								Interest Rate
								and Foreign
Balance Sheet Location	Commodity (a)				Commodity (a)			Currency (a)			Other (b)				Total
	(in thousands)
Current Risk Management Assets		$	8,887			$	89		$	-		$	(8,116	)		$	860
Long-term Risk Management Assets			755				-			-			(500	)			255
Total Assets			9,642				89			-			(8,616	)			1,115
Current Risk Management Liabilities			12,134				-			-			(8,075	)			4,059
Long-term Risk Management Liabilities			3,910				-			-			(500	)			3,410
Total Liabilities			16,044				-			-			(8,575	)			7,469
Total MTM Derivative Contract Net
Assets (Liabilities)		$	(6,402	)		$	89		$	-		$	(41	)		$	(6,354	)

Fair Value of Derivative Instruments
December 31, 2011
PSO
	Risk
	Management
	Contracts				Hedging Contracts
									Interest Rate
									and Foreign
Balance Sheet Location	Commodity (a)				Commodity (a)				Currency (a)			Other (b)				Total
	(in thousands)
Current Risk Management Assets		$	6,980			$	-			$	-		$	(6,415	)		$	565
Long-term Risk Management Assets			914				-				-			(600	)			314
Total Assets			7,894				-				-			(7,015	)			879
Current Risk Management Liabilities			7,665				107				-			(6,492	)			1,280
Long-term Risk Management Liabilities			1,930				-				-			(600	)			1,330
Total Liabilities			9,595				107				-			(7,092	)			2,610
Total MTM Derivative Contract Net
Assets (Liabilities)		$	(1,701	)		$	(107	)		$	-		$	77			$	(1,731	)

152

Fair Value of Derivative Instruments
March 31, 2012
SWEPCo
	Risk
	Management
	Contracts				Hedging Contracts
								Interest Rate
								and Foreign
Balance Sheet Location	Commodity (a)				Commodity (a)			Currency (a)			Other (b)				Total
	(in thousands)
Current Risk Management Assets		$	14,625			$	86		$	5		$	(13,519	)		$	1,197
Long-term Risk Management Assets			1,253				-			-			(830	)			423
Total Assets			15,878				86			5			(14,349	)			1,620
Current Risk Management Liabilities			24,200				-			-			(13,467	)			10,733
Long-term Risk Management Liabilities			1,139				-			-			(830	)			309
Total Liabilities			25,339				-			-			(14,297	)			11,042
Total MTM Derivative Contract Net
Assets (Liabilities)		$	(9,461	)		$	86		$	5		$	(52	)		$	(9,422	)

Fair Value of Derivative Instruments
December 31, 2011
SWEPCo
	Risk
	Management
	Contracts				Hedging Contracts
									Interest Rate
									and Foreign
Balance Sheet Location	Commodity (a)				Commodity (a)				Currency (a)				Other (b)				Total
	(in thousands)
Current Risk Management Assets		$	6,327			$	-			$	3			$	(5,885	)		$	445
Long-term Risk Management Assets			818				-				-				(536	)			282
Total Assets			7,145				-				3				(6,421	)			727
Current Risk Management Liabilities			11,062				97				19,143				(5,943	)			24,359
Long-term Risk Management Liabilities			757				-				-				(536	)			221
Total Liabilities			11,819				97				19,143				(6,479	)			24,580
Total MTM Derivative Contract Net
Assets (Liabilities)		$	(4,674	)		$	(97	)		$	(19,140	)		$	58			$	(23,853	)

 (a) Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."

 (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."  Amounts also include de-designated risk management contracts.

153

The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three months ended March 31, 2012 and 2011:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended March 31, 2012
Location of Gain (Loss)	APCo				I&M				OPCo				PSO				SWEPCo
	(in thousands)
Electric Generation, Transmission and
Distribution Revenues		$	(327	)		$	2,813			$	8,493			$	(5	)		$	(51	)
Sales to AEP Affiliates			-				-				-				-				-
Fuel and Other Consumables Used for
Electric Generation			-				-				-				-				-
Regulatory Assets (a)			(3,481	)			(3,110	)			(3,131	)			(5,201	)			(6,727	)
Regulatory Liabilities (a)			6,409				6,726				-				27				21
Total Gain (Loss) on Risk Management
Contracts		$	2,601			$	6,429			$	5,362			$	(5,179	)		$	(6,757	)

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended March 31, 2011
Location of Gain (Loss)	APCo			I&M			OPCo				PSO				SWEPCo
	(in thousands)
Electric Generation, Transmission and
Distribution Revenues		$	1,816		$	5,415		$	10,590			$	119			$	123
Sales to AEP Affiliates			20			17			32				1				1
Fuel and Other Consumables Used for
Electric Generation			-			-			-				-				-
Regulatory Assets (a)			373			186			395				(368	)			1,642
Regulatory Liabilities (a)			6,754			360			(105	)			392				340
Total Gain (Loss) on Risk Management
Contracts		$	8,963		$	5,978		$	10,912			$	144			$	2,106

(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.”  Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis.

The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship.  Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes.  Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances.  However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

154

Accounting for Fair Value Hedging Strategies

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change.

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income.  During the three months ended March 31, 2012 and 2011, the Registrant Subsidiaries did not employ any fair value hedging strategies.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income.  The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged.  During the three months ended March 31, 2012 and 2011, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income.  During the three months ended March 31, 2012 and 2011, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur.  During the three months ended March 31, 2012, I&M and SWEPCo designated interest rate derivatives as cash flow hedges.  During the three months ended March 31, 2011, APCo and PSO designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets that were designated as the hedged items in qualifying foreign currency hedging relationships.  During the three months ended March 31, 2012 and 2011, SWEPCo designated foreign currency derivatives as cash flow hedges.

During the three months ended March 31, 2012 and 2011, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

155

The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three months ended March 31, 2012 and 2011.  All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended March 31, 2012
Commodity Contracts	APCo				I&M				OPCo				PSO				SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2011		$	(1,309	)		$	(819	)		$	(1,748	)		$	(69	)		$	(62	)
Changes in Fair Value Recognized in AOCI			(1,845	)			(1,394	)			(2,877	)			139				132
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Electric Generation, Transmission, and
Distribution Revenues			-				-				-				-				-
Fuel and Other Consumables Used for
Electric Generation			-				-				-				-				-
Purchased Electricity for Resale			219				567				1,486				-				-
Other Operation Expense			(2	)			(2	)			(5	)			(2	)			(2	)
Maintenance Expense			(3	)			(1	)			(2	)			-				(1	)
Property, Plant and Equipment			(2	)			(1	)			(3	)			(1	)			(1	)
Regulatory Assets (a)			825				142				-				-				-
Regulatory Liabilities (a)			-				-				-				-				-
Balance in AOCI as of March 31, 2012		$	(2,117	)		$	(1,508	)		$	(3,149	)		$	67			$	66

Interest Rate and
Foreign Currency Contracts	APCo			I&M				OPCo				PSO				SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2011		$	1,024		$	(14,465	)		$	9,454			$	7,218			$	(15,462	)
Changes in Fair Value Recognized in AOCI			-			2,996				-				-				(2,776	)
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Depreciation and Amortization
Expense			-			-				1				-				-
Other Operation Expense			-			-				-				-				-
Interest Expense			269			149				(341	)			(189	)			873
Balance in AOCI as of March 31, 2012		$	1,293		$	(11,320	)		$	9,114			$	7,029			$	(17,365	)

Total Contracts	APCo				I&M				OPCo				PSO				SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2011		$	(285	)		$	(15,284	)		$	7,706			$	7,149			$	(15,524	)
Changes in Fair Value Recognized in AOCI			(1,845	)			1,602				(2,877	)			139				(2,644	)
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Electric Generation, Transmission, and
Distribution Revenues			-				-				-				-				-
Fuel and Other Consumables Used for
Electric Generation			-				-				-				-				-
Purchased Electricity for Resale			219				567				1,486				-				-
Other Operation Expense			(2	)			(2	)			(5	)			(2	)			(2	)
Maintenance Expense			(3	)			(1	)			(2	)			-				(1	)
Depreciation and Amortization
Expense			-				-				1				-				-
Interest Expense			269				149				(341	)			(189	)			873
Property, Plant and Equipment			(2	)			(1	)			(3	)			(1	)			(1	)
Regulatory Assets (a)			825				142				-				-				-
Regulatory Liabilities (a)			-				-				-				-				-
Balance in AOCI as of March 31, 2012		$	(824	)		$	(12,828	)		$	5,965			$	7,096			$	(17,299	)

156

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended March 31, 2011
Commodity Contracts	APCo				I&M				OPCo				PSO				SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2010		$	(273	)		$	(178	)		$	(364	)		$	88			$	82
Changes in Fair Value Recognized in AOCI			178				78				207				212				194
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Electric Generation, Transmission, and
Distribution Revenues			(4	)			(10	)			(26	)			-				-
Fuel and Other Consumables Used for
Electric Generation			-				-				-				-				-
Purchased Electricity for Resale			87				194				521				-				-
Other Operation Expense			(13	)			(9	)			(23	)			(13	)			(13	)
Maintenance Expense			(25	)			(10	)			(19	)			(7	)			(8	)
Property, Plant and Equipment			(23	)			(11	)			(27	)			(16	)			(11	)
Regulatory Assets (a)			311				47				-				-				-
Regulatory Liabilities (a)			-				-				-				-				-
Balance in AOCI as of March 31, 2011		$	238			$	101			$	269			$	264			$	244

Interest Rate and
Foreign Currency Contracts	APCo				I&M				OPCo				PSO				SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2010		$	217			$	(8,507	)		$	10,813			$	8,406			$	(4,272	)
Changes in Fair Value Recognized in AOCI			(373	)			-				-				(476	)			7
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Depreciation and Amortization
Expense			-				-				1				-				-
Other Operation Expense			-				-				-				-				-
Interest Expense			373				252				(341	)			(143	)			207
Balance in AOCI as of March 31, 2011		$	217			$	(8,255	)		$	10,473			$	7,787			$	(4,058	)
Total Contracts	APCo				I&M				OPCo				PSO				SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2010		$	(56	)		$	(8,685	)		$	10,449			$	8,494			$	(4,190	)
Changes in Fair Value Recognized in AOCI			(195	)			78				207				(264	)			201
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Electric Generation, Transmission, and
Distribution Revenues			(4	)			(10	)			(26	)			-				-
Fuel and Other Consumables Used for
Electric Generation			-				-				-				-				-
Purchased Electricity for Resale			87				194				521				-				-
Other Operation Expense			(13	)			(9	)			(23	)			(13	)			(13	)
Maintenance Expense			(25	)			(10	)			(19	)			(7	)			(8	)
Depreciation and Amortization
Expense			-				-				1				-				-
Interest Expense			373				252				(341	)			(143	)			207
Property, Plant and Equipment			(23	)			(11	)			(27	)			(16	)			(11	)
Regulatory Assets (a)			311				47				-				-				-
Regulatory Liabilities (a)			-				-				-				-				-
Balance in AOCI as of March 31, 2011		$	455			$	(8,154	)		$	10,742			$	8,051			$	(3,814	)

(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.

157

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets at March 31, 2012 and December 31, 2011 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
March 31, 2012
	Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
				Interest Rate						Interest Rate							Interest Rate
				and Foreign						and Foreign							and Foreign
Company	Commodity			Currency			Commodity			Currency			Commodity				Currency
	(in thousands)
APCo		$	1,166		$	-		$	4,369		$	-		$	(2,117	)		$	1,293
I&M			792			-			3,073			6,026			(1,508	)			(11,320	)
OPCo			1,683			-			6,443			-			(3,149	)			9,114
PSO			89			-			-			-			67				7,029
SWEPCo			86			5			-			-			66				(17,365	)

	Expected to be Reclassified to
	Net Income During the Next
	Twelve Months								Maximum Term for
					Interest Rate				Exposure to
					and Foreign				Variability of Future
Company	Commodity				Currency				Cash Flows
	(in thousands)								(in months)
APCo		$	(1,986	)		$	(1,037	)		26
I&M			(1,419	)			(612	)		26
OPCo			(2,957	)			1,359			26
PSO			67				759			9
SWEPCo			66				(2,410	)		9

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 2011
	Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
				Interest Rate						Interest Rate							Interest Rate
				and Foreign						and Foreign							and Foreign
Company	Commodity			Currency			Commodity			Currency			Commodity				Currency
	(in thousands)
APCo		$	431		$	-		$	2,418		$	-		$	(1,309	)		$	1,024
I&M			277			-			1,523			10,637			(819	)			(14,465	)
OPCo			584			-			3,239			-			(1,748	)			9,454
PSO			-			-			107			-			(69	)			7,218
SWEPCo			-			3			97			19,143			(62	)			(15,462	)

	Expected to be Reclassified to
	Net Income During the Next
	Twelve Months
					Interest Rate
					and Foreign
Company	Commodity				Currency
	(in thousands)
APCo		$	(1,140	)		$	(1,052	)
I&M			(712	)			(595	)
OPCo			(1,518	)			1,359
PSO			(70	)			759
SWEPCo			(63	)			(1,864	)

(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.

158

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

Credit Risk

AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements which may include collateral requirements.  These master agreements facilitate the netting of cash flows associated with a single counterparty.  Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk.  The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold.  The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy.  In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade.  The amount of collateral required fluctuates based on market prices and total exposure.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts.  The Registrant Subsidiaries have not experienced a downgrade below investment grade.  The following tables represent: (a) the Registrant Subsidiaries’ aggregate fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of March 31, 2012 and December 31, 2011:

	March 31, 2012
	Liabilities for		Amount of Collateral the		Amount
	Derivative Contracts		Registrant Subsidiaries		Attributable to
	with Credit		Would Have Been		RTO and ISO
Company	Downgrade Triggers		Required to Post		Activities
	(in thousands)
APCo	$	6,219	$	7,611	$	7,611
I&M		4,374		5,353		5,353
OPCo		9,171		11,223		11,223
PSO		-		5,355		4,686
SWEPCo		-		6,975		5,906

	December 31, 2011
	Liabilities for		Amount of Collateral the		Amount
	Derivative Contracts		Registrant Subsidiaries		Attributable to
	with Credit		Would Have Been		RTO and ISO
Company	Downgrade Triggers		Required to Post		Activities
	(in thousands)
APCo	$	10,007	$	6,211	$	6,211
I&M		6,418		3,983		3,983
OPCo		13,550		8,410		8,410
PSO		-		856		414
SWEPCo		-		1,128		522

As of March 31, 2012 and December 31, 2011, the Registrant Subsidiaries were not required to post any collateral.

159

In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts.  The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of March 31, 2012 and December 31, 2011:

	March 31, 2012
	Liabilities for				Additional
	Contracts with Cross				Settlement
	Default Provisions				Liability if Cross
	Prior to Contractual		Amount of Cash		Default Provision
Company	Netting Arrangements		Collateral Posted		is Triggered
	(in thousands)
APCo	$	121,922	$	518	$	43,565
I&M		91,784		365		36,669
OPCo		179,790		764		64,242
PSO		181		-		86
SWEPCo		228		-		108

	December 31, 2011
	Liabilities for				Additional
	Contracts with Cross				Settlement
	Default Provisions				Liability if Cross
	Prior to Contractual		Amount of Cash		Default Provision
Company	Netting Arrangements		Collateral Posted		is Triggered
	(in thousands)
APCo	$	76,868	$	8,107	$	27,603
I&M		59,936		5,200		28,339
OPCo		104,091		10,978		37,380
PSO		142		-		61
SWEPCo		19,322		-		19,220

7.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which are non-binding in nature, but are based on recent

160

trades in the marketplace.  When multiple broker quotes are obtained, the quoted bid and ask prices are averaged.  In certain circumstances, a broker quote may be discarded if it is a clear outlier.  Management uses a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.  The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market.   To a lesser extent, these contracts could be sensitive to volumetric estimates for some structured transactions.  However, a significant portion of the Level 3 volumetric contractual positions have been economically hedged which greatly limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts.  AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value.  AEP’s management performs its own valuation testing to verify the fair values of the securities.  AEP receives audit reports of the trustee’s operating controls and valuation processes.  The trustee uses multiple pricing vendors for the assets held in the trusts.

Assets in the nuclear trusts, Other Cash Deposits and Cash and Cash Equivalents are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds.  Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

Fair Value Measurements of Long-term Debt

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of March 31, 2012 and December 31, 2011 are summarized in the following table:

	March 31, 2012						December 31, 2011
Company	Book Value			Fair Value			Book Value			Fair Value
	(in thousands)
APCo		$	3,676,934		$	4,224,974		$	3,726,251		$	4,431,912
I&M			2,041,741			2,268,828			2,057,675			2,339,344
OPCo			3,904,346			4,398,892			4,054,148			4,665,739
PSO			949,393			1,087,296			947,364			1,123,306
SWEPCo			2,047,587			2,277,018			1,728,637			2,019,094

161

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

·   Acceptable investments (rated investment grade or above when purchased).

·   Maximum percentage invested in a specific type of investment.

·   Prohibition of investment in obligations of AEP or its affiliates.

·   Withdrawals permitted only for payment of decommissioning costs and trust expenses.

I&M maintains trust records for each regulatory jurisdiction.  These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities.  The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value.  I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose.  Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the equity and debt investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.  The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities.  Regulatory approval is required to withdraw decommissioning funds.

The following is a summary of nuclear trust fund investments at March 31, 2012 and December 31, 2011:

		March 31, 2012						December 31, 2011
		Estimated		Gross		Other-Than-		Estimated		Gross		Other-Than-
	��	Fair		Unrealized		Temporary		Fair		Unrealized		Temporary
		Value		Gains		Impairments		Value		Gains		Impairments
		(in thousands)
Cash and Cash Equivalents		$	19,159	$	-	$	-	$	18,229	$	-	$	-
Fixed Income Securities:
	United States Government		547,708		49,101		(709)		543,506		60,946		(547)
	Corporate Debt		51,854		4,532		(1,489)		53,979		4,932		(1,536)
	State and Local Government		323,194		380		(1,347)		329,986		(430)		(2,236)
	Subtotal Fixed Income Securities		922,756		54,013		(3,545)		927,471		65,448		(4,319)
Equity Securities - Domestic			719,665		285,562		(80,055)		646,032		214,748		(79,536)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,661,580	$	339,575	$	(83,600)	$	1,591,732	$	280,196	$	(83,855)

162

The following table provides the securities activity within the decommissioning and SNF trusts for the three months ended March 31, 2012 and 2011:

	Three Months Ended March 31,
	2012			2011
	(in thousands)
Proceeds from Investment Sales		$	334,400		$	287,761
Purchases of Investments			352,877			305,945
Gross Realized Gains on Investment Sales			1,552			5,013
Gross Realized Losses on Investment Sales			1,416			5,247

The adjusted cost of debt securities was $869 million and $862 million as of March 31, 2012 and December 31, 2011, respectively.  The adjusted cost of equity securities was $434 million and $431 million as of March 31, 2012 and December 31, 2011, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at March 31, 2012 was as follows:

	Fair Value
	of Debt
	Securities
	(in thousands)
Within 1 year		$	39,247
1 year – 5 years			321,816
5 years – 10 years			340,738
After 10 years			220,955
Total		$	922,756

163

Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 and December 31, 2011.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in management’s valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2012
APCo
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)	$	6,961	$	430,518	$	30,498	$	(374,828	)	$	93,149
Cash Flow Hedges:
Commodity Hedges (a)		-		1,671		26		(531	)		1,166
De-designated Risk Management Contracts (b)		-		-		-		1,254			1,254
Total Risk Management Assets	$	6,961	$	432,189	$	30,524	$	(374,105	)	$	95,569
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)	$	3,966	$	420,306	$	22,532	$	(396,155	)	$	50,649
Cash Flow Hedges:
Commodity Hedges (a)		-		4,889		11		(531	)		4,369
Total Risk Management Liabilities	$	3,966	$	425,195	$	22,543	$	(396,686	)	$	55,018

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2011
APCo
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)	$	4,680	$	302,128	$	25,423	$	(255,324	)	$	76,907
Cash Flow Hedges:
Commodity Hedges (a)		-		1,095		-		(664	)		431
De-designated Risk Management Contracts (b)		-		-		-		1,533			1,533
Total Risk Management Assets	$	4,680	$	303,223	$	25,423	$	(254,455	)	$	78,871
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)	$	2,535	$	291,194	$	23,379	$	(279,997	)	$	37,111
Cash Flow Hedges:
Commodity Hedges (a)		-		3,009		73		(664	)		2,418
Total Risk Management Liabilities	$	2,535	$	294,203	$	23,452	$	(280,661	)	$	39,529

164

Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2012
I&M
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)	$	4,896	$	315,221	$	21,452	$	(263,661	)	$	77,908
Cash Flow Hedges:
Commodity Hedges (a)		-		1,148		18		(374	)		792
De-designated Risk Management Contracts (b)		-		-		-		882			882
Total Risk Management Assets		4,896		316,369		21,470		(263,153	)		79,582
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (d)		-		9,783		-		9,376			19,159
Fixed Income Securities:
United States Government		-		547,708		-		-			547,708
Corporate Debt		-		51,854		-		-			51,854
State and Local Government		-		323,194		-		-			323,194
Subtotal Fixed Income Securities		-		922,756		-		-			922,756
Equity Securities - Domestic (e)		719,665		-		-		-			719,665
Total Spent Nuclear Fuel and Decommissioning Trusts		719,665		932,539		-		9,376			1,661,580
Total Assets	$	724,561	$	1,248,908	$	21,470	$	(253,777	)	$	1,741,162
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)	$	2,790	$	295,645	$	15,848	$	(278,662	)	$	35,621
Cash Flow Hedges:
Commodity Hedges (a)		-		3,439		8		(374	)		3,073
Interest Rate/Foreign Currency Hedges		-		6,026		-		-			6,026
Total Risk Management Liabilities	$	2,790	$	305,110	$	15,856	$	(279,036	)	$	44,720

165

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2011
I&M
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)	$	3,001	$	203,175	$	16,305	$	(162,227	)	$	60,254
Cash Flow Hedges:
Commodity Hedges (a)		-		702		-		(425	)		277
De-designated Risk Management Contracts (b)		-		-		-		983			983
Total Risk Management Assets		3,001		203,877		16,305		(161,669	)		61,514
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (d)		-		5,431		-		12,798			18,229
Fixed Income Securities:
United States Government		-		543,506		-		-			543,506
Corporate Debt		-		53,979		-		-			53,979
State and Local Government		-		329,986		-		-			329,986
Subtotal Fixed Income Securities		-		927,471		-		-			927,471
Equity Securities - Domestic (e)		646,032		-		-		-			646,032
Total Spent Nuclear Fuel and Decommissioning Trusts		646,032		932,902		-		12,798			1,591,732
Total Assets	$	649,033	$	1,136,779	$	16,305	$	(148,871	)	$	1,653,246
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)	$	1,626	$	185,092	$	14,995	$	(178,022	)	$	23,691
Cash Flow Hedges:
Commodity Hedges (a)		-		1,901		47		(425	)		1,523
Interest Rate/Foreign Currency Hedges		-		10,637		-		-			10,637
Total Risk Management Liabilities	$	1,626	$	197,630	$	15,042	$	(178,447	)	$	35,851

166

Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2012
OPCo
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)
Other Cash Deposits (c)	$	26	$	-	$	-	$	39		$	65
Risk Management Assets
Risk Management Commodity Contracts (a) (f)		10,264		647,991		44,973		(564,722	)		138,506
Cash Flow Hedges:
Commodity Hedges (a)		-		2,429		37		(783	)		1,683
De-designated Risk Management Contracts (b)		-		-		-		1,850			1,850
Total Risk Management Assets		10,264		650,420		45,010		(563,655	)		142,039
Total Assets	$	10,290	$	650,420	$	45,010	$	(563,616	)	$	142,104
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)	$	5,849	$	632,776	$	33,226	$	(596,172	)	$	75,679
Cash Flow Hedges:
Commodity Hedges (a)		-		7,209		17		(783	)		6,443
Total Risk Management Liabilities	$	5,849	$	639,985	$	33,243	$	(596,955	)	$	82,122

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2011
OPCo
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)
Other Cash Deposits (c)	$	26	$	-	$	-	$	22		$	48
Risk Management Assets
Risk Management Commodity Contracts (a) (f)		6,339		421,249		34,425		(356,766	)		105,247
Cash Flow Hedges:
Commodity Hedges (a)		-		1,483		-		(899	)		584
De-designated Risk Management Contracts (b)		-		-		-		2,076			2,076
Total Risk Management Assets		6,339		422,732		34,425		(355,589	)		107,907
Total Assets	$	6,365	$	422,732	$	34,425	$	(355,567	)	$	107,955
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)	$	3,433	$	406,259	$	31,659	$	(390,139	)	$	51,212
Cash Flow Hedges:
Commodity Hedges (a)		-		4,038		100		(899	)		3,239
Total Risk Management Liabilities	$	3,433	$	410,297	$	31,759	$	(391,038	)	$	54,451

167

Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2012
PSO
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)	$	135	$	9,492	$	-	$	(8,601	)	$	1,026
Cash Flow Hedges:
Commodity Hedges		-		89		-		-			89
Total Risk Management Assets	$	135	$	9,581	$	-	$	(8,601	)	$	1,115
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)	$	76	$	15,953	$	-	$	(8,560	)	$	7,469

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2011
PSO
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)	$	97	$	7,797	$	-	$	(7,015	)	$	879
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)	$	53	$	9,542	$	-	$	(7,092	)	$	2,503
Cash Flow Hedges:
Commodity Hedges		-		107		-		-			107
Total Risk Management Liabilities	$	53	$	9,649	$	-	$	(7,092	)	$	2,610

168

Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2012
SWEPCo
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)
Cash and Cash Equivalents (c)	$	17,356	$	-	$	-	$	676		$	18,032
Risk Management Assets
Risk Management Commodity Contracts (a) (f)		170		15,682		-		(14,323	)		1,529
Cash Flow Hedges:
Commodity Hedges		-		86		-		-			86
Interest Rate/Foreign Currency Hedges		-		5		-		-			5
Total Risk Management Assets		170		15,773		-		(14,323	)		1,620
Total Assets	$	17,526	$	15,773	$	-	$	(13,647	)	$	19,652
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)	$	96	$	25,217	$	-	$	(14,271	)	$	11,042

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2011
SWEPCo
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)	$	122	$	7,023	$	-	$	(6,421	)	$	724
Cash Flow Hedges:
Interest Rate/Foreign Currency Hedges		-		3		-		-			3
Total Risk Management Assets	$	122	$	7,026	$	-	$	(6,421	)	$	727
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)	$	66	$	11,753	$	-	$	(6,479	)	$	5,340
Cash Flow Hedges:
Commodity Hedges		-		97		-		-			97
Interest Rate/Foreign Currency Hedges		-		19,143		-		-			19,143
Total Risk Management Liabilities	$	66	$	30,993	$	-	$	(6,479	)	$	24,580

(a) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”

(b) Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.”  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This MTM value will be amortized into revenues over the remaining life of the contracts.

(c) Amounts in “Other” column primarily represent cash deposits with third parties.  Level 1 amounts primarily represent investments in money market funds.

(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions.  Level 2 amounts primarily represent investments in money market funds.

(e) Amounts represent publicly traded equity securities and equity-based mutual funds.

(f) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.

There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2012 and 2011.

169

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:

Three Months Ended March 31, 2012		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of December 31, 2011		$	1,971	$	1,263	$	2,666	$	-	$	-
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(3,580)		(2,411)		(5,056)		-		-
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		-		6,509		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		49		31		66		-		-
Purchases, Issuances and Settlements (c)			5,948		4,043		8,477		-		-
Transfers into Level 3 (d) (f)			2,508		1,764		3,699		-		-
Transfers out of Level 3 (e) (f)			(4,001)		(2,814)		(5,900)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		5,086		3,738		1,306		-		-
Balance as of March 31, 2012		$	7,981	$	5,614	$	11,767	$	-	$	-

Three Months Ended March 31, 2011		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of December 31, 2010		$	5,131	$	3,108	$	6,583	$	1	$	2
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(586)		(344)		(736)		-		-
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		-		4,683		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-
Purchases, Issuances and Settlements (c)			(1,333)		(783)		(1,679)		-		-
Transfers into Level 3 (d) (f)			95		57		122		-		-
Transfers out of Level 3 (e) (f)			(2,654)		(1,596)		(3,399)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		4,819		2,767		1,319		(1)		(2)
Balance as of March 31, 2011		$	5,472	$	3,209	$	6,893	$	-	$	-

(a) Included in revenues on the condensed statements of income.

(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.

(c) Represents the settlement of risk management commodity contracts for the reporting period.

(d) Represents existing assets or liabilities that were previously categorized as Level 2.

(e) Represents existing assets or liabilities that were previously categorized as Level 3.

(f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income.  These net gains (losses) are recorded as regulatory assets/liabilities.

170

8.  INCOME TAXES

AEP System Tax Allocation Agreement

The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System.  The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense.  The tax benefit of the Parent is allocated to its subsidiaries with taxable income.  With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Federal and State Income Tax Audit Status

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2009.  The Registrant Subsidiaries completed the examination of the years 2007 and 2008 in April 2011 and settled all outstanding issues on appeal for the years 2001 through 2006 in October 2011.  The settlements did not have a material impact on the Registrant Subsidiaries’ net income, cash flows or financial condition.  The IRS examination of years 2009 and 2010 started in October 2011.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions.  Management is not aware of any issues for open tax years that upon final resolution are expected to have a material effect on net income.

The Registrant Subsidiaries file income tax returns in various state and local jurisdictions.  These taxing authorities routinely examine their tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions.  Management believes that previously filed tax returns have positions that may be challenged by these tax authorities.  However, management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income.  With few exceptions, the Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2000.  In March 2012, AEP settled all outstanding franchise tax issues with the State of Ohio for the years 2000 through 2009.  The settlements did not have a material impact on the Registrants Subsidiaries' net income, cash flows or financial condition.

Uncertain Tax Positions

The reconciliation of the beginning and ending amount of unrecognized tax benefits for OPCo as a result of the franchise tax settlement with the State of Ohio is as follows:

	OPCo
	(in thousands)
Balance at December 31, 2011	$	43,565
Increase - Tax Positions Taken During a Prior Period		-
Decrease - Tax Positions Taken During a Prior Period		(23,813	)
Increase - Tax Positions Taken During the Current Year		-
Decrease - Tax Positions Taken During the Current Year		-
Decrease - Settlements with Taxing Authorities		(4,742	)
Decrease - Lapse of the Applicable Statute of Limitations		-
Balance at March 31, 2012	$	15,010

171

9.  FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first three months of 2012 are shown in the tables below:

		Principal		Interest
Company	Type of Debt	Amount		Rate	Due Date
Issuances:		(in thousands)		(%)
PSO	Notes Payable	$	1,944	3.00	2027
SWEPCo	Senior Unsecured Notes		275,000	3.55	2022
SWEPCo	Notes Payable		65,000	4.58	2032

			Principal		Interest
Company		Type of Debt	Amount Paid		Rate	Due Date
Retirements and			(in thousands)		(%)
	Principal Payments:
APCo		Pollution Control Bonds	$	30,000	6.05	2024
APCo		Pollution Control Bonds		19,500	5.00	2021
APCo		Land Note		6	13.718	2026
I&M		Notes Payable		6,147	Variable	2016
I&M		Notes Payable		4,257	2.12	2016
I&M		Notes Payable		5,548	Variable	2015
I&M		Other Long-term Debt		122	6.00	2025
OPCo		Senior Unsecured Notes		150,000	Variable	2012
SWEPCo		Notes Payable		20,000	7.03	2012

In April 2012, I&M retired $26 million of Notes Payable and issued $110 million of variable rate Notes Payable related to DCC Fuel.

As of March 31, 2012, trustees held, on behalf of OPCo, $418 million of its reacquired Pollution Control Bonds.

Dividend Restrictions

The Registrant Subsidiaries pay dividends to Parent provided funds are legally available.  Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

Federal Power Act

The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.”  The term “capital account” is not defined in the Federal Power Act or its regulations.  As applicable, the Registrant Subsidiaries understand “capital account” to mean the value of the common stock.

Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants.  Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo.

None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

Leverage Restrictions

Pursuant to the credit agreement leverage restrictions, APCo, I&M and OPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.

172

Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of the subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries.  The AEP System Utility Money Pool operates in accordance with the terms and conditions approved in a regulatory order.  The amount of outstanding loans (borrowings) to/from the Utility Money Pool as of March 31, 2012 and December 31, 2011 is included in Advances to/from Affiliates on each of the Registrant Subsidiaries’ balance sheets.  The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the three months ended March 31, 2012 are described in the following table:

									Net
									Loans
	Maximum		Maximum		Average		Average		(Borrowings)		Authorized
	Borrowings		Loans		Borrowings		Loans		to/from Utility		Short-term
	from Utility		to Utility		from Utility		to Utility		Money Pool as of		Borrowing
Company	Money Pool		Money Pool		Money Pool		Money Pool		March 31, 2012		Limit
	(in thousands)
APCo	$	275,241	$	22,614	$	176,597	$	22,377	$	(161,634)	$	600,000
I&M		-		193,190		-		139,106		143,962		500,000
OPCo		30,625		290,356		30,625		175,174		89,840		600,000
PSO		-		76,743		-		49,485		29,136		300,000
SWEPCo		227,087		65,837		179,934		38,120		27,651		350,000

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:

	Three Months Ended March 31,
	2012		2011
Maximum Interest Rate	0.56	%	0.56	%
Minimum Interest Rate	0.45	%	0.06	%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 2012 and 2011 are summarized for all Registrant Subsidiaries in the following table:

	Average Interest Rate						Average Interest Rate
	for Funds Borrowed						for Funds Loaned
	from Utility Money Pool for						to Utility Money Pool for
	Three Months Ended March 31,						Three Months Ended March 31,
Company	2012			2011			2012			2011
APCo		0.51	%		0.38	%		0.51	%		0.17	%
I&M		-	%		0.48	%		0.51	%		0.25	%
OPCo		0.47	%		0.45	%		0.52	%		0.26	%
PSO		-	%		0.47	%		0.51	%		0.19	%
SWEPCo		0.53	%		0.36	%		0.51	%		0.32	%

Short-term Debt
The Registrant Subsidiaries’ outstanding short-term debt was as follows:
			March 31, 2012				December 31, 2011
			Outstanding		Interest		Outstanding		Interest
	Company	Type of Debt	Amount		Rate (a)		Amount		Rate (a)
			(in thousands)				(in thousands)
SWEPCo		Line of Credit – Sabine	$	-	-	%	$	17,016	1.79	%

(a) Weighted average rate.

173

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 3.

Sale of Receivables – AEP Credit

Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables.  APCo does not have regulatory authority to sell its West Virginia accounts receivable.  The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ income statements.  The Registrant Subsidiaries manage and service their customer accounts receivable sold.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of March 31, 2012 and December 31, 2011 was as follows:

	March 31,			December 31,
Company	2012			2011
	(in thousands)
APCo		$	131,909		$	121,605
I&M			122,370			121,597
OPCo			361,495			346,695
PSO			102,258			123,172
SWEPCo			114,510			140,440

The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:

	Three Months Ended March 31,
Company	2012			2011
	(in thousands)
APCo		$	2,130		$	2,575
I&M			1,543			1,627
OPCo			5,916			4,035
PSO			1,732			1,234
SWEPCo			1,386			1,100

The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:

	Three Months Ended March 31,
Company	2012			2011
	(in thousands)
APCo		$	346,526		$	366,209
I&M			339,581			351,021
OPCo			837,897			911,038
PSO			272,795			268,569
SWEPCo			321,608			314,124

174

COMBINED MANAGEMENT’S NARRATIVE DISCUSSION

AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the Registrant Subsidiaries’ management’s discussion and analysis.  The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (a) Management’s Narrative Financial Discussion and Analysis, (b) financial statements, (c) footnotes and (d) the schedules of each individual registrant.  The Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries section of the 2011 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

Cost Reduction Initiatives

In April 2012, management initiated a process to identify employee repositioning opportunities and efficiencies that will result in sustainable cost savings.  The process will result in the redeployment of employees and involuntary severances.  The process is expected to be completed by the end of 2012.

ENVIRONMENTAL ISSUES

The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements.  The Registrant Subsidiaries will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants from fossil fuel-fired power plants, new proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.

The Registrant Subsidiaries are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of I&M’s nuclear units.  Management is also engaged in the development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change.  AEP, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court.  The U.S. House of Representatives passed legislation called the Transparency in Regulatory Analysis of Impacts on the Nation (the TRAIN Act) that would delay implementation of certain Federal EPA rules to facilitate a comprehensive analysis of their impacts.  The Senate is considering similar legislation.  Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

See a complete discussion of these matters in the “Environmental Issues” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2011 Annual Report.  Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  The Registrant Subsidiaries should be able to recover certain of these expenditures through market prices in deregulated jurisdictions.  If not, the costs of environmental compliance could reduce future net income and cash flows and impact financial condition.

175

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of March 31, 2012, the AEP System had a total generating capacity of nearly 37,080 MWs, of which 23,900 MWs are coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the coal-fired generating facilities.  For the Registrant Subsidiaries, management’s current ranges of estimates of environmental investments to comply with these proposed requirements are listed below:

	2012 to 2020
	Estimated Environmental Investment
Company	Low			High
	(in millions)
APCo		$	415		$	515
I&M			1,490			1,710
OPCo			1,260			1,510
PSO			430			530
SWEPCo			1,250			1,450

For APCo and OPCo, the projected environmental investments above include the conversion of 470 MWs and 585 MWs, respectively, of coal generation to natural gas-fired generation.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules.  The cost estimates for each Registrant Subsidiary will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose standards more stringent than the proposed rules, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.

Subject to the factors listed above and based upon continuing evaluation, management has given notice to the applicable RTO of the intent to retire the following plants or units of plants before or during 2015:

		Generating
Company	Plant Name and Unit	Capacity
		(in MWs)
APCo	Clinch River Plant, Unit 3		235
APCo	Glen Lyn Plant		335
APCo	Kanawha River Plant		400
APCo/OPCo	Philip Sporn Plant, Units 1-4		600
I&M	Tanners Creek Plant, Units 1-3		495
OPCo	Conesville Plant, Unit 3		165
OPCo	Kammer Plant		630
OPCo	Muskingum River Plant, Units 1-4		840
OPCo	Picway Plant		100
SWEPCo	Welsh Plant, Unit 2		528

Duke Energy Corporation, the operator of W. C. Beckjord Generating Station, has announced its intent to close the facility in 2015.  OPCo owns 12.5% (54 MWs) of one unit at that station.

Management is monitoring the potential impact that the proposed corporate separation of OPCo’s generation assets and the proposed termination of the Interconnection Agreement could have on the recoverability of OPCo's generation assets.

176

In April 2012, management reached an agreement in principle with the Federal EPA, the State of Oklahoma and other parties to retire one coal-fired unit of PSO’s Northeastern Station no later than 2016, install emission controls on the second coal-fired Northeastern unit and retire the second unit no later than 2026.  These two coal-fired units have a combined generating capacity of 930 MWs.   The parties are working toward a final settlement agreement.  Management expects this agreement, if approved, to reduce PSO's environmental investments for 2012 to 2020 by approximately $400 million to the amounts shown in the table above.

Plans for and the timing of conversion of some of the coal units to natural gas, installing emission control equipment on other units and closure of existing units will be impacted by changes in emission requirements and demand for power.  To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows.

Scrubber Applications

Rockport Plant

I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit its Rockport Plant.  As part of I&M’s compliance plan to address new environmental requirements, I&M needs to install FGD and selective catalytic reduction equipment on one unit of the Rockport Plant.  As a result of environmental requirements, I&M is evaluating options related to maturity of the lease for Rockport Plant Unit 2 in 2022.  If I&M receives approval of a CPCN, I&M will file for cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism.  An IURC decision is expected in the third quarter of 2012.

Flint Creek Plant

In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to go forward with the estimated $408 million FGD project at the Flint Creek Plant.  As a joint owner of the Flint Creek Plant, SWEPCo’s portion of the FGD project costs is estimated at $204 million.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions.  The states implement and administer many of these programs and could impose additional or more stringent requirements.

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas.  BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.  CAVR will be implemented through individual state implementation plans (SIPs) or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs).  The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas and Oklahoma.  The Federal EPA finalized a FIP for Oklahoma that contains more stringent control requirements for SO2 emissions from affected units in that state.  No action has been finalized in Arkansas.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for SO2, NOx and lead, and is currently reviewing the NAAQS for ozone and PM.  States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for facilities as a result of those evaluations.  Management cannot currently predict the nature, stringency or timing of those requirements.

Notable developments in significant CAA regulatory requirements affecting the Registrant Subsidiaries’ operations are discussed in the following sections.

177

Cross-State Air Pollution Rule (CSAPR)

In August 2011, the Federal EPA issued CSAPR.  Certain revisions to the rule were finalized in March 2012.  CSAPR relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states.  Interstate trading of allowances is allowed on a restricted sub-regional basis beginning in 2012.  Arkansas and Louisiana are subject only to the seasonal NOx program in the rule.  Texas is subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program.  The annual SO2 allowance budgets in Indiana, Ohio and West Virginia have been reduced significantly in the rule.  Numerous affected entities, states and other parties filed petitions to review the CSAPR in the United States Court of Appeals for the District of Columbia Circuit.  Several of the petitioners filed motions to stay the implementation of the rule pending judicial review.  In December 2011, the court granted the motions for stay.  Oral argument was heard in April 2012.  A supplemental rule includes Oklahoma in the seasonal NOx program.  The supplemental rule was finalized in December 2011, with an increased NOx emission budget for the 2012 compliance year.  A separate appeal of the supplemental rule has been filed, but is being held in abeyance until the court issues a decision in the main CSAPR appeal.

The time frames and stringency of the required emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and its electric utility customers.   Management cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In February 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal, on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  The effective date of the final rule was April 16, 2012 and compliance is required within three years.

The final rule contains a slightly less stringent PM limit than the original proposal and allows operators to exclude periods of startup and shutdown from the emissions averaging periods.  The compliance time frame remains a serious concern.  A one-year administrative extension may be available if the extension is necessary for the installation of controls or to avoid a serious reliability problem.  In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades.  Management is concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines.  The AEP System is participating in petitions for review filed in the United States Court of Appeals for the District of Columbia Circuit by several organizations in which the Registrant Subsidiaries are members.

Regional Haze – Affecting PSO

In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze SIP submitted by the State of Oklahoma through the Department of Environmental Quality.  The Federal EPA proposed to approve all of the NOx control measures in the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO.  The Federal EPA proposed a FIP that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP.  PSO submitted comments on the proposed action demonstrating that the cost-effectiveness calculations performed by the Federal EPA were unsound, challenging the period for compliance with the final rule and showing that the visibility improvements secured by the proposed SIP were significant and cost-effective.  The Federal EPA finalized the FIP in December 2011 that mirrored the proposed rule but established a five-year compliance schedule.  PSO filed a petition for review of the FIP in the Tenth Circuit Court of Appeals and engaged in settlement discussions with the Federal EPA, the State of Oklahoma and other parties.  In April 2012, an agreement in principle was reached that would provide for submission of a revised Regional Haze SIP requiring the retirement of one coal-fired unit of PSO’s Northeastern Station no later than 2016, installation of emission controls on the second coal-fired Northeastern unit and retirement of the second unit no later than 2026.  The parties are working toward finalizing a settlement agreement.

178

CO2 Regulation

In March 2012, the Federal EPA issued a proposal to regulate CO2 emissions from new fossil fuel-fired electricity generating units.  The proposed rule establishes a new source performance standard of 1,000 pounds of CO2 per megawatt hour of electricity generated, a rate that most natural gas combined cycle units can meet, but that is substantially below the emission rate of a new pulverized coal generator or an integrated gas combined cycle unit that uses coal for fuel.  As proposed, the rule does not apply to new gas-fired stationary combustion turbines used as peaking units, does not apply to existing, modified or reconstructed sources, and does not apply to units whose CO2 emission rate increases as a result of the addition of pollution control equipment to control criteria or HAPs.  The rule is not anticipated to have a significant immediate impact on the AEP System since it does not apply to existing units or units that have already commenced construction, like SWEPCo’s Turk Plant.  Once the proposal is published in the Federal Register, the Federal EPA intends to solicit comments for 60 days.  Management will be evaluating the proposal and preparing comments to submit to the Federal EPA.

Coal Combustion Residual Rule

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 the coal-fired electric generating units.  The rule contains two alternative proposals.  One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management.  Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule.  In October 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment.

Currently, approximately 40% of the coal ash and other residual products from the AEP System’s generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses.  Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes.  In addition,   surface impoundments and landfills to manage these materials are currently used at the generating facilities.  The Registrant Subsidiaries will incur significant costs to upgrade or close and replace their existing facilities under the proposed solid waste management alternative.  Regulation of these materials as hazardous wastes would significantly increase these costs.  As the rule is not final, management is unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

Clean Water Act Regulations

In April 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling.  Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority.  Management is evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at the AEP System’s facilities.  Comments on the proposal were submitted in July and August 2011.  A final rule is expected to be signed by the Federal EPA Administrator by the end of July 2012.  Management is preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

179

Global Warming

National public policy makers and regulators in the 10 states the Registrant Subsidiaries serve have conflicting views on global warming.  While comprehensive economy-wide regulation of CO2 emissions might be achieved through future legislation, Congress has yet to enact such legislation.  The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA.

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 the Registrant Subsidiaries have generating facilities.  Certain states, including Michigan, Ohio, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements.  Management is taking steps to comply with these requirements.

Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others.  The Registrant Subsidiaries have been named in pending lawsuits, which management is defending.  In March 2012, the court granted the defendants’ motion for dismissal of the suit in “Carbon Dioxide Public Nuisance Claims” on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations.  Plaintiffs appealed the decision to the Fifth Circuit Court of Appeals.  It is not possible to predict the outcome of these lawsuits or their impact on operations or financial condition.  See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 3.

Future federal and state legislation or regulations that mandate limits on the emission of CO2 would result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force the Registrant Subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets.  As a result, mandatory limits could reduce future net income and cash flows and impact financial condition.

For additional information on global warming, other environmental issues and the actions management is taking to address potential impacts, see Part I of the 2011 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters” and “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries.”

ACCOUNTING PRONOUNCEMENTS

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, management cannot determine the impact on the reporting of the Registrant Subsidiaries’ operations and financial position that may result from any such future changes.  The FASB is currently working on several projects including revenue recognition, contingencies, financial instruments, leases, insurance, hedge accounting and consolidation policy.  Management also expects to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP.  The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.

Item 4.     Controls and Procedures

During the first quarter of 2012, management, including the principal executive officer and principal financial officer of each of AEP, APCo, I&M, OPCo, PSO and SWEPCo (collectively, the Registrants), evaluated the Registrants’ disclosure controls and procedures.  Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

180

As of March 31, 2012, 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.

In 2012, customers continued to switch from OPCo to competitive retail electric service providers.  Related to this growth in customer switching, AEP and OPCo implemented or modified a number of business processes and controls in connection with customer switching and related financial reporting.  Apart from this, there have been no material changes (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter of 2012 that have materially affected, or are reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.     Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 3incorporated herein by reference.

Item 1A.  Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2011 includes a detailed discussion of risk factors.  The information presented below amends and restates, in their entirety, certain of those risk factors that have been updated and should be read in conjunction with the risk factors and information disclosed in the 2011 Annual Report on Form 10-K.

GENERAL RISKS OF OUR REGULATED OPERATIONS

Rate and other recovery in Ohio for distribution service may not provide full recovery of costs. – Affecting AEP and OPCo

In February 2011, OPCo filed with the PUCO for an annual increase in distribution rates.  In December 2011, a stipulation was approved by the PUCO providing recovery of certain distribution regulatory assets.  Due to a February 2012 PUCO order which rejected the modified stipulation, collection of the Distribution Investment Rider (DIR) terminated.  In March 2012, OPCo filed an application with the PUCO to approve an ESP for the period June 2012 through May 2015, which includes a request for a new DIR.  If OPCo is not ultimately permitted to recover its costs and deferrals, it would reduce future net income and cash flows and impact financial condition.

Rate recovery in Ohio for generation service may not provide full recovery of costs. – Affecting AEP and OPCo

In March 2012, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing.  The SSO rates would be effective through May 2015.  The ESP will transition OPCo to an auction-based SSO for capacity and energy by June 1, 2015.  If OPCo is not ultimately permitted to recover its costs, it would reduce future net income and cash flows and impact financial condition.

Rate recovery approved in Ohio may have to be returned and/or may not provide full recovery of costs. – Affecting AEP and OPCo

The PUCO issued an order in March 2009 that modified and approved the 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 provided a fuel adjustment clause for the three-year period of the ESP.  The recovery under the fuel adjustment clause included deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges.  In January 2011, the PUCO issued an order on the 2009 SEET filing, which is currently under appeal at the Supreme Court of Ohio.  In July 2011, OPCo filed its 2010 SEET filing with the PUCO.  OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis.  If the PUCO and/or the Supreme Court of Ohio reverses all or part of the rate recovery or if deferred fuel costs are not recovered for other reasons, it could reduce future net income and cash flows and impact financial condition.

181

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

In January 2012, the PUCO ordered that proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance.  Further, the January 2012 PUCO order stated that a consultant be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.  Management is unable to predict the outcome of the consultant’s recommendation.  If the PUCO ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition.

In May 2011, the PUCO-selected outside consultant issued its results of the 2010 FAC audit.  The audit report included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes.  The 2011 FAC audit is in progress and an audit report is expected to be issued in the second quarter of 2012.  If the PUCO orders result in a reduction in the carrying charges related to the FAC deferrals, it would reduce future net income and cash flows and impact financial condition.

Request for rate recovery in Indiana may not be approved in its entirety. – Affecting AEP and I&M

In September 2011, I&M filed a request with the IURC for annual increases in Indiana base rates.  If the IURC denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

RISKS RELATING TO STATE RESTRUCTURING

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

In March 2012, OPCo filed a corporate separation plan with the PUCO for its generation assets.  Additional filings at the FERC and other state commissions related to corporate separation are expected to be filed in the future.  If all regulatory approvals are received, APCo and KPCo will seek recovery of associated costs from customers through their regulated rates.  Our results of operations related to generation will be determined by our ability to sell power and capacity at a profit at rates determined by the prevailing market.  If we are unable to sell power and capacity at a profit, it could reduce future net income and cash flows and impact financial condition.  We can give no assurance that the PUCO, the FERC or other state commissions will not impose material adverse terms as a condition to approving our corporate 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.  This could result in material impairments.

We are unable to predict the consequences of terminating the Interconnection Agreement. – 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 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 Interconnection Agreement will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral 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 Interconnection Agreement 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 intend to file an application to terminate the Interconnection Agreement with the FERC in the future.  We can give no assurance that the FERC will not impose material adverse terms as a condition to approving these arrangements.

182

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

NONE

Item 4.  Mine Safety Disclosures

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations.  The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters.  SWEPCo, through its ownership of DHLC, and OPCo, through its ownership of Conesville Coal Preparation Company (CCPC) and use of the Conner Run fly ash impoundment, are subject to the provisions of the Mine Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act and its related regulations require companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act.  Exhibit 95 contains the notices of violation and proposed assessments received by DHLC, CCPC and Conner Run under the Mine Act for the quarter ended March 31, 2012.

Item 5.  Other Information

NONE

Item 6.  Exhibits

10 – AEP Stock Unit Accumulation Plan for Non-Employee Directors

12 – Computation of Consolidated Ratio of Earnings to Fixed Charges

31(a) – Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31(b) – Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32(a) – Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

32(b) – Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

95 – Mine Safety Disclosures

101.INS – XBRL Instance Document

101.SCH – XBRL Taxonomy Extension Schema

101.CAL – XBRL Taxonomy Extension Calculation Linkbase

101.DEF – XBRL Taxonomy Extension Definition Linkbase

101.LAB – XBRL Taxonomy Extension Label Linkbase

101.PRE – XBRL Taxonomy Extension Presentation Linkbase

183

SIGNATURE

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

AMERICAN ELECTRIC POWER COMPANY, INC.

By: /s/ Joseph M. Buonaiuto

Joseph M. Buonaiuto

Controller and Chief Accounting Officer

APPALACHIAN POWER COMPANY

INDIANA MICHIGAN POWER COMPANY

OHIO POWER COMPANY

PUBLIC SERVICE COMPANY OF OKLAHOMA

SOUTHWESTERN ELECTRIC POWER COMPANY

By: /s/ Joseph M. Buonaiuto

Joseph M. Buonaiuto

Controller and Chief Accounting Officer

Date:  April 27, 2012

184