Edgar Filing: AMERICAN ELECTRIC POWER CO INC

Unassociated Document

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 June 30, 2012

[ ] 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 July 26, 2012

American Electric Power Company, Inc.			484,902,556
			($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

June 30, 2012

			Page Number
Glossary of Terms			i

Forward-Looking Information			iv

Part I. FINANCIAL INFORMATION

		Items 1, 2 and 3 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Quantitative and Qualitative Disclosures About Market Risk:
American Electric Power Company, Inc. and Subsidiary Companies:
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		1
	Condensed Consolidated Financial Statements		30
	Index of Condensed Notes to Condensed Consolidated Financial Statements		36

Appalachian Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations		80
	Condensed Consolidated Financial Statements		86
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		92

Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations		94
	Condensed Consolidated Financial Statements		100
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		106

Ohio Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations		108
	Condensed Consolidated Financial Statements		115
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		121

Public Service Company of Oklahoma:
	Management’s Narrative Discussion and Analysis of Results of Operations		123
	Condensed Financial Statements		126
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		132

Southwestern Electric Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations		134
	Condensed Consolidated Financial Statements		139
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		145

Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries			146

Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries			201

Controls and Procedures			207

Part II. OTHER INFORMATION

	Item 1.	Legal Proceedings		208
	Item 1A.	Risk Factors		208
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		211
	Item 4.	Mine Safety Disclosures		211
	Item 5.	Other Information		211
	Item 6.	Exhibits:		211
			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				212

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 consolidated variable interest entity of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East companies		APCo, I&M, KPCo and OPCo.
AEP Energy		AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States. BlueStar began doing business as AEP Energy, Inc. in June 2012.
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. BlueStar began doing business as AEP Energy, Inc. in June 2012.
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.
CRES		Competitive Retail Electric Service.
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, DCC Fuel IV LLC and DCC Fuel V LLC, consolidated 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 and consolidated variable interest entity of AEP.
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.

Term		Meaning

FERC		Federal Energy Regulatory Commission.
FGD		Flue Gas Desulfurization or scrubbers.
FTR		Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP		Accounting Principles Generally Accepted in the United States of America.
I&M		Indiana Michigan Power Company, an AEP electric utility subsidiary.
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.
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.

Term		Meaning

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.
Stall Unit		J. Lamar Stall Unit at Arsenal Hill Plant.
SWEPCo		Southwestern Electric Power Company, an AEP electric utility subsidiary.
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 recent storms in our eastern service territory, 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 could result in an accelerated return of deferred federal income taxes to customers.
·	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.
·	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.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

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 through May 2015. The ESP will transition OPCo to an auction-based SSO for capacity and energy by June 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 would be effective through May 2015. Finally, the ESP proposed a storm damage recovery mechanism for the deferral of operation and maintenance costs above $5 million, effective January 2012.

Intervenors and the PUCO staff filed testimony in May 2012 in opposition to many aspects of OPCo’s ESP, including the proposed RSR and the two-tiered capacity pricing structure for CRES providers. In addition, the PUCO staff’s testimony included a proposal to increase the vegetation management base used for calculating over/under recovery on incremental vegetation spend from $21 million to $39 million, which could increase future Other Operation and Maintenance expense by $18 million on an annual basis. A decision from the PUCO is expected in August 2012. See “Ohio Electric Security Plan Filing” section of Note 2.

Ohio Customer Choice

In our Ohio service territory, various CRES providers are targeting retail customers by offering alternative generation service. As a result, in comparison to the second quarter of 2011 and the first six months of 2011, we lost approximately $56 million and $99 million, respectively, of gross margin. We are recovering a portion of lost margins through collection of capacity revenues from 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. We have lost 34% of our Ohio load to CRES providers. To enhance our competitive position in Ohio, AEP Retail Energy Partners LLC targets retail customers, both within and outside of our retail service territory.

Ohio Capacity Rate

In March 2012, in response to OPCo’s motion for relief, the PUCO ordered that CRES providers not qualifying for the tier one capacity billing rate of $146/MW day, which is substantially below OPCo’s current capacity cost of approximately $355/MW day, will pay a tier two capacity billing rate of $255/MW day. In July 2012, the PUCO issued an order in the capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer its incurred capacity costs not recovered from CRES providers to the extent that the total incurred capacity costs do not exceed $188.88/MW day. The RPM price is approximately $20/MW day through May 2013. The order stated that the PUCO would establish an appropriate recovery mechanism in the pending June 2012 – May 2015 ESP proceeding. The PUCO postponed implementation of the order until August 8, 2012 or until an order is issued in OPCo’s pending June 2012 – May 2015 ESP proceeding, whichever is sooner. In July 2012, OPCo requested rehearing of the PUCO order. See “Ohio Electric Security Plan Filing” section of Note 2.

Proposed Corporate Separation and Termination of the Interconnection Agreement

In March 2012, OPCo 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. 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, 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. A decision is pending from the PUCO.

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.

Sustainable Cost Reductions

In April 2012, we initiated a process to identify employee repositioning opportunities and efficiencies that will result in sustainable cost savings. We recorded a charge to expense of $13 million in the second quarter of 2012 related to the elimination of approximately 170 positions in the first phase of this process. In May 2012, we selected one consulting firm to conduct an organizational and process optimization evaluation and a second consulting firm to evaluate our current employee benefit programs. The second phase of this process is expected to be completed by the end of 2012 with additional cost reductions.

Storm Damage

In late June 2012 and early July 2012, our eastern service territory was significantly impacted by several severe storms. In the second quarter of 2012, AEP recorded minimal incremental operation and maintenance expenses related to the June 2012 storms. AEP expects to incur an estimated $230 million in total storm restoration costs in the third quarter of 2012, including an estimated $70 million in capital spending related to these storms and an estimated $160 million in incremental operation and maintenance costs. We intend to defer the majority of the incremental operation and maintenance costs and seek future recovery. If we are not ultimately permitted to recover these storm costs, it would reduce future net income and cash flows and impact financial condition.

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. 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 refunds of 2010 earnings. OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis. The PUCO approved OPCo’s request to file the 2011 SEET on July 31, 2012 or one month after the PUCO issues an order on the 2010 SEET, whichever is later. Management does not currently believe that there were 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 $149 million net annual increase reflects an increase in base rates of $178 million offset by proposed corresponding reductions of $13 million to the off-system sales sharing rider, $9 million to the PJM cost rider and $7 million to the clean coal technology rider rates. The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.

In May 2012, the Indiana Office of Utility Consumer Counselor filed testimony that recommended an increase in base rates of $28 million, excluding reductions to certain riders, based upon a return on common equity of 9.2%. I&M filed rebuttal testimony in May 2012 which supported an increase of $170 million in base rates, excluding reductions to certain riders. Final hearings were held in June 2012. A decision from the IURC is expected in the fourth quarter of 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 pulverized coal ultra-supercritical generating unit in Arkansas, which is scheduled 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.

Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million based upon an 11.25% return on common equity to be effective January 2013. The requested base rate increase includes a return on and of the Texas jurisdictional share of Turk Plant generation investment at December 2011 and total estimated transmission costs of the Turk Plant along with associated costs, including operations and maintenance costs. It also proposed vegetation management expenditures and includes recovery of the Stall Unit.

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. 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.

Life Cycle Management Project

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects for Cook Plant Units 1 and 2. The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.

In Indiana, I&M requested recovery of certain project costs, including interest, through a rider effective January 2013. In Michigan, I&M requested that the MPSC approve a Certificate of Public Convenience and Necessity and authorize I&M to defer, on an interim basis, incremental depreciation and property tax costs, including interest, along with study, analysis and development costs until the applicable costs are included in I&M’s base rates. As of June 30, 2012, I&M has incurred $92 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.

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 June 30, 2012, the AEP System had a total generating capacity of 37,035 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 RTOs of our intent to retire the following plants or units of plants before or during 2016:

		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 in 2016 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.

Environmental Control Applications

Rockport Plant

I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit one unit at its Rockport Plant with environmental controls estimated to cost $1.4 billion to comply with new requirements. AEGCo and I&M jointly own Unit 1 and jointly lease Unit 2 of the Rockport Plant. I&M is also evaluating options related to the maturity of the lease for Rockport Plant Unit 2 in 2022 and continues to investigate alternative compliance technologies for these Units as part of its overall compliance strategy. As of June 30, 2012, AEGCo and I&M have incurred $10 million and $10 million, respectively, related to this project.

In July 2012, certain intervenors filed testimony which recommended costs caps ranging from $1.1 billion to $1.4 billion if the IURC approved the CPCN. In addition, the Indiana Office of Utility Consumer Counselor recommended the CPCN be denied until a more detailed and precise project plan and cost estimates are filed with the IURC. 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 fourth quarter of 2012.

Big Sandy Unit 2 FGD System

In May 2012, KPCo filed a motion with the KPSC to withdraw its application seeking approval of a Certificate of Public Convenience and Necessity to retrofit Big Sandy Unit 2 with a dry FGD system. The motion was accepted by the KPSC in May 2012. KPCo is currently re-evaluating its needs to meet the short and long-term energy needs of its customers at the most reasonable costs. KPCo has not determined its future plan. As of June 30, 2012, KPCo has incurred $29 million related to the project. Management intends to pursue recovery of all costs related to this project. 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 install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA. The estimated cost of the project is $408 million, excluding AFUDC and company overheads. As a joint owner of the Flint Creek Plant, SWEPCo’s portion of those costs is estimated at $204 million. Through June 30, 2012, SWEPCo has incurred $9 million related to this project. In June 2012, the APSC staff and the Arkansas Attorney General’s office filed testimony that recommended additional analysis be performed in order to reach a final conclusion. The Sierra Club filed testimony that recommended the APSC deny the declaratory order. SWEPCo is currently reviewing the testimony and will file rebuttal testimony on July 30, 2012. A decision is pending from the APSC.

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. In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the Cross-State Air Pollution Rule (CSAPR) trading programs to use those programs in place of source-specific BART for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states. As a result, depending on how the states decide to implement the CAVR, compliance with the CSAPR requirements may be sufficient to satisfy CAVR's BART requirements without the need for additional unit-specific controls.

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.

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 Federal EPA issued a final Error Corrections Rule and further CSAPR revisions in 2012 to make corrections to state budgets and unit allocations and to remove the restrictions on interstate trading in the first phase of CSAPR. Challenges to these rules have also been filed, but are being held in abeyance pending a decision in the main 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. We are participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed. In July 2012, the Federal EPA issued a letter announcing that it will grant petitions for administrative reconsideration of certain issues related to the new source standards, including measurement issues and application of variability factors that may have an impact on the level of the standards. The letter also announced a three-month stay in the effective date of the new source standards. It is uncertain whether any of the information generated during the reconsideration process will affect the standards for existing sources.

The final rule contains a slightly less stringent PM limit for existing sources 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. Certain issues related to the standards for new coal-fired units have been severed from the main case and will be considered by the court on an expedited basis. The Federal EPA’s grant of certain reconsideration petitions may alter this schedule.

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 in 2016 and retirement of the second unit no later than 2026. The parties are working toward finalizing a settlement agreement which is intended to allow PSO to meet its compliance obligations under the regional haze and HAPs rules.

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 pollutant emissions 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. The comment period closed in June 2012. New Source Performance Standards affect units that have not yet received permits, but complete the permitting process while the proposal is pending. The standards have been challenged in the United States Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of that litigation.

In June 2012, the United States Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO2 emissions from new motor vehicles and its plan to phase in regulation of CO2 emissions from stationary source under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. The Federal EPA also finalized a rule in June 2012 that retains the current thresholds for permitting stationary sources under the PSD and Title V operating permit programs at 100,000 tons per year for new sources and 75,000 tons per year for modified sources. The Federal EPA also confirmed that it will re-evaluate these thresholds during its five-year review in 2016. Our generating units are large sources of CO2 emissions and we will continue to evaluate the permitting obligations in light of these thresholds.

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. The Federal EPA has also announced its intention to complete a risk assessment of various beneficial uses of coal ash.

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. In June 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments. We submitted comments in July 2012. Issuance of a final rule is not expected until July 2013. We are preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

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. 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.”

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 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.

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 and six months ended June 30, 2012 and 2011. We reclassified prior year amounts to conform to the current year’s presentation.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)
Utility Operations	$	365		$	350		$	749		$	724
Transmission Operations		8			6			17			10
AEP River Operations		3			(1	)		12			6
Generation and Marketing		(5	)		11			(6	)		12
All Other (a)		(8	)		(13	)		(19	)		(44	)
Net Income	$	363		$	353		$	753		$	708

(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.

AEP CONSOLIDATED

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income increased from $353 million in 2011 to $363 million in 2012 primarily due to:

·	A decrease in other operation and maintenance expenses as a result of reduced spending.
·	A second quarter 2012 partial reversal of a 2011 deferred fuel adjustment based on an April 2012 PUCO order related to the 2009 FAC audit.

These increases were partially offset by:

·	The loss of retail customers in Ohio to various CRES providers.
·	A net decrease in regulated revenue primarily due to the elimination of POLR charges in Ohio effective June 2011, resulting from an October 2011 PUCO remand order.
·	The increase in depreciation expenses as a result of shortened depreciable lives for certain OPCo generating plants and increases in depreciation rates for APCo and I&M in February 2012 (Virginia) and April 2012 (Michigan), respectively.

Average basic shares outstanding increased from 482 million in 2011 to 485 million in 2012. Actual shares outstanding were 485 million as of June 30, 2012.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income increased from $708 million in 2011 to $753 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.
·	A first quarter 2011 settlement of litigation with BOA and Enron.
·	A second quarter 2012 partial reversal of a 2011 deferred fuel adjustment based on an April 2012 PUCO order related to the 2009 FAC audit.

These increases were partially offset by:

·	The loss of retail customers in Ohio to various CRES providers.
·	A decrease in weather-related usage, primarily due to a decrease in heating degree days in the first quarter of 2012.
·	A net decrease in regulated revenue primarily due to the elimination of POLR charges in Ohio effective June 2011, resulting from an October 2011 PUCO remand order.
·	The increase in depreciation expenses as a result of shortened depreciable lives for certain OPCo generating plants and increases in depreciation rates for APCo and I&M in February 2012 (Virginia) and April 2012 (Michigan), respectively.

Average basic shares outstanding increased from 482 million in 2011 to 484 million in 2012. Actual shares outstanding were 485 million as of June 30, 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 electricity. We reclassified prior year amounts to conform to the current year’s presentation.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	(in millions)
Revenues	$	3,258		$	3,388		$	6,643		$	6,912
Fuel and Purchased Electricity		1,096			1,230			2,365			2,527
Gross Margin		2,162			2,158			4,278			4,385
Other Operation and Maintenance		770			852			1,525			1,702
Depreciation and Amortization		448			398			860			791
Taxes Other Than Income Taxes		202			199			413			408
Operating Income		742			709			1,480			1,484
Interest and Investment Income		2			2			3			4
Carrying Costs Income		11			17			31			32
Allowance for Equity Funds Used During Construction		20			22			40			42
Interest Expense		(224	)		(227	)		(441	)		(459	)
Income Before Income Tax Expense and Equity
Earnings		551			523			1,113			1,103
Income Tax Expense		186			173			365			380
Equity Earnings of Unconsolidated Subsidiaries		-			-			1			1
Net Income	$	365		$	350		$	749		$	724

Summary of KWH Energy Sales for Utility Operations

	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2012	2011		2012	2011
	(in millions of KWHs)
Retail:
Residential	13,155		13,503	27,954	30,452
Commercial	13,087		12,913	24,353	24,559
Industrial	15,422		15,153	30,069	29,482
Miscellaneous	779		777	1,500	1,500
Total Retail (a)	42,443		42,346	83,876	85,993

Wholesale	8,620		10,216	17,533	19,367

Total KWHs	51,063		52,562	101,409	105,360

(a) Represents energy delivered to distribution customers.

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				Six Months Ended
		June 30,				June 30,
		2012		2011		2012		2011
		(in degree days)
Eastern Region
Actual - Heating (a)			118		134		1,379		1,989
Normal - Heating (b)			165		168		1,916		1,907

Actual - Cooling (c)			401		368		429		371
Normal - Cooling (b)			300		295		303		299

Western Region
Actual - Heating (a)			1		10		348		702
Normal - Heating (b)			20		21		601		600

Actual - Cooling (d)			961		1,035		1,094		1,144
Normal - Cooling (b)			774		762		834		820

(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.

Second Quarter of 2012 Compared to Second Quarter of 2011

Reconciliation of Second Quarter of 2011 to Second Quarter of 2012
Net Income from Utility Operations
(in millions)

Second Quarter of 2011	$	350

Changes in Gross Margin:
Retail Margins		(15	)
Off-system Sales		5
Transmission Revenues		22
Other Revenues		(8	)
Total Change in Gross Margin		4

Changes in Expenses and Other:
Other Operation and Maintenance		82
Depreciation and Amortization		(50	)
Taxes Other Than Income Taxes		(3	)
Carrying Costs Income		(6	)
Allowance for Equity Funds Used During Construction		(2	)
Interest Expense		3
Total Change in Expenses and Other		24

Income Tax Expense		(13	)

Second Quarter of 2012	$	365

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

·	Retail Margins decreased $15 million primarily due to the following:
	·	A $70 million decrease attributable to Ohio customers switching to alternative CRES providers. This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
	·	A $13 million net decrease in regulated revenue primarily due to the elimination of POLR charges in Ohio effective June 2011, resulting from an October 2011 PUCO remand order.
	These decreases were partially offset by:
	·	A $35 million increase due to OPCo’s partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
	·	A $21 million increase in revenues related to TCC’s issuance of securitization bonds in March 2012. This increase is partially offset by an increase in Depreciation and Amortization expense.
	·	A $9 million rate increase for APCo.
·	Margins from Off-system Sales increased $5 million primarily due to higher PJM capacity revenues, partially offset by lower physical sales volumes and lower trading and marketing margins.
·	Transmission Revenues increased $22 million primarily due to net increases in ERCOT 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 $8 million primarily due to a decrease in gains on other miscellaneous sales.

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

·	Other Operation and Maintenance expenses decreased $82 million primarily due to the following:
	·	A $46 million decrease in plant outage and other plant operating and maintenance expenses.
	·	A $30 million decrease in employee-related expenses and other reduced spending.
	·	A $19 million decrease in storm expenses.
	These decreases were partially offset by:
	·	A $13 million increase due to expenses related to the 2012 sustainable cost reductions.
·	Depreciation and Amortization expenses increased $50 million primarily due to the following:
	·	An $18 million increase due to TCC’s issuance of securitization bonds in March 2012. The increase in TCC’s securitization related amortizations are offset within Gross Margin.
	·	An $18 million increase due to shortened depreciable lives for certain OPCo generating plants effective December 2011.
	·	A $14 million combined increase in depreciation for APCo and I&M primarily due to increases in depreciation rates effective February 2012 (Virginia) and April 2012 (Michigan), respectively.
	·	A $5 million increase in amortization primarily 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 $10 million decrease due to an amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
	·	A $5 million decrease in OPCo’s depreciation due to the third quarter 2011 plant impairment of Sporn Unit 5.
·	Carrying Costs Income decreased $6 million primarily due to OPCo’s reduction in debt carrying charges associated with the 2008 coal contract settlement for the period January 2009 through March 2012 as ordered by the PUCO in April 2012 related to the 2009 FAC audit.
·	Income Tax Expense increased $13 million primarily due to an increase in pre-tax book income.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Reconciliation of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2012
Net Income from Utility Operations
(in millions)

Six Months Ended June 30, 2011	$	724

Changes in Gross Margin:
Retail Margins		(113)
Off-system Sales		2
Transmission Revenues		34
Other Revenues		(30)
Total Change in Gross Margin		(107)

Changes in Expenses and Other:
Other Operation and Maintenance		177
Depreciation and Amortization		(69)
Taxes Other Than Income Taxes		(5)
Interest and Investment Income		(1)
Carrying Costs Income		(1)
Allowance for Equity Funds Used During Construction		(2)
Interest Expense		18
Total Change in Expenses and Other		117

Income Tax Expense		15

Six Months Ended June 30, 2012	$	749

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 electricity were as follows:

·	Retail Margins decreased $113 million primarily due to the following:
	·	A $124 million decrease attributable to Ohio customers switching to alternative CRES providers. This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
	·	An $89 million decrease in weather-related usage in our eastern and western regions primarily due to decreases of 31% and 50%, respectively, in heating degree days.
	·	A $17 million net decrease in regulated revenue primarily due to the elimination of POLR charges in Ohio effective June 2011, resulting from an October 2011 PUCO remand order.
	These decreases were partially offset by:
	·	Successful rate proceedings in our service territories which include:
		·	A $31 million rate increase for APCo.
		·	A $14 million rate increase for I&M.
		·	A $9 million rate increase for PSO.
			For the rate increases described above, $46 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
	·	A $35 million increase due to OPCo’s second quarter 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
	·	A $24 million increase in revenues related to TCC’s issuance of securitization bonds in March 2012. This increase is partially offset by an increase in Depreciation and Amortization expense.
·	Margins from Off-system Sales increased $2 million primarily due to higher PJM capacity revenues, partially offset by lower physical sales volumes and lower trading and marketing margins.
·	Transmission Revenues increased $34 million primarily due to net increases in ERCOT and increased transmission revenues for Ohio customers who have switched to alternative CRES providers. The increase in transmission revenues related to CRES providers offsets lost revenues included in Retail Margins above.
·	Other Revenues decreased $30 million primarily due to an unfavorable regulatory order in Ohio and a decrease in gains on other miscellaneous sales.

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

·	Other Operation and Maintenance expenses decreased $177 million primarily due to the following:
	·	A $75 million decrease in plant outage and other plant operating and maintenance expenses.
	·	A $75 million decrease in employee-related expenses and other reduced spending.
	·	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.
	·	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 $16 million decrease in other storm expenses.
	These decreases were partially offset by:
	·	A $33 million increase due to the first quarter 2011 deferral of 2009 storm costs and the 2010 cost reduction initiatives as allowed by the WVPSC in 2011.
	·	A $13 million increase due to expenses related to the 2012 sustainable cost reductions.
	·	An $8 million increase in energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
·	Depreciation and Amortization expenses increased $69 million primarily due to the following:
	·	A $32 million increase due to shortened depreciable lives for certain OPCo generating plants effective December 2011.
	·	A $23 million increase due to TCC’s issuance of securitization bonds in March 2012. The increase in TCC’s securitization related amortizations are offset within Gross Margin.
	·	A $21 million combined increase in depreciation for APCo and I&M primarily due to increases in depreciation rates effective February 2012 (Virginia) and April 2012 (Michigan), respectively.
	·	A $9 million increase in amortization primarily 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 $19 million decrease due to an amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
	·	A $10 million decrease in OPCo’s depreciation due to the third quarter 2011 plant impairment of Sporn Unit 5.
·	Carrying Costs Income decreased $1 million primarily due to the following:
	·	A $6 million decrease due to OPCo’s collection of carrying costs in the first quarter 2012 on phase-in FAC deferrals and line extension carrying charges recorded in 2011.
	·	A $5 million decrease for OPCo due to a reduction in debt carrying charges associated with the 2008 coal contract settlement for the period January 2009 through March 2012 as ordered by the PUCO in April 2012 related to the 2009 FAC audit.
	These decreases were offset by:
	·	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.
·	Interest Expense decreased $18 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·	Income Tax Expense decreased $15 million primarily due to audit settlements for previous years and federal income tax adjustments recorded in 2011 related to prior year tax returns, partially offset by an increase in pre-tax book income.

TRANSMISSION OPERATIONS

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income from our Transmission Operations segment increased from $6 million in 2011 to $8 million in 2012 primarily due to an increase in investments by ETT and our wholly-owned transmission subsidiaries.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income from our Transmission Operations segment increased from $10 million in 2011 to $17 million in 2012 primarily due to an increase in investments by ETT and our wholly-owned transmission subsidiaries.

AEP RIVER OPERATIONS

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income from our AEP River Operations segment increased from a loss of $1 million in 2011 to a gain of $3 million in 2012 primarily due to flood-related expenses incurred in the second quarter of 2011 and reduced spending in 2012.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income from our AEP River Operations segment increased from $6 million in 2011 to $12 million in 2012 primarily due to flood-related expenses incurred in the second quarter of 2011 and reduced spending in 2012.

GENERATION AND MARKETING

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income from our Generation and Marketing segment decreased from a gain of $11 million in 2011 to a loss of $5 million in 2012 primarily due to the expiration of wind-related production tax credits in 2011, lower trading margins and reduced inception gains from ERCOT marketing activities.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income from our Generation and Marketing segment decreased from a gain of $12 million in 2011 to a loss of $6 million in 2012 primarily due to the expiration of wind-related production tax credits in 2011 and lower trading margins.

ALL OTHER

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income from All Other increased from a loss of $13 million in 2011 to a loss of $8 million in 2012 primarily due to a decrease in various parent related expenses.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income from All Other increased from a loss of $44 million in 2011 to a loss of $19 million in 2012 due to a loss incurred in the first quarter of 2011 related to the settlement of litigation with BOA and Enron.

AEP SYSTEM INCOME TAXES

Second Quarter of 2012 Compared to Second Quarter of 2011

Income Tax Expense increased $16 million primarily due to an increase in pretax book income and the expiration of wind production tax credits in 2011.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Income Tax Expense decreased $73 million primarily due to the unrealized capital loss valuation allowance related to a deferred tax asset associated with the settlement of litigation with BOA and Enron, audit settlements for previous years and a decrease in pretax book income.

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

	June 30, 2012				December 31, 2011
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	17,302	51.6	%	$	16,516	50.3	%
Short-term Debt		1,208	3.6			1,650	5.0
Total Debt		18,510	55.2			18,166	55.3
AEP Common Equity		15,007	44.8			14,664	44.7
Noncontrolling Interests		1	-			1	-

Total Debt and Equity Capitalization	$	33,518	100.0	%	$	32,831	100.0	%

Our ratio of debt-to-total capital decreased from 55.3% at December 31, 2011 to 55.2% at June 30, 2012. Long-term debt outstanding increased due to the March 2012 issuance of $800 million of securitization bonds.

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 June 30, 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-and-leaseback or leasing agreements or common stock.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. At June 30, 2012, our available liquidity was approximately $2.8 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			297
Total Liquidity Sources			3,547
Less:	AEP Commercial Paper Outstanding		550
	Letters of Credit Issued		167

Net Available Liquidity		$	2,830

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 six months of 2012 was $1.2 billion. The weighted-average interest rate for our commercial paper during 2012 was 0.46%.

Securitized Accounts Receivables

In June 2012, we renewed our receivables securitization agreement. The agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2013 and the remaining commitment of $315 million expires in June 2015.

Securitization of Regulatory Assets

In March 2012, West Virginia passed securitization legislation, which allows the WVPSC to establish a regulatory framework to securitize certain deferred Expanded Net Energy Charge (ENEC) balances and other ENEC related assets. APCo and WPCo anticipate filing, in the third quarter of 2012, a request for a financing order with the WVPSC pursuant to the securitization legislation to securitize approximately $400 million. See “APCo’s and WPCo’s Expanded Net Energy Charge (ENEC) Filing” section of Note 2.

OPCo plans to file, in the third quarter of 2012, an application with the PUCO requesting securitization of the Distribution Asset Recovery Rider (DARR) balance. As of June 30, 2012, OPCo’s DARR balance was $309 million, including $145 million of unrecognized equity carrying costs. Currently, the DARR is being recovered through 2018.

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 June 30, 2012, this contractually-defined percentage was 50%. Nonperformance under these covenants could result in an event of default under these credit agreements. At June 30, 2012, we complied with all of the covenants contained in these 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 June 30, 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 July 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.

	Six Months Ended
	June 30,
	2012				2011
	(in millions)
Cash and Cash Equivalents at Beginning of Period		$	221			$	294
Net Cash Flows from Operating Activities			1,713				1,732
Net Cash Flows Used for Investing Activities			(1,530	)			(1,280	)
Net Cash Flows Used for Financing Activities			(107	)			(329	)
Net Increase in Cash and Cash Equivalents			76				123
Cash and Cash Equivalents at End of Period		$	297			$	417

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

Operating Activities

	Six Months Ended
	June 30,
	2012			2011
	(in millions)
Net Income		$	753		$	708
Depreciation and Amortization			883			813
Other			77			211
Net Cash Flows from Operating Activities		$	1,713		$	1,732

Net Cash Flows from Operating Activities were $1.7 billion in 2012 consisting primarily of Net Income of $753 million and $883 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 winter weather. Cash was also used to pay real and personal property taxes and to reduce 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 and an increase in tax versus book temporary differences from operations.

Net Cash Flows from Operating Activities were $1.7 billion in 2011 consisting primarily of Net Income of $708 million and $813 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 a decrease in fuel inventory and the unfavorable impact of reducing accounts payable and adjusting accrued taxes for a net operating loss and tax credit carryforward. 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 of which $211 million was used to settle litigation with BOA and Enron. The remaining $214 million was used to acquire cushion gas as discussed in Investing Activities below.

Investing Activities

	Six Months Ended
	June 30,
	2012				2011
	(in millions)
Construction Expenditures		$	(1,371	)		$	(1,113	)
Acquisitions of Nuclear Fuel			(11	)			(93	)
Acquisitions of Assets/Businesses			(88	)			(10	)
Acquisition of Cushion Gas from BOA			-				(214	)
Proceeds from Sales of Assets			8				94
Other			(68	)			56
Net Cash Flows Used for Investing Activities		$	(1,530	)		$	(1,280	)

Net Cash Flows Used for Investing Activities were $1.5 billion 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 $1.3 billion 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.

Financing Activities

	Six Months Ended
	June 30,
	2012				2011
	(in millions)
Issuance of Common Stock, Net		$	50			$	49
Issuance of Debt, Net			332				104
Dividends Paid on Common Stock			(458	)			(446	)
Other			(31	)			(36	)
Net Cash Flows Used for Financing Activities		$	(107	)		$	(329	)

Net Cash Flows Used for Financing Activities in 2012 were $107 million. Our net debt issuances were $332 million. The net issuances included issuances of $800 million of securitization bonds, $275 million of senior unsecured notes and $197 million of notes payable and other debt offset by retirements of $234 million of senior unsecured and other debt notes, $155 million of pollution control bonds, $98 million of securitization bonds and a decrease in short-term borrowing of $442 million. We paid common stock dividends of $458 million. See Note 10 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows Used for Financing Activities in 2011 were $329 million. Our net debt issuances were $104 million. The net issuances included issuances of $600 million of senior unsecured notes, $481 million of pollution control bonds and an increase in short-term borrowing of $293 million offset by retirements of $578 million of senior unsecured and debt notes, $591 million of pollution control bonds and $92 million of securitization bonds. We paid common stock dividends of $446 million.

In July 2012, I&M retired $9 million of Notes Payable related to DCC Fuel.

In July 2012, TCC retired $73 million of Securitization Bonds.

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:

	June 30,			December 31,
	2012			2011
	(in millions)
Rockport Plant Unit 2 Future Minimum Lease Payments		$	1,552		$	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.

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, 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 as we occasionally 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.

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)
Six Months Ended June 30, 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		14		(14	)		-
Fair Value of New Contracts at Inception When Entered During the
Period (a)		5		9			14
Changes in Fair Value Due to Market Fluctuations During the
Period (b)		5		(1	)		4
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		4		-			4
Total MTM Risk Management Contract Net Assets
at June 30, 2012	$	87	$	126			213

Commodity Cash Flow Hedge Contracts							(22	)
Interest Rate and Foreign Currency Cash Flow Hedge Contracts							(35	)
Fair Value Hedge Contracts							2
Collateral Deposits							76
Total MTM Derivative Contract Net Assets at June 30, 2012						$	234

(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.

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 June 30, 2012, our credit exposure net of collateral to sub investment grade counterparties was approximately 6%, 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 June 30, 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		$	739	$	2	$	737		2	$	313
Split Rating			-		-		-		-		-
Noninvestment Grade			12		2		10		1		10
No External Ratings:
	Internal Investment Grade		168		-		168		1		42
	Internal Noninvestment Grade		58		10		48		1		35
Total as of June 30, 2012		$	977	$	14	$	963		5	$	400

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 June 30, 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

Six Months Ended								Twelve Months Ended
June 30, 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.

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 June 30, 2012 and December 31, 2011, the estimated EaR on our debt portfolio for the following twelve months was $37 million and $29 million, respectively.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2012 and 2011
(in millions, except per-share and share amounts)
(Unaudited)

	Three Months Ended						Six Months Ended
	2012			2011			2012			2011
REVENUES
Utility Operations	$	3,235		$	3,360		$	6,598		$	6,857
Other Revenues		316			249			578			482
TOTAL REVENUES		3,551			3,609			7,176			7,339
EXPENSES
Fuel and Other Consumables Used for Electric Generation		904			980			1,957			2,036
Purchased Electricity for Resale		268			287			528			562
Other Operation		719			697			1,375			1,383
Maintenance		252			316			514			581
Depreciation and Amortization		460			410			883			813
Taxes Other Than Income Taxes		207			202			424			415
TOTAL EXPENSES		2,810			2,892			5,681			5,790

OPERATING INCOME		741			717			1,495			1,549

Other Income (Expense):
Interest and Investment Income		2			3			4			5
Carrying Costs Income		11			17			31			32
Allowance for Equity Funds Used During Construction		24			23			47			43
Interest Expense		(235	)		(239	)		(464	)		(481	)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		543			521			1,113			1,148

Income Tax Expense		190			174			379			452
Equity Earnings of Unconsolidated Subsidiaries		10			6			19			12

NET INCOME		363			353			753			708

Net Income Attributable to Noncontrolling Interests		1			1			2			2

NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS		362			352			751			706

Preferred Stock Dividend Requirements of Subsidiaries		-			-			-			1

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	362		$	352		$	751		$	705

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING		484,500,029			481,928,494			484,164,065			481,538,549

TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
SHAREHOLDERS	$	0.75		$	0.73		$	1.55		$	1.46

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING		484,860,690			482,203,255			484,554,779			481,786,698

TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
SHAREHOLDERS	$	0.75		$	0.73		$	1.55		$	1.46

CASH DIVIDENDS DECLARED PER SHARE	$	0.47		$	0.46		$	0.94		$	0.92

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 36.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2012 and 2011
(in millions)
(Unaudited)

	Three Months Ended					Six Months Ended
	2012			2011		2012			2011
Net Income	$	363		$	353	$	753		$	708

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $5 and $2 for the Three Months Ended
June 30, 2012 and 2011, Respectively, and $11 and $3 for the Six
Months Ended June 30, 2012 and 2011, Respectively		(10	)		5		(21	)		6
Securities Available for Sale, Net of Tax of $- and $- for the Three Months
Ended June 30, 2012 and 2011, Respectively, and $1 and $- for the
Six Months Ended June 30, 2012 and 2011, Respectively		(1	)		-		1			1
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $4
and $3 for the Three Months Ended June 30, 2012 and 2011,
Respectively, and $8 and $6 for the Six Months Ended June 30,
2012 and 2011, Respectively		8			6		15			12

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(3	)		11		(5	)		19

TOTAL COMPREHENSIVE INCOME		360			364		748			727

Total Comprehensive Income Attributable to Noncontrolling Interests		1			1		2			2

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
SHAREHOLDERS		359			363		746			725

Preferred Stock Dividend Requirements of Subsidiaries		-			-		-			1

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
COMMON SHAREHOLDERS	$	359		$	363	$	746		$	724

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 36.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 30, 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		9		40								49
Common Stock Dividends									(444)				(2)		(446)
Preferred Stock Dividend Requirements of
	Subsidiaries								(1)						(1)
Other Changes in Equity							(12)