AEP 10-Q Quarterly Report June 30, 2013

AMERICAN ELECTRIC POWER CO INC

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10-Q 1 q213aep10q.htm AMERICAN ELECTRIC POWER 2Q2013 10-Q q213aep10q.htm

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, 2013

[ ] 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 as of July 25, 2013

American Electric Power Company, Inc.			486,772,596
			($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, 2013

		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	31
	Index of Condensed Notes to Condensed Consolidated Financial Statements	37

Appalachian Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	86
	Condensed Consolidated Financial Statements	92
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	98

Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	100
	Condensed Consolidated Financial Statements	105
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	111

Ohio Power Company and Subsidiary:
	Management’s Narrative Discussion and Analysis of Results of Operations	113
	Condensed Consolidated Financial Statements	120
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	126

Public Service Company of Oklahoma:
	Management’s Narrative Discussion and Analysis of Results of Operations	128
	Condensed Financial Statements	132
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	138

Southwestern Electric Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations	140
	Condensed Consolidated Financial Statements	146
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	152

Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		153

Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries		220

Controls and Procedures		227


Part II. OTHER INFORMATION

	Item 1.	Legal Proceedings		228
	Item 1A.	Risk Factors		228
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		229
	Item 4.	Mine Safety Disclosures		230
	Item 5.	Other Information		230
	Item 6.	Exhibits:		230
			Exhibit 4
			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				231

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., an electric 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.
AEPGenCo		AEP Generation Resources Inc., a nonregulated AEP subsidiary in the Generation and Marketing segment.
AEP System		American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP Transmission Holding Company		AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEPSC		American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo		American Electric Power Transmission Company, a wholly-owned subsidiary of AEP Transmission Holding Company.
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.
CAA		Clean Air Act.
CLECO		Central Louisiana Electric Company, a nonaffiliated utility company.
CO 2		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.
CWIP		Construction Work in Progress.
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.
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.

Term		Meaning

FASB		Financial Accounting Standards Board.
Federal EPA		United States Environmental Protection Agency.
FERC		Federal Energy Regulatory Commission.
FGD		Flue Gas Desulfurization or scrubbers.
FTR		Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP		Accounting Principles Generally Accepted in the United States of America.
I&M		Indiana Michigan Power Company, an AEP electric utility subsidiary.
IEU		Industrial Energy Users-Ohio.
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.
MWh		Megawatthour.
NO x		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.
SO 2		Sulfur dioxide.
SPP		Southwest Power Pool regional transmission organization.
SSO		Standard service offer.
Stall Unit		J. Lamar Stall Unit at Arsenal Hill Plant, a 543 MW natural gas unit owned by SWEPCo.
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 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 Discussion and Analysis of Financial Condition and Results of Operations” of the 2012 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, growth or contraction within and changes in market demand and demographic patterns in our service territory.
·	Inflationary or deflationary interest rate trends.
·	Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·	The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
·	Electric load, customer growth and the impact of retail competition, particularly in Ohio.
·	Weather conditions, including storms and drought conditions, 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 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.
·	Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
·	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 and other energy-related commodities.
·	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.
·	Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.

·	Changes in utility regulation, including the implementation of ESPs and the transition to market and the legal separation of generation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.
·	Our ability to successfully manage negotiations with stakeholders and obtain regulatory approval to terminate the Interconnection Agreement.
·	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.
·	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.
·	Accounting pronouncements periodically issued by accounting standard-setting bodies.
·	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 Part I of the 2012 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

Corporate Separation, Plant Transfers and Termination of Interconnection Agreement

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets at net book value (NBV) to AEPGenCo. AEPGenCo will also assume the associated generation liabilities. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.

Also in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations. The filings requested approval to transfer at NBV approximately 9,200 MW of OPCo-owned generation assets to AEPGenCo. The AEP East Companies also requested FERC approval to transfer at NBV OPCo’s current two-thirds ownership in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests. In December 2012, APCo and KPCo filed requests with their respective commissions for the approval of the plant transfers discussed above. We are currently pursuing cost recovery of these plants in Kentucky and West Virginia and plan to pursue cost recovery in Virginia. In April 2013, the FERC issued orders approving the merger of APCo and WPCo and approving the transfer of OPCo’s generation assets to AEPGenCo and the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo, to be effective using our requested date of December 31, 2013. In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo. OPCo strongly contested the petition for rehearing, which remains pending before the FERC. In June 2013, a settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club was filed with the KPSC which supported the plant transfer discussed above. The Attorney General was not party to the settlement agreement. If approved, KPCo will withdraw the current base rate case request and current rates will remain in effect until at least May 2015. Hearings in the plant transfer cases were held at the Virginia SCC in June 2013 and at the KPSC and WVPSC in July 2013. See the “Plant Transfers” sections of APCo and WPCo Rate Matters and KPCo Rate Matters in Note 3 and the “2013 Kentucky Base Rate Case” section below.

The AEP East Companies also requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ power supply resources. Under the PCA, APCo, I&M and KPCo would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. In March 2013, a revised PCA was filed at the FERC that included certain clarifying wording changes agreed upon by intervenors. A decision is pending at the FERC. See the “Corporate Separation and Termination of Interconnection Agreement” section of Note 3.

Additionally, FERC approval was sought for a power supply agreement between AEPGenCo and OPCo. This agreement provides for AEPGenCo to supply capacity for OPCo’s switched and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that is not acquired through an auction from January 1, 2014 through December 31, 2014.

If approved as filed, for any AEPGenCo generation not serving OPCo’s retail load, AEPGenCo’s results of operations will be largely determined by prevailing market conditions effective January 1, 2014. If incurred costs are not ultimately recovered, it could reduce future net income and cash flows and impact financial condition.

Ohio Electric Security Plan Filing

2009 – 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover OPCo’s deferred fuel costs in rates beginning September 2012. As of June 30, 2013, OPCo’s net deferred fuel balance was $484 million, excluding unrecognized equity carrying costs. Decisions from the Supreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance.

June 2012 – May 2015 Ohio ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015, which was generally upheld in rehearing orders in January and March 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The RPM price is approximately $33/MW day through May 2014. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. As of June 30, 2013, OPCo’s incurred deferred capacity costs balance was $171 million, including debt carrying costs.

In June 2013, intervenors in the competitive bid process (CBP) docket filed recommendations that include prospective rate reductions for capacity and non-energy FAC issues. OPCo maintains that the August 2012 ESP order fixed OPCo’s non-energy generation rates through December 31, 2014 and ordered the application of a $188.88/MW day price for capacity for non-shopping customers effective January 1, 2015. However, intervenors maintained that OPCo’s non-energy generation rates should be reduced prior to January 1, 2015 to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned (10% prior to June 2014 and 60% for the period June 1, 2014 through December 31, 2014). Depending upon actual customer switching levels and the timing of the auctions, OPCo estimates that these capacity issues could reduce OPCo’s projected future revenues by up to approximately $160 million through May 2015. An additional proposal to prospectively offset deferred capacity costs based upon the results of the energy-only auctions was not quantified and OPCo maintains that proposal should not be adopted in light of prior PUCO orders. Hearings related to the CBP were held at the PUCO in June and July 2013.

If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its deferred capacity costs, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filing” section of Note 3.

Ohio Customer Choice

In our Ohio service territory, various CRES providers are targeting retail customers by offering alternative generation service. The reduction in gross margin as a result of customer switching in Ohio is partially offset by (a) collection of capacity revenues from CRES providers, (b) off-system sales, (c) deferral of unrecovered capacity costs, (d) Retail Stability Rider collections and (e) revenues from AEP Energy. AEP Energy is our CRES provider and part of our Generation and Marketing segment which targets retail customers, both within and outside of our retail service territory.

Customer Demand

In comparison to 2012, our weather-normalized retail sales were down 2.7% and 2.1% for the three and six months ended June 30, 2013, respectively. Our industrial sales declined 5.3% and 5.7%, respectively, partially due to Ormet, a large aluminum company that lowered their production in the third quarter of 2012 by one-third and is currently in bankruptcy proceedings.

PJM Capacity Market

If corporate separation and asset transfers are approved as filed, AEPGenCo will be subject to the PJM capacity auction prices after May 2015 for the majority of the current OPCo-owned generation assets. Under the previously approved June 2012 – May 2015 ESP, OPCo is allowed to receive revenues through May 2015 for the generation assets from base generation rates and allowed to defer incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The PJM base capacity price for the planning year June 2015 through May 2016 was previously announced as $136.00/MW day. In May 2013, PJM announced the base capacity auction price for the June 2016 through May 2017 planning period would be $59.37/MW day.

Significantly Excessive Earnings Test

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order. Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings. OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO-ordered SEET refund. OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in 2012 for OPCo. Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo. Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition. See the “Ohio Electric Security Plan Filing” section of Note 3.

U.K. Windfall Tax Decision

In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. We filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, we recognized a tax benefit of $80 million, plus $43 million of pretax interest income in the second quarter of 2013. The tax benefit and interest income resulted in an increase in net income of $108 million, but did not result in the receipt of cash during the second quarter of 2013.

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility. As of June 30, 2013, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital cost cap, SWEPCo has capitalized approximately $1.8 billion of expenditures, including AFUDC and capitalized interest of $328 million and related transmission costs of $118 million.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the SPP market. If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition. See the “Turk Plant” section of Note 3.

2012 Texas Base Rate Case

In 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 included a return on and of the Texas jurisdictional share of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs. In September 2012, an Administrative Law Judge (ALJ) issued an order that granted the establishment of SWEPCo’s existing rates as temporary rates beginning in late January 2013, subject to true-up to the final PUCT-approved rates.

In December 2012, several intervenors filed opposing testimony and in May 2013, the ALJ issued a proposal for decision (PFD) and added clarifications to the PFD in July 2013. The PFD, as clarified, made various recommendations including (a) an annual base rate increase of approximately $41 million based upon a return on common equity of 9.65%, (b) the disallowance of the Turk Plant capital costs in excess of the investment and committed costs as of June 2010 plus the cost to retrofit Welsh Plant, Unit 2 which, as of June 30, 2013, SWEPCo estimates could result in a write-off of approximately $74 million (in excess of the $62 million reserve previously recorded related to the Texas capital cost cap) and (c) the exclusion, until SWEPCo’s next Texas base rate case, of the Turk Plant transmission line investment that was not in service at the end of the test year. A decision from the PUCT is expected in the third quarter of 2013. If the PUCT does not approve full cost recovery of SWEPCo’s Texas jurisdictional share of assets, it could reduce future net income and cash flows and impact financial condition. See the “2012 Texas Base Rate Case” section of Note 3.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant. In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013. The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover all non-fuel Turk Plant costs and a full weighted-average cost of capital return on the Turk Plant portion of rate base, effective January 2013. In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant. If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition. See the “2012 Louisiana Formula Rate Filing” section of Note 3.

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%. In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates to $92 million. In March 2013, the Indiana Office of Utility Consumer Counselor filed an appeal of the order with the Indiana Court of Appeals. If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows. See the “2011 Indiana Base Rate Case” section of Note 3.

2013 Kentucky Base Rate Case

In June 2013, KPCo filed a request with the KPSC for an annual increase in base rates of $114 million based upon a return on common equity of 10.65% to be effective January 2014. The proposed revenue increase includes the cost recovery of the pending transfer of the one-half interest in the Mitchell Plant, cost recovery of Big Sandy Plant, Units 1 and 2 and includes requests for recovery of deferrals related to the Big Sandy Plant FGD project and 2012 storm costs. Also in June 2013, a settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club was filed with the KPSC which supported the Mitchell plant transfer discussed above. If the settlement agreement is approved, KPCo will withdraw this base rate case request and current rates will remain in effect until at least May 2015. If KPCo is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows and impact financial condition. See the “2013 Kentucky Base Rate Case” section of Note 3.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. As of June 30, 2013, I&M has incurred $240 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items which the IURC stated could be sought for recovery in a base rate case. I&M was granted recovery through an LCM rider which will be determined by a mid-September 2013 proceeding and semi-annual proceedings thereafter. The IURC authorized deferral accounting for I&M’s incurred project costs effective January 2012 to the extent such costs are not reflected in its rates.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON. If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition. See “Cook Plant Life Cycle Management Project (LCM Project)” section of Note 3.

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 Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report. Additionally, see Note 3 – Rate Matters and Note 4 – 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 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 SO 2 , NO x , PM and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, 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, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court. We are also engaged in the development of possible future requirements including the items discussed below and reductions of CO 2 emissions to address concerns about global climate change. 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 Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report. We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Recovery in Ohio will be dependent upon prevailing market conditions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If we are unable to recover the costs of environmental compliance, it would 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, 2013, the AEP System had a total generating capacity of 37,600 MWs, of which 23,700 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, investments to meet these proposed requirements range from approximately $4 billion to $5 billion through 2020. These amounts include investments to convert some of our coal generation units to natural gas. If natural gas conversion is not completed, the units could be retired sooner than planned.

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 intend 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 2		800
OPCo	Kammer Plant		630
OPCo	Muskingum River Plant, Units 1-5		1,440
OPCo	Picway Plant		100
PSO	Northeastern Station, Unit 4		470
SWEPCo	Welsh Plant, Unit 2		528
Total			6,033

As of June 30, 2013, the net book value of all of OPCo’s units above is zero and the net book value including related inventory and CWIP balances of the other plants in the table above was $873 million.

In the second quarter of 2013, we re-evaluated potential courses of action with respect to the planned operation of Muskingum River Plant, Unit 5 and concluded that completion of a refueling project which would extend the unit’s useful life is remote. As a result, in the second quarter of 2013, we completed an impairment analysis and recorded a $154 million pretax ($99 million, net of tax) impairment charge for OPCo’s net book value of Muskingum River Plant, Unit 5. We expect to retire the plant no later than 2015. See “Muskingum River Plant, Unit 5” section of Note 5.

In addition, we are in the process of obtaining permits and other necessary regulatory approvals for either the conversion of some of our coal units to natural gas or installing emission control equipment on certain units. The following table lists the plants or units that are either awaiting regulatory approval or are still being evaluated by management based on changes in emission requirements and demand for power:

		Generating
Company	Plant Name and Unit	Capacity
		(in MWs)
APCo	Clinch River Plant, Units 1-2		470
I&M/AEGCo/KPCo	Rockport Plant, Units 1-2		2,620
I&M	Tanners Creek Plant, Unit 4		500
KPCo	Big Sandy Plant, Unit 1		278
PSO	Northeastern Station, Unit 3		460
Total			4,328

As of June 30, 2013, the net book value including related inventory and CWIP balances of the plants in the table above was $1.3 billion.

Volatility in natural gas prices, pending environmental rules and other market factors could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of coal-fired units. For regulated plants that we may close early, we are seeking regulatory recovery of remaining net book values. 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.

Modification of the New Source Review (NSR) Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between the AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when it undertook various equipment repair and replacement projects over a period of nearly 20 years. The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO 2 and NO x emissions from the AEP System and various mitigation projects.

The consent decree requires certain types of control equipment to be installed at Muskingum River Plant, Unit 5, Big Sandy Plant, Unit 2 and the two units of the Rockport Plant in 2015, 2017 and 2019. In January 2013, an agreement to modify the consent decree was reached and filed with the court. The terms of the agreement include more options for the affected units (including alternative control technologies, re-fueling and/or retirement), more stringent SO 2 emission caps for the AEP System and additional mitigation measures. The Federal EPA sought public comments on the modification prior to its entry by the court in May 2013. For the units of the Rockport Plant, the modified decree requires installation of dry sorbent injection technology for SO 2 control on both units in 2015 and imposes a declining plant-wide cap on SO 2 emissions beginning in 2016.

Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both of its units at the Rockport Plant with a Dry Sorbent Injection system. The estimated cost in the application was $285 million, excluding AFUDC. In July 2013, a settlement agreement was filed with the IURC. The settlement agreement includes the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s direct ownership share. Hearings at the IURC are scheduled for August 2013. A decision is expected by November 2013. As of June 30, 2013, we have incurred costs of $77 million related to the CCT Project, including AFUDC. If we are not ultimately permitted to recover our incurred costs, it could reduce future net income and cash flows. See the “Rockport Plant Clean Coal Technology Project (CCT Project)” section of Note 3.

Flint Creek Plant Environmental Controls

In 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. SWEPCo’s portion of those costs is estimated at $204 million. As of June 30, 2013, SWEPCo has incurred $24 million related to this project, including AFUDC and company overheads. In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant. See the “Flint Creek Plant Environmental Controls” section of Note 3.

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES) Unit 4 in 2016 and additional environmental controls on NES Unit 3 to continue operations through 2026. The plan requested approval for (a) an estimated $210 million of new environmental investment, excluding AFUDC and overheads of $46 million, that will be incurred prior to 2016 at NES Unit 3, (b) accelerated recovery through 2026 of the net book value of NES Units 3 and 4 (combined net book value of the two units is $231 million as of June 30, 2013), (c) an estimated $83 million of new investment incurred through 2016 at various gas units and (d) a new 15-year purchase power agreement with a nonaffiliated entity, effective in 2016, with cost recovery through a rider, including an annual earnings component of $3 million. Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery in a future rate proceeding.

In January 2013, several parties filed testimony with various recommendations. In March 2013, the OCC granted a stay in this proceeding. In July 2013, the OCC staff filed a motion to lift the stay and dismiss PSO’s environmental compliance plan case without prejudice. A hearing on the motion will be held in August 2013. If this case is dismissed, PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan.

If PSO is ultimately not permitted to fully recover its net book value of NES Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition. See “Oklahoma Environmental Compliance Plan” section of Note 3.

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 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 SO 2 emissions from affected units in that state. The Arkansas SIP was disapproved and the state is developing a revised submittal. 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 SO 2 and NO x emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states. This rule is being challenged in the U.S. Court of Appeals for the District of Columbia Circuit and its fate is uncertain given developments in the CSAPR litigation.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for PM, SO 2 , NO x and lead, and is currently reviewing the NAAQS for ozone. 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 SO 2 and NO x allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states. Interstate trading of allowances was allowed on a restricted sub-regional basis. Arkansas and Louisiana are subject only to the seasonal NO x program in the rule. Texas is subject to the annual programs for SO 2 and NO x in addition to the seasonal NO x program. The annual SO 2 allowance budgets in Indiana, Ohio and West Virginia were reduced significantly in the rule. A supplemental rule includes Oklahoma in the seasonal NO x program. The supplemental rule was finalized in December 2011 with an increased NO x emission budget for the 2012 compliance year. 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.

Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. 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. In August 2012, the panel issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the Clean Air Interstate Rule until a replacement rule is finalized. The majority determined that the CAA does not allow the Federal EPA to “overcontrol” emissions in an upwind state and that the Federal EPA exceeded its statutory authority by failing to allow states an opportunity to develop their own implementation plans before issuing a FIP. The Federal EPA and other respondents filed petitions for rehearing but in January 2013, the U.S. Court of Appeals for the District of Columbia Circuit denied all petitions for rehearing. The petition for further review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013. Separate appeals of the supplemental rule, the Error Corrections Rule and the further revisions have been filed, but are being held in abeyance.

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 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards. Revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions, were issued by the Federal EPA in March 2013. The Federal EPA has reopened the public comment period to consider additional changes to the start-up and shut down provisions.

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 U.S. 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 are being held in abeyance pending completion of the Federal EPA’s reconsideration proceeding. The case is proceeding on the remaining issues and briefing was completed in April 2013.

Regional Haze

In 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 NO x control measures in the SIP and disapprove the SO 2 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 SO 2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP. 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 November 2012, we notified the court that the parties had reached agreement on a settlement 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 Tenth Circuit Court of Appeals is holding the appeal in abeyance pending implementation of the settlement. A revised regional haze SIP has been adopted by the State of Oklahoma and submitted to the Federal EPA for review.

CO 2 Regulation

In March 2012, the Federal EPA issued a proposal to regulate CO 2 emissions from new fossil fuel-fired electricity generating units. The proposed rule establishes a new source performance standard of 1,000 pounds of CO 2 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 CO 2 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. New source performance standards affect units that have not yet received permits. The proposed standards were challenged in the U.S. Court of Appeals for the District of Columbia Circuit. That case was dismissed because the court determined that no final agency action had yet been taken.

In June 2013, President Obama issued a memorandum to the Administrator of the Federal EPA directing the agency to develop and issue a new proposal regulating carbon emissions from new electric generating units in September 2013. A proposal was sent to the Office of Management and Budget for interagency review the following week, but the details of the proposal are not known. The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from existing, modified and reconstructed electric generating units before June 2014, to finalize those standards by June 2015 and to require states to submit revisions to their implementation plans including such standards no later than June 2016. In developing this proposal, the President directed the Federal EPA to directly engage states, leaders in the power sector, labor leaders and other stakeholders, to tailor the regulations to reduce costs, to develop market-based instruments and allow regulatory flexibilities and “assure that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power.” We cannot currently predict the impact these programs may have on future resource plans or our existing generating fleet, but the costs may be substantial.

In June 2012, the U.S. 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 CO 2 emissions from new motor vehicles and its plan to phase in regulation of CO 2 emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. A petition for rehearing was filed which the court denied in December 2012. Petitioners filed petitions for further review in the U.S. Supreme Court.

The Federal EPA also finalized a rule in June 2012 that retains the current CO 2 emission 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 CO 2 emissions and we will continue to evaluate the permitting obligations in light of these thresholds.

Coal Combustion Residual Rule

In 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 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. Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule. The Federal EPA opposed the petition and is seeking additional time to coordinate the issuance of a final rule with the issuance of new effluent limitations under the Clean Water Act for utility facilities.

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 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 November 2013. We are preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

In addition, the Federal EPA issued an information collection request and is developing revised effluent limitation guidelines for electricity generating facilities. A proposed rule was signed in April 2013 with a final rule expected in 2014. The Federal EPA proposed eight options of increasing stringency and cost for fly ash and bottom ash transport water, scrubber wastewater, leachate from coal combustion byproduct landfills and impoundments and other wastewaters associated with coal-fired generating units, with four labeled preferred options. Certain of the Federal EPA's preferred options have already been implemented or are part of our long-term plans. We will review the proposal in detail to evaluate whether our plants are currently meeting the proposed limitations, what technologies have been incorporated into our long-range plans and what additional costs might be incurred if the Federal EPA's most stringent options were adopted. We plan to submit detailed comments to the Federal EPA.

Climate Change

National public policy makers and regulators in the 11 states we serve have diverse views on climate change. We are currently focused on responding to these emerging views with prudent actions, such as improving energy efficiency, investing in developing cost-effective and less carbon-intensive technologies and evaluating our assets across a range of plausible scenarios and outcomes. We are also active participants in a variety of public policy discussions at state and federal levels to assure that proposed new requirements are feasible and the economies of the states we serve are not placed at a competitive disadvantage.

While comprehensive economy-wide regulation of CO 2 emissions might be achieved through future legislation, Congress has yet to enact such legislation. The Federal EPA continues to take action to regulate CO 2 emissions under the existing requirements of the CAA.

Several states have adopted programs that directly regulate CO 2 emissions from power plants. The majority of the states where we have generating facilities have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements. We are taking steps to comply with these requirements.

Certain groups have filed lawsuits alleging that emissions of CO 2 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 one remaining pending lawsuit, which we are defending. It is not possible to predict the outcome of this lawsuit or its impact on our operations or financial condition. See “Carbon Dioxide Public Nuisance Claims” section of Note 4.

Future federal and state legislation or regulations that mandate limits on the emission of CO 2 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 climate change, other environmental issues and the actions we are taking to address potential impacts, see Part I of the 2012 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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.

Our reportable segments and their related business activities are outlined 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 and 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 Net Income by segment for the three and six months ended June 30, 2013 and 2012.

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in millions)
Utility Operations	$	222	$	365	$	571	$	749
Transmission Operations		18		8		31		17
AEP River Operations		(9)		3		(11)		12
Generation and Marketing		4		(5)		11		(6)
All Other (a)		104		(8)		101		(19)
Net Income	$	339	$	363	$	703	$	753

(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.

AEP CONSOLIDATED

Second Quarter of 2013 Compared to Second Quarter of 2012

Net Income decreased from $363 million in 2012 to $339 million in 2013 primarily due to:

·	The second quarter 2013 impairment of Muskingum River Plant, Unit 5.
·	The loss of retail customers in Ohio to various CRES providers.
·	A decrease in margins from off-system sales primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity revenues and reduced trading and marketing margins.
·	A decrease 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 decrease in weather-related usage.
·	An increase in storm-related expenses during the second quarter of 2013.

These decreases were partially offset by:

·	Successful rate proceedings in our various jurisdictions.
·	A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.
·	The deferral of Ohio capacity costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Net Income decreased from $753 million in 2012 to $703 million in 2013 primarily due to:

·	The second quarter 2013 impairment of Muskingum River Plant, Unit 5.
·	The loss of retail customers in Ohio to various CRES providers.
·	A decrease in margins from off-system sales primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity revenues and reduced trading and marketing margins.
·	An increase in plant outages during 2013.
·	A decrease in AEP River Operations' 2013 earnings due to weak demand for grain and coal and river conditions in the first quarter of 2013.
·	A decrease 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 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 the Ohio modified stipulation.

These decreases were partially offset by:

·	Successful rate proceedings in our various jurisdictions.
·	A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.
·	The deferral of Ohio capacity costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
·	An increase in weather-related usage in the first quarter of 2013.

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.

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
		(in millions)
Revenues		$	3,278	$	3,258	$	6,795	$	6,643
Fuel and Purchased Electricity			1,130		1,096		2,407		2,365
Gross Margin			2,148		2,162		4,388		4,278
Other Operation and Maintenance			806		770		1,685		1,525
Asset Impairments and Other Related Charges			154		-		154		-
Depreciation and Amortization			429		448		835		860
Taxes Other Than Income Taxes			213		202		422		413
Operating Income			546		742		1,292		1,480
Interest and Investment Income			6		2		9		3
Carrying Costs Income			8		11		12		31
Allowance for Equity Funds Used During Construction			10		20		20		40
Interest Expense			(221)		(224)		(447)		(441)
Income Before Income Tax Expense and Equity
	Earnings		349		551		886		1,113
Income Tax Expense			127		186		315		365
Equity Earnings of Unconsolidated Subsidiaries			-		-		-		1
Net Income		$	222	$	365	$	571	$	749

Summary of KWh Energy Sales for Utility Operations

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
		(in millions of KWhs)
Retail:
	Residential		12,630		13,155		28,885		27,954
	Commercial		12,553		13,087		24,104		24,353
	Industrial		14,601		15,422		28,363		30,069
	Miscellaneous		747		779		1,455		1,500
Total Retail (a)			40,531		42,443		82,807		83,876

Wholesale			9,180		8,620		20,204		17,533

Total KWhs			49,711		51,063		103,011		101,409

(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,
		2013		2012		2013		2012
		(in degree days)
Eastern Region
Actual - Heating (a)			167		118		1,985		1,379
Normal - Heating (b)			161		165		1,880		1,916

Actual - Cooling (c)			351		401		351		429
Normal - Cooling (b)			306		300		310		303

Western Region
Actual - Heating (a)			54		1		606		348
Normal - Heating (b)			18		20		587		601

Actual - Cooling (d)			797		961		867		1,094
Normal - Cooling (b)			786		774		848		834

(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 2013 Compared to Second Quarter of 2012


Reconciliation of Second Quarter of 2012 to Second Quarter of 2013
Net Income from Utility Operations
(in millions)

Second Quarter of 2012	$	365

Changes in Gross Margin:
Retail Margins		7
Off-system Sales		(46)
Transmission Revenues		13
Other Revenues		12
Total Change in Gross Margin		(14)

Changes in Expenses and Other:
Other Operation and Maintenance		(36)
Asset Impairments and Other Related Charges		(154)
Depreciation and Amortization		19
Taxes Other Than Income Taxes		(11)
Interest and Investment Income		4
Carrying Costs Income		(3)
Allowance for Equity Funds Used During Construction		(10)
Interest Expense		3
Total Change in Expenses and Other		(188)

Income Tax Expense		59

Second Quarter of 2013	$	222

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 increased $7 million primarily due to the following:
	·	Successful rate proceedings in our service territories which include:
		·	An $85 million rate increase for OPCo.
		·	A $44 million rate increase for I&M.
		·	A $24 million rate increase for SWEPCo.
				For the rate increases described above, $48 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
	·	A $26 million increase due to the deferral of consumables and purchased power as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
	These increases were partially offset by:
	·	A $66 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 $46 million increase in other variable electric generation expenses.
	·	A $35 million decrease 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 $28 million decrease in weather-related usage primarily due to 12% and 17% decreases in cooling degree days in our eastern and western regions, respectively.
·	Margins from Off-system Sales decreased $46 million primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity revenues and reduced trading and marketing margins. The decrease in CRES capacity revenues is partially offset in other expense items below.
·	Transmission Revenues increased $13 million primarily due to increased transmission revenues from Ohio customers who have switched to alternative CRES providers and rate increases for customers in the SPP region. The increase in transmission revenues related to CRES providers offsets a portion of the lost revenues included in Retail Margins above.
·	Other Revenues increased $12 million primarily due to increases in gains on other miscellaneous sales.

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

·	Other Operation and Maintenance expenses increased $36 million primarily due to the following:
	·	A $21 million increase in storm-related expenses.
	·	A $20 million increase in plant outages.
	·	A $19 million increase in remitted Universal Service Fund (USF) surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins.
	·	A $12 million increase in energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
	These increases were partially offset by:
	·	A $13 million decrease in administrative and general expenses.
	·	A $13 million decrease due to expenses recorded in 2012 related to the 2012 sustainable cost reductions program.
	·	A $12 million decrease due to the deferral of capacity-related costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
·	Asset Impairments and Other Related Charges increased by $154 million due to the second quarter 2013 impairment of Muskingum River Plant, Unit 5.
·	Depreciation and Amortization expenses decreased $19 million primarily due to the following:
	·	A $26 million decrease as a result of depreciation ceasing on certain Ohio generating plants that were impaired in November 2012.
	·	A $15 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
	These decreases were partially offset by:
	·	An $11 million increase due to the Turk Plant being placed in service in December 2012.
	·	Overall higher depreciable property balances.
·	Taxes Other Than Income Taxes increased $11 million primarily due to increased property taxes as a result of increased capital investments.
·	Allowance for Equity Funds Used During Construction decreased $10 million primarily due to completed construction of the Turk Plant in December 2012.
·	Income Tax Expense d e creased $59 million primarily due to a decrease in pretax book income.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012


Reconciliation of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2013
Net Income from Utility Operations
(in millions)

Six Months Ended June 30, 2012	$	749

Changes in Gross Margin:
Retail Margins		125
Off-system Sales		(75)
Transmission Revenues		35
Other Revenues		25
Total Change in Gross Margin		110

Changes in Expenses and Other:
Other Operation and Maintenance		(160)
Asset Impairments and Other Related Charges		(154)
Depreciation and Amortization		25
Taxes Other Than Income Taxes		(9)
Interest and Investment Income		6
Carrying Costs Income		(19)
Allowance for Equity Funds Used During Construction		(20)
Interest Expense		(6)
Equity Earnings of Unconsolidated Subsidiaries		(1)
Total Change in Expenses and Other		(338)

Income Tax Expense		50

Six Months Ended June 30, 2013	$	571

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 increased $125 million primarily due to the following:
	·	Successful rate proceedings in our service territories which include:
		·	A $146 million rate increase for OPCo.
		·	A $52 million rate increase for I&M.
		·	A $47 million rate increase for SWEPCo.
		·	A $21 million rate increase for APCo.
				For the rate increases described above, $109 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
	·	A $50 million net increase in weather-related usage in our eastern and western regions primarily due to increases of 44% and 74%, respectively, in heating degree days in our eastern and western regions, respectively, partially offset by decreases in cooling degree days of 18% and 21% in our eastern and western regions, respectively.
	·	A $47 million increase due to the deferral of consumables and purchased power as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
	These increases were partially offset by:
	·	A $153 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 $66 million increase in other variable electric generation expenses.
	·	A $35 million decrease 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.
·	Margins from Off-system Sales decreased $75 million primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity revenues and reduced trading and marketing margins, partially offset by higher physical sales volumes and margins. The decrease in CRES capacity revenues is partially offset in other expense items below.

·	Transmission Revenues increased $35 million primarily due to increased transmission revenues from Ohio customers who have switched to alternative CRES providers and rate increases for customers in the SPP region. The increase in transmission revenues related to CRES providers offsets a portion of the lost revenues included in Retail Margins above.
·	Other Revenues increased $25 million primarily due to increases in gains on other miscellaneous sales.

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

·	Other Operation and Maintenance expenses increased $160 million primarily due to the following:
	·	A $45 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins.
	·	A $42 million increase in plant outages during 2013.
	·	A $35 million increase 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 the Ohio modified stipulation.
	·	A $30 million write-off in the first quarter of 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.
	·	A $28 million increase in energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
	·	A $26 million increase in storm-related expenses primarily in APCo's service territory.
	These increases were partially offset by:
	·	A $25 million decrease due to an agreement reached to settle an insurance claim in the first quarter of 2013.
	·	A $20 million decrease due to the deferral of capacity-related costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
·	Asset Impairments and Other Related Charges increased $154 million due to the second quarter 2013 impairment of Muskingum River Plant, Unit 5.
·	Depreciation and Amortization expenses decreased $25 million primarily due to the following:
	·	A $53 million decrease as a result of depreciation ceasing on certain Ohio generating plants that were impaired in November 2012.
	·	A $35 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
	These decreases were partially offset by:
	·	A $22 million increase due to the Turk Plant being placed in service in December 2012.
	·	Overall higher depreciable property balances.
·	Taxes Other Than Income Taxes increased $9 million primarily due to increased property taxes as a result of increased capital investments.
·	Carrying Costs Income decreased $19 million primarily due to the following:
	·	A $10 million decrease due to an increased recovery of Virginia environmental costs in new base rates as approved by the Virginia SCC in late January 2012 and decreased carrying charges related to the Dresden Plant.
	·	An $8 million decrease in carrying costs income due to the first quarter 2012 recording of debt carrying costs prior to TCC's issuance of securitization bonds in March 2012.
·	Allowance for Equity Funds Used During Construction decreased $20 million primarily due to completed construction of the Turk Plant in December 2012.
·	Income Tax Expense decreased $50 million primarily due to a decrease in pretax book income partially offset by audit settlements for previous years recorded in 2012 and other book/tax differences which are accounted for on a flow through basis.

TRANSMISSION OPERATIONS

Second Quarter of 2013 Compared to Second Quarter of 2012

Net Income from our Transmission Operations segment increased from $8 million in 2012 to $18 million in 2013 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Net Income from our Transmission Operations segment increased from $17 million in 2012 to $31 million in 2013 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT.

AEP RIVER OPERATIONS

Second Quarter of 2013 Compared to Second Quarter of 2012

Net Income from our AEP River Operations segment decreased from income of $3 million in 2012 to a loss of $9 million in 2013 primarily due to weak demand for grain and coal.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Net Income from our AEP River Operations segment decreased from income of $12 million in 2012 to a loss of $11 million in 2013 primarily due to weak demand for grain and coal and the 2012 drought which continued to have negative impacts on river conditions in the first quarter of 2013.

GENERATION AND MARKETING

Second Quarter of 2013 Compared to Second Quarter of 2012

Net Income from our Generation and Marketing segment increased from a loss of $5 million in 2012 to income of $4 million in 2013 primarily due to higher trading and marketing margins and increased retail activity.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Net Income from our Generation and Marketing segment increased from a loss of $6 million in 2012 to income of $11 million in 2013 primarily due to higher trading and marketing margins and increased retail activity resulting from our March 2012 acquisition of BlueStar.

ALL OTHER

Second Quarter of 2013 Compared to Second Quarter of 2012

Net Income from All Other increased from a loss of $8 million in 2012 to income of $104 million in 2013 primarily due to a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Net Income from All Other increased from a loss of $19 million in 2012 to income of $101 million in 2013 primarily due to a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.

AEP SYSTEM INCOME TAXES

Second Quarter of 2013 Compared to Second Quarter of 2012

Income Tax Expense decreased $122 million primarily due to the recognition of the tax benefits associated with the U.K. Windfall Tax decision and a decrease in pre-tax book income.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Income Tax Expense decreased $116 million primarily due to the recognition of the tax benefits associated with the U.K. Windfall Tax decision and a decrease in pre-tax book income, partially offset by audit settlements for previous years recorded in 2012.

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, 2013				December 31, 2012
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	17,618	50.8	%	$	17,757	52.3	%
Short-term Debt		1,538	4.4			981	2.9
Total Debt		19,156	55.2			18,738	55.2
AEP Common Equity		15,537	44.8			15,237	44.8

Total Debt and Equity Capitalization	$	34,693	100.0	%	$	33,975	100.0	%

Our ratio of debt-to-total capital remained unchanged at 55.2% as of December 31, 2012 and June 30, 2013. Short-term debt outstanding increased primarily due to borrowing for our commercial paper program under credit facilities and our common equity increased due to earnings.

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. As of June 30, 2013, we had $4.5 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. As of June 30, 2013, our available liquidity was approximately $3.4 billion as illustrated in the table below:

		Amount		Maturity
		(in millions)
Commercial Paper Backup:
	Revolving Credit Facility	$	1,750	June 2016
	Revolving Credit Facility		1,750	July 2017
Term Credit Facility			1,000	May 2015
Total			4,500
Cash and Cash Equivalents			117
Total Liquidity Sources			4,617
Less:	AEP Commercial Paper Outstanding		850
	Letters of Credit Issued		120
	Draw on Term Credit Facility		200

Net Available Liquidity		$	3,447

We have credit facilities totaling $3.5 billion to support our commercial paper program. The credit facilities allow us to issue letters of credit in an amount up to $1.2 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 2013 was $866 million. The weighted-average interest rate for our commercial paper during 2013 was 0.34%.

In February 2013, we entered into a $1 billion term credit facility due in May 2015 to fund certain OPCo maturities on an interim basis and to facilitate the corporate separation of generation assets from transmission and distribution. In July 2013, we terminated the $1 billion term credit facility. In July 2013, AEPGenCo, APCo, KPCo and OPCo entered into a $1 billion term credit facility due in May 2015 to fund certain OPCo maturities on an interim basis and to facilitate the corporate separation of generation assets from transmission and distribution.

Securitized Accounts Receivable

In June 2013, we amended our receivables securitization agreement. The agreement provides a commitment of $700 million from bank conduits to purchase receivables. We amended a commitment of $385 million to now expire in June 2014. The remaining commitment of $315 million expires in June 2015.

West Virginia Securitization of Regulatory Assets

Ohio Securitization of Regulatory Assets

In March 2013, the PUCO approved OPCo’s request to securitize the Deferred Asset Recovery Rider (DARR) balance. As of June 30, 2013, OPCo’s DARR balance was $268 million, including $126 million of unrecognized equity carrying costs. The DARR is being recovered through 2018 by a non-bypassable rider. Once the securitization bonds are issued, the DARR will cease and will be replaced by the Deferred Asset Phase-in Rider, which will recover the securitized asset over a period not to exceed eight years. The securitization bonds are expected to be issued in the third quarter of 2013.

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 securitization bonds and debt of AEP Credit. As of June 30, 2013, this contractually-defined percentage was 51.6%. Nonperformance under these covenants could result in an event of default under these credit agreements. As of June 30, 2013, 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.

The term credit facility may be drawn upon until February 2014. Repayments prior to maturity are permitted. However, any amount that is repaid may not be re-borrowed and is a permanent reduction of the facility.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders. As of June 30, 2013, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.49 per share in July 2013. 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 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,
	2013		2012
	(in millions)
Cash and Cash Equivalents at Beginning of Period	$	279	$	221
Net Cash Flows from Operating Activities		1,516		1,713
Net Cash Flows Used for Investing Activities		(1,643)		(1,530)
Net Cash Flows Used for Financing Activities		(35)		(107)
Net Increase (Decrease) in Cash and Cash Equivalents		(162)		76
Cash and Cash Equivalents at End of Period	$	117	$	297

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,
	2013		2012
	(in millions)
Net Income	$	703	$	753
Depreciation and Amortization		863		883
Other		(50)		77
Net Cash Flows from Operating Activities	$	1,516	$	1,713

Net Cash Flows from Operating Activities were $1.5 billion in 2013 consisting primarily of Net Income of $703 million, $863 million of noncash Depreciation and Amortization and $154 million of Asset Impairments related to Muskingum River Plant, Unit 5 partially offset by $102 million of Ohio capacity deferrals as a result of the PUCO's July 2012 approval of a capacity deferral mechanism. 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. Deferred Income Taxes increased primarily due to provisions in the Taxpayer Relief Act of 2012 and an increase in tax/book temporary differences from operations. Net cash flows for Accrued Taxes were a result of recording the estimated federal tax loss associated with tax/book temporary differences and the recognition of the tax benefit related to the U.K. Windfall Tax.

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.

Investing Activities


	Six Months Ended
	June 30,
	2013		2012
	(in millions)
Construction Expenditures	$	(1,637)	$	(1,371)
Acquisitions of Nuclear Fuel		(59)		(11)
Acquisitions of Assets/Businesses		(4)		(88)
Insurance Proceeds Related to Cook Plant Fire		72		-
Proceeds from Sales of Assets		11		8
Other		(26)		(68)
Net Cash Flows Used for Investing Activities	$	(1,643)	$	(1,530)

Net Cash Flows Used for Investing Activities were $1.6 billion in 2013 primarily due to Construction Expenditures for environmental, distribution and transmission investments.

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.

Financing Activities


	Six Months Ended
	June 30,
	2013		2012
	(in millions)
Issuance of Common Stock, Net	$	41	$	50
Issuance of Debt, Net		425		332
Dividends Paid on Common Stock		(469)		(458)
Other		(32)		(31)
Net Cash Flows Used for Financing Activities	$	(35)	$	(107)

Net Cash Flows Used for Financing Activities in 2013 were $35 million. Our net debt issuances were $425 million. The net issuances included issuances of $475 million of senior unsecured notes, a $200 million draw on a $1 billion term credit facility, $170 million of pollution control bonds, $101 million of notes payable and an increase in short-term borrowing of $557 million offset by retirements of $796 million of senior unsecured and other debt notes, $131 million of securitization bonds and $146 million of pollution control bonds. We paid common stock dividends of $469 million. See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

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.

In July 2013, I&M retired $12 million of Notes Payable related to DCC Fuel.

In July 2013, OPCo retired $65 million of 4.9% Pollution Control Bonds due in 2037 and issued $65 million of variable rate Pollution Control Bonds due in 2014.

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,
	2013		2012
	(in millions)
Rockport Plant, Unit 2 Future Minimum Lease Payments	$	1,404	$	1,478
Railcars Maximum Potential Loss From Lease Agreement		19		25

For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2012 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 Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, 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. 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, Executive Vice President of Energy Supply, 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, 2012:

	MTM Risk Management Contract Net Assets (Liabilities)
	Six Months Ended June 30, 2013

				Generation
		Utility		and
		Operations		Marketing		Total
		(in millions)
Total MTM Risk Management Contract Net Assets
	as of December 31, 2012	$	68	$	128	$	196
(Gain) Loss from Contracts Realized/Settled During the Period and
	Entered in a Prior Period		(17)		(11)		(28)
Fair Value of New Contracts at Inception When Entered During the
	Period (a)		-		10		10
Changes in Fair Value Due to Market Fluctuations During the
	Period (b)		1		13		14
Changes in Fair Value Allocated to Regulated Jurisdictions (c)			12		-		12
Total MTM Risk Management Contract Net Assets
	as of June 30, 2013	$	64	$	140		204

Commodity Cash Flow Hedge Contracts							2
Interest Rate and Foreign Currency Cash Flow Hedge Contracts							(2)
Fair Value Hedge Contracts							(12)
Collateral Deposits							20
Total MTM Derivative Contract Net Assets as of June 30, 2013						$	212

(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 8 – Derivatives and Hedging and Note 9 – 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, 2013, our credit exposure net of collateral to sub investment grade counterparties was approximately 8.1%, 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, 2013, 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		$	594	$	1	$	593		2	$	263
Split Rating			1		1		-		-		-
Noninvestment Grade			1		1		-		1		-
No External Ratings:
	Internal Investment Grade		71		-		71		3		29
	Internal Noninvestment Grade		69		11		58		2		40
Total as of June 30, 2013		$	736	$	14	$	722		8	$	332

Total as of December 31, 2012		$	807	$	13	$	794		7	$	338

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, 2013, a near term typical change in commodity prices is not expected to materially impact 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, 2013								December 31, 2012
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	-	$	1	$	-	$	-	$	-	$	1	$	-	$	-

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, 2013 and December 31, 2012, the estimated EaR on our debt portfolio for the following twelve months was $39 million and $42 million, respectively.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2013 and 2012
(in millions, except per-share and share amounts)
(Unaudited)

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
REVENUES
Utility Operations		$	3,253	$	3,235	$	6,742	$	6,598
Other Revenues			329		316		666		578
TOTAL REVENUES			3,582		3,551		7,408		7,176
EXPENSES
Fuel and Other Consumables Used for Electric Generation			908		904		1,939		1,957
Purchased Electricity for Resale			359		268		730		528
Other Operation			664		719		1,402		1,375
Maintenance			285		252		578		514
Asset Impairments and Other Related Charges			154		-		154		-
Depreciation and Amortization			443		460		863		883
Taxes Other Than Income Taxes			222		207		440		424
TOTAL EXPENSES			3,035		2,810		6,106		5,681

OPERATING INCOME			547		741		1,302		1,495

Other Income (Expense):
Interest and Investment Income			49		2		52		4
Carrying Costs Income			8		11		12		31
Allowance for Equity Funds Used During Construction			17		24		32		47
Interest Expense			(228)		(235)		(460)		(464)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS			393		543		938		1,113

Income Tax Expense			68		190		263		379
Equity Earnings of Unconsolidated Subsidiaries			14		10		28		19

NET INCOME			339		363		703		753

Net Income Attributable to Noncontrolling Interests			1		1		2		2

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	338	$	362	$	701	$	751

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING			486,293,026		484,500,029		486,059,643		484,164,065

TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
	SHAREHOLDERS	$	0.69	$	0.75	$	1.44	$	1.55

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING			486,763,615		484,860,690		486,555,121		484,554,779

TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
	SHAREHOLDERS	$	0.69	$	0.75	$	1.44	$	1.55

CASH DIVIDENDS DECLARED PER SHARE		$	0.49	$	0.47	$	0.96	$	0.94

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 37.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2013 and 2012
(in millions)
(Unaudited)

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
Net Income		$	339	$	363	$	703	$	753

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $5 and $5 for the Three Months Ended
	June 30, 2013 and 2012, Respectively, and $8 and $11 for the Six
	Months Ended June 30, 2013 and 2012, Respectively		(10)		(10)		14		(21)
Securities Available for Sale, Net of Tax of $- and $- for the Three Months
	Ended June 30, 2013 and 2012, Respectively, and $- and $1 for the
	Six Months Ended June 30, 2013 and 2012, Respectively		-		(1)		1		1
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $2
	and $4 for the Three Months Ended June 30, 2013 and 2012,
	Respectively, and $5 and $8 for the Six Months Ended June 30,
	2013 and 2012, Respectively		3		8		9		15

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			(7)		(3)		24		(5)

TOTAL COMPREHENSIVE INCOME			332		360		727		748

Total Comprehensive Income Attributable to Noncontrolling Interests			1		1		2		2

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
	COMMON SHAREHOLDERS	$	331	$	359	$	725	$	746

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 37.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 30, 2013 and 2012
(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, 2011		504	$	3,274	$	5,970	$	5,890	$	(470)	$	1	$	14,665

Issuance of Common Stock		1		10		40								50
Common Stock Dividends								(456)				(2)		(458)
Other Changes in Equity						3								3
Net Income								751				2		753
Other Comprehensive Loss										(5)				(5)
TOTAL EQUITY – JUNE 30, 2012		505	$	3,284	$	6,013	$	6,185	$	(475)	$	1	$	15,008

TOTAL EQUITY – DECEMBER 31, 2012		506	$	3,289	$	6,049	$	6,236	$	(337)	$	-	$	15,237

Issuance of Common Stock		1		7		34								41
Common Stock Dividends								(467)				(2)		(469)
Other Changes in Equity						1								1
Net Income								701				2		703
Other Comprehensive Income										24				24
TOTAL EQUITY – JUNE 30, 2013		507	$	3,296	$	6,084	$	6,470	$	(313)	$	-	$	15,537

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 37.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2013 and December 31, 2012
(in millions)
(Unaudited)

			June 30,		December 31,
			2013		2012
CURRENT ASSETS
Cash and Cash Equivalents			$	117	$	279
Other Temporary Investments
	(June 30, 2013 and December 31, 2012 Amounts Include $281 and $311, Respectively, Related to Transition Funding and EIS)			298		324
Accounts Receivable:
	Customers			725		685
	Accrued Unbilled Revenues			95		195
	Pledged Accounts Receivable – AEP Credit			975		856
	Miscellaneous			174		171
	Allowance for Uncollectible Accounts			(38)		(36)
		Total Accounts Receivable		1,931		1,871
Fuel				879		844
Materials and Supplies				695		675
Risk Management Assets				187		191
Regulatory Asset for Under-Recovered Fuel Costs				98		88
Margin Deposits				80		76
Prepayments and Other Current Assets				337		241
TOTAL CURRENT ASSETS				4,622		4,589

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			26,183		26,279
	Transmission			10,081		9,846
	Distribution			15,887		15,565
Other Property, Plant and Equipment (Including Nuclear Fuel and Coal Mining)				4,033		3,945
Construction Work in Progress				2,173		1,819
Total Property, Plant and Equipment				58,357		57,454
Accumulated Depreciation and Amortization				18,932		18,691
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				39,425		38,763

OTHER NONCURRENT ASSETS
Regulatory Assets				5,139		5,106
Securitized Transition Assets				2,013		2,117
Spent Nuclear Fuel and Decommissioning Trusts				1,791		1,706
Goodwill				91		91
Long-term Risk Management Assets				317		368
Deferred Charges and Other Noncurrent Assets				1,581		1,627
TOTAL OTHER NONCURRENT ASSETS				10,932		11,015

TOTAL ASSETS			$	54,979	$	54,367

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 37.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2013 and December 31, 2012
(dollars in millions)
(Unaudited)

					June 30,		December 31,
					2013		2012
CURRENT LIABILITIES
Accounts Payable					$	987	$	1,169
Short-term Debt:
	Securitized Debt for Receivables - AEP Credit					688		657
	Other Short-term Debt					850		324
		Total Short-term Debt				1,538		981
Long-term Debt Due Within One Year
	(June 30, 2013 and December 31, 2012 Amounts Include $396 and $367, Respectively, Related to Transition Funding, DCC Fuel and Sabine)					1,819		2,171
Risk Management Liabilities						111		155
Customer Deposits						297		316
Accrued Taxes						680		747
Accrued Interest						254		269
Regulatory Liability for Over-Recovered Fuel Costs						10		47
Other Current Liabilities						823		968
TOTAL CURRENT LIABILITIES						6,519		6,823

NONCURRENT LIABILITIES
Long-term Debt
	(June 30, 2013 and December 31, 2012 Amounts Include $2,105 and $2,227, Respectively, Related to Transition Funding, DCC Fuel and Sabine)					15,799		15,586
Long-term Risk Management Liabilities						181		214
Deferred Income Taxes						9,691		9,252
Regulatory Liabilities and Deferred Investment Tax Credits						3,585		3,544
Asset Retirement Obligations						1,734		1,696
Employee Benefits and Pension Obligations						1,044		1,075
Deferred Credits and Other Noncurrent Liabilities						889		940
TOTAL NONCURRENT LIABILITIES						32,923		32,307

TOTAL LIABILITIES						39,442		39,130

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

EQUITY
Common Stock – Par Value – $6.50 Per Share:
			2013	2012
	Shares Authorized		600,000,000	600,000,000
	Shares Issued		507,071,824	506,004,962
(20,336,592 Shares were Held in Treasury as of June 30, 2013 and December 31, 2012)						3,296		3,289
Paid-in Capital						6,084		6,049
Retained Earnings						6,470		6,236
Accumulated Other Comprehensive Income (Loss)						(313)		(337)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY						15,537		15,237

Noncontrolling Interests						-		-

TOTAL EQUITY						15,537		15,237

TOTAL LIABILITIES AND EQUITY					$	54,979	$	54,367

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 37.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2013 and 2012
(in millions)
(Unaudited)

			Six Months Ended June 30,
			2013		2012
OPERATING ACTIVITIES
Net Income			$	703	$	753
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			863		883
	Deferred Income Taxes			367		417
	Asset Impairments and Other Related Charges			154		-
	Carrying Costs Income			(12)		(31)
	Allowance for Equity Funds Used During Construction			(32)		(47)
	Mark-to-Market of Risk Management Contracts			16		8
	Amortization of Nuclear Fuel			63		64
	Property Taxes			68		68
	Fuel Over/Under-Recovery, Net			(4)		91
	Deferral of Ohio Capacity Costs, Net			(102)		-
	Change in Other Noncurrent Assets			(20)		(80)
	Change in Other Noncurrent Liabilities			12		31
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		(53)		93
		Fuel, Materials and Supplies		(61)		(199)
		Accounts Payable		(57)		(100)
		Accrued Taxes, Net		(214)		(92)
		Other Current Assets		(10)		(7)
		Other Current Liabilities		(165)		(139)
Net Cash Flows from Operating Activities				1,516		1,713

INVESTING ACTIVITIES
Construction Expenditures				(1,637)		(1,371)
Change in Other Temporary Investments, Net				38		(1)
Purchases of Investment Securities				(423)		(546)
Sales of Investment Securities				385		517
Acquisitions of Nuclear Fuel				(59)		(11)
Acquisitions of Assets/Businesses				(4)		(88)
Insurance Proceeds Related to Cook Plant Fire				72		-
Proceeds from Sales of Assets				11		8
Other Investing Activities				(26)		(38)
Net Cash Flows Used for Investing Activities				(1,643)		(1,530)

FINANCING ACTIVITIES
Issuance of Common Stock, Net				41		50
Issuance of Long-term Debt				941		1,261
Commercial Paper and Credit Facility Borrowings				17		21
Change in Short-term Debt, Net				560		(425)
Retirement of Long-term Debt				(1,073)		(487)
Commercial Paper and Credit Facility Repayments				(20)		(38)
Principal Payments for Capital Lease Obligations				(33)		(36)
Dividends Paid on Common Stock				(469)		(458)
Other Financing Activities				1		5
Net Cash Flows Used for Financing Activities				(35)		(107)

Net Increase (Decrease) in Cash and Cash Equivalents				(162)		76
Cash and Cash Equivalents at Beginning of Period				279		221
Cash and Cash Equivalents at End of Period			$	117	$	297

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	455	$	444
Net Cash Paid (Received) for Income Taxes				(10)		(42)
Noncash Acquisitions Under Capital Leases				31		33
Construction Expenditures Included in Current Liabilities as of June 30,				297		255
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,				41		-
Noncash Assumption of Liabilities Related to Acquisitions				-		56

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 37.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Page
	Number

Significant Accounting Matters	38
Comprehensive Income	39
Rate Matters	43
Commitments, Guarantees and Contingencies	53
Acquisition and Impairment	56
Benefit Plans	57
Business Segments	58
Derivatives and Hedging	60
Fair Value Measurements	67
Income Taxes	76
Financing Activities	77
Variable Interest Entities	80
Sustainable Cost Reductions	84

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. SIGNIFICANT ACCOUNTING MATTERS

General

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

In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods. Net income for the three and six months ended June 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013. The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2012 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 26, 2013.

Earnings Per Share (EPS)

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

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

		Three Months Ended June 30,
		2013				2012
		(in millions, except per share data)
				$/share				$/share
Earnings Attributable to AEP Common Shareholders		$	338			$	362

Weighted Average Number of Basic Shares Outstanding			486.3	$	0.69		484.5	$	0.75
Weighted Average Dilutive Effect of:
	Stock Options		-		-		0.1		-
	Restricted Stock Units		0.5		-		0.3		-
Weighted Average Number of Diluted Shares Outstanding			486.8	$	0.69		484.9	$	0.75

		Six Months Ended June 30,
		2013				2012
		(in millions, except per share data)
				$/share				$/share
Earnings Attributable to AEP Common Shareholders		$	701			$	751

Weighted Average Number of Basic Shares Outstanding			486.1	$	1.44		484.2	$	1.55
Weighted Average Dilutive Effect of:
	Stock Options		-		-		0.1		-
	Restricted Stock Units		0.5		-		0.3		-
Weighted Average Number of Diluted Shares Outstanding			486.6	$	1.44		484.6	$	1.55

There were no antidilutive shares outstanding as of June 30, 2013 and 2012.

2. COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI for the three and six months ended June 30, 2013. All amounts in the following tables are presented net of related income taxes.

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2013

		Cash Flow Hedges
				Interest Rate and		Securities		Pension
		Commodity		Foreign Currency		Available for Sale		and OPEB		Total
		(in millions)
Balance in AOCI as of March 31, 2013		$	12	$	(26)	$	5	$	(297)	$	(306)
Change in Fair Value Recognized in AOCI			(8)		(1)		-		-		(9)
Amounts Reclassified from AOCI			(3)		2		-		3		2
Net Current Period Other
	Comprehensive Income		(11)		1		-		3		(7)
Balance in AOCI as of June 30, 2013		$	1	$	(25)	$	5	$	(294)	$	(313)

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2013

		Cash Flow Hedges
				Interest Rate and		Securities		Pension
		Commodity		Foreign Currency		Available for Sale		and OPEB		Total
		(in millions)
Balance in AOCI as of December 31, 2012		$	(8)	$	(30)	$	4	$	(303)	$	(337)
Change in Fair Value Recognized in AOCI			10		2		1		-		13
Amounts Reclassified from AOCI			(1)		3		-		9		11
Net Current Period Other
	Comprehensive Income		9		5		1		9		24
Balance in AOCI as of June 30, 2013		$	1	$	(25)	$	5	$	(294)	$	(313)

Reclassifications Out of Accumulated Other Comprehensive Income

The following tables provide details of reclassifications from AOCI for the three and six months ended June 30, 2013. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details.

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Three Months Ended June 30, 2013

		Amount of
		(Gain) Loss
		Reclassified
		from AOCI
Gains and Losses on Cash Flow Hedges		(in millions)
Commodity:
	Utility Operations Revenues	$	-
	Other Revenues		(2)
	Purchased Electricity for Resale		(2)
	Property, Plant and Equipment		-
	Regulatory Assets (a)		-
Subtotal - Commodity			(4)

Interest Rate and Foreign Currency:
	Interest Expense		2
Subtotal - Interest Rate and Foreign Currency			2

Reclassifications from AOCI, before Income Tax (Expense) Credit			(2)
Income Tax (Expense) Credit			(1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit			(1)

Gains and Losses on Available-for-Sale Securities
Interest Income			-
Interest Expense			-
Reclassifications from AOCI, before Income Tax (Expense) Credit			-
Income Tax (Expense) Credit			-
Reclassifications from AOCI, Net of Income Tax (Expense) Credit			-

Amortization of Pension and OPEB
Prior Service Cost (Credit)			(4)
Actuarial (Gains)/Losses			9
Reclassifications from AOCI, before Income Tax (Expense) Credit			5
Income Tax (Expense) Credit			2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit			3

Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	2

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Six Months Ended June 30, 2013

		Amount of
		(Gain) Loss
		Reclassified
		from AOCI
Gains and Losses on Cash Flow Hedges		(in millions)
Commodity:
	Utility Operations Revenues	$	-
	Other Revenues		(5)
	Purchased Electricity for Resale		4
	Property, Plant and Equipment		-
	Regulatory Assets (a)		-
Subtotal - Commodity			(1)

Interest Rate and Foreign Currency:
	Interest Expense		4
Subtotal - Interest Rate and Foreign Currency			4

Reclassifications from AOCI, before Income Tax (Expense) Credit			3
Income Tax (Expense) Credit			1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit			2

Gains and Losses on Available-for-Sale Securities
Interest Income			-
Interest Expense			-
Reclassifications from AOCI, before Income Tax (Expense) Credit			-
Income Tax (Expense) Credit			-
Reclassifications from AOCI, Net of Income Tax (Expense) Credit			-

Amortization of Pension and OPEB
Prior Service Cost (Credit)			(9)
Actuarial (Gains)/Losses			23
Reclassifications from AOCI, before Income Tax (Expense) Credit			14
Income Tax (Expense) Credit			5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit			9

Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	11

(a)

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

The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2012. All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2012
					Interest Rate
					and Foreign
			Commodity		Currency		Total
			(in millions)
Balance in AOCI as of March 31, 2012			$	(16)	$	(18)	$	(34)
Changes in Fair Value Recognized in AOCI				(3)		(13)		(16)
Amount of (Gain) or Loss Reclassified from AOCI
	to Statement of Income/within Balance Sheet:
		Utility Operations Revenues		-		-		-
		Other Revenues		(2)		-		(2)
		Purchased Electricity for Resale		6		-		6
		Interest Expense		-		1		1
		Regulatory Assets (a)		1		-		1
Balance in AOCI as of June 30, 2012			$	(14)	$	(30)	$	(44)

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2012
					Interest Rate
					and Foreign
			Commodity		Currency		Total
			(in millions)
Balance in AOCI as of December 31, 2011			$	(3)	$	(20)	$	(23)
Changes in Fair Value Recognized in AOCI				(23)		(12)		(35)
Amount of (Gain) or Loss Reclassified from AOCI
	to Statement of Income/within Balance Sheet:
		Utility Operations Revenues		-		-		-
		Other Revenues		(3)		-		(3)
		Purchased Electricity for Resale		13		-		13
		Interest Expense		-		2		2
		Regulatory Assets (a)		2		-		2
Balance in AOCI as of June 30, 2012			$	(14)	$	(30)	$	(44)

(a)

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

The following tables provide details of changes in unrealized gains and losses related to Securities Available for Sale and the reasons for changes for the three and six months ended June 30, 2012. All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Securities Available for Sale
For the Three Months Ended June 30, 2012

		(in millions)
Balance in AOCI as of March 31, 2012		$	4
Changes in Fair Value Recognized in AOCI			(1)
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income:
	Interest Income		-
Balance in AOCI as of June 30, 2012		$	3

Total Accumulated Other Comprehensive Income (Loss) Activity for Securities Available for Sale
For the Six Months Ended June 30, 2012

		(in millions)
Balance in AOCI as of December 31, 2011		$	2
Changes in Fair Value Recognized in AOCI			1
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income:
	Interest Income		-
Balance in AOCI as of June 30, 2012		$	3

3. RATE MATTERS

As discussed in the 2012 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2012 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2013 and updates the 2012 Annual Report.

Regulatory Assets Not Yet Being Recovered

		June 30,		December 31,
		2013		2012
		(in millions)
Noncurrent Regulatory Assets
Regulatory assets not yet being recovered pending future proceedings:

Regulatory Assets Currently Earning a Return
	Storm Related Costs	$	22	$	23
	Economic Development Rider		14		13
	Other Regulatory Assets Not Yet Being Recovered		3		1
Regulatory Assets Currently Not Earning a Return
	Storm Related Costs		142		172
	Virginia Environmental Rate Adjustment Clause		29		29
	Ormet Delayed Payment Arrangement		20		5
	Mountaineer Carbon Capture and Storage Product Validation Facility		14		14
	Litigation Settlement		-		11
	Other Regulatory Assets Not Yet Being Recovered		44		36
Total Regulatory Assets Not Yet Being Recovered		$	288	$	304

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

OPCo Rate Matters

Ohio Electric Security Plan Filing

2009 – 2011 ESP

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

In October 2011, the PUCO issued an order in the remand proceeding. As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011. In February 2012, the Ohio Consumers’ Counsel and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance. As of June 30, 2013, OPCo’s net deferred fuel balance was $484 million, excluding unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending.

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off in 2010 and a subsequent refund to customers during 2011. The IEU and the Ohio Energy Group filed appeals with the Supreme Court of Ohio challenging the PUCO’s SEET decision. In December 2012, the Supreme Court of Ohio issued an order which rejected all of the intervenors’ challenges and affirmed the PUCO decision.

The 2009 SEET order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project by the end of 2013. Management continues to evaluate other investment alternatives.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order. Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings, which included off-system sales in the SEET calculation. In December 2011, the PUCO staff filed testimony that recommended a $23 million refund of 2010 earnings. OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO-ordered SEET refund. OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. The PUCO approved OPCo’s requests to file the SEET for 2011 and 2012 one month after the PUCO issues an order on the 2010 SEET. Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in 2012 for OPCo. Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo.

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo filed an appeal at the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate. The IEU and the Ohio Consumers’ Counsel also filed appeals at the Supreme Court of Ohio in November 2012 arguing that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues and reduced carrying costs due to an accumulated deferred income tax credit. These appeals could reduce OPCo’s net deferred fuel balance up to the total balance, which could reduce future net income and cash flows. A decision from the Supreme Court of Ohio is pending.

Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition.

June 2012 – May 2015 ESP Including Capacity Charge

As part of the ESP decision, the PUCO ordered OPCo to conduct an energy-only auction for 10% of the SSO load with delivery beginning six months after the receipt of final orders in both the ESP and corporate separation cases and extending through May 2015. The initiation of the auction is pending the issuance of an order by the PUCO in a separate docket. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning June 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015. OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015.

As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012. The RSR is expected to provide approximately $500 million of revenue over the ESP period and will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In August 2012, the IEU filed an action with the Supreme Court of Ohio stating, among other things, that OPCo’s collection of its capacity costs is illegal. In April 2013, the Supreme Court of Ohio dismissed the IEU’s action.

In January and March 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order including the implementation of the RSR. The PUCO clarified that a final reconciliation of revenues and costs would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order.

In June 2013, intervenors in the competitive bid process (CBP) docket filed recommendations that include prospective rate reductions for capacity and non-energy FAC issues. OPCo maintains that the August 2012 ESP order fixed OPCo’s non-energy generation rates through December 31, 2014 and ordered the application of a $188.88/MW day price for capacity for non-shopping customers effective January 1, 2015. However, intervenors maintained that OPCo’s non-energy generation rates should be reduced prior to January 1, 2015 to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned (10% prior to June 2014 and 60% for the period June 1, 2014 through December 31, 2014). An additional proposal to prospectively offset deferred capacity costs based upon the results of the energy-only auctions was not quantified and OPCo maintains that proposal should not be adopted in light of prior PUCO orders. Hearings related to the CBP were held at the PUCO in June and July 2013.

If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its deferred capacity costs, it could reduce future net income and cash flows and impact financial condition.

Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets at net book value to AEPGenCo. AEPGenCo will also assume the associated generation liabilities. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.

Also in October 2012, filings at the FERC were submitted related to corporate separation. In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AEPGenCo. Results of operations related to generation in Ohio will be largely determined by prevailing market conditions effective January 1, 2014. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.

Storm Damage Recovery Rider (SDRR)

In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates. The SDRR seeks recovery of 2012 incremental storm distribution expenses over twelve months starting with the effective date of the SDRR as approved by the PUCO. OPCo also requested approval of a weighted average cost of capital carrying charge if recovery of these costs did not begin prior to April 2013. In May 2013, intervenors filed comments with various recommendations including reductions in the amount of storm costs recoverable up to the amount deferred, an extended recovery period, and an additional review of the storm costs including the allocation of costs to capital. As of June 30, 2013, OPCo recorded $ 61 million in Regulatory Assets on the balance sheet related to 2012 storm damage. If OPCo is not ultimately permitted to recover these storm costs, it could reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

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

In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges, which, if ordered, would be $35 million plus carrying charges. If the Supreme Court of Ohio ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes. As of June 30, 2013, the amount of OPCo’s carrying costs that could potentially be reduced due to the accumulated income tax issue is estimated to be $34 million, including $18 million of unrecognized equity carrying costs. These amounts include the carrying costs exposure of the 2009 FAC audit, which has been appealed by an intervenor to the Supreme Court of Ohio. Decisions from the PUCO are pending. Management is unable to predict the outcome of these proceedings. If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. In November 2009, OPCo requested that the PUCO approve recovery of the deferral under the interim agreement plus a weighted average cost of capital carrying charge. The deferral amount is included in OPCo’s FAC phase-in deferral balance. In the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related regulatory asset and requested that the PUCO prevent OPCo from collecting the Ormet-related revenues in the future. The PUCO did not take any action on this request. The intervenors raised the issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. This issue remains pending before the PUCO. If OPCo is not ultimately permitted to fully recover its requested deferrals under the interim arrangement, it could reduce future net income and cash flows and impact financial condition.

Special Rate Mechanism for Ormet

In October 2012, the PUCO issued an order approving a delayed payment plan for Ormet’s October and November 2012 power billings totaling $27 million to be paid in equal monthly installments over the period January 2014 to May 2015 without interest. In the event Ormet does not pay its $27 million obligation, the PUCO permitted OPCo to recover the unpaid balance, up to $20 million, in the economic development rider. To the extent unpaid amounts exceed $20 million, it could reduce future net income and cash flows and impact financial condition.

In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware but is current on all payments due to OPCo. In June 2013, Ormet filed a motion with the PUCO to amend its contract with OPCo which currently provides for services through 2018. The proposed amendments would allow Ormet to purchase power from a third party beginning January 2014. In July 2013, OPCo filed its objections with the PUCO which included a recommendation to have Ormet pay an exit fee as a potential resolution to address the financial concerns associated with amending the current contract. Hearings at the PUCO are scheduled for August 2013. As of June 30, 2013, OPCo has a regulatory asset of $20 million and a net receivable of $6 million recorded related to the special rate mechanism for Ormet.

Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. As of June 30, 2013, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting OPCo refund all collected pre-construction costs to Ohio ratepayers with interest.

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

SWEPCo Rate Matters

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility. As of June 30, 2013, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital cost cap, SWEPCo has capitalized approximately $ 1.8 billion of expenditures, including AFUDC and capitalized interest of $328 million and related transmission costs of $ 118 million.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the SPP market.

The PUCT approved a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO 2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers. SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful. The Texas Industrial Energy Consumers (TIEC) filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers. The Texas District Court and the Texas Court of Appeals affirmed the PUCT’s order in all respects. In April 2012, SWEPCo and the TIEC filed petitions for review at the Supreme Court of Texas, which were denied in March 2013. In April 2013, SWEPCo and the TIEC filed motions for rehearing at the Supreme Court of Texas. In May 2013, the Supreme Court of Texas requested the PUCT and the TIEC respond to SWEPCo’s motion.

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

2012 Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million, primarily due to the Turk Plant, based upon an 11.25% return on common equity to be effective January 2013. The requested base rate increase included a return on and of the Texas jurisdictional share (approximately 33%) of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs. The filing also (a) increased depreciation expense due to the decrease in the average remaining life of the Welsh Plant to account for the change in the retirement date of the Welsh Plant, Unit 2 from 2040 to 2016, (b) proposed increased vegetation management expenditures and (c) included a return on and of the Stall Unit as of December 2011 and associated operation and maintenance costs.

In September 2012, an Administrative Law Judge (ALJ) issued an order that granted the establishment of SWEPCo’s existing rates as temporary rates beginning in late January 2013, subject to true-up to the final PUCT-approved rates.

In December 2012, several intervenors, including the PUCT staff, filed testimony that recommended an annual base rate increase between $16 million and $51 million based upon a return on common equity between 9% and 9.55%. In addition, two intervenors recommended that the Turk Plant be excluded from rate base. In May 2013, the ALJ issued a proposal for decision (PFD) and added clarifications in July 2013. The PFD, as clarified, made various recommendations including (a) an annual base rate increase of approximately $ 41 million based upon a return on common equity of 9.65%, (b) the disallowance of the Turk Plant capital costs in excess of the investment and committed costs as of June 2010 plus the cost to retrofit Welsh Plant, Unit 2 which, as of June 30, 2013, SWEPCo estimates could result in a write-off of approximately $ 74 million (in excess of the $62 million reserve previously recorded related to the Texas capital cost cap) and (c) the exclusion, until SWEPCo’s next Texas base rate case, of the Turk Plant transmission line investment that was not in service at the end of the test year. A decision from the PUCT is expected in the third quarter of 2013. If the PUCT does not approve full cost recovery of SWEPCo’s Texas jurisdictional share of assets, it could reduce future net income and cash flows and impact financial condition.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund based on the staff review of the cost of service and the prudence review of the Turk Plant. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover all non-fuel Turk Plant costs and a full weighted-average cost of capital return on the Turk Plant portion of rate base, effective January 2013. In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant. If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

Flint Creek Plant Environmental Controls

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. As of June 30, 2013, SWEPCo has incurred $24 million related to this project, including AFUDC and company overheads. In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant.

APCo and WPCo Rate Matters

Plant Transfers

In October 2012, the AEP East Companies submitted several filings with the FERC regarding the transfer of certain generation plants within the AEP System. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant, comprising 1,647 MW of average annual generating capacity presently owned by OPCo. In April 2013, several intervenors filed testimony with the Virginia SCC and made recommendations relating to APCo’s proposed asset transfers including the issuance of a Request for Proposal (RFP) for APCo’s resource needs. In May 2013, Virginia SCC staff filed testimony making recommendations including several alternatives to the asset transfers as proposed including the recommendation to approve only the Amos Plant, Unit 3 asset transfer and limiting the non-contractual liabilities to be assumed by APCo. Hearings were held at the Virginia SCC in June 2013. In June 2013, intervenors filed testimony with the WVPSC and made recommendations relating to APCo’s proposed asset transfers including the transfer of only one plant, the issuance of a RFP for any additional capacity and energy requirements and limiting the liabilities to the types and amounts reflected in the net book value of the asset transfers. Hearings were held at the WVPSC in July 2013. APCo is currently pursuing cost recovery of these plants in West Virginia and plans to pursue cost recovery in Virginia. If APCo and WPCo are not ultimately permitted to recover their incurred costs, it could reduce future net income and cash flows and impact financial condition.

APCo IGCC Plant

As of June 30, 2013, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $10 million applicable to its Virginia jurisdiction. If the costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs effective February 2014 over a one-year period. In March 2013, the environmental RAC surcharge expired related to the collection of 2009 and 2010 environmental compliance costs. APCo has deferred $28 million as of June 30, 2013 for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $11 million of unrecognized equity carrying costs. Hearings at the Virginia SCC are scheduled for August 2013. If the Virginia SCC were to disallow any portion of the environmental RAC, it could reduce future net income and cash flows.

2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing

In March 2013, APCo filed with the Virginia SCC for an increase in its generation RAC revenues of $12 million for a total of $ 38 million annually to collect costs related to the Dresden Plant. The generation RAC increase is expected to be effective in March 2014. APCo has deferred $4 million as of June 30, 2013 for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $4 million of unrecognized equity carrying costs. Hearings at the Virginia SCC are scheduled for August 2013. If the Virginia SCC were to disallow any portion of the generation RAC, it could reduce future net income and cash flows.

2012 West Virginia Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation which allows the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred ENEC balances and other ENEC-related assets. In August 2012, APCo and WPCo filed a request with the WVPSC for a financing order to securitize a total of $422 million related to the December 2011 under-recovered ENEC deferral balance including other ENEC-related assets of $13 million and related future financing costs of $7 million. Upon completion of the securitization, APCo would offset its current ENEC rates by an amount to recover the securitized balance over the securitization period. In March 2013, APCo, WPCo and intervenors filed a settlement agreement with the WVPSC which recommended the WVPSC authorize APCo to securitize $ 376 million plus upfront financing costs. Hearings at the WVPSC on the securitization are scheduled for July 2013. As of June 30, 2013, APCo’s ENEC under-recovery balance of $287 million, net of 2012 and 2013 over-recovery, was recorded in Regulatory Assets on the balance sheet, excluding $3 million of unrecognized equity carrying costs and $15 million of other ENEC-related assets.

In April 2013, APCo and WPCo filed to keep total rates unchanged with a portion of the ENEC to be specifically identified for the amount to be securitized in accordance with the proposed securitization settlement agreement. The remaining ENEC rate is proposed to include (a) the proposed transfer of certain generation facilities from OPCo and the APCo/WPCo merger, (b) construction surcharges and (c) ongoing ENEC costs. Management is currently reviewing intervenor testimony filed in July 2013 that recommends lower ENEC revenues. Hearings at the WVPSC are scheduled for August 2013. If the WVPSC were to disallow any portion of the ENEC, it could reduce future net income and cash flows.

Virginia Storm Costs

In March 2013, due to the 2013 enactment of a Virginia law, APCo wrote off $30 million of previously deferred 2012 Virginia storm costs. The change in law affected the test years to be included in APCo's next biennial Virginia base rate filing in March 2014 and the determination of how these costs are treated in the Virginia jurisdictional biennial earnings test for 2012 actual results and 2013 estimated results. The 2013 earnings component will be reviewed quarterly to determine if any storm costs can be deferred. As of June 30, 2013, there were no Virginia deferred storm costs. If this quarterly test allows APCo to recover previously expensed storm costs, it could increase future net income and cash flows.

PSO Rate Matters

Oklahoma Environmental Compliance Plan

In September 2012, based upon an agreement with the Federal EPA, the State of Oklahoma and other parties, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES) Unit 4 in 2016 and additional environmental controls on NES Unit 3 to continue operations through 2026. The plan requested approval for (a) an estimated $210 million of new environmental investment, excluding AFUDC and overheads of $46 million, that will be incurred prior to 2016 at NES Unit 3, (b) accelerated recovery through 2026 of the net book value of NES Units 3 and 4 (combined net book value of the two units is $231 million as of June 30, 2013), (c) an estimated $83 million of new investment incurred through 2016 at various gas units and (d) a new 15-year purchase power agreement (PPA) with a nonaffiliated entity, effective in 2016, with cost recovery through a rider, including an annual earnings component of $3 million. Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery in a future rate proceeding.

In January 2013, testimony filed by the OCC staff and the Oklahoma Office of the Attorney General (OOAG) recommended no earnings component on the PPA and to delay final decisions until 2020 on parts of the plan including cost recovery of the net book value of NES Unit 3 and any increases in fuel costs due to reductions in the output of energy from NES Unit 3 beginning in 2021. The testimony recommended that cost recovery could extend past 2026 on parts of the plan and recommended a $175 million cost cap on NES Unit 3 environmental investment, excluding AFUDC and overheads.

In March 2013, the OCC staff and the OOAG filed additional testimony revising the recommended cost cap on NES Unit 3 to $210 million, excluding AFUDC and overheads, and recommended conditional approval of the planned NES Unit 3 retirement subject to OCC approval in 2020 provided the planned retirement is consistent with environmental rules at that time.

Also, an intervenor representing some of PSO’s large industrial users opposed the majority of PSO’s plan, including recommending no cost recovery of NES Units 3 and 4 book value amounts not recovered at the time of their retirement and no recovery of the PPA costs, including earnings on the PPA. In February 2013, the OCC staff requested a stay in this proceeding, which was granted by the OCC in March 2013. In July 2013, the OCC staff filed a motion to lift the stay and dismiss PSO’s environmental compliance plan case without prejudice. A hearing on the motion will be held in August 2013. If this case is dismissed, PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan.

I&M Rate Matters

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $ 85 million annual increase in base rates based upon a return on common equity of 10.2%. In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates from $85 million to $ 92 million. In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed a request for reconsideration with the IURC, which was denied. Also in March 2013, the OUCC filed an appeal of the order with the Indiana Court of Appeals. If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

Cook Plant Life Cycle Management Project (LCM Project)

In April 2012, I&M filed a petition with the IURC for recovery of project costs, including interest, through a new rider. In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $ 23 million related to certain items that might accommodate a future potential power uprate which the IURC stated could be sought for recovery in a base rate case. I&M was granted recovery through an LCM rider which will be determined by a mid-September 2013 proceeding and semi-annual proceedings thereafter. The IURC authorized deferral accounting for I&M’s incurred project costs effective January 2012 to the extent such costs are not reflected in its rates.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project. If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

Rockport Plant Clean Coal Technology Project (CCT Project)

In July 2013, a settlement agreement was filed with the IURC. The settlement agreement includes the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s direct ownership share. The settlement agreement specifies that 80% of the recoverable I&M direct ownership share of CCT Project costs will be recovered through a Federal Mandate Rider with the remaining 20% deferred until rates are established in a subsequent rate case. If the IURC approves the settlement agreement, I&M’s Indiana allocated share of the CCT Project costs received in the form of purchased power from AEGCo will be recovered in subsequent I&M rate cases. Hearings at the IURC are scheduled for August 2013. A decision is expected by November 2013. As of June 30, 2013, we have incurred costs of $77 million related to the CCT Project, including AFUDC. If we are not ultimately permitted to recover our incurred costs, it could reduce future net income and cash flows.

KPCo Rate Matters

Plant Transfer

In October 2012, the AEP East Companies submitted several filings with the FERC. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. In December 2012, KPCo filed a request with the KPSC for approval to transfer at net book value to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by OPCo. KPCo also requested costs related to the Big Sandy Plant, Unit 2 FGD project be established as a regulatory asset. KPCo is currently seeking recovery of these costs with the KPSC. In March 2013, KPCo issued a Request for Proposal (RFP) to purchase up to 250 MW of long-term capacity and energy to replace the capacity from the retirement of Big Sandy Plant, Unit 1. In June 2013, KPCo filed the results of its RFP with the KPSC. As of June 30, 2013, KPCo has incurred $ 28 million related to the FGD project, which is recorded in Deferred Charges and Other Noncurrent Assets on the balance sheet.

In May 2013, a memorandum of understanding (MOU) between KPCo, KIUC and the Sierra Club was filed with the KPSC. The MOU includes (a) the transfer of a one-half interest in the Mitchell Plant to KPCo at net book value on December 31, 2013 (b) the implementation of an Asset Transfer Rider to collect $44 million annually effective January 2014, subject to true-up, (c) the authorization to record FGD project costs as a regulatory asset, (d) the conversion of Big Sandy Plant, Unit 1 to natural gas and (e) any off-system sales margins above the $15.3 million annual level in base rates be retained by KPCo. In July 2013, KPCo, KIUC and the Sierra Club filed a settlement agreement with the KPSC pursuant to the MOU as modified. The settlement agreement also addressed potential greenhouse gas initiatives on the Mitchell Plant. The Attorney General was not a party to the settlement agreement. If approved, KPCo will withdraw the current base rate case request and current rates will remain in effect until at least May 2015. Hearings were held at the KPSC in July 2013. If KPCo is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows and impact financial condition.

2013 Kentucky Base Rate Case

In June 2013, KPCo filed a request with the KPSC for an annual increase in base rates of $ 114 million based upon a return on common equity of 10.65% to be effective January 2014. The proposed revenue increase includes cost recovery of the pending transfer of the one-half interest in the Mitchell Plant (780 MW) and cost recovery of Big Sandy Plant, Units 1 and 2. The filing also includes requests for recovery of deferrals totaling $ 48 million including $28 million related to the Big Sandy Plant FGD project and $ 12 million related to 2012 storm costs which are recorded in Deferred Charges and Other Noncurrent Assets and Regulatory Assets, respectively, on the balance sheet. Additionally, KPCo proposed that Big Sandy Plant, Unit 2 expenses incurred over the period January 2014 through May 2015 be deferred and recovered over five years beginning January 2014. Also in June 2013, a settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club was filed with the KPSC which supported the Mitchell plant transfer discussed above. If the settlement agreement is approved, KPCo will withdraw this base rate case request and current rates will remain in effect until at least May 2015. If KPCo is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows and impact financial condition.

FERC Rate Matters

Corporate Separation and Termination of Interconnection Agreement

In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations. The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets to a new wholly-owned company, AEPGenCo. The AEP East Companies also requested FERC approval to transfer at NBV OPCo’s current two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests (780 MW each). These transfers are proposed to be effective December 31, 2013. In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AEPGenCo, the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo and the merger of APCo and WPCo. In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo. OPCo has contested the petition for rehearing, which remains pending before the FERC. Similar asset transfer filings have been made at the KPSC, the Virginia SCC and the WVPSC. See the “Plant Transfers” section of APCo and WPCo Rate Matters and the “Plant Transfer” section of KPCo Rate Matters.

Additionally, the AEP East Companies requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Under the PCA, APCo, I&M and KPCo would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. Intervenors have opposed several of these filings. The AEP East Companies responded to intervenor comments and filed a revised PCA at the FERC in March 2013. The revised PCA included certain clarifying wording changes that have been agreed upon by intervenors. A decision is pending at the FERC.

4. COMMITMENTS, GUARANTEES AND CONTINGENCIES

We are subject to certain claims and legal actions arising in our ordinary course of business. In addition, our business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against us cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on our financial statements. The Commitments, Guarantees and Contingencies note within our 2012 Annual Report should be read in conjunction with this report.

GUARANTEES

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

Letters of Credit

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

We have two credit facilities totaling $3.5 billion, under which we may issue up to $1.2 billion as letters of credit. As of June 30, 2013, the maximum future payments for letters of credit issued under the credit facilities were $ 120 million with maturities ranging from October 2013 to June 2014.

We have $402 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $ 407 million. The letters of credit have maturities ranging from March 2014 to March 2015.

Guarantees of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $ 115 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million. Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2013, SWEPCo has collected approximately $ 62 million through a rider for final mine closure and reclamation costs, of which $12 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $ 50 million is recorded in Asset Retirement Obligations on our condensed balance sheets.

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

Indemnifications and Other Guarantees

Contracts

We enter into several types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the sale price. The status of certain sale agreements is discussed in the 2012 Annual Report “Dispositions” section of Note 6. As of June 30, 2013, there were no material liabilities recorded for any indemnifications.

Master Lease Agreements

We lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, we are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of June 30, 2013, the maximum potential loss for these lease agreements was approximately $ 20 million assuming the fair value of the equipment is zero at the end of the lease term.

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $13 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2013.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 83% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are approximately $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, we believe that the fair value would produce a sufficient sales price to avoid any loss.

ENVIRONMENTAL CONTINGENCIES

Carbon Dioxide Public Nuisance Claims

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO 2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision. The petition was denied in January 2011. Plaintiffs refiled their complaint in federal district court. The court ordered all defendants to respond to the refiled complaints in October 2011. In March 2012, the court granted the defendants’ motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations. In May 2013, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court’s dismissal of the complaint. The plaintiffs may seek further review in the U.S. Supreme Court. We will continue to defend against the claims. We are unable to determine a range of potential losses that are reasonably possible of occurring.

Alaskan Villages’ Claims

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO 2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $ 95 million to $400 million. In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim. The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court. In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court’s decision, holding that the CAA displaced Kivalina’s claims for damages. Plaintiffs filed seeking further review in the U.S. Supreme Court. In May 2013, the U.S. Supreme Court denied the plaintiffs’ request for review.

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

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

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

NUCLEAR CONTINGENCIES

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

Nuclear Incident Insurance

Prior to April 2013, I&M carried insurance coverage for a nuclear or nonnuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion. Effective April 2013, insurance coverage for a nonnuclear incident at the Cook Plant was reduced to $ 1.7 billion. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition.

OPERATIONAL CONTINGENCIES

Natural Gas Markets Lawsuits

In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) is among the companies named as defendants in some of these cases. We settled, received summary judgment or were dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court's dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court's orders in these cases. The appellate court reversed the district court's holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases. AEP filed a motion with the appellate court for rehearing on the issue of whether the district court had personal jurisdiction of AEP in the two referenced cases. No decision has been rendered on that motion. We will continue to defend the cases. We believe the provision we have is adequate.

5. ACQUISITION AND IMPAIRMENT

ACQUISITION

2012

BlueStar Energy (Generation and Marketing segment)

In March 2012, we completed the acquisition of BlueStar Energy Holdings, Inc. (BlueStar) and its independent retail electric supplier BlueStar Energy Solutions for $70 million. This transaction also included goodwill of $15 million, intangible assets associated with sales contracts and customer accounts of $ 58 million and liabilities associated with supply contracts of $25 million. BlueStar has been in operation since 2002. Beginning in June 2012, BlueStar began doing business as AEP Energy. AEP Energy provides electric supply for retail customers in Ohio, Illinois and other deregulated electricity markets and also provides energy solutions throughout the United States, including demand response and energy efficiency services.

IMPAIRMENT

2013

Muskingum River Plant, Unit 5 (Utility Operations segment)

In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including OPCo’s 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant. Under the modification to the consent decree, OPCo has the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017. In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, we re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project which would have extended the useful life of MR5 is remote. As a result, management completed an impairment analysis and concluded that MR5 was impaired. Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit. In the second quarter of 2013, OPCo recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory. Management expects to retire the plant in 2015.

6. BENEFIT PLANS

Components of Net Periodic Benefit Cost

The following tables provide the components of our net periodic benefit cost (credit) for the plans for the three and six months ended June 30, 2013 and 2012:

					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2013		2012		2013		2012
	(in millions)
Service Cost	$	18	$	19	$	6	$	11
Interest Cost		51		55		17		26
Expected Return on Plan Assets		(70)		(79)		(26)		(25)
Amortization of Prior Service Credit		-		-		(18)		(4)
Amortization of Net Actuarial Loss		46		38		16		15
Net Periodic Benefit Cost (Credit)	$	45	$	33	$	(5)	$	23

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in millions)
Service Cost	$	35	$	38	$	12	$	23
Interest Cost		101		111		35		52
Expected Return on Plan Assets		(139)		(159)		(53)		(50)
Amortization of Prior Service Cost (Credit)		1		-		(35)		(9)
Amortization of Net Actuarial Loss		92		75		32		29
Net Periodic Benefit Cost (Credit)	$	90	$	65	$	(9)	$	45

7. BUSINESS SEGMENTS

As outlined in our 2012 Annual Report, our primary business is the generation, transmission and distribution of electricity. Within our Utility Operations segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

Our reportable segments and their related business activities are outlined 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 and 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 remainder of our activities is presented as All Other. While not considered a reportable segment, All Other includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

The tables below present our reportable segment information for the three and six months ended June 30, 2013 and 2012 and balance sheet information as of June 30, 2013 and December 31, 2012. These amounts include certain estimates and allocations where necessary.

						Nonutility Operations
								Generation
		Utility		Transmission		AEP River		and		All Other		Reconciling
		Operations		Operations		Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Three Months Ended June 30, 2013
Revenues from:
	External Customers	$	3,246	$	7	$	112	$	214	$	3	$	-	$	3,582
	Other Operating Segments		32		12		5		-		1		(50)		-
Total Revenues		$	3,278	$	19	$	117	$	214	$	4	$	(50)	$	3,582

Net Income (Loss)		$	222	$	18	$	(9)	$	4	$	104	$	-	$	339

						Nonutility Operations
								Generation
		Utility		Transmission		AEP River		and		All Other		Reconciling
		Operations		Operations		Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Three Months Ended June 30, 2012
Revenues from:
	External Customers	$	3,234	$	1	$	163	$	148	$	5	$	-	$	3,551
	Other Operating Segments		24		1		4		-		1		(30)		-
Total Revenues		$	3,258	$	2	$	167	$	148	$	6	$	(30)	$	3,551

Net Income (Loss)		$	365	$	8	$	3	$	(5)	$	(8)	$	-	$	363

						Nonutility Operations
								Generation
		Utility		Transmission		AEP River		and		All Other		Reconciling
		Operations		Operations		Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Six Months Ended June 30, 2013
Revenues from:
	External Customers	$	6,732	$	10	$	240	$	420	$	6	$	-	$	7,408
	Other Operating Segments		63		17		10		-		3		(93)		-
Total Revenues		$	6,795	$	27	$	250	$	420	$	9	$	(93)	$	7,408

Net Income (Loss)		$	571	$	31	$	(11)	$	11	$	101	$	-	$	703

						Nonutility Operations
								Generation
		Utility		Transmission		AEP River		and		All Other		Reconciling
		Operations		Operations		Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Six Months Ended June 30, 2012
Revenues from:
	External Customers	$	6,596	$	2	$	335	$	233	$	10	$	-	$	7,176
	Other Operating Segments		47		3		11		-		3		(64)		-
Total Revenues		$	6,643	$	5	$	346	$	233	$	13	$	(64)	$	7,176

Net Income (Loss)		$	749	$	17	$	12	$	(6)	$	(19)	$	-	$	753

						Nonutility Operations
								Generation				Reconciling
		Utility		Transmission		AEP River		and		All Other		Adjustments
		Operations		Operations		Operations		Marketing		(a)		(b)			Consolidated
		(in millions)
June 30, 2013
Total Property, Plant and Equipment		$	56,275	$	1,079	$	638	$	626	$	8	$	(269)		$	58,357
Accumulated Depreciation and
	Amortization		18,561		6		175		261		7		(78)			18,932
Total Property, Plant and
	Equipment - Net	$	37,714	$	1,073	$	463	$	365	$	1	$	(191)		$	39,425

Total Assets		$	51,841	$	1,588	$	646	$	1,017	$	18,155	$	(18,268)	(c)	$	54,979

						Nonutility Operations
								Generation				Reconciling
		Utility		Transmission		AEP River		and		All Other		Adjustments
		Operations		Operations		Operations		Marketing		(a)		(b)			Consolidated
		(in millions)
December 31, 2012
Total Property, Plant and Equipment		$	55,707	$	748	$	636	$	621	$	8	$	(266)		$	57,454
Accumulated Depreciation and
	Amortization		18,344		4		161		246		7		(71)			18,691
Total Property, Plant and
	Equipment - Net	$	37,363	$	744	$	475	$	375	$	1	$	(195)		$	38,763

Total Assets		$	51,477	$	1,216	$	670	$	1,005	$	17,191	$	(17,192)	(c)	$	54,367

(a)	All Other includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

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

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

8. DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

Our strategy surrounding the use of derivative instruments primarily focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. Our risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact. To accomplish our objectives, we primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

We enter into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business. We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities. We also engage in risk management of interest rate risk associated with debt financing and

foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.

The following table represents the gross notional volume of our outstanding derivative contracts as of June 30, 2013 and December 31, 2012:

Notional Volume of Derivative Instruments

		Volume
		June 30,		December 31,		Unit of
		2013		2012		Measure
Primary Risk Exposure		(in millions)
Commodity:
	Power		553		498	MWhs
	Coal		5		10	Tons
	Natural Gas		159		147	MMBtus
	Heating Oil and Gasoline		5		6	Gallons
	Interest Rate	$	197	$	235	USD

Interest Rate and Foreign Currency		$	874	$	1,199	USD

Fair Value Hedging Strategies

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

Cash Flow Hedging Strategies

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

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

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

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

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS

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

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

According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the June 30, 2013 and December 31, 2012 condensed balance sheets, we netted $8 million and $7 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $28 million and $50 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

The following tables represent the gross fair value impact of our derivative activity on our condensed balance sheets as of June 30, 2013 and December 31, 2012:

Fair Value of Derivative Instruments
June 30, 2013

									Gross Amounts	Gross		Net Amounts of
		Risk Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign			Liabilities	Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (c)
		(in millions)
Current Risk Management Assets		$	518	$	27	$	4	$	549	$	(362)	$	187
Long-term Risk Management Assets			449		6		-		455		(138)		317
Total Assets			967		33		4		1,004		(500)		504

Current Risk Management Liabilities			458		29		1		488		(377)		111
Long-term Risk Management Liabilities			312		2		17		331		(150)		181
Total Liabilities			770		31		18		819		(527)		292

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	197	$	2	$	(14)	$	185	$	27	$	212

Fair Value of Derivative Instruments
December 31, 2012

								Gross Amounts		Gross		Net Amounts of
		Risk Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (c)
		(in millions)
Current Risk Management Assets		$	589	$	32	$	3	$	624	$	(433)	$	191
Long-term Risk Management Assets			528		5		1		534		(166)		368
Total Assets			1,117		37		4		1,158		(599)		559

Current Risk Management Liabilities			546		43		35		624		(469)		155
Long-term Risk Management Liabilities			383		6		6		395		(181)		214
Total Liabilities			929		49		41		1,019		(650)		369

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	188	$	(12)	$	(37)	$	139	$	51	$	190

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

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

(c)	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.

The table below presents our activity of derivative risk management contracts for the three and six months ended June 30, 2013 and 2012:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three and Six Months Ended June 30, 2013 and 2012

	Three Months Ended June 30,				Six Months Ended June 30,
Location of Gain (Loss)	2013		2012		2013		2012
	(in millions)
Utility Operations Revenues	$	5	$	4	$	13	$	14
Other Revenues		16		5		30		8
Regulatory Assets (a)		(8)		(17)		(5)		(38)
Regulatory Liabilities (a)		4		13		(3)		27
Total Gain (Loss) on Risk
Management Contracts	$	17	$	5	$	35	$	11

(a)

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

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

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

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

Accounting for Fair Value Hedging Strategies

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

We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our condensed statements of income. During the three and six months ended June 30, 2013, we recognized losses of $11 million and $12 million, respectively, on our hedging instruments and offsetting gains of $11 million and $12 million, respectively, on our long-term debt. During the three and six months ended June 30, 2012, we recognized gains of $1 million and $2 million, respectively, on our hedging instruments and offsetting losses of $1 million and $2 million, respectively, on our long-term debt. During the three and six months ended June 30, 2013 and 2012, hedge ineffectiveness was immaterial.

Accounting for Cash Flow Hedging Strategies

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

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on our condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2013 and 2012, we designated power, coal and natural gas derivatives as cash flow hedges.

We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our condensed statements of income. During the three and six months ended June 30, 2013 and 2012, we designated heating oil and gasoline derivatives as cash flow hedges.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Interest Expense on our condensed statements of income in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2013 and 2012, we designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Depreciation and Amortization expense on our condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and six months ended June 30, 2013, we did not designate any foreign currency derivatives as cash flow hedges. During the three and six months ended June 30, 2012, we designated foreign currency derivatives as cash flow hedges.

During the three and six months ended June 30, 2013 and 2012, hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies disclosed above.

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2013 and 2012, see Note 2.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of June 30, 2013 and December 31, 2012 were:

Impact of Cash Flow Hedges on the Condensed Balance Sheet
June 30, 2013

				Interest Rate
				and Foreign
		Commodity		Currency		Total
		(in millions)
Hedging Assets (a)		$	14	$	-	$	14
Hedging Liabilities (a)			12		2		14
AOCI Gain (Loss) Net of Tax			1		(25)		(24)
Portion Expected to be Reclassified to Net
	Income During the Next Twelve Months		(2)		(4)		(6)

Impact of Cash Flow Hedges on the Condensed Balance Sheet
December 31, 2012

				Interest Rate
				and Foreign
		Commodity		Currency		Total
		(in millions)
Hedging Assets (a)		$	24	$	-	$	24
Hedging Liabilities (a)			36		37		73
AOCI Gain (Loss) Net of Tax			(8)		(30)		(38)
Portion Expected to be Reclassified to Net
	Income During the Next Twelve Months		(8)		(4)		(12)

(a)

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

The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. As of June 30, 2013, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions is 27 months.

Credit Risk

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

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

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, we are obligated to post an additional amount of collateral if our credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and our total exposure. On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP and its subsidiaries have not experienced a downgrade below investment grade. The following table represents: (a) our fair value of such derivative contracts, (b) the amount of collateral we would have been required to post for all derivative and non-derivative contracts if our credit ratings had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of June 30, 2013 and December 31, 2012:

		June 30,		December 31,
		2013		2012
		(in millions)
Liabilities for Derivative Contracts with Credit Downgrade Triggers		$	4	$	7
Amount of Collateral AEP Subsidiaries Would Have Been
	Required to Post		48		32
Amount Attributable to RTO and ISO Activities			47		31

In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts. The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of June 30, 2013 and December 31, 2012:

	June 30,		December 31,
	2013		2012
	(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual
Netting Arrangements	$	360	$	469
Amount of Cash Collateral Posted		3		8
Additional Settlement Liability if Cross Default Provision is Triggered		252		328

9. FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. Our market risk oversight staff independently monitors our valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of our Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer.

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

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

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

Fair Value Measurements of Long-term Debt

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

The book values and fair values of Long-term Debt as of June 30, 2013 and December 31, 2012 are summarized in the following table:

	June 30, 2013				December 31, 2012
	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
Long-term Debt	$	17,618	$	19,509	$	17,757	$	20,907

Fair Value Measurements of Other Temporary Investments

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

The following is a summary of Other Temporary Investments:

			June 30, 2013
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
Other Temporary Investments			Cost		Gains		Losses		Value
			(in millions)
Restricted Cash (a)			$	204	$	-	$	-	$	204
Fixed Income Securities:
	Mutual Funds			76		-		-		76
Equity Securities - Mutual Funds				10		8		-		18
Total Other Temporary Investments			$	290	$	8	$	-	$	298

			December 31, 2012
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
Other Temporary Investments			Cost		Gains		Losses		Value
			(in millions)
Restricted Cash (a)			$	241	$	-	$	-	$	241
Fixed Income Securities:
	Mutual Funds			65		2		-		67
Equity Securities - Mutual Funds				10		6		-		16
Total Other Temporary Investments			$	316	$	8	$	-	$	324

(a)		Primarily represents amounts held for the repayment of debt.

The following table provides the activity for our fixed income and equity securities within Other Temporary Investments for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in millions)
Proceeds from Investment Sales	$	-	$	-	$	-	$	-
Purchases of Investments		-		1		11		1
Gross Realized Gains on Investment Sales		-		-		-		-
Gross Realized Losses on Investment Sales		-		-		-		-

As of June 30, 2013 and December 31, 2012, we had no Other Temporary Investments with an unrealized loss position. As of June 30, 2013, fixed income securities are primarily debt based mutual funds with short and intermediate maturities. Mutual funds may be sold and do not contain maturity dates.

For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and six months ended June 30, 2013 and 2012, see Note 2.

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

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

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

·	Maximum percentage invested in a specific type of investment.

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

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

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

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

The following is a summary of nuclear trust fund investments as of June 30, 2013 and December 31, 2012:

		June 30, 2013						December 31, 2012
		Estimated		Gross		Other-Than-		Estimated		Gross		Other-Than-
		Fair		Unrealized		Temporary		Fair		Unrealized		Temporary
		Value		Gains		Impairments		Value		Gains		Impairments
		(in millions)
Cash and Cash Equivalents		$	14	$	-	$	-	$	17	$	-	$	-
Fixed Income Securities:
	United States Government		605		37		(2)		648		58		(1)
	Corporate Debt		35		3		(2)		35		5		(1)
	State and Local Government		262		-		(3)		270		1		(1)
	Subtotal Fixed Income Securities		902		40		(7)		953		64		(3)
Equity Securities - Domestic			875		373		(82)		736		285		(77)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,791	$	413	$	(89)	$	1,706	$	349	$	(80)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in millions)
Proceeds from Investment Sales	$	217	$	183	$	385	$	517
Purchases of Investments		227		192		412		545
Gross Realized Gains on Investment Sales		9		3		12		5
Gross Realized Losses on Investment Sales		8		1		10		2

The adjusted cost of fixed income securities was $862 million and $889 million as of June 30, 2013 and December 31, 2012, respectively. The adjusted cost of equity securities was $502 million and $451 million as of June 30, 2013 and December 31, 2012, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2013 was as follows:

	Fair Value of
	Fixed Income
	Securities
	(in millions)
Within 1 year	$	79
1 year – 5 years		340
5 years – 10 years		238
After 10 years		245
Total	$	902

Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2013 and December 31, 2012. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in our valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2013

			Level 1		Level 2		Level 3		Other		Total
Assets:			(in millions)

Cash and Cash Equivalents (a)			$	10	$	1	$	-	$	106	$	117

Other Temporary Investments
Restricted Cash (a)				186		6		-		12		204
Fixed Income Securities:
	Mutual Funds			76		-		-		-		76
Equity Securities - Mutual Funds (b)				18		-		-		-		18
Total Other Temporary Investments				280		6		-		12		298

Risk Management Assets
Risk Management Commodity Contracts (c) (d)				38		776		142		(479)		477
Cash Flow Hedges:
	Commodity Hedges (c)			4		28		-		(18)		14
Fair Value Hedges				-		1		-		3		4
De-designated Risk Management Contracts (e)				-		-		-		9		9
Total Risk Management Assets				42		805		142		(485)		504

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (f)				3		-		-		11		14
Fixed Income Securities:
	United States Government			-		605		-		-		605
	Corporate Debt			-		35		-		-		35
	State and Local Government			-		262		-		-		262
		Subtotal Fixed Income Securities		-		902		-		-		902
Equity Securities - Domestic (b)				875		-		-		-		875
Total Spent Nuclear Fuel and Decommissioning Trusts				878		902		-		11		1,791

Total Assets			$	1,210	$	1,714	$	142	$	(356)	$	2,710

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)			$	42	$	697	$	20	$	(497)	$	262
Cash Flow Hedges:
	Commodity Hedges (c)			-		30		-		(18)		12
	Interest Rate/Foreign Currency Hedges			-		2		-		-		2
Fair Value Hedges				-		13		-		3		16
Total Risk Management Liabilities			$	42	$	742	$	20	$	(512)	$	292

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2012

			Level 1		Level 2		Level 3		Other		Total
Assets:			(in millions)

Cash and Cash Equivalents (a)			$	6	$	1	$	-	$	272	$	279

Other Temporary Investments
Restricted Cash (a)				227		5		-		9		241
Fixed Income Securities:
	Mutual Funds			67		-		-		-		67
Equity Securities - Mutual Funds (b)				16		-		-		-		16
Total Other Temporary Investments				310		5		-		9		324

Risk Management Assets
Risk Management Commodity Contracts (c) (g)				47		938		131		(599)		517
Cash Flow Hedges:
	Commodity Hedges (c)			8		28		-		(12)		24
Fair Value Hedges				-		2		-		2		4
De-designated Risk Management Contracts (e)				-		-		-		14		14
Total Risk Management Assets				55		968		131		(595)		559

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (f)				7		-		-		10		17
Fixed Income Securities:
	United States Government			-		648		-		-		648
	Corporate Debt			-		35		-		-		35
	State and Local Government			-		270		-		-		270
		Subtotal Fixed Income Securities		-		953		-		-		953
Equity Securities - Domestic (b)				736		-		-		-		736
Total Spent Nuclear Fuel and Decommissioning Trusts				743		953		-		10		1,706

Total Assets			$	1,114	$	1,927	$	131	$	(304)	$	2,868

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)			$	45	$	838	$	45	$	(636)	$	292
Cash Flow Hedges:
	Commodity Hedges (c)			-		48		-		(12)		36
	Interest Rate/Foreign Currency Hedges			-		37		-		-		37
Fair Value Hedges				-		2		-		2		4
Total Risk Management Liabilities			$	45	$	925	$	45	$	(646)	$	369

(a)	Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.

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

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

(d)

The June 30, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $3 million in 2013, ($3) million in periods 2014-2016 and ($4) million in periods 2017-2018; Level 2 matures $12 million in 2013, $53 million in periods 2014-2016, $8 million in periods 2017-2018 and $6 million in periods 2019-2030; Level 3 matures $19 million in 2013, $50 million in periods 2014-2016, $30 million in periods 2017-2018 and $23 million in periods 2019-2030. Risk management commodity contracts are substantially comprised of power contracts.

(e)

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

(f)	Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

(g)

The December 31, 2012 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $9 million in 2013, ($3) million in periods 2014-2016 and ($4) million in periods 2017-2018; Level 2 matures $16 million in 2013, $61 million in periods 2014-2016, $16 million in periods 2017-2018 and $7 million in periods 2019-2030; Level 3 matures $18 million in 2013, $31 million in periods 2014-2016, $13 million in periods 2017-2018 and $24 million in periods 2019-2030. Risk management commodity contracts are substantially comprised of power contracts.

There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2013 and 2012.

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

		Net Risk Management
Three Months Ended June 30, 2013		Assets (Liabilities)
		(in millions)
Balance as of March 31, 2013		$	76
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)			(1)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		26
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			(1)
Purchases, Issuances and Settlements (c)			(2)
Transfers into Level 3 (d) (e)			12
Transfers out of Level 3 (e) (f)			1
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			11
Balance as of June 30, 2013		$	122

		Net Risk Management
Three Months Ended June 30, 2012		Assets (Liabilities)
		(in millions)
Balance as of March 31, 2012		$	92
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)			(11)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		4
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			-
Purchases, Issuances and Settlements (c)			15
Transfers into Level 3 (d) (e)			(1)
Transfers out of Level 3 (e) (f)			(8)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			6
Balance as of June 30, 2012		$	97

		Net Risk Management
Six Months Ended June 30, 2013		Assets (Liabilities)
		(in millions)
Balance as of December 31, 2012		$	86
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)			(12)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		22
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			-
Purchases, Issuances and Settlements (c)			(1)
Transfers into Level 3 (d) (e)			18
Transfers out of Level 3 (e) (f)			1
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			8
Balance as of June 30, 2013		$	122

		Net Risk Management
Six Months Ended June 30, 2012		Assets (Liabilities)
		(in millions)
Balance as of December 31, 2011		$	69
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)			(17)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		5
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			-
Purchases, Issuances and Settlements (c)			33
Transfers into Level 3 (d) (e)			14
Transfers out of Level 3 (e) (f)			(20)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			13
Balance as of June 30, 2012		$	97

(a)

Included in revenues on the condensed statements of income.

(b)

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

(c)

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

(d)

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

(e)

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

(f)

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

(g)

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

The following table quantifies the significant unobservable inputs used in developing the fair value of our Level 3 positions as of June 30, 2013:

	Fair Value				Valuation	Significant	Input/Range
	Assets		Liabilities		Technique	Unobservable Input	Low		High
	(in millions)
Energy Contracts	$	128	$	16	Discounted Cash Flow	Forward Market Price (a)	$	10.17	$	140.98
						Counterparty Credit Risk (b)		356
FTRs		14		4	Discounted Cash Flow	Forward Market Price (a)		(26.98)		11.19
Total	$	142	$	20

(a)

Represents market prices in dollars per MWh.

(b)

Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.

10. INCOME TAXES

AEP System Tax Allocation Agreement

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

Federal and State Income Tax Audit Status

The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013. The completion of the federal audit did not result in a material impact on net income, cash flows or financial condition. Although the outcome of tax audits is uncertain, in our opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, we accrue interest on these uncertain tax positions. We are not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.

We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine our tax returns and we are currently under examination in several state and local jurisdictions. However, we believe that we have filed tax returns with positions that may be challenged by these tax authorities. We believe that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and the ultimate resolution of these audits will not materially impact net income. We are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2008.

Uncertain Tax Positions

In May 2013 the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. We filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, we recognized a tax benefit of $80 million, plus $43 million of pretax interest income in the second quarter of 2013. The tax benefit and interest income resulted in an increase in net income of $108 million, but did not result in the receipt of cash during the second quarter of 2013.

The tax benefit associated with the U.K. Windfall Tax was reported as a $64 million unrecognized tax benefit as of December 31, 2012 and was included in the amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate. Therefore, the related amounts reported as of December 31, 2012 have been reduced due to the recognition of the U.K. Windfall Tax benefit during the second quarter of 2013.

11. FINANCING ACTIVITIES

Long-term Debt

The following table details long-term debt outstanding as of June 30, 2013 and December 31, 2012:

Type of Debt	June 30, 2013		December 31, 2012
	(in millions)
Senior Unsecured Notes	$	12,458	$	12,712
Pollution Control Bonds		1,982		1,958
Notes Payable		462		427
Securitization Bonds		2,150		2,281
Spent Nuclear Fuel Obligation (a)		265		265
Other Long-term Debt		338		140
Fair Value of Interest Rate Hedges		(10)		3
Unamortized Discount, Net		(27)		(29)
Total Long-term Debt Outstanding		17,618		17,757
Long-term Debt Due Within One Year		1,819		2,171
Long-term Debt	$	15,799	$	15,586

(a)

Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $308 million and $308 million as of June 30, 2013 and December 31, 2012, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets.

Long-term debt and other securities issued, retired and principal payments made during the first six months of 2013 are shown in the tables below:

			Principal			Interest
Company	Type of Debt		Amount			Rate	Due Date
Issuances:		(in millions)				(%)
AEP	Other Long-term Debt		$	200	(a)	Variable	2015
I&M	Senior Unsecured Notes			250		3.20	2023
I&M	Notes Payable			101		Variable	2017
OPCo	Pollution Control Bonds			50		Variable	2014

Non-Registrant:
AEPTCo	Senior Unsecured Notes			25		4.83	2043
TCC	Pollution Control Bonds			120		4.00	2030
TNC	Senior Unsecured Notes			125		3.09	2023
TNC	Senior Unsecured Notes			75		4.48	2043
Total Issuances			$	946	(b)

(a)

Draw on a $1 billion term credit facility due in May 2015.

(b)

Amount indicated on the statement of cash flows is net of issuance costs and premium or discount and will not tie to the total issuances.

				Principal		Interest
Company		Type of Debt		Amount Paid		Rate	Due Date
Retirements and			(in millions)			(%)
	Principal Payments:
I&M		Notes Payable		$	6	5.44	2013
I&M		Notes Payable			10	4.00	2014
I&M		Notes Payable			8	Variable	2015
I&M		Notes Payable			10	Variable	2016
I&M		Notes Payable			7	2.12	2016
I&M		Notes Payable			21	Variable	2016
I&M		Pollution Control Bonds			40	5.25	2025
I&M		Other Long-term Debt			2	Variable	2015
OPCo		Senior Unsecured Notes			250	5.50	2013
OPCo		Senior Unsecured Notes			250	5.50	2013
OPCo		Pollution Control Bonds			56	5.10	2013
OPCo		Pollution Control Bonds			50	5.15	2026
SWEPCo		Notes Payable			1	4.58	2032

Non-Registrant:
AEP Subsidiaries		Notes Payable			1	Variable	2017
AEP Subsidiaries		Notes Payable			1	7.59 - 8.03	2026
AEGCo		Senior Unsecured Notes			4	6.33	2037
TCC		Securitization Bonds			67	4.98	2013
TCC		Securitization Bonds			38	5.96	2013
TCC		Securitization Bonds			26	0.88	2017
TNC		Senior Unsecured Notes			225	5.50	2013
Total Retirements and
	Principal Payments			$	1,073

In July 2013, we terminated the $1 billion term credit facility due in May 2015. In July 2013, AEPGenCo, APCo, KPCo and OPCo entered into a $1 billion term credit facility due in May 2015 to provide liquidity during the corporate separation process. Under the credit facility, OPCo may assign borrowings to AEPGenCo upon the transfer of OPCo’s generation assets to AEPGenCo. Subject to regulatory approval, AEPGenCo may further assign a portion of the borrowings to APCo and KPCo, not to exceed $500 million and $250 million, respectively, upon AEPGenCo’s subsequent transfer of certain of those generation assets to APCo and KPCo.

In July 2013, I&M retired $12 million of Notes Payable related to DCC Fuel.

In July 2013, OPCo retired $ 65 million of 4.9% Pollution Control Bonds due in 2037 and issued $ 65 million of variable rate Pollution Control Bonds due in 2014.

As of June 30, 2013, trustees held, on our behalf, $504 million of our reacquired Pollution Control Bonds.

Dividend Restrictions

Parent Restrictions

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

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

Utility Subsidiaries’ Restrictions

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

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

Short-term Debt

Our outstanding short-term debt was as follows:


	June 30, 2013				December 31, 2012
	Outstanding		Interest		Outstanding		Interest
Type of Debt	Amount		Rate (a)		Amount		Rate (a)
	(in millions)				(in millions)
Securitized Debt for Receivables (b)	$	688	0.23	%	$	657	0.26	%
Commercial Paper		850	0.32	%		321	0.42	%
Line of Credit – Sabine (c)		-	-	%		3	1.82	%
Total Short-term Debt	$	1,538			$	981

(a)

Weighted average rate.

(b)

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

(c)

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

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 4.

Securitized Accounts Receivable – AEP Credit

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

Accounts receivable information for AEP Credit is as follows:

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2013			2012			2013			2012
		(dollars in millions)
Effective Interest Rates on Securitization of
	Accounts Receivable		0.22	%		0.26	%		0.23	%		0.26	%
Net Uncollectible Accounts Receivable
	Written Off	$	7		$	6		$	14		$	14

		June 30,		December 31,
		2013		2012
		(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
	Less Uncollectible Accounts	$	954	$	835
Total Principal Outstanding			688		657
Delinquent Securitized Accounts Receivable			45		37
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable			21		21
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable			369		316

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

12. VARIABLE INTEREST ENTITIES

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

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

Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended June 30, 2013 and 2012 were $40 million and $36 million, respectively, and for the six months ended June 30, 2013 and 2012 were $84 million and $91 million, respectively. See the tables below for the classification of Sabine’s assets and liabilities on the condensed balance sheets.

I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI LLC (collectively DCC Fuel). DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended June 30, 2013 and 2012 were $38 million and $42 million, respectively, and for the six months ended June 30, 2013 and 2012 were $64 million and $ 59 million, respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel’s assets and liabilities on the condensed balance sheets.

AEP Credit is a wholly-owned subsidiary of AEP. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings. Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on our control of AEP Credit, management has concluded that we are the primary beneficiary and are required to consolidate its assets and liabilities. See the tables below for the classification of AEP Credit’s assets and liabilities on the condensed balance sheets. See “Securitized Accounts Receivable – AEP Credit” section of Note 11.

Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The securitized bonds totaled $2.2 billion and $2.3 billion as of June 30, 2013 and December 31, 2012, respectively, and are included in current and long-term debt on the condensed balance sheets. Transition Funding has securitized transition assets of $2 billion and $2.1 billion as of June 30, 2013 and December 31, 2012, respectively, which are presented separately on the face of the condensed balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to TCC or any other AEP entity. TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the condensed balance sheets.

Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on our control and the structure of the protected cell and EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate its assets and liabilities. Our insurance premium expense to the protected cell for the three months ended June 30, 2013 and 2012 were $14 thousand and $0, respectively, and for the six months ended June 30, 2013 and 2012 were $15 million and $15 million, respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the condensed balance sheets. The amount reported as equity is the protected cell’s policy holders’ surplus.

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

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
June 30, 2013
(in millions)

							TCC
	SWEPCo		I&M				Transition			Protected Cell
	Sabine		DCC Fuel		AEP Credit		Funding			of EIS
ASSETS
Current Assets	$	66	$	161	$	963	$	221		$	136
Net Property, Plant and Equipment		163		219		-		-			-
Other Noncurrent Assets		66		104		-		2,060	(a)		5
Total Assets	$	295	$	484	$	963	$	2,281		$	141

LIABILITIES AND EQUITY
Current Liabilities	$	31	$	143	$	904	$	307		$	42
Noncurrent Liabilities		264		341		1		1,956			68
Equity		-		-		58		18			31
Total Liabilities and Equity	$	295	$	484	$	963	$	2,281		$	141

(a) Includes an intercompany item eliminated in consolidation of $86 million.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2012
(in millions)

							TCC
	SWEPCo		I&M				Transition			Protected Cell
	Sabine		DCC Fuel		AEP Credit		Funding			of EIS
ASSETS
Current Assets	$	57	$	133	$	843	$	250		$	130
Net Property, Plant and Equipment		170		176		-		-			-
Other Noncurrent Assets		55		92		1		2,167	(a)		4
Total Assets	$	282	$	401	$	844	$	2,417		$	134

LIABILITIES AND EQUITY
Current Liabilities	$	32	$	121	$	800	$	304		$	43
Noncurrent Liabilities		250		280		1		2,095			66
Equity		-		-		43		18			25
Total Liabilities and Equity	$	282	$	401	$	844	$	2,417		$	134

(a) Includes an intercompany item eliminated in consolidation of $89 million.

DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended June 30, 2013 and 2012 were $13 million and $20 million, respectively, and for the six months ended June 30, 2013 and 2012 were $31 million and $34 million, respectively. We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC. Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets.

Our investment in DHLC was:

	June 30, 2013				December 31, 2012
	As Reported on		Maximum		As Reported on		Maximum
	the Balance Sheet		Exposure		the Balance Sheet		Exposure
	(in millions)
Capital Contribution from SWEPCo	$	8	$	8	$	8	$	8
Retained Earnings		1		1		1		1
SWEPCo's Guarantee of Debt		-		50		-		49

Total Investment in DHLC	$	9	$	59	$	9	$	58

We and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH). PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region. PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy. Provisions exist within the PATH-WV agreement that make it a VIE. The “Allegheny Series” is not considered a VIE. We are not required to consolidate PATH-WV as we are not the primary beneficiary, although we hold a significant variable interest in PATH-WV. Our equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on our condensed balance sheets. We and FirstEnergy share the returns and losses equally in PATH-WV. Our subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements. The entities recover costs through regulated rates.

In August 2012, the PJM board cancelled the PATH Project, our transmission joint venture with FirstEnergy, and removed it from the 2012 Regional Transmission Expansion Plan. In November 2012, the FERC issued an order accepting AEP’s and FirstEnergy’s abandonment cost recovery filing which requested authority to recover prudently-incurred costs associated with the PATH Project, subject to refund based on the outcome of hearings and settlement procedures.

Our investment in PATH-WV was:

	June 30, 2013					December 31, 2012
	As Reported on			Maximum		As Reported on		Maximum
	the Balance Sheet			Exposure		the Balance Sheet		Exposure
			(in millions)
Capital Contribution from AEP	$	19		$	19	$	19	$	19
Retained Earnings		13			13		12		12

Total Investment in PATH-WV	$	32		$	32	$	31	$	31

13. SUSTAINABLE COST REDUCTIONS

In April 2012, we initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings. We selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate our current employee benefit programs. The process resulted in involuntary severances and was completed by the end of the first quarter of 2013. The severance program provides two weeks of base pay for every year of service along with other severance benefits.

We recorded a charge of $ 47 million to Other Operation expense in 2012 primarily related to severance benefits as a result of the sustainable cost reductions initiative. In addition, the sustainable cost reduction activity for the six months ended June 30, 2013 is described in the following table:

	Sustainable Cost
	Reduction Activity
	(in millions)
Balance as of December 31, 2012	$	25
Incurred		16
Settled		(29)
Adjustments		(6)
Balance as of June 30, 2013	$	6

These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. Approximately 94% of the expense was within the Utility Operations segment. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. We do not expect additional costs to be incurred related to this initiative.

APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Regulatory Activity

Plant Transfers and Termination of Interconnection Agreement

Based upon the PUCO’s approval of OPCo’s corporate separation plan in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations, transfer these assets to AEPGenCo and subsequently transfer, at net book value (NBV), OPCo’s current two-thirds ownership in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests. In December 2012, APCo filed requests with the Virginia SCC and WVPSC for the approval of the plant transfers discussed above. APCo is currently pursuing cost recovery of these plants in West Virginia and plans to pursue cost recovery in Virginia. In April 2013, the FERC issued orders approving the merger of APCo and WPCo and approving the transfer of the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo, to be effective using the requested date of December 31, 2013. In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo. This issue remains pending before the FERC. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. Hearings in the plant transfer cases were held at the Virginia SCC in June 2013 and at the WVPSC in July 2013. See the “Plant Transfers” section of APCo Rate Matters in Note 3.

Additionally, the AEP East Companies requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Under the PCA, APCo would be individually responsible for planning its capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. In March 2013, a revised PCA was filed at the FERC that included certain clarifying wording changes agreed upon by intervenors. A decision is pending at the FERC. See the “Corporate Separation and Termination of Interconnection Agreement” section of Note 3.

If APCo experiences decreases in revenues or increases in expenses as a result of changes to its relationship with affiliates and is unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

If APCo is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs effective February 2014 over a one-year period. APCo has deferred $28 million as of June 30, 2013 for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $11 million of unrecognized equity carrying costs. Hearings at the Virginia SCC are scheduled for August 2013. If the Virginia SCC were to disallow any portion of the environmental RAC, it could reduce future net income and cash flows. See “2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing” section of Note 3.

2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing

In March 2013, APCo filed with the Virginia SCC for an increase in its generation RAC revenues of $12 million for a total of $38 million annually to collect costs related to the Dresden Plant. The generation RAC increase is expected to be effective in March 2014. APCo has deferred $4 million as of June 30, 2013 for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $4 million of unrecognized equity carrying costs. Hearings at the Virginia SCC are scheduled for August 2013. If the Virginia SCC were to disallow any portion of the generation RAC, it could reduce future net income and cash flows. See “2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing” section of Note 3.

Securitization of Regulatory Assets

WPCo Merger with APCo

Litigation and Environmental Issues

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 153. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 220 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2013		2012		2013		2012
			(in millions of KWhs)
Retail:
	Residential			2,256		2,184		6,257		5,634
	Commercial			1,617		1,683		3,359		3,309
	Industrial			2,655		2,702		5,243		5,306
	Miscellaneous			198		201		415		402
Total Retail (a)				6,726		6,770		15,274		14,651

Wholesale				1,788		1,492		4,069		2,873

Total KWhs				8,514		8,262		19,343		17,524

(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.

Summary of Heating and Cooling Degree Days

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
		(in degree days)
Actual - Heating (a)			92		61		1,497		983
Normal - Heating (b)			93		97		1,405		1,440

Actual - Cooling (c)			388		419		388		444
Normal - Cooling (b)			360		354		367		360

(a)	Eastern Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Eastern Region cooling degree days are calculated on a 65 degree temperature base.

Second Quarter of 2013 Compared to Second Quarter of 2012

	Reconciliation of Second Quarter of 2012 to Second Quarter of 2013
	Net Income
	(in millions)

	Second Quarter of 2012	$	62

	Changes in Gross Margin:
	Retail Margins		(26)
	Off-system Sales		(1)
	Transmission Revenues		2
	Other Revenues		3
	Total Change in Gross Margin		(22)

	Changes in Expenses and Other:
	Other Operation and Maintenance		(28)
	Depreciation and Amortization		2
	Taxes Other Than Income Taxes		(3)
	Carrying Costs Income		(2)
	Other Income		2
	Interest Expense		4
	Total Change in Expenses and Other		(25)

	Income Tax Expense		15

	Second Quarter of 2013	$	30

·	Retail Margins decreased $26 million primarily due to the following:
	·	A $9 million deferral of additional wind purchase costs in the second quarter of 2012 as a result of the June 2012 Virginia SCC fuel factor order.
	·	A $6 million net decrease in rates primarily due to the expiration of the Virginia Environmental Rate Adjustment Clause in March 2013.
	·	A $4 million decrease in revenues due to a 0.5% decrease in weather-normalized retail sales.

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

·	Other Operation and Maintenance expenses increased $28 million primarily due to the following:
	·	A $10 million increase in distribution maintenance expense primarily due to the June 2013 storms.
	·	A $5 million increase in generation plant maintenance expenses due to Mountaineer Plant routine outages in 2013.
	·	A $5 million increase in provisions for uncollectible accounts.
	·	A $4 million increase in transmission expenses due to higher Network Integration Transmission Service (NITS) expenses. These expenses are offset in Transmission Revenues.
	·	A $3 million increase due to the change in the recovery position of transmission costs for the Virginia Transmission Rate Adjustment Clause as allowed by the Virginia SCC.
·	Taxes Other Than Income Taxes expenses increased $3 million primarily due to an increase in the Virginia State Minimum Tax accrual and an increase in real and personal property tax amortization.
·	Interest Expense decreased $4 million primarily due to lower long-term interest rates.
·	Income Tax Expense decreased $15 million primarily due to a decrease in pretax book income.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

	Reconciliation of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2013
	Net Income
	(in millions)

		Six Months Ended June 30, 2012	$	138

		Changes in Gross Margin:
		Retail Margins		35
		Off-system Sales		(2)
		Transmission Revenues		4
		Other Revenues		1
		Total Change in Gross Margin		38

		Changes in Expenses and Other:
		Other Operation and Maintenance		(86)
		Depreciation and Amortization		(6)
		Taxes Other Than Income Taxes		(3)
		Carrying Costs Income		(10)
		Other Income		3
		Interest Expense		7
		Total Change in Expenses and Other		(95)

		Income Tax Expense		19

		Six Months Ended June 30, 2013	$	100

·	Retail Margins increased $35 million primarily due to the following:
	·	A $37 million increase in weather-related usage primarily due to a 52% increase in heating degree days.
	·	A $21 million increase due to higher rates in Virginia and West Virginia. For this increase, $7 million have a corresponding increase in Depreciation and Amortization expenses below.
	These increases were partially offset by:
	·	A $13 million increase in other variable electric generation expenses.
	·	A $9 million deferral of additional wind purchase costs in the second quarter of 2012 as a result of the June 2012 Virginia SCC fuel factor order.

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

·	Other Operation and Maintenance expenses increased $86 million primarily due to the following:
	·	A $30 million write-off in the first quarter of 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.
	·	A $25 million increase in distribution maintenance expense primarily due to storms in January and June 2013.
	·	An $11 million increase in generation plant maintenance expenses due to Mountaineer Plant routine outages in 2013.
·	Depreciation and Amortization expenses increased $6 million primarily due to the following:
	·	A $3 million increase as a result of increased depreciation rates in Virginia effective February 2012. The majority of this increase in depreciation is offset within Gross Margin.
	·	A $3 million increase as a result of the Dresden Plant being placed in service in late January 2012.
·	Taxes Other Than Income Taxes expenses increased $3 million primarily due to an increase in the Virginia State Minimum Tax accrual and an increase in real and personal property tax amortization.

·	Carrying Costs Income decreased $10 million primarily due to an increased recovery of Virginia environmental costs in new base rates as approved by the Virginia SCC in late January 2012 and decreased carrying charges related to Dresden Plant.
·	Other Income increased $3 million primarily due to the following:
	·	A $1 million increase in equity AFUDC.
	·	A $1 million increase in interest income related to the 2009-2010 federal income tax audit.
·	Interest Expense decreased $7 million primarily due to lower long-term interest rates.
·	Income Tax Expense decreased $19 million primarily due to a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 220 for a discussion of accounting pronouncements.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
REVENUES
Electric Generation, Transmission and Distribution	$	670,249	$	647,236	$	1,542,981	$	1,385,835
Sales to AEP Affiliates		73,893		67,043		150,753		131,344
Other Revenues		2,362		2,182		4,264		4,758
TOTAL REVENUES		746,504		716,461		1,697,998		1,521,937

EXPENSES
Fuel and Other Consumables Used for Electric Generation		163,521		181,653		368,460		368,537
Purchased Electricity for Resale		59,487		44,869		124,943		110,225
Purchased Electricity from AEP Affiliates		181,856		125,864		404,798		281,881
Other Operation		79,764		72,685		158,672		147,004
Maintenance		58,560		37,830		157,946		84,165
Depreciation and Amortization		83,240		85,139		171,143		165,552
Taxes Other Than Income Taxes		28,004		24,995		55,404		51,957
TOTAL EXPENSES		654,432		573,035		1,441,366		1,209,321

OPERATING INCOME		92,072		143,426		256,632		312,616

Other Income (Expense):
Interest Income		1,469		359		1,800		702
Carrying Costs Income		3,133		5,467		3,236		13,252
Allowance for Equity Funds Used During Construction		1,213		4		1,983		517
Interest Expense		(48,128)		(51,945)		(96,332)		(103,252)

INCOME BEFORE INCOME TAX EXPENSE		49,759		97,311		167,319		223,835

Income Tax Expense		19,897		34,979		66,909		86,192

NET INCOME	$	29,862	$	62,332	$	100,410	$	137,643

The common stock of APCo is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
Net Income		$	29,862	$	62,332	$	100,410	$	137,643

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $48 and $305 for the Three Months Ended
	June 30, 2013 and 2012, Respectively, and $725 and $15 for the Six
	Months Ended June 30, 2013 and 2012, Respectively		89		566		1,347		27
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $193
	and $484 for the Three Months Ended June 30, 2013 and 2012,
	Respectively, and $386 and $969 for the Six Months Ended
	June 30, 2013 and 2012, Respectively		358		899		716		1,799

TOTAL OTHER COMPREHENSIVE INCOME			447		1,465		2,063		1,826

TOTAL COMPREHENSIVE INCOME		$	30,309	$	63,797	$	102,473	$	139,469

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

								Accumulated
								Other
		Common		Paid-in		Retained		Comprehensive
		Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S EQUITY –
	DECEMBER 31, 2011	$	260,458	$	1,573,752	$	1,160,747	$	(58,543)	$	2,936,414

Common Stock Dividends							(100,000)				(100,000)
Net Income							137,643				137,643
Other Comprehensive Income									1,826		1,826
TOTAL COMMON SHAREHOLDER'S EQUITY –
	JUNE 30, 2012	$	260,458	$	1,573,752	$	1,198,390	$	(56,717)	$	2,975,883

TOTAL COMMON SHAREHOLDER'S EQUITY –
	DECEMBER 31, 2012	$	260,458	$	1,573,752	$	1,248,250	$	(29,898)	$	3,052,562

Common Stock Dividends							(90,000)				(90,000)
Net Income							100,410				100,410
Other Comprehensive Income									2,063		2,063
TOTAL COMMON SHAREHOLDER'S EQUITY –
	JUNE 30, 2013	$	260,458	$	1,573,752	$	1,258,660	$	(27,835)	$	3,065,035

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2013 and December 31, 2012
(in thousands)
(Unaudited)

			June 30,		December 31,
			2013		2012
CURRENT ASSETS
Cash and Cash Equivalents			$	2,735	$	3,576
Advances to Affiliates				23,303		23,024
Accounts Receivable:
	Customers			145,730		158,380
	Affiliated Companies			58,353		96,213
	Accrued Unbilled Revenues			44,839		70,825
	Miscellaneous			2,177		1,344
	Allowance for Uncollectible Accounts			(2,656)		(6,087)
		Total Accounts Receivable		248,443		320,675
Fuel				218,577		185,813
Materials and Supplies				108,522		105,208
Risk Management Assets				28,520		30,960
Accrued Tax Benefits				37,354		50,032
Regulatory Asset for Under-Recovered Fuel Costs				62,849		74,906
Prepayments and Other Current Assets				16,262		18,690
TOTAL CURRENT ASSETS				746,565		812,884

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			5,678,562		5,632,665
	Transmission			2,053,457		2,042,144
	Distribution			3,049,503		2,991,898
Other Property, Plant and Equipment				380,863		373,327
Construction Work in Progress				241,215		266,247
Total Property, Plant and Equipment				11,403,600		11,306,281
Accumulated Depreciation and Amortization				3,263,771		3,196,639
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				8,139,829		8,109,642

OTHER NONCURRENT ASSETS
Regulatory Assets				1,364,541		1,435,704
Long-term Risk Management Assets				23,608		34,360
Deferred Charges and Other Noncurrent Assets				109,465		115,078
TOTAL OTHER NONCURRENT ASSETS				1,497,614		1,585,142

TOTAL ASSETS			$	10,384,008	$	10,507,668

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2013 and December 31, 2012
(Unaudited)

		June 30,		December 31,
		2013		2012
			(in thousands)
CURRENT LIABILITIES
Advances from Affiliates		$	87,783	$	173,965
Accounts Payable:
	General		150,500		195,203
	Affiliated Companies		99,096		137,088
Long-term Debt Due Within One Year – Nonaffiliated			574,681		574,679
Risk Management Liabilities			13,397		16,698
Customer Deposits			65,999		67,339
Deferred Income Taxes			8,388		11,715
Accrued Taxes			80,347		74,967
Accrued Interest			51,207		51,442
Other Current Liabilities			97,782		110,657
TOTAL CURRENT LIABILITIES			1,229,180		1,413,753

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			3,128,078		3,127,763
Long-term Risk Management Liabilities			14,007		18,476
Deferred Income Taxes			1,968,214		1,928,683
Regulatory Liabilities and Deferred Investment Tax Credits			623,394		607,680
Employee Benefits and Pension Obligations			202,114		204,207
Deferred Credits and Other Noncurrent Liabilities			153,986		154,544
TOTAL NONCURRENT LIABILITIES			6,089,793		6,041,353

TOTAL LIABILITIES			7,318,973		7,455,106

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
	Authorized – 30,000,000 Shares
	Outstanding – 13,499,500 Shares		260,458		260,458
Paid-in Capital			1,573,752		1,573,752
Retained Earnings			1,258,660		1,248,250
Accumulated Other Comprehensive Income (Loss)			(27,835)		(29,898)
TOTAL COMMON SHAREHOLDER’S EQUITY			3,065,035		3,052,562

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	10,384,008	$	10,507,668

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

			Six Months Ended June 30,
			2013		2012
OPERATING ACTIVITIES
Net Income			$	100,410	$	137,643
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			171,143		165,552
	Deferred Income Taxes			42,158		56,927
	Carrying Costs Income			(3,236)		(13,252)
	Allowance for Equity Funds Used During Construction			(1,983)		(517)
	Mark-to-Market of Risk Management Contracts			6,765		(2,323)
	Fuel Over/Under-Recovery, Net			25,919		26,417
	Change in Other Noncurrent Assets			35,219		(16,708)
	Change in Other Noncurrent Liabilities			9,670		18,266
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		73,280		103,680
		Fuel, Materials and Supplies		(36,078)		(54,954)
		Accounts Payable		(57,034)		(43,538)
		Accrued Taxes, Net		18,058		30,032
		Other Current Assets		1,621		2,579
		Other Current Liabilities		(14,440)		(15,880)
Net Cash Flows from Operating Activities				371,472		393,924

INVESTING ACTIVITIES
Construction Expenditures				(194,200)		(212,959)
Change in Advances to Affiliates, Net				(279)		(565)
Other Investing Activities				(108)		3,158
Net Cash Flows Used for Investing Activities				(194,587)		(210,366)

FINANCING ACTIVITIES
Change in Advances from Affiliates, Net				(86,182)		(31,260)
Retirement of Long-term Debt – Nonaffiliated				(14)		(49,512)
Principal Payments for Capital Lease Obligations				(2,623)		(3,258)
Dividends Paid on Common Stock				(90,000)		(100,000)
Other Financing Activities				1,093		264
Net Cash Flows Used for Financing Activities				(177,726)		(183,766)

Net Decrease in Cash and Cash Equivalents				(841)		(208)
Cash and Cash Equivalents at Beginning of Period				3,576		2,317
Cash and Cash Equivalents at End of Period			$	2,735	$	2,109

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	92,994	$	100,319
Net Cash Paid (Received) for Income Taxes				425		(10,090)
Noncash Acquisitions Under Capital Leases				2,422		1,265
Construction Expenditures Included in Current Liabilities as of June 30,				34,114		30,439

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

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

	Page
	Number

Significant Accounting Matters	154
Comprehensive Income	154
Rate Matters	168
Commitments, Guarantees and Contingencies	178
Benefit Plans	183
Business Segments	185
Derivatives and Hedging	186
Fair Value Measurements	199
Income Taxes	211
Financing Activities	212
Variable Interest Entities	216
Sustainable Cost Reductions	219

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Regulatory Activity

Termination of Interconnection Agreement

Based upon the PUCO’s approval of OPCo’s corporate separation plan in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations and transfer at net book value certain plants to APCo and KPCo. Additionally, the AEP East Companies requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Under the PCA, I&M would be individually responsible for planning its capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. In March 2013, a revised PCA was filed at the FERC that included certain clarifying wording changes agreed upon by intervenors. A decision is pending at the FERC. See the “Corporate Separation and Termination of Interconnection Agreement” section of Note 3.

If I&M experiences decreases in revenues or increases in expenses as a result of changes to its relationship with affiliates and is unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

2011 Indiana Base Rate Case

Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both of its units at the Rockport Plant with a Dry Sorbent Injection system. The estimated cost in the application was $285 million, excluding AFUDC, of which I&M’s ownership share is $142 million. In July 2013, a settlement agreement was filed with the IURC. The settlement agreement includes the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s direct ownership share of $129 million. Hearings at the IURC are scheduled for August 2013. A decision is expected by November 2013. As of June 30, 2013, I&M has incurred costs of $39 million related to the CCT Project, including AFUDC. If I&M is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows. See the “Rockport Plant Clean Coal Technology Project (CCT Project)” section of Note 3.

Cook Plant Life Cycle Management Project (LCM 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, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. As of June 30, 2013, I&M has incurred $240 million related to the LCM Project, including AFUDC.

100

Litigation and Environmental Issues

In the ordinary course of business, I&M is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 153. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2013		2012		2013		2012
			(in millions of KWhs)
Retail:
	Residential			1,152		1,217		2,878		2,786
	Commercial			1,197		1,290		2,385		2,456
	Industrial			1,884		1,964		3,697		3,797
	Miscellaneous			15		15		35		38
Total Retail (a)				4,248		4,486		8,995		9,077

Wholesale				2,251		2,068		4,831		4,029

Total KWhs				6,499		6,554		13,826		13,106

(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.

Summary of Heating and Cooling Degree Days

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
		(in degree days)
Actual - Heating (a)			263		163		2,551		1,784
Normal - Heating (b)			230		235		2,385		2,420

Actual - Cooling (c)			278		369		278		398
Normal - Cooling (b)			260		256		262		257

(a)	Eastern Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Eastern Region cooling degree days are calculated on a 65 degree temperature base.

101

Second Quarter of 2013 Compared to Second Quarter of 2012

	Reconciliation of Second Quarter of 2012 to Second Quarter of 2013
	Net Income
	(in millions)

	Second Quarter of 2012	$	30

	Changes in Gross Margin:
	Retail Margins		13
	FERC Municipals and Cooperatives		21
	Off-system Sales		(3)
	Transmission Revenues		(4)
	Other Revenues		(1)
	Total Change in Gross Margin		26

	Changes in Expenses and Other:
	Other Operation and Maintenance		(1)
	Depreciation and Amortization		(8)
	Taxes Other Than Income Taxes		(4)
	Other Income		5
	Total Change in Expenses and Other		(8)

	Income Tax Expense		(7)

	Second Quarter of 2013	$	41

·	Retail Margins increased $13 million primarily due to the following:
	·	A $24 million increase due to rate increases in Indiana effective March 2013, higher PJM revenue and higher Indiana Demand Side Management (DSM) revenue. The PJM and DSM increases were partially offset in expense items below.
	These increases were partially offset by:
	·	An $8 million decrease due to lower weather-normalized sales.
	·	A $4 million decrease in weather-related usage primarily due to a decrease in cooling degree days.
·	Margins from FERC Municipal and Cooperatives increased $21 million primarily due to the annual true-up adjustment of formula rates to actual costs.
·	Margins from Off-system Sales decreased $3 million primarily due to lower PJM capacity revenues and reduced trading and marketing margins.
·	Transmission Revenues decreased $4 million primarily due to increased PJM costs.

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

	·	Depreciation and Amortization expenses increased $8 million primarily due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant’s estimated life approved in Indiana effective March 2013. The majority of the increase in depreciation for Tanners Creek Plant’s life is offset within Gross Margin.
	·	Taxes Other Than Income Taxes expenses increased $4 million primarily due to property tax increases.
	·	Other Income increased $5 million primarily due to an increase in equity AFUDC.
	·	Income Tax Expense increased $7 million primarily due to an increase in pretax book income.

102

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

	Reconciliation of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2013
	Net Income
	(in millions)

		Six Months Ended June 30, 2012	$	69

		Changes in Gross Margin:
		Retail Margins		37
		FERC Municipals and Cooperatives		20
		Off-system Sales		(4)
		Transmission Revenues		(4)
		Other Revenues		2
		Total Change in Gross Margin		51

		Changes in Expenses and Other:
		Other Operation and Maintenance		(14)
		Depreciation and Amortization		(15)
		Taxes Other Than Income Taxes		(4)
		Other Income		8
		Interest Expense		1
		Total Change in Expenses and Other		(24)

		Income Tax Expense		(12)

		Six Months Ended June 30, 2013	$	84

·	Retail Margins increased $37 million primarily due to the following:
	·	A $33 million increase due to rate increases in Indiana effective March 2013, higher PJM revenue and higher Indiana Demand Side Management (DSM) revenue. The PJM and DSM increases were partially offset in expense items below.
·	Margins from FERC Municipal and Cooperatives increased $20 million primarily due to the annual true-up adjustment of formula rates to actual costs.
·	Margins from Off-system Sales decreased $4 million primarily due to lower PJM capacity revenues and reduced trading and marketing margins.
·	Transmission Revenues decreased $4 million primarily due to increased PJM costs.

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

·	Other Operation and Maintenance expenses increased $14 million primarily due to the following:
	·	An $8 million increase in steam maintenance expenses primarily due to Rockport Plant and Tanners Creek Plant outages in the first quarter of 2013.
	·	A $7 million increase in transmission expenses primarily due to increased PJM costs.
	·	A $4 million increase in customer service costs primarily due to higher DSM expenses. The increase in DSM expenses was offset by a corresponding increase in Retail Margins discussed above.
	These increases were partially offset by:
	·	A $5 million decrease in administrative and general operation expenses.
·	Depreciation and Amortization expenses increased $15 million primarily due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant’s estimated life approved in Michigan effective April 2012 and in Indiana effective March 2013. The majority of the increase in depreciation for Tanners Creek Plant’s life is offset within Gross Margin.

103

	·	Taxes Other Than Income Taxes expenses increased $4 million primarily due to property tax increases.
	·	Other Income increased $8 million primarily due to an increase in equity AFUDC .
	·	Income Tax Expense increased $12 million primarily due to an increase in pretax book income and other book/tax differences which are accounted for on a flow-through basis.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

104

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
REVENUES
Electric Generation, Transmission and Distribution	$	490,301	$	435,965	$	980,904	$	871,992
Sales to AEP Affiliates		31,335		45,728		86,312		121,643
Other Revenues – Affiliated		26,815		29,052		62,640		59,763
Other Revenues – Nonaffiliated		1,050		131		3,038		3,685
TOTAL REVENUES		549,501		510,876		1,132,894		1,057,083

EXPENSES
Fuel and Other Consumables Used for Electric Generation		85,030		96,715		189,895		209,085
Purchased Electricity for Resale		36,814		29,488		78,626		65,398
Purchased Electricity from AEP Affiliates		99,547		82,188		200,923		170,141
Other Operation		132,478		134,274		277,716		269,490
Maintenance		50,238		47,244		95,752		89,509
Depreciation and Amortization		45,696		37,560		86,598		71,539
Taxes Other Than Income Taxes		22,165		18,604		44,621		40,793
TOTAL EXPENSES		471,968		446,073		974,131		915,955

OPERATING INCOME		77,533		64,803		158,763		141,128

Other Income (Expense):
Interest Income		2,662		524		4,717		1,775
Allowance for Equity Funds Used During Construction		4,881		2,324		10,527		5,335
Interest Expense		(24,436)		(25,373)		(48,647)		(50,426)

INCOME BEFORE INCOME TAX EXPENSE		60,640		42,278		125,360		97,812

Income Tax Expense		19,886		12,468		41,149		28,781

NET INCOME	$	40,754	$	29,810	$	84,211	$	69,031

The common stock of I&M is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

105

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
Net Income		$	40,754	$	29,810	$	84,211	$	69,031

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $172 and $4,002 for the Three Months Ended
	June 30, 2013 and 2012, Respectively, and $1,854 and $2,680 for the
	Six Months Ended June 30, 2013 and 2012, Respectively		321		(7,433)		3,444		(4,977)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $95
	and $150 for the Three Months Ended June 30, 2013 and 2012,
	Respectively, and $189 and $300 for the Six Months Ended June 30, 2013
	and 2012, Respectively		175		278		351		557

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			496		(7,155)		3,795		(4,420)

TOTAL COMPREHENSIVE INCOME		$	41,250	$	22,655	$	88,006	$	64,611

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

106

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

								Accumulated
								Other
		Common		Paid-in		Retained		Comprehensive
		Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2011	$	56,584	$	980,896	$	751,721	$	(28,221)	$	1,760,980

Common Stock Dividends							(25,000)				(25,000)
Net Income							69,031				69,031
Other Comprehensive Loss									(4,420)		(4,420)
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2012	$	56,584	$	980,896	$	795,752	$	(32,641)	$	1,800,591

TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2012	$	56,584	$	980,896	$	795,178	$	(28,883)	$	1,803,775

Common Stock Dividends							(25,000)				(25,000)
Net Income							84,211				84,211
Other Comprehensive Income									3,795		3,795
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2013	$	56,584	$	980,896	$	854,389	$	(25,088)	$	1,866,781

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

107

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2013 and December 31, 2012
(in thousands)
(Unaudited)

			June 30,		December 31,
			2013		2012
CURRENT ASSETS
Cash and Cash Equivalents			$	1,014	$	1,562
Advances to Affiliates				273,117		116,977
Accounts Receivable:
	Customers			79,501		61,776
	Affiliated Companies			58,494		79,886
	Accrued Unbilled Revenues			11,207		11,218
	Miscellaneous			6,400		12,260
	Allowance for Uncollectible Accounts			(67)		(229)
		Total Accounts Receivable		155,535		164,911
Fuel				74,818		53,406
Materials and Supplies				191,195		195,147
Risk Management Assets				19,599		26,974
Deferred Cook Plant Fire Costs				-		80,000
Prepayments and Other Current Assets				71,782		83,270
TOTAL CURRENT ASSETS				787,060		722,247

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			4,130,327		4,062,733
	Transmission			1,298,743		1,278,236
	Distribution			1,580,709		1,553,358
Other Property, Plant and Equipment (Including Nuclear Fuel and Coal Mining)				752,084		725,313
Construction Work in Progress				370,384		341,063
Total Property, Plant and Equipment				8,132,247		7,960,703
Accumulated Depreciation, Depletion and Amortization				3,269,566		3,232,135
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				4,862,681		4,728,568

OTHER NONCURRENT ASSETS
Regulatory Assets				564,163		540,019
Spent Nuclear Fuel and Decommissioning Trusts				1,791,394		1,705,772
Long-term Risk Management Assets				16,315		23,569
Deferred Charges and Other Noncurrent Assets				117,327		111,364
TOTAL OTHER NONCURRENT ASSETS				2,489,199		2,380,724

TOTAL ASSETS			$	8,138,940	$	7,831,539

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

108

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2013 and December 31, 2012
(dollars in thousands)
(Unaudited)

		June 30,		December 31,
		2013		2012
CURRENT LIABILITIES
Accounts Payable:
	General	$	143,935	$	208,701
	Affiliated Companies		59,793		104,631
Long-term Debt Due Within One Year – Nonaffiliated
	(June 30, 2013 and December 31, 2012 Amounts Include $141,869 and
	$119,890, Respectively, Related to DCC Fuel)		228,748		203,953
Risk Management Liabilities			9,387		31,517
Customer Deposits			29,794		31,142
Accrued Taxes			66,786		67,675
Accrued Interest			28,745		26,859
Other Current Liabilities			102,011		122,053
TOTAL CURRENT LIABILITIES			669,199		796,531

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			2,076,444		1,853,713
Long-term Risk Management Liabilities			10,020		13,898
Deferred Income Taxes			1,090,509		1,019,160
Regulatory Liabilities and Deferred Investment Tax Credits			990,801		948,292
Asset Retirement Obligations			1,233,640		1,192,313
Deferred Credits and Other Noncurrent Liabilities			201,546		203,857
TOTAL NONCURRENT LIABILITIES			5,602,960		5,231,233

TOTAL LIABILITIES			6,272,159		6,027,764

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
	Authorized – 2,500,000 Shares
	Outstanding – 1,400,000 Shares		56,584		56,584
Paid-in Capital			980,896		980,896
Retained Earnings			854,389		795,178
Accumulated Other Comprehensive Income (Loss)			(25,088)		(28,883)
TOTAL COMMON SHAREHOLDER’S EQUITY			1,866,781		1,803,775

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	8,138,940	$	7,831,539

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

109

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

			Six Months Ended June 30,
			2013		2012
OPERATING ACTIVITIES
Net Income			$	84,211	$	69,031
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			86,598		71,539
	Deferred Income Taxes			51,234		40,899
	Deferral of Incremental Nuclear Refueling Outage Expenses, Net			(18,283)		(9,163)
	Allowance for Equity Funds Used During Construction			(10,527)		(5,335)
	Mark-to-Market of Risk Management Contracts			9,096		(2,798)
	Amortization of Nuclear Fuel			62,625		64,228
	Fuel Over/Under-Recovery, Net			(1,796)		(2,650)
	Change in Other Noncurrent Assets			(2,690)		6,849
	Change in Other Noncurrent Liabilities			3,599		42,793
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		9,376		31,614
		Fuel, Materials and Supplies		(17,460)		(8,475)
		Accounts Payable		(48,048)		(33,573)
		Accrued Taxes, Net		10,250		19,642
		Other Current Assets		12,209		(9,183)
		Other Current Liabilities		(16,764)		(26,557)
Net Cash Flows from Operating Activities				213,630		248,861

INVESTING ACTIVITIES
Construction Expenditures				(267,201)		(137,473)
Change in Advances to Affiliates, Net				(156,140)		(142,752)
Purchases of Investment Securities				(411,769)		(544,981)
Sales of Investment Securities				385,942		516,579
Acquisitions of Nuclear Fuel				(58,900)		(11,263)
Insurance Proceeds Related to Cook Plant Fire				72,000		-
Other Investing Activities				3,898		26,692
Net Cash Flows Used for Investing Activities				(432,170)		(293,198)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated				348,899		128,533
Retirement of Long-term Debt – Nonaffiliated				(103,793)		(55,995)
Principal Payments for Capital Lease Obligations				(2,791)		(3,490)
Dividends Paid on Common Stock				(25,000)		(25,000)
Other Financing Activities				677		167
Net Cash Flows from Financing Activities				217,992		44,215

Net Decrease in Cash and Cash Equivalents				(548)		(122)
Cash and Cash Equivalents at Beginning of Period				1,562		1,020
Cash and Cash Equivalents at End of Period			$	1,014	$	898

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	44,165	$	48,565
Net Cash Paid (Received) for Income Taxes				(27,608)		(31,921)
Noncash Acquisitions Under Capital Leases				1,888		4,341
Construction Expenditures Included in Current Liabilities as of June 30,				44,060		26,509
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,				41,086		14

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

110

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

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

	Page
	Number

Significant Accounting Matters	154
Comprehensive Income	154
Rate Matters	168
Commitments, Guarantees and Contingencies	178
Benefit Plans	183
Business Segments	185
Derivatives and Hedging	186
Fair Value Measurements	199
Income Taxes	211
Financing Activities	212
Variable Interest Entities	216
Sustainable Cost Reductions	219

111

OHIO POWER COMPANY AND SUBSIDIARY

112

OHIO POWER COMPANY AND SUBSIDIARY

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Ohio Customer Choice

In OPCo’s service territory, various CRES providers are targeting retail customers by offering alternative generation service. The reduction in gross margin as a result of customer switching in Ohio is partially offset by (a) collection of capacity revenues from CRES providers, (b) off-system sales, (c) deferral of unrecovered capacity costs and (d) Retail Stability Rider collections.

Regulatory Activity

Ohio Electric Security Plan Filing

2009 – 2011 ESP

June 2012 – May 2015 Ohio ESP Including Capacity Charge

113

Corporate Separation, Plant Transfers and Termination of Interconnection Agreement

Significantly Excessive Earnings Test

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order. Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings. OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO-ordered SEET refund. OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in 2012 for OPCo. Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo. Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filing” section of Note 3.

Securitization of Regulatory Assets

Muskingum River Plant, Unit 5 Impairment

Muskingum River Plant, Unit 5 (MR5) had options under a consent decree to cease burning coal and retire in 2015 or cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017. In the second quarter of 2013, management re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project which would have extended the useful life of MR5 is remote.

114

As a result, in the second quarter of 2013, OPCo completed an impairment analysis and recorded a $154 million ($99 million, net of tax) pretax impairment charge for OPCo’s net book value of MR5. Management expects to retire the plant in 2015. See “Muskingum River Plant, Unit 5” section of Note 5.

Litigation and Environmental Issues

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 153. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2013		2012		2013		2012
			(in millions of KWhs)
Retail:
	Residential			3,000		3,002		7,264		6,881
	Commercial			3,506		3,582		6,892		6,818
	Industrial			4,203		4,799		8,285		9,520
	Miscellaneous			27		27		62		58
Total Retail (a)				10,736		11,410		22,503		23,277

Wholesale				2,417		2,798		5,461		5,304

Total KWhs				13,153		14,208		27,964		28,581

(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.

Summary of Heating and Cooling Degree Days

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
		(in degree days)
Actual - Heating (a)			193		146		2,164		1,543
Normal - Heating (b)			190		195		2,075		2,112

Actual - Cooling (c)			346		401		346		428
Normal - Cooling (b)			277		270		280		273

(a)	Eastern Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Eastern Region cooling degree days are calculated on a 65 degree temperature base.

115

Second Quarter of 2013 Compared to Second Quarter of 2012

Reconciliation of Second Quarter of 2012 to Second Quarter of 2013
Net Income
(in millions)

	Second Quarter of 2012	$	101

	Changes in Gross Margin:
	Retail Margins		(4)
	Off-system Sales		(42)
	Transmission Revenues		5
	Total Change in Gross Margin		(41)

	Changes in Expenses and Other:
	Other Operation and Maintenance		26
	Asset Impairments and Other Related Charges		(154)
	Depreciation and Amortization		35
	Taxes Other Than Income Taxes		(2)
	Interest Expense		6
	Total Change in Expenses and Other		(89)

	Income Tax Expense		50

	Second Quarter of 2013	$	21

·	Retail Margins decreased $4 million primarily due to the following:
	·	A $66 million decrease attributable to 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 $35 million decrease due to the second quarter 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
	·	An $8 million decrease due to lower sales to Buckeye Power, Inc. to provide backup energy under the Cardinal Station Agreement.
	·	A $6 million decrease in weather-related usage primarily due to a 14% decrease in cooling degree days.
	These decreases were partially offset by:
	·	An $85 million increase in revenues associated with the Universal Service Fund (USF) surcharge, Retail Stability Rider, Deferred Asset Recovery Rider and Distribution Investment Recovery Rider. The majority of these increases have corresponding increases in other expense items below.
	·	A $26 million increase due to the deferral of consumables and purchased power as a result of the PUCO’s July 2012 approval of the capacity deferral mechanism.
·	Margins from Off-system Sales decreased $42 million primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity revenues and reduced trading and marketing margins. The decrease in CRES capacity revenues is partially offset in other expense items below.
·	Transmission Revenues increased $5 million primarily due to increased transmission revenues from 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.

116

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

·	Other Operation and Maintenance expenses decreased $26 million primarily due to the following:
	·	A $12 million decrease due to the deferral of capacity-related costs as a result of the PUCO's July 2012 approval of the capacity deferral mechanism.
	·	A $12 million decrease in recoverable PJM expenses.
	·	A $6 million decrease in advertising expenses.
	·	A $3 million decrease due to expenses recorded in 2012 for the 2012 sustainable cost reductions program.
	·	A $3 million decrease due to updated gridSMART rider allocation ratios between capital carrying charges and operations expense beginning in January 2013. This decrease was partially offset by a corresponding increase in Depreciation and Amortization.
	These decreases were partially offset by:
	·	A $19 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins above.
·	Asset Impairments and Other Related Charges increased $154 million due to the second quarter 2013 impairment of Muskingum River Plant, Unit 5.
·	Depreciation and Amortization expenses decreased $35 million primarily due to the following:
	·	A $26 million decrease as a result of depreciation ceasing on certain generating plants that were impaired in November 2012.
	·	A $15 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of the capacity deferral mechanism.
·	Interest Expense decreased $6 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·	Income Tax Expense decreased $50 million primarily due to a decrease in pretax book income.

117

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

	Reconciliation of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2013
	Net Income
	(in millions)

	Six Months Ended June 30, 2012	$	252

	Changes in Gross Margin:
	Retail Margins		(3)
	Off-system Sales		(74)
	Transmission Revenues		16
	Total Change in Gross Margin		(61)

	Changes in Expenses and Other:
	Other Operation and Maintenance		(22)
	Asset Impairments and Other Related Charges		(154)
	Depreciation and Amortization		76
	Interest Expense		10
	Total Change in Expenses and Other		(90)

	Income Tax Expense		50

	Six Months Ended June 30, 2013	$	151

·	Retail Margins decreased $3 million primarily due to the following:
	·	A $153 million decrease attributable to 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 $35 million decrease due to the second quarter 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
	·	A $15 million decrease due to lower sales to Buckeye Power, Inc. to provide backup energy under the Cardinal Station Agreement.
	·	A $5 million decrease in capacity settlement revenues under the Interconnection Agreement.
	These decreases were partially offset by:
	·	A $146 million increase in revenues associated with the USF surcharge, Retail Stability Rider, Deferred Asset Recovery Rider and Distribution Investment Recovery Rider. The majority of these increases have corresponding increases in other expense items below.
	·	A $47 million increase due to the deferral of consumables and purchased power as a result of the PUCO’s July 2012 approval of the capacity deferral mechanism.
	·	A $15 million increase in weather-related usage primarily due to a 40% increase in heating degree days.
·	Margins from Off-system Sales decreased $74 million primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity revenues and reduced trading and marketing margins, partially offset by higher physical sales volumes and margins. The decrease in CRES capacity revenues is partially offset in other expense items below.
·	Transmission Revenues increased $16 million primarily due to increased transmission revenues from 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.

118

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

·	Other Operation and Maintenance expenses increased $22 million primarily due to the following:
	·	A $45 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins above.
	·	A $35 million increase 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 the Ohio modified stipulation.
	These increases were partially offset by:
	·	A $20 million decrease due to the deferral of capacity-related costs as a result of the PUCO's July 2012 approval of the capacity deferral mechanism.
	·	A $9 million decrease in recoverable PJM expenses.
	·	An $8 million decrease primarily due to the 2012 reversal of storm damage deferrals as a result of the PUCO’s February 2012 rejection of the Ohio modified stipulation.
	·	A $7 million decrease due to updated gridSMART rider allocation ratios between capital carrying charges and operations expense beginning in January 2013. This decrease was partially offset by a corresponding increase in Depreciation and Amortization.
	·	A $6 million decrease in advertising expenses.
·	Asset Impairments and Other Related Charges increased $154 million due to the second quarter 2013 impairment of Muskingum River Plant, Unit 5.
·	Depreciation and Amortization expenses decreased $76 million primarily due to the following:
	·	A $53 million decrease as a result of depreciation ceasing on certain generating plants that were impaired in November 2012.
	·	A $35 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO’s July 2012 approval of the capacity deferral mechanism.
·	Interest Expense decreased $10 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·	Income Tax Expense decreased $50 million primarily due to a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

119

OHIO POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
REVENUES
Electric Generation, Transmission and Distribution	$	817,493	$	929,487	$	1,751,174	$	1,970,318
Sales to AEP Affiliates		274,390		172,561		560,032		354,318
Other Revenues – Affiliated		7,583		7,979		15,423		17,090
Other Revenues – Nonaffiliated		3,528		3,723		10,155		9,247
TOTAL REVENUES		1,102,994		1,113,750		2,336,784		2,350,973

EXPENSES
Fuel and Other Consumables Used for Electric Generation		352,368		298,294		761,952		668,287
Purchased Electricity for Resale		37,158		52,104		80,343		110,238
Purchased Electricity from AEP Affiliates		73,290		81,818		153,671		170,501
Other Operation		137,265		162,086		321,452		292,428
Maintenance		72,997		74,015		147,292		154,619
Asset Impairments and Other Related Charges		154,304		-		154,304		-
Depreciation and Amortization		102,346		137,009		194,670		271,439
Taxes Other Than Income Taxes		100,194		98,420		205,215		203,838
TOTAL EXPENSES		1,029,922		903,746		2,018,899		1,871,350

OPERATING INCOME		73,072		210,004		317,885		479,623

Other Income (Expense):
Interest Income		2,326		345		2,689		1,443
Carrying Costs Income		3,757		4,511		7,020		7,269
Allowance for Equity Funds Used During Construction		521		915		1,825		2,038
Interest Expense		(47,244)		(53,147)		(97,417)		(107,408)

INCOME BEFORE INCOME TAX EXPENSE		32,432		162,628		232,002		382,965

Income Tax Expense		11,376		61,205		81,172		130,712

NET INCOME	$	21,056	$	101,423	$	150,830	$	252,253

The common stock of OPCo is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

120

OHIO POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

		Three Months Ended				Six Months Ended
		June 30,					June 30,
		2013		2012		2013		2012
Net Income		$	21,056	$	101,423	$	150,830	$	252,253

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $293 and $91 for the Three Months Ended
	June 30, 2013 and 2012, Respectively, and $281 and $846 for the Six
	Months Ended June 30, 2013 and 2012, Respectively		(545)		170		521		(1,571)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,760
	and $1,745 for the Three Months Ended June 30, 2013 and 2012,
	Respectively, and $3,520 and $3,490 for the Six Months Ended
	June 30, 2013 and 2012, Respectively		3,270		3,240		6,539		6,481

TOTAL OTHER COMPREHENSIVE INCOME			2,725		3,410		7,060		4,910

TOTAL COMPREHENSIVE INCOME		$	23,781	$	104,833	$	157,890	$	257,163

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

121

OHIO POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

								Accumulated
								Other
		Common		Paid-in		Retained		Comprehensive
		Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2011	$	321,201	$	1,744,099	$	2,582,600	$	(197,722)	$	4,450,178

Common Stock Dividends							(150,000)				(150,000)
Net Income							252,253				252,253
Other Comprehensive Income									4,910		4,910
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2012	$	321,201	$	1,744,099	$	2,684,853	$	(192,812)	$	4,557,341

TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2012	$	321,201	$	1,744,099	$	2,626,134	$	(165,725)	$	4,525,709

Common Stock Dividends							(175,000)				(175,000)
Net Income							150,830				150,830
Other Comprehensive Income									7,060		7,060
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2013	$	321,201	$	1,744,099	$	2,601,964	$	(158,665)	$	4,508,599

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

122

OHIO POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2013 and December 31, 2012
(in thousands)
(Unaudited)

			June 30,		December 31,
			2013		2012
CURRENT ASSETS
Cash and Cash Equivalents			$	2,545	$	3,640
Advances to Affiliates				10,321		116,422
Accounts Receivable:
	Customers			115,913		135,954
	Affiliated Companies			158,313		176,590
	Accrued Unbilled Revenues			11,674		57,887
	Miscellaneous			3,887		9,327
	Allowance for Uncollectible Accounts			(7,418)		(129)
		Total Accounts Receivable		282,369		379,629
Fuel				312,293		328,840
Materials and Supplies				186,662		186,269
Risk Management Assets				41,145		44,313
Accrued Tax Benefits				43,706		17,785
Prepayments and Other Current Assets				32,684		26,807
TOTAL CURRENT ASSETS				911,725		1,103,705

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			8,363,747		8,673,296
	Transmission			2,011,693		2,013,737
	Distribution			3,773,461		3,722,745
Other Property, Plant and Equipment				584,611		571,154
Construction Work in Progress				409,751		354,497
Total Property, Plant and Equipment				15,143,263		15,335,429
Accumulated Depreciation and Amortization				5,154,691		5,242,805
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				9,988,572		10,092,624

OTHER NONCURRENT ASSETS
Regulatory Assets				1,527,609		1,420,966
Long-term Risk Management Assets				33,381		48,288
Deferred Charges and Other Noncurrent Assets				193,947		320,026
TOTAL OTHER NONCURRENT ASSETS				1,754,937		1,789,280

TOTAL ASSETS			$	12,655,234	$	12,985,609

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

123


OHIO POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2013 and December 31, 2012
(Unaudited)

		June 30,		December 31,
		2013		2012
			(in thousands)
CURRENT LIABILITIES
Advances from Affiliates		$	292,051	$	-
Accounts Payable:
	General		228,348		276,220
	Affiliated Companies		112,737		153,222
Long-term Debt Due Within One Year – Nonaffiliated			664,450		856,000
Risk Management Liabilities			19,769		24,155
Accrued Taxes			324,412		467,309
Accrued Interest			52,499		63,560
Other Current Liabilities			231,272		263,638
TOTAL CURRENT LIABILITIES			1,925,538		2,104,104

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			2,440,344		2,804,440
Long-term Debt – Affiliated			400,000		200,000
Long-term Risk Management Liabilities			19,803		25,965
Deferred Income Taxes			2,412,119		2,345,850
Regulatory Liabilities and Deferred Investment Tax Credits			444,931		451,071
Deferred Credits and Other Noncurrent Liabilities			503,900		528,470
TOTAL NONCURRENT LIABILITIES			6,221,097		6,355,796

TOTAL LIABILITIES			8,146,635		8,459,900

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
	Authorized – 40,000,000 Shares
	Outstanding – 27,952,473 Shares		321,201		321,201
Paid-in Capital			1,744,099		1,744,099
Retained Earnings			2,601,964		2,626,134
Accumulated Other Comprehensive Income (Loss)			(158,665)		(165,725)
TOTAL COMMON SHAREHOLDER’S EQUITY			4,508,599		4,525,709

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	12,655,234	$	12,985,609

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

124

OHIO POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

			Six Months Ended June 30,
			2013		2012
OPERATING ACTIVITIES
Net Income			$	150,830	$	252,253
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			194,670		271,439
	Deferred Income Taxes			55,839		82,961
	Asset Impairments and Other Related Charges			154,304		-
	Carrying Costs Income			(7,020)		(7,269)
	Allowance for Equity Funds Used During Construction			(1,825)		(2,038)
	Mark-to-Market of Risk Management Contracts			9,448		(8,328)
	Property Taxes			111,392		109,892
	Fuel Over/Under-Recovery, Net			15,267		(19,433)
	Deferral of Ohio Capacity Costs, Net			(102,240)		-
	Change in Other Noncurrent Assets			(16,273)		(20,063)
	Change in Other Noncurrent Liabilities			2,421		416
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		100,747		64,404
		Fuel, Materials and Supplies		9,714		(70,666)
		Accounts Payable		(66,947)		(134,823)
		Accrued Taxes, Net		(168,818)		(115,596)
		Other Current Assets		5,391		7,982
		Other Current Liabilities		(25,859)		(13,884)
Net Cash Flows from Operating Activities				421,041		397,247

INVESTING ACTIVITIES
Construction Expenditures				(296,888)		(246,657)
Change in Advances to Affiliates, Net				106,101		186,787
Proceeds from Sales of Assets				10,875		5,475
Other Investing Activities				1,085		6,705
Net Cash Flows Used for Investing Activities				(178,827)		(47,690)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated				49,562		-
Issuance of Long-term Debt – Affiliated				200,000		-
Change in Advances from Affiliates, Net				292,051		-
Retirement of Long-term Debt – Nonaffiliated				(606,000)		(194,500)
Principal Payments for Capital Lease Obligations				(4,747)		(4,920)
Dividends Paid on Common Stock				(175,000)		(150,000)
Other Financing Activities				825		134
Net Cash Flows Used for Financing Activities				(243,309)		(349,286)

Net Increase (Decrease) in Cash and Cash Equivalents				(1,095)		271
Cash and Cash Equivalents at Beginning of Period				3,640		2,095
Cash and Cash Equivalents at End of Period			$	2,545	$	2,366

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	105,876	$	107,216
Net Cash Paid (Received) for Income Taxes				48,841		15,019
Noncash Acquisitions Under Capital Leases				3,335		4,239
Government Grants Included in Accounts Receivable as of June 30,				-		1,094
Construction Expenditures Included in Current Liabilities as of June 30,				56,618		41,873

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

125

OHIO POWER COMPANY AND SUBSIDIARY

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

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

	Page
	Number

Significant Accounting Matters	154
Comprehensive Income	154
Rate Matters	168
Commitments, Guarantees and Contingencies	178
Disposition and Impairment	182
Benefit Plans	183
Business Segments	185
Derivatives and Hedging	186
Fair Value Measurements	199
Income Taxes	211
Financing Activities	212
Variable Interest Entities	216
Sustainable Cost Reductions	219

126

PUBLIC SERVICE COMPANY OF OKLAHOMA

127

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Regulatory Activity

Oklahoma Environmental Compliance Plan

Litigation and Environmental Issues

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 153. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

128

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2013		2012		2013		2012
			(in millions of KWhs)
Retail:
	Residential			1,370		1,542		2,806		2,879
	Commercial			1,275		1,373		2,354		2,474
	Industrial			1,291		1,298		2,485		2,491
	Miscellaneous			321		341		598		641
Total Retail (a)				4,257		4,554		8,243		8,485

Wholesale				267		394		522		939

Total KWhs				4,524		4,948		8,765		9,424

(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.

Summary of Heating and Cooling Degree Days

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
		(in degree days)
Actual - Heating (a)			119		-		1,208		676
Normal - Heating (b)			37		41		1,082		1,107

Actual - Cooling (c)			644		871		649		935
Normal - Cooling (b)			649		635		664		648

(a)	Western Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Western Region cooling degree days are calculated on a 65 degree temperature base.

129

Second Quarter of 2013 Compared to Second Quarter of 2012

	Reconciliation of Second Quarter of 2012 to Second Quarter of 2013
	Net Income
	(in millions)

	Second Quarter of 2012		$	35

	Changes in Gross Margin:
	Retail Margins (a)			(7)
	Transmission Revenues			2
	Other Revenues			1
	Total Change in Gross Margin			(4)

	Changes in Expenses and Other:
	Other Operation and Maintenance			(5)
	Taxes Other Than Income Taxes			(1)
	Total Change in Expenses and Other			(6)

	Income Tax Expense			3

	Second Quarter of 2013		$	28

	(a)	Includes firm wholesale sales to municipals and cooperatives.

·	Retail Margins decreased $7 million primarily due to the following:
	·	A $7 million decrease in weather-related usage primarily due to a 26% decrease in cooling degree days.
	·	A $2 million decrease primarily due to lower weather-normalized retail sales.
	These decreases were partially offset by:
	·	A $3 million increase primarily due to revenue increases from rate riders. This increase in retail margins has corresponding increases to riders/trackers recognized in other expense items below.

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

	·	Other Operation and Maintenance expenses increased $5 million primarily due to increased SPP transmission services.
	·	Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income.

130

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

	Reconciliation of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2013
	Net Income
	(in millions)

		Six Months Ended June 30, 2012		$	48

		Changes in Gross Margin:
		Retail Margins (a)			(6)
		Transmission Revenues			3
		Other Revenues			(1)
		Total Change in Gross Margin			(4)

		Changes in Expenses and Other:
		Other Operation and Maintenance			(6)
		Depreciation and Amortization			(1)
		Interest Expense			2
		Total Change in Expenses and Other			(5)

		Income Tax Expense			3

		Six Months Ended June 30, 2013		$	42

		(a)	Includes firm wholesale sales to municipals and cooperatives.

·	Retail Margins decreased $6 million primarily due to the following:
	·	A $6 million decrease primarily due to lower weather-normalized retail sales.
	·	A $4 million net decrease in weather-related usage primarily due to a 31% decrease in cooling degree days, partially offset by an increase in heating degree days.
	These decreases were partially offset by:
	·	A $6 million increase primarily due to revenue increases from rate riders. This increase in retail margins has corresponding increases to riders/trackers recognized in other expense items below.
·	Transmission Revenues increased $3 million primarily due to rate increases for customers in the SPP region.

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

·	Other Operation and Maintenance expenses increased $6 million primarily due to the following:
	·	A $9 million increase in transmission expenses primarily due to increased SPP transmission services.
	This increase was partially offset by:
	·	A $2 million decrease in administrative and general expenses.
·	Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

131

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
REVENUES
Electric Generation, Transmission and Distribution	$	317,302	$	311,310	$	577,205	$	603,832
Sales to AEP Affiliates		5,693		5,407		7,527		12,512
Other Revenues		1,692		594		2,244		1,498
TOTAL REVENUES		324,687		317,311		586,976		617,842

EXPENSES
Fuel and Other Consumables Used for Electric Generation		86,241		91,126		129,551		216,551
Purchased Electricity for Resale		58,835		44,822		123,490		70,264
Purchased Electricity from AEP Affiliates		6,823		4,260		17,039		10,458
Other Operation		53,659		48,880		101,466		95,859
Maintenance		24,753		24,853		53,325		53,178
Depreciation and Amortization		24,078		23,390		48,258		46,923
Taxes Other Than Income Taxes		11,827		10,681		21,824		21,820
TOTAL EXPENSES		266,216		248,012		494,953		515,053

OPERATING INCOME		58,471		69,299		92,023		102,789

Other Income (Expense):
Interest Income		193		97		1,121		1,032
Carrying Costs Income		110		529		317		1,142
Allowance for Equity Funds Used During Construction		844		468		1,824		890
Interest Expense		(13,259)		(13,766)		(26,599)		(28,477)

INCOME BEFORE INCOME TAX EXPENSE		46,359		56,627		68,686		77,376

Income Tax Expense		17,927		21,416		26,561		29,517

NET INCOME	$	28,432	$	35,211	$	42,125	$	47,859

The common stock of PSO is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

132

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
Net Income		$	28,432	$	35,211	$	42,125	$	47,859

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $137 and $193 for the Three Months Ended
	June 30, 2013 and 2012, Respectively, and $227 and $222 for the Six
	Months Ended June 30, 2013 and 2012, Respectively		(254)		(359)		(421)		(412)

TOTAL COMPREHENSIVE INCOME		$	28,178	$	34,852	$	41,704	$	47,447

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

133

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

								Accumulated
								Other
		Common		Paid-in		Retained		Comprehensive
		Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2011	$	157,230	$	364,037	$	364,389	$	7,149	$	892,805

Common Stock Dividends							(30,000)				(30,000)
Net Income							47,859				47,859
Other Comprehensive Loss									(412)		(412)
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2012	$	157,230	$	364,037	$	382,248	$	6,737	$	910,252

TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2012	$	157,230	$	364,037	$	388,530	$	6,481	$	916,278

Common Stock Dividends							(27,500)				(27,500)
Net Income							42,125				42,125
Other Comprehensive Loss									(421)		(421)
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2013	$	157,230	$	364,037	$	403,155	$	6,060	$	930,482

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

134

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
June 30, 2013 and December 31, 2012
(in thousands)
(Unaudited)

			June 30,		December 31,
			2013		2012
CURRENT ASSETS
Cash and Cash Equivalents			$	1,042	$	1,367
Advances to Affiliates				-		10,558
Accounts Receivable:
	Customers			42,422		31,047
	Affiliated Companies			21,844		24,751
	Miscellaneous			2,336		6,216
	Allowance for Uncollectible Accounts			(713)		(872)
		Total Accounts Receivable		65,889		61,142
Fuel				22,459		22,085
Materials and Supplies				52,908		52,183
Risk Management Assets				484		509
Deferred Income Tax Benefits				2,459		7,183
Accrued Tax Benefits				21,358		11,812
Regulatory Asset for Under-Recovered Fuel Costs				9,986		-
Prepayments and Other Current Assets				4,880		7,633
TOTAL CURRENT ASSETS				181,465		174,472

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			1,374,411		1,346,530
	Transmission			723,331		706,917
	Distribution			1,909,976		1,859,557
Other Property, Plant and Equipment				215,260		210,549
Construction Work in Progress				101,119		95,170
Total Property, Plant and Equipment				4,324,097		4,218,723
Accumulated Depreciation and Amortization				1,309,699		1,278,941
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				3,014,398		2,939,782

OTHER NONCURRENT ASSETS
Regulatory Assets				181,392		202,328
Long-term Risk Management Assets				-		31
Deferred Charges and Other Noncurrent Assets				27,927		8,560
TOTAL OTHER NONCURRENT ASSETS				209,319		210,919

TOTAL ASSETS			$	3,405,182	$	3,325,173

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

135

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2013 and December 31, 2012
(Unaudited)

		June 30,		December 31,
		2013		2012
			(in thousands)
CURRENT LIABILITIES
Advances from Affiliates		$	25,276	$	-
Accounts Payable:
	General		96,206		87,050
	Affiliated Companies		49,320		36,189
Long-term Debt Due Within One Year – Nonaffiliated			34,108		764
Risk Management Liabilities			2,111		5,848
Customer Deposits			46,223		46,533
Accrued Taxes			42,173		28,024
Accrued Interest			12,318		12,654
Regulatory Liability for Over-Recovered Fuel Costs			-		7,945
Other Current Liabilities			50,139		50,684
TOTAL CURRENT LIABILITIES			357,874		275,691

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			915,733		949,107
Long-term Risk Management Liabilities			2		31
Deferred Income Taxes			798,812		740,676
Regulatory Liabilities and Deferred Investment Tax Credits			329,359		344,817
Employee Benefits and Pension Obligations			34,853		34,906
Deferred Credits and Other Noncurrent Liabilities			38,067		63,667
TOTAL NONCURRENT LIABILITIES			2,116,826		2,133,204

TOTAL LIABILITIES			2,474,700		2,408,895


Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
	Authorized – 11,000,000 Shares
	Issued – 10,482,000 Shares
	Outstanding – 9,013,000 Shares		157,230		157,230
Paid-in Capital			364,037		364,037
Retained Earnings			403,155		388,530
Accumulated Other Comprehensive Income (Loss)			6,060		6,481
TOTAL COMMON SHAREHOLDER’S EQUITY			930,482		916,278

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	3,405,182	$	3,325,173

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

136

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

				Six Months Ended June 30,
				2013		2012
OPERATING ACTIVITIES
Net Income				$	42,125	$	47,859
Adjustments to Reconcile Net Income to Net Cash Flows from Operating
	Activities:
		Depreciation and Amortization			48,258		46,923
		Deferred Income Taxes			27,562		15,275
		Carrying Costs Income			(317)		(1,142)
		Allowance for Equity Funds Used During Construction			(1,824)		(890)
		Mark-to-Market of Risk Management Contracts			(3,779)		4,652
		Property Taxes			(20,353)		(19,347)
		Fuel Over/Under-Recovery, Net			(19,331)		76,098
		Change in Other Noncurrent Assets			10,999		1,043
		Change in Other Noncurrent Liabilities			(10,740)		(5,409)
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		(4,747)		2,560
			Fuel, Materials and Supplies		(1,099)		2,481
			Accounts Payable		21,581		(3,263)
			Accrued Taxes, Net		13,052		32,771
			Other Current Assets		2,257		919
			Other Current Liabilities		(7,298)		(3,987)
Net Cash Flows from Operating Activities					96,346		196,543

INVESTING ACTIVITIES
Construction Expenditures					(112,864)		(102,354)
Change in Advances to Affiliates, Net					10,558		(80,548)
Other Investing Activities					9,090		413
Net Cash Flows Used for Investing Activities					(93,216)		(182,489)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated					-		2,395
Change in Advances from Affiliates, Net					25,276		-
Retirement of Long-term Debt – Nonaffiliated					(200)		(32)
Principal Payments for Capital Lease Obligations					(1,586)		(1,704)
Dividends Paid on Common Stock					(27,500)		(15,000)
Other Financing Activities					555		107
Net Cash Flows Used for Financing Activities					(3,455)		(14,234)

Net Decrease in Cash and Cash Equivalents					(325)		(180)
Cash and Cash Equivalents at Beginning of Period					1,367		1,413
Cash and Cash Equivalents at End of Period				$	1,042	$	1,233

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	26,155	$	26,581
Net Cash Paid for Income Taxes					6,295		5,992
Noncash Acquisitions Under Capital Leases					5,594		759
Construction Expenditures Included in Current Liabilities as of June 30,					26,812		14,881
Cash Dividends Declared but Not Paid					-		15,000

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

137

PUBLIC SERVICE COMPANY OF OKLAHOMA

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

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

	Page
	Number

Significant Accounting Matters	154
Comprehensive Income	154
Rate Matters	168
Commitments, Guarantees and Contingencies	178
Benefit Plans	183
Business Segments	185
Derivatives and Hedging	186
Fair Value Measurements	199
Income Taxes	211
Financing Activities	212
Variable Interest Entities	216
Sustainable Cost Reductions	219

138

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

139

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Regulatory Activity

Turk Plant

2012 Texas Base Rate Case

In December 2012, several intervenors filed opposing testimony and in May 2013, the ALJ issued a proposal for decision (PFD) and added clarifications to the PFD in July 2013. The PFD, as clarified, made various recommendations including (a) an annual base rate increase of approximately $41 million based upon a return on common equity of 9.65%, (b) the disallowance of the Turk Plant capital costs in excess of the investment and committed costs as of June 2010 plus the cost to retrofit Welsh Plant, Unit 2 which, as of June 30, 2013, SWEPCo estimates could result in a write-off of approximately $74 million (in excess of the $62 million reserve previously recorded related to the Texas capital cost cap) and (c) the exclusion, until SWEPCo’s next Texas base rate case, of the Turk Plant transmission line investment that was not in service at the end of the test year. A decision from the PUCT is expected in the third quarter of 2013. If the PUCT does not approve full cost recovery of SWEPCo’s assets, it could reduce future net income and cash flows and impact financial condition. See “2012 Texas Base Rate Case” section of Note 3.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant. In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover all non-fuel Turk Plant costs and a full weighted-average cost of capital return on the Turk Plant portion of rate base, effective January 2013. In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant. If the LPSC orders refunds based upon the pending staff review of the cost of service or prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition. See “2012 Louisiana Formula Rate Filing” section of Note 3.

140

Flint Creek Plant Environmental Controls

Litigation and Environmental Issues

In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 2 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the 2012 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 153. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2013		2012		2013		2012
			(in millions of KWhs)
Retail:
	Residential			1,446		1,570		2,940		2,952
	Commercial			1,556		1,643		2,835		2,954
	Industrial			1,465		1,513		2,724		2,831
	Miscellaneous			22		21		41		41
Total Retail (a)				4,489		4,747		8,540		8,778

Wholesale				2,131		1,607		4,574		3,879

Total KWhs				6,620		6,354		13,114		12,657

(a)		Represents energy delivered to distribution customers.

141

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

Summary of Heating and Cooling Degree Days

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
		(in degree days)
Actual - Heating (a)			68		4		800		427
Normal - Heating (b)			25		27		753		773

Actual - Cooling (c)			703		910		719		1,024
Normal - Cooling (b)			725		710		758		740

(a)	Western Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Western Region cooling degree days are calculated on a 65 degree temperature base.

142

Second Quarter of 2013 Compared to Second Quarter of 2012

	Reconciliation of Second Quarter of 2012 to Second Quarter of 2013
	Net Income
	(in millions)

	Second Quarter of 2012		$	55

	Changes in Gross Margin:
	Retail Margins (a)			6
	Off-system Sales			1
	Transmission Revenues			6
	Total Change in Gross Margin			13

	Changes in Expenses and Other:
	Other Operation and Maintenance			(9)
	Asset Impairments and Other Related Charges			13
	Depreciation and Amortization			(11)
	Taxes Other Than Income Taxes			(2)
	Allowance for Equity Funds Used During Construction			(13)
	Interest Expense			(12)
	Total Change in Expenses and Other			(34)

	Income Tax Expense			(4)

	Second Quarter of 2013		$	30

	(a)	Includes firm wholesale sales to municipals and cooperatives.

·	Retail Margins increased $6 million primarily due to the following:
	·	A $24 million increase primarily due to the Louisiana formula rate order related to the Turk Plant.
	This increase was partially offset by:
	·	A $12 million decrease due to fuel cost adjustments.
	·	An $8 million decrease in weather-related usage primarily due to a 23% decrease in cooling degree days.
·	Transmission Revenues increased $6 million primarily due rate increases for customers in the SPP region.

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

·	Other Operation and Maintenance expenses increased $9 million primarily due to the following:
	·	A $5 million increase in transmission expenses primarily due to increased SPP transmission services.
	·	A $3 million increase in generation plant operation and maintenance expenses primarily due to Turk Plant operations in addition to higher planned and unplanned plant outages.
·	Asset Impairments and Other Related Charges decreased $13 million due to the second quarter 2012 write-off of the expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap.
·	Depreciation and Amortization expenses increased $11 million primarily due to the Turk Plant being placed in service in December 2012.
·	Taxes Other Than Income Taxes increased $2 million primarily due to higher property taxes related to the Turk Plant being placed in service in December 2012.
·	Allowance for Equity Funds Used During Construction decreased $13 million primarily due to completed construction of the Turk Plant in December 2012.
·	Interest Expense increased $12 million primarily due to a decrease in the debt component of AFUDC due to completed construction of the Turk Plant in December 2012.
·	Income Tax Expense increased $4 million primarily due to other book/tax differences which are accounted for on a flow-through basis and the regulatory accounting treatment of state income taxes, partially offset by a decrease in pretax book income.

143

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

	Reconciliation of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2013
	Net Income
	(in millions)

		Six Months Ended June 30, 2012		$	91

		Changes in Gross Margin:
		Retail Margins (a)			26
		Off-system Sales			2
		Transmission Revenues			8
		Other Revenues			1
		Total Change in Gross Margin			37

		Changes in Expenses and Other:
		Other Operation and Maintenance			(23)
		Asset Impairments and Other Related Charges			13
		Depreciation and Amortization			(22)
		Taxes Other Than Income Taxes			(5)
		Interest Income			(1)
		Allowance for Equity Funds Used During Construction			(26)
		Interest Expense			(24)
		Total Change in Expenses and Other			(88)

		Income Tax Expense			2

		Six Months Ended June 30, 2013		$	42

		(a)	Includes firm wholesale sales to municipals and cooperatives.

·	Retail Margins increased $26 million primarily due to the following:
	·	A $47 million increase primarily due to the Louisiana formula rate order related to the Turk Plant.
	This increase was partially offset by:
	·	A $10 million decrease in municipal and cooperative revenues due to formula rate adjustments.
	·	A $6 million decrease in weather-related usage primarily due to a 30% decrease in cooling degree days.
	·	A $5 million decrease due to fuel cost adjustments.
·	Transmission Revenues increased $8 million primarily due to rate increases for customers in the SPP region.

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

·	Other Operation and Maintenance expenses increased $23 million primarily due to the following:
	·	A $9 million increase in generation plant operation and maintenance expenses primarily due to Turk Plant operations in addition to higher planned and unplanned plant outages.
	·	An $8 million increase in transmission expenses primarily due to increased SPP transmission services.
	·	A $2 million increase in distribution maintenance expenses primarily due to storm-related expenses.
·	Asset Impairments and Other Related Charges decreased $13 million due to the second quarter 2012 write-off of the expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap.
·	Depreciation and Amortization expenses increased $22 million primarily due to the Turk Plant being placed in service in December 2012.
·	Taxes Other Than Income Taxes increased $5 million primarily due to higher property taxes related to the Turk Plant being placed in service in December 2012.

144

	·	Allowance for Equity Funds Used During Construction decreased $26 million primarily due to completed construction of the Turk Plant in December 2012.
	·	Interest Expense increased $24 million primarily due to a decrease in the debt component of AFUDC due to completed construction of the Turk Plant in December 2012.
	·	Income Tax Expense decreased $2 million primarily due to a decrease in pretax book income, partially offset by other book/tax differences which are accounted for on a flow-through basis and the regulatory accounting treatment of state income taxes.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

145

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
REVENUES
Electric Generation, Transmission and Distribution		$	408,852	$	383,659	$	790,129	$	723,362
Sales to AEP Affiliates			10,930		6,890		23,639		15,847
Other Revenues			391		397		722		723
TOTAL REVENUES			420,173		390,946		814,490		739,932

EXPENSES
Fuel and Other Consumables Used for Electric Generation			137,065		138,008		288,423		266,242
Purchased Electricity for Resale			43,008		26,574		82,768		62,041
Purchased Electricity from AEP Affiliates			4,925		4,589		5,942		10,844
Other Operation			60,795		54,067		120,243		105,660
Maintenance			32,280		29,757		60,071		51,019
Asset Impairments and Other Related Charges			-		13,000		-		13,000
Depreciation and Amortization			45,732		34,655		90,614		68,676
Taxes Other Than Income Taxes			19,336		17,320		38,758		34,106
TOTAL EXPENSES			343,141		317,970		686,819		611,588

OPERATING INCOME			77,032		72,976		127,671		128,344

Other Income (Expense):
Interest Income			169		11		199		1,132
Allowance for Equity Funds Used During Construction			1,368		14,412		2,392		28,185
Interest Expense			(33,547)		(21,710)		(67,537)		(43,712)

INCOME BEFORE INCOME TAX EXPENSE AND
	EQUITY EARNINGS		45,022		65,689		62,725		113,949

Income Tax Expense			15,326		11,505		22,122		23,977
Equity Earnings of Unconsolidated Subsidiary			531		718		1,172		1,325

NET INCOME			30,227		54,902		41,775		91,297

Net Income Attributable to Noncontrolling Interest			1,056		1,061		2,146		2,144

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON
	SHAREHOLDER	$	29,171	$	53,841	$	39,629	$	89,153

The common stock of SWEPCo is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

146

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
Net Income		$	30,227	$	54,902	$	41,775	$	91,297

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $264 and $213 for the Three Months Ended
	June 30, 2013 and 2012, Respectively, and $585 and $743 for the
	Six Months Ended June 30, 2013 and 2012, Respectively		490		396		1,086		(1,379)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $34
	and $90 for the Three Months Ended June 30, 2013 and 2012,
	Respectively, and $68 and $179 for the Six Months Ended June 30,
	2013 and 2012, Respectively		(64)		167		(127)		332

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			426		563		959		(1,047)

TOTAL COMPREHENSIVE INCOME			30,653		55,465		42,734		90,250

Total Comprehensive Income Attributable to Noncontrolling Interest			1,056		1,061		2,146		2,144

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo
	COMMON SHAREHOLDER	$	29,597	$	54,404	$	40,588	$	88,106

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

147

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

	SWEPCo Common Shareholder
							Accumulated
							Other
	Common		Paid-in		Retained		Comprehensive		Noncontrolling
	Stock		Capital		Earnings		Income (Loss)		Interest		Total

TOTAL EQUITY – DECEMBER 31, 2011	$	135,660	$	674,606	$	1,029,915	$	(26,815)	$	391	$	1,813,757

Common Stock Dividends – Nonaffiliated										(2,195)		(2,195)
Net Income						89,153				2,144		91,297
Other Comprehensive Loss								(1,047)				(1,047)
TOTAL EQUITY – JUNE 30, 2012	$	135,660	$	674,606	$	1,119,068	$	(27,862)	$	340	$	1,901,812

TOTAL EQUITY – DECEMBER 31, 2012	$	135,660	$	674,606	$	1,228,806	$	(17,860)	$	261	$	2,021,473

Common Stock Dividends						(62,500)						(62,500)
Common Stock Dividends – Nonaffiliated										(2,040)		(2,040)
Net Income						39,629				2,146		41,775
Other Comprehensive Income								959				959
TOTAL EQUITY – JUNE 30, 2013	$	135,660	$	674,606	$	1,205,935	$	(16,901)	$	367	$	1,999,667

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

148

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2013 and December 31, 2012
(in thousands)
(Unaudited)

			June 30,		December 31,
			2013		2012
CURRENT ASSETS
Cash and Cash Equivalents			$	11,840	$	2,036
Advances to Affiliates				14,806		153,829
Accounts Receivable:
	Customers			42,443		39,349
	Affiliated Companies			30,602		26,288
	Miscellaneous			20,958		35,514
	Allowance for Uncollectible Accounts			(2,045)		(2,041)
		Total Accounts Receivable		91,958		99,110
Fuel
	(June 30, 2013 and December 31, 2012 Amounts Include $36,893 and
	$42,084, Respectively, Related to Sabine)			137,238		134,234
Materials and Supplies				72,660		69,212
Risk Management Assets				398		695
Deferred Income Tax Benefits				104,894		101,403
Accrued Tax Benefits				30,801		9,616
Regulatory Asset for Under-Recovered Fuel Costs				14,210		8,527
Prepayments and Other Current Assets				12,795		16,489
TOTAL CURRENT ASSETS				491,600		595,151

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			3,919,327		3,888,230
	Transmission			1,140,451		1,115,795
	Distribution			1,794,684		1,758,988
Other Property, Plant and Equipment
	(June 30, 2013 and December 31, 2012 Amounts Include $288,776 and
	$287,032, Respectively, Related to Sabine)			695,944		688,254
Construction Work in Progress				153,715		99,783
Total Property, Plant and Equipment				7,704,121		7,551,050
Accumulated Depreciation and Amortization
	(June 30, 2013 and December 31, 2012 Amounts Include $125,834 and
	$116,597, Respectively, Related to Sabine)			2,353,562		2,284,258
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				5,350,559		5,266,792

OTHER NONCURRENT ASSETS
Regulatory Assets				407,408		403,278
Deferred Charges and Other Noncurrent Assets				100,880		76,432
TOTAL OTHER NONCURRENT ASSETS				508,288		479,710

TOTAL ASSETS			$	6,350,447	$	6,341,653

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

149

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2013 and December 31, 2012
(Unaudited)

		June 30,		December 31,
		2013		2012
			(in thousands)
CURRENT LIABILITIES
Accounts Payable:
	General	$	107,438	$	126,768
	Affiliated Companies		64,553		62,835
Short-term Debt – Nonaffiliated			-		2,603
Long-term Debt Due Within One Year – Nonaffiliated			3,250		3,250
Risk Management Liabilities			941		1,128
Customer Deposits			55,658		69,393
Accrued Taxes			63,796		31,532
Accrued Interest			43,335		43,950
Obligations Under Capital Leases			17,978		17,599
Regulatory Liability for Over-Recovered Fuel Costs			5,102		16,761
Other Current Liabilities			66,388		64,997
TOTAL CURRENT LIABILITIES			428,439		440,816

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			2,041,530		2,042,978
Long-term Risk Management Liabilities			3		-
Deferred Income Taxes			1,122,609		1,075,551
Regulatory Liabilities and Deferred Investment Tax Credits			472,434		476,471
Asset Retirement Obligations			86,998		78,017
Employee Benefits and Pension Obligations			41,795		38,240
Obligations Under Capital Leases			107,728		114,161
Deferred Credits and Other Noncurrent Liabilities			49,244		53,946
TOTAL NONCURRENT LIABILITIES			3,922,341		3,879,364

TOTAL LIABILITIES			4,350,780		4,320,180

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

EQUITY
Common Stock – Par Value – $18 Per Share:
	Authorized – 7,600,000 Shares
	Outstanding – 7,536,640 Shares		135,660		135,660
Paid-in Capital			674,606		674,606
Retained Earnings			1,205,935		1,228,806
Accumulated Other Comprehensive Income (Loss)			(16,901)		(17,860)
TOTAL COMMON SHAREHOLDER’S EQUITY			1,999,300		2,021,212

Noncontrolling Interest			367		261

TOTAL EQUITY			1,999,667		2,021,473

TOTAL LIABILITIES AND EQUITY		$	6,350,447	$	6,341,653

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

150

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2013 and 2012
(in thousands)
(Unaudited)

				Six Months Ended June 30,
				2013		2012
OPERATING ACTIVITIES
Net Income				$	41,775	$	91,297
Adjustments to Reconcile Net Income to Net Cash Flows from
	Operating Activities:
		Depreciation and Amortization			90,614		68,676
		Deferred Income Taxes			39,624		138,594
		Asset Impairments and Other Related Charges			-		13,000
		Allowance for Equity Funds Used During Construction			(2,392)		(28,185)
		Mark-to-Market of Risk Management Contracts			35		1,927
		Property Taxes			(23,607)		(19,790)
		Fuel Over/Under-Recovery, Net			(17,350)		(4,398)
		Change in Other Noncurrent Assets			(3,639)		1,678
		Change in Other Noncurrent Liabilities			5,647		17,707
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		6,979		(12,989)
			Fuel, Materials and Supplies		(6,452)		(16,901)
			Accounts Payable		1,277		2,938
			Accrued Taxes, Net		11,079		(40,616)
			Other Current Assets		3,541		(7,685)
			Other Current Liabilities		(12,121)		(6,367)
Net Cash Flows from Operating Activities					135,010		198,886

INVESTING ACTIVITIES
Construction Expenditures					(187,607)		(246,957)
Change in Advances to Affiliates, Net					139,023		(97,022)
Other Investing Activities					342		(1,927)
Net Cash Flows Used for Investing Activities					(48,242)		(345,906)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated					-		336,576
Credit Facility Borrowings					17,091		21,462
Change in Advances from Affiliates, Net					-		(132,473)
Retirement of Long-term Debt – Nonaffiliated					(1,625)		(20,000)
Credit Facility Repayments					(19,694)		(38,478)
Principal Payments for Capital Lease Obligations					(8,877)		(7,899)
Dividends Paid on Common Stock					(62,500)		-
Dividends Paid on Common Stock – Nonaffiliated					(2,040)		(2,195)
Other Financing Activities					681		3,843
Net Cash Flows from (Used for) Financing Activities					(76,964)		160,836

Net Increase in Cash and Cash Equivalents					9,804		13,816
Cash and Cash Equivalents at Beginning of Period					2,036		801
Cash and Cash Equivalents at End of Period				$	11,840	$	14,617

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	61,663	$	32,595
Net Cash Paid (Received) for Income Taxes					1,161		(47,741)
Noncash Acquisitions Under Capital Leases					2,851		12,350
Construction Expenditures Included in Current Liabilities as of June 30,					35,940		79,960

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 153.

151

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

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

	Page
	Number

Significant Accounting Matters	154
Comprehensive Income	154
Rate Matters	168
Commitments, Guarantees and Contingencies	178
Benefit Plans	183
Business Segments	185
Derivatives and Hedging	186
Fair Value Measurements	199
Income Taxes	211
Financing Activities	212
Variable Interest Entities	216
Sustainable Cost Reductions	219

152

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to condensed financial statements that follow are a combined presentation for the Registrant Subsidiaries. The following list indicates the registrants to which the footnotes apply:

		Page
		Number

Significant Accounting Matters	APCo, I&M, OPCo, PSO, SWEPCo	154
Comprehensive Income	APCo, I&M, OPCo, PSO, SWEPCo	154
Rate Matters	APCo, I&M, OPCo, PSO, SWEPCo	168
Commitments, Guarantees and Contingencies	APCo, I&M, OPCo, PSO, SWEPCo	178
Disposition and Impairment	OPCo	182
Benefit Plans	APCo, I&M, OPCo, PSO, SWEPCo	183
Business Segments	APCo, I&M, OPCo, PSO, SWEPCo	185
Derivatives and Hedging	APCo, I&M, OPCo, PSO, SWEPCo	186
Fair Value Measurements	APCo, I&M, OPCo, PSO, SWEPCo	199
Income Taxes	APCo, I&M, OPCo, PSO, SWEPCo	211
Financing Activities	APCo, I&M, OPCo, PSO, SWEPCo	212
Variable Interest Entities	APCo, I&M, OPCo, PSO, SWEPCo	216
Sustainable Cost Reductions	APCo, I&M, OPCo, PSO, SWEPCo	219

153

1. SIGNIFICANT ACCOUNTING MATTERS

General

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

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and six months ended June 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013. The condensed financial statements are unaudited and should be read in conjunction with the audited 2012 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2012 as filed with the SEC on February 26, 2013.

2. COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI for the three and six months ended June 30, 2013. All amounts in the following tables are presented net of related income taxes.

APCo
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended June 30, 2013

			Cash Flow Hedges
					Interest Rate and		Pension
			Commodity		Foreign Currency		and OPEB		Total
			(in thousands)
	Balance in AOCI as of March 31, 2013		$	361	$	2,330	$	(30,973)	$	(28,282)
	Change in Fair Value Recognized in AOCI			(63)		1		-		(62)
	Amounts Reclassified from AOCI			(101)		252		358		509
	Net Current Period Other
		Comprehensive Income		(164)		253		358		447
	Balance in AOCI as of June 30, 2013		$	197	$	2,583	$	(30,615)	$	(27,835)

APCo
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Six Months Ended June 30, 2013

			Cash Flow Hedges
					Interest Rate and		Pension
			Commodity		Foreign Currency		and OPEB		Total
			(in thousands)
	Balance in AOCI as of December 31, 2012		$	(644)	$	2,077	$	(31,331)	$	(29,898)
	Change in Fair Value Recognized in AOCI			731		-		-		731
	Amounts Reclassified from AOCI			110		506		716		1,332
	Net Current Period Other
		Comprehensive Income		841		506		716		2,063
	Balance in AOCI as of June 30, 2013		$	197	$	2,583	$	(30,615)	$	(27,835)

154

I&M
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended June 30, 2013

			Cash Flow Hedges
					Interest Rate and		Pension
			Commodity		Foreign Currency		and OPEB		Total
			(in thousands)
	Balance in AOCI as of March 31, 2013		$	236	$	(17,206)	$	(8,614)	$	(25,584)
	Change in Fair Value Recognized in AOCI			(40)		(1)		-		(41)
	Amounts Reclassified from AOCI			(49)		411		175		537
	Net Current Period Other
		Comprehensive Income		(89)		410		175		496
	Balance in AOCI as of June 30, 2013		$	147	$	(16,796)	$	(8,439)	$	(25,088)

I&M
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Six Months Ended June 30, 2013

			Cash Flow Hedges
					Interest Rate and		Pension
			Commodity		Foreign Currency		and OPEB		Total
			(in thousands)
	Balance in AOCI as of December 31, 2012		$	(446)	$	(19,647)	$	(8,790)	$	(28,883)
	Change in Fair Value Recognized in AOCI			492		2,248		-		2,740
	Amounts Reclassified from AOCI			101		603		351		1,055
	Net Current Period Other
		Comprehensive Income		593		2,851		351		3,795
	Balance in AOCI as of June 30, 2013		$	147	$	(16,796)	$	(8,439)	$	(25,088)

OPCo
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended June 30, 2013

			Cash Flow Hedges
					Interest Rate and		Pension
			Commodity		Foreign Currency		and OPEB		Total
			(in thousands)
	Balance in AOCI as of March 31, 2013		$	494	$	7,755	$	(169,639)	$	(161,390)
	Change in Fair Value Recognized in AOCI			(109)		-		-		(109)
	Amounts Reclassified from AOCI			(96)		(340)		3,270		2,834
	Net Current Period Other
		Comprehensive Income		(205)		(340)		3,270		2,725
	Balance in AOCI as of June 30, 2013		$	289	$	7,415	$	(166,369)	$	(158,665)

OPCo
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Six Months Ended June 30, 2013

			Cash Flow Hedges
					Interest Rate and		Pension
			Commodity		Foreign Currency		and OPEB		Total
			(in thousands)
	Balance in AOCI as of December 31, 2012		$	(912)	$	8,095	$	(172,908)	$	(165,725)
	Change in Fair Value Recognized in AOCI			993		-		-		993
	Amounts Reclassified from AOCI			208		(680)		6,539		6,067
	Net Current Period Other
		Comprehensive Income		1,201		(680)		6,539		7,060
	Balance in AOCI as of June 30, 2013		$	289	$	7,415	$	(166,369)	$	(158,665)

155

PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended June 30, 2013

		Cash Flow Hedges
				Interest Rate and
		Commodity		Foreign Currency		Total
		(in thousands)
Balance in AOCI as of March 31, 2013		$	44	$	6,270	$	6,314
Change in Fair Value Recognized in AOCI			(61)		1		(60)
Amounts Reclassified from AOCI			(4)		(190)		(194)
Net Current Period Other
	Comprehensive Income		(65)		(189)		(254)
Balance in AOCI as of June 30, 2013		$	(21)	$	6,081	$	6,060

PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Six Months Ended June 30, 2013

		Cash Flow Hedges
				Interest Rate and
		Commodity		Foreign Currency		Total
		(in thousands)
Balance in AOCI as of December 31, 2012		$	21	$	6,460	$	6,481
Change in Fair Value Recognized in AOCI			(25)		1		(24)
Amounts Reclassified from AOCI			(17)		(380)		(397)
Net Current Period Other
	Comprehensive Income		(42)		(379)		(421)
Balance in AOCI as of June 30, 2013		$	(21)	$	6,081	$	6,060

SWEPCo
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended June 30, 2013

			Cash Flow Hedges
					Interest Rate and		Pension
			Commodity		Foreign Currency		and OPEB		Total
			(in thousands)
	Balance in AOCI as of March 31, 2013		$	51	$	(15,004)	$	(2,374)	$	(17,327)
	Change in Fair Value Recognized in AOCI			(71)		-		-		(71)
	Amounts Reclassified from AOCI			(6)		567		(64)		497
	Net Current Period Other
		Comprehensive Income		(77)		567		(64)		426
	Balance in AOCI as of June 30, 2013		$	(26)	$	(14,437)	$	(2,438)	$	(16,901)

SWEPCo
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Six Months Ended June 30, 2013

			Cash Flow Hedges
					Interest Rate and		Pension
			Commodity		Foreign Currency		and OPEB		Total
			(in thousands)
	Balance in AOCI as of December 31, 2012		$	22	$	(15,571)	$	(2,311)	$	(17,860)
	Change in Fair Value Recognized in AOCI			(27)		-		-		(27)
	Amounts Reclassified from AOCI			(21)		1,134		(127)		986
	Net Current Period Other
		Comprehensive Income		(48)		1,134		(127)		959
	Balance in AOCI as of June 30, 2013		$	(26)	$	(14,437)	$	(2,438)	$	(16,901)

156

Reclassifications Out of Accumulated Other Comprehensive Income

APCo
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Three Months Ended June 30, 2013

			Amount of
			(Gain) Loss
			Reclassified
			from AOCI
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Electric Generation, Transmission and Distribution Revenues	$	2
		Purchased Electricity for Resale		(31)
		Other Operation Expense		(13)
		Maintenance Expense		(2)
		Property, Plant and Equipment		(5)
		Regulatory Assets (a)		(108)
	Subtotal - Commodity			(157)

	Interest Rate and Foreign Currency:
		Interest Expense		389
	Subtotal - Interest Rate and Foreign Currency			389

	Reclassifications from AOCI, before Income Tax (Expense) Credit			232
	Income Tax (Expense) Credit			81
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			151

	Amortization of Pension and OPEB
	Prior Service Cost (Credit)			(1,283)
	Actuarial (Gains)/Losses			1,834
	Reclassifications from AOCI, before Income Tax (Expense) Credit			551
	Income Tax (Expense) Credit			193
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			358

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	509

157

APCo
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Six Months Ended June 30, 2013

			Amount of
			(Gain) Loss
			Reclassified
			from AOCI
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Electric Generation, Transmission and Distribution Revenues	$	22
		Purchased Electricity for Resale		26
		Other Operation Expense		(24)
		Maintenance Expense		(18)
		Property, Plant and Equipment		(19)
		Regulatory Assets (a)		181
	Subtotal - Commodity			168

	Interest Rate and Foreign Currency:
		Interest Expense		779
	Subtotal - Interest Rate and Foreign Currency			779

	Reclassifications from AOCI, before Income Tax (Expense) Credit			947
	Income Tax (Expense) Credit			331
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			616

	Amortization of Pension and OPEB
	Prior Service Cost (Credit)			(2,565)
	Actuarial (Gains)/Losses			3,667
	Reclassifications from AOCI, before Income Tax (Expense) Credit			1,102
	Income Tax (Expense) Credit			386
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			716

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	1,332

158

I&M
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Three Months Ended June 30, 2013

			Amount of
			(Gain) Loss
			Reclassified
			from AOCI
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Electric Generation, Transmission and Distribution Revenues	$	32
		Purchased Electricity for Resale		(81)
		Other Operation Expense		(8)
		Maintenance Expense		(2)
		Property, Plant and Equipment		(3)
		Regulatory Assets (a)		(12)
	Subtotal - Commodity			(74)

	Interest Rate and Foreign Currency:
		Interest Expense		631
	Subtotal - Interest Rate and Foreign Currency			631

	Reclassifications from AOCI, before Income Tax (Expense) Credit			557
	Income Tax (Expense) Credit			195
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			362

	Amortization of Pension and OPEB
	Prior Service Cost (Credit)			(198)
	Actuarial (Gains)/Losses			468
	Reclassifications from AOCI, before Income Tax (Expense) Credit			270
	Income Tax (Expense) Credit			95
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			175

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	537

159

I&M
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Six Months Ended June 30, 2013

			Amount of
			(Gain) Loss
			Reclassified
			from AOCI
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Electric Generation, Transmission and Distribution Revenues	$	84
		Purchased Electricity for Resale		68
		Other Operation Expense		(15)
		Maintenance Expense		(9)
		Property, Plant and Equipment		(10)
		Regulatory Assets (a)		38
	Subtotal - Commodity			156

	Interest Rate and Foreign Currency:
		Interest Expense		927
	Subtotal - Interest Rate and Foreign Currency			927

	Reclassifications from AOCI, before Income Tax (Expense) Credit			1,083
	Income Tax (Expense) Credit			379
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			704

	Amortization of Pension and OPEB
	Prior Service Cost (Credit)			(397)
	Actuarial (Gains)/Losses			937
	Reclassifications from AOCI, before Income Tax (Expense) Credit			540
	Income Tax (Expense) Credit			189
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			351

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	1,055

160

OPCo
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Three Months Ended June 30, 2013

			Amount of
			(Gain) Loss
			Reclassified
			from AOCI
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Electric Generation, Transmission and Distribution Revenues	$	81
		Purchased Electricity for Resale		(202)
		Other Operation Expense		(19)
		Maintenance Expense		(3)
		Property, Plant and Equipment		(4)
	Subtotal - Commodity			(147)

	Interest Rate and Foreign Currency:
		Depreciation and Amortization Expense		1
		Interest Expense		(525)
	Subtotal - Interest Rate and Foreign Currency			(524)

	Reclassifications from AOCI, before Income Tax (Expense) Credit			(671)
	Income Tax (Expense) Credit			(235)
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			(436)

	Amortization of Pension and OPEB
	Prior Service Cost (Credit)			(1,469)
	Actuarial (Gains)/Losses			6,499
	Reclassifications from AOCI, before Income Tax (Expense) Credit			5,030
	Income Tax (Expense) Credit			1,760
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			3,270

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	2,834

161

OPCo
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Six Months Ended June 30, 2013

			Amount of
			(Gain) Loss
			Reclassified
			from AOCI
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Electric Generation, Transmission and Distribution Revenues	$	215
		Purchased Electricity for Resale		180
		Other Operation Expense		(37)
		Maintenance Expense		(15)
		Property, Plant and Equipment		(23)
	Subtotal - Commodity			320

	Interest Rate and Foreign Currency:
		Depreciation and Amortization Expense		3
		Interest Expense		(1,049)
	Subtotal - Interest Rate and Foreign Currency			(1,046)

	Reclassifications from AOCI, before Income Tax (Expense) Credit			(726)
	Income Tax (Expense) Credit			(254)
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			(472)

	Amortization of Pension and OPEB
	Prior Service Cost (Credit)			(2,937)
	Actuarial (Gains)/Losses			12,996
	Reclassifications from AOCI, before Income Tax (Expense) Credit			10,059
	Income Tax (Expense) Credit			3,520
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			6,539

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	6,067

162

PSO
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Three Months Ended June 30, 2013

			Amount of
			(Gain) Loss
			Reclassified
			from AOCI
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Other Operation Expense	$	(6)
		Maintenance Expense		-
		Property, Plant and Equipment		-
	Subtotal - Commodity			(6)

	Interest Rate and Foreign Currency:
		Interest Expense		(292)
	Subtotal - Interest Rate and Foreign Currency			(292)

	Reclassifications from AOCI, before Income Tax (Expense) Credit			(298)
	Income Tax (Expense) Credit			(104)
	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	(194)

PSO
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Six Months Ended June 30, 2013

			Amount of
			(Gain) Loss
			Reclassified
			from AOCI
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Other Operation Expense	$	(15)
		Maintenance Expense		(4)
		Property, Plant and Equipment		(7)
	Subtotal - Commodity			(26)

	Interest Rate and Foreign Currency:
		Interest Expense		(584)
	Subtotal - Interest Rate and Foreign Currency			(584)

	Reclassifications from AOCI, before Income Tax (Expense) Credit			(610)
	Income Tax (Expense) Credit			(213)
	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	(397)

163

SWEPCo
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Three Months Ended June 30, 2013

			Amount of
			(Gain) Loss
			Reclassified
			from AOCI
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Other Operation Expense	$	(6)
		Maintenance Expense		(1)
		Property, Plant and Equipment		(1)
	Subtotal - Commodity			(8)

	Interest Rate and Foreign Currency:
		Interest Expense		872
	Subtotal - Interest Rate and Foreign Currency			872

	Reclassifications from AOCI, before Income Tax (Expense) Credit			864
	Income Tax (Expense) Credit			303
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			561

	Amortization of Pension and OPEB
	Prior Service Cost (Credit)			(447)
	Actuarial (Gains)/Losses			348
	Reclassifications from AOCI, before Income Tax (Expense) Credit			(99)
	Income Tax (Expense) Credit			(35)
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			(64)

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	497

164

SWEPCo
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Six Months Ended June 30, 2013

			Amount of
			(Gain) Loss
			Reclassified
			from AOCI
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Other Operation Expense	$	(16)
		Maintenance Expense		(7)
		Property, Plant and Equipment		(8)
	Subtotal - Commodity			(31)

	Interest Rate and Foreign Currency:
		Interest Expense		1,744
	Subtotal - Interest Rate and Foreign Currency			1,744

	Reclassifications from AOCI, before Income Tax (Expense) Credit			1,713
	Income Tax (Expense) Credit			600
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			1,113

	Amortization of Pension and OPEB
	Prior Service Cost (Credit)			(892)
	Actuarial (Gains)/Losses			696
	Reclassifications from AOCI, before Income Tax (Expense) Credit			(196)
	Income Tax (Expense) Credit			(69)
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			(127)

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	986

(a)

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

165

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2012

Commodity Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2012				$	(2,117)	$	(1,508)	$	(3,149)	$	67	$	66
Changes in Fair Value Recognized in AOCI					(403)		(234)		(525)		(155)		(149)
Amount of (Gain) or Loss Reclassified
	from AOCI to Statement of Income/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(3)		(9)		(24)		-		-
		Purchased Electricity for Resale			157		419		1,099		-		-
		Other Operation Expense			(14)		(8)		(19)		(9)		(7)
		Maintenance Expense			(6)		(3)		(8)		(2)		(2)
		Property, Plant and Equipment			(10)		(6)		(13)		(3)		(5)
		Regulatory Assets (a)			576		103		-		-		-
Balance in AOCI as of June 30, 2012				$	(1,820)	$	(1,246)	$	(2,639)	$	(102)	$	(97)

Interest Rate and
Foreign Currency Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2012				$	1,293	$	(11,320)	$	9,114	$	7,029	$	(17,365)
Changes in Fair Value Recognized in AOCI					-		(7,844)		-		-		(1)
Amount of (Gain) or Loss Reclassified
	from AOCI to Statement of Income/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		1		-		-
		Interest Expense			269		149		(341)		(190)		560
Balance in AOCI as of June 30, 2012				$	1,562	$	(19,015)	$	8,774	$	6,839	$	(16,806)

Total Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2012				$	(824)	$	(12,828)	$	5,965	$	7,096	$	(17,299)
Changes in Fair Value Recognized in AOCI					(403)		(8,078)		(525)		(155)		(150)
Amount of (Gain) or Loss Reclassified
	from AOCI to Statement of Income/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(3)		(9)		(24)		-		-
		Purchased Electricity for Resale			157		419		1,099		-		-
		Other Operation Expense			(14)		(8)		(19)		(9)		(7)
		Maintenance Expense			(6)		(3)		(8)		(2)		(2)
		Depreciation and Amortization
			Expense		-		-		1		-		-
		Interest Expense			269		149		(341)		(190)		560
		Property, Plant and Equipment			(10)		(6)		(13)		(3)		(5)
		Regulatory Assets (a)			576		103		-		-		-
Balance in AOCI as of June 30, 2012				$	(258)	$	(20,261)	$	6,135	$	6,737	$	(16,903)

166

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2012

Commodity Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2011				$	(1,309)	$	(819)	$	(1,748)	$	(69)	$	(62)
Changes in Fair Value Recognized in AOCI					(2,248)		(1,628)		(3,402)		(16)		(17)
Amount of (Gain) or Loss Reclassified
	from AOCI to Statement of Income/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(3)		(9)		(24)		-		-
		Purchased Electricity for Resale			376		986		2,585		-		-
		Other Operation Expense			(16)		(10)		(24)		(11)		(9)
		Maintenance Expense			(9)		(4)		(10)		(2)		(3)
		Property, Plant and Equipment			(12)		(7)		(16)		(4)		(6)
		Regulatory Assets (a)			1,401		245		-		-		-
Balance in AOCI as of June 30, 2012				$	(1,820)	$	(1,246)	$	(2,639)	$	(102)	$	(97)

Interest Rate and
Foreign Currency Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2011				$	1,024	$	(14,465)	$	9,454	$	7,218	$	(15,462)
Changes in Fair Value Recognized in AOCI					-		(4,848)		-		-		(2,777)
Amount of (Gain) or Loss Reclassified
	from AOCI to Statement of Income/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		2		-		-
		Interest Expense			538		298		(682)		(379)		1,433
Balance in AOCI as of June 30, 2012				$	1,562	$	(19,015)	$	8,774	$	6,839	$	(16,806)

Total Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2011				$	(285)	$	(15,284)	$	7,706	$	7,149	$	(15,524)
Changes in Fair Value Recognized in AOCI					(2,248)		(6,476)		(3,402)		(16)		(2,794)
Amount of (Gain) or Loss Reclassified
	from AOCI to Statement of Income/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(3)		(9)		(24)		-		-
		Purchased Electricity for Resale			376		986		2,585		-		-
		Other Operation Expense			(16)		(10)		(24)		(11)		(9)
		Maintenance Expense			(9)		(4)		(10)		(2)		(3)
		Depreciation and Amortization
			Expense		-		-		2		-		-
		Interest Expense			538		298		(682)		(379)		1,433
		Property, Plant and Equipment			(12)		(7)		(16)		(4)		(6)
		Regulatory Assets (a)			1,401		245		-		-		-
Balance in AOCI as of June 30, 2012				$	(258)	$	(20,261)	$	6,135	$	6,737	$	(16,903)

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

167

3. RATE MATTERS

As discussed in the 2012 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2012 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2013 and updates the 2012 Annual Report.

Regulatory Assets Not Yet Being Recovered

			APCo
			June 30,		December 31,
			2013		2012
Noncurrent Regulatory Assets			(in thousands)
Regulatory assets not yet being recovered pending future proceedings:

Regulatory Assets Currently Not Earning a Return
	Storm Related Costs		$	65,206	$	94,458
	Virginia Environmental Rate Adjustment Clause			28,777		29,320
	Mountaineer Carbon Capture and Storage
		Product Validation Facility		14,155		14,155
	Dresden Plant Operating Costs			8,760		8,758
	Deferred Wind Power Costs			-		5,143
	Transmission Agreement Phase-In			3,267		2,992
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility		1,287		1,287
	Other Regulatory Assets Not Yet Being Recovered			3,652		1,447
Total Regulatory Assets Not Yet Being Recovered			$	125,104	$	157,560

			I&M
			June 30,		December 31,
			2013		2012
Noncurrent Regulatory Assets			(in thousands)
Regulatory assets not yet being recovered pending future proceedings:

Regulatory Assets Currently Not Earning a Return
	Litigation Settlement		$	-	$	11,098
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility		-		1,380
	Under-Recovered Capacity Costs			10,792		-
	Other Regulatory Asset Not Yet Being Recovered			2,634		786
Total Regulatory Assets Not Yet Being Recovered			$	13,426	$	13,264

		OPCo
		June 30,		December 31,
		2013		2012
Noncurrent Regulatory Assets		(in thousands)
Regulatory assets not yet being recovered pending future proceedings:

Regulatory Assets Currently Earning a Return
	Economic Development Rider	$	13,533	$	13,213
Regulatory Assets Currently Not Earning a Return
	Storm Related Costs		58,512		61,828
	Ormet Delayed Payment Arrangement		20,000		5,453
	Other Regulatory Assets Not Yet Being Recovered		706		30
Total Regulatory Assets Not Yet Being Recovered		$	92,751	$	80,524

168

		PSO
		June 30,		December 31,
		2013		2012
Noncurrent Regulatory Assets		(in thousands)
Regulatory assets not yet being recovered pending future proceedings:

Regulatory Assets Currently Not Earning a Return
	Other Regulatory Assets Not Yet Being Recovered	$	803	$	423
Total Regulatory Assets Not Yet Being Recovered		$	803	$	423

			SWEPCo
			June 30,		December 31,
			2013		2012
Noncurrent Regulatory Assets			(in thousands)
Regulatory assets not yet being recovered pending future proceedings:

Regulatory Assets Currently Not Earning a Return
	Rate Case Expenses		$	7,234	$	4,517
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility		2,295		2,295
	Other Regulatory Assets Not Yet Being Recovered			2,373		2,188
Total Regulatory Assets Not Yet Being Recovered			$	11,902	$	9,000

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

OPCo Rate Matters

Ohio Electric Security Plan Filing

2009 – 2011 ESP

In October 2011, the PUCO issued an order in the remand proceeding. As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011. In February 2012, the Ohio Consumers’ Counsel and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance. As of June 30, 2013, OPCo’s net deferred fuel balance was $ 484 million, excluding unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending.

169

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order. Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings, which included off-system sales in the SEET calculation. In December 2011, the PUCO staff filed testimony that recommended a $23 million refund of 2010 earnings. OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO-ordered SEET refund. OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. The PUCO approved OPCo’s requests to file the SEET for 2011 and 2012 one month after the PUCO issues an order on the 2010 SEET. Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in 2012 for OPCo. Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo.

June 2012 – May 2015 ESP Including Capacity Charge

170

In June 2013, intervenors in the competitive bid process (CBP) docket filed recommendations that include prospective rate reductions for capacity and non-energy FAC issues. OPCo maintains that the August 2012 ESP order fixed OPCo’s non-energy generation rates through December 31, 2014 and ordered the application of a $188.88/MW day price for capacity for non-shopping customers effective January 1, 2015. However, intervenors maintained that OPCo’s non-energy generation rates should be reduced prior to January 1, 2015 to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned (10% prior to June 2014 and 60% for the period June 1, 2014 through December 31, 2014). An additional proposal to prospectively offset deferred capacity costs based upon the results of the energy-only auctions was not quantified and OPCo maintains that proposal should not be adopted in light of prior PUCO orders. Hearings related to the CBP were held at the PUCO in June and July 2013.

If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its deferred capacity costs, it could reduce future net income and cash flows and impact financial condition.

Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets at net book value to AEPGenCo. AEPGenCo will also assume the associated generation liabilities. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.

Storm Damage Recovery Rider (SDRR)

2009 Fuel Adjustment Clause Audit

171

2010 and 2011 Fuel Adjustment Clause Audits

Ormet Interim Arrangement

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

Special Rate Mechanism for Ormet

172

Ohio IGCC Plant

SWEPCo Rate Matters

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility. As of June 30, 2013, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital cost cap, SWEPCo has capitalized approximately $ 1.8 billion of expenditures, including AFUDC and capitalized interest of $328 million and related transmission costs of $ 118 million.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the SPP market.

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

2012 Texas Base Rate Case

173

2012 Louisiana Formula Rate Filing

Flint Creek Plant Environmental Controls

APCo Rate Matters

Plant Transfers

174

of a RFP for any additional capacity and energy requirements and limiting the liabilities to the types and amounts reflected in the net book value of the asset transfers. Hearings were held at the WVPSC in July 2013. APCo is currently pursuing cost recovery of these plants in West Virginia and plans to pursue cost recovery in Virginia. If APCo and WPCo are not ultimately permitted to recover their incurred costs, it could reduce future net income and cash flows and impact financial condition.

APCo IGCC Plant

2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $ 39 million related to 2012 and 2011 environmental compliance costs effective February 2014 over a one-year period. In March 2013, the environmental RAC surcharge expired related to the collection of 2009 and 2010 environmental compliance costs. APCo has deferred $ 28 million as of June 30, 2013 for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $11 million of unrecognized equity carrying costs. Hearings at the Virginia SCC are scheduled for August 2013. If the Virginia SCC were to disallow any portion of the environmental RAC, it could reduce future net income and cash flows.

2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing

In March 2013, APCo filed with the Virginia SCC for an increase in its generation RAC revenues of $12 million for a total of $38 million annually to collect costs related to the Dresden Plant. The generation RAC increase is expected to be effective in March 2014. APCo has deferred $4 million as of June 30, 2013 for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $4 million of unrecognized equity carrying costs. Hearings at the Virginia SCC are scheduled for August 2013. If the Virginia SCC were to disallow any portion of the generation RAC, it could reduce future net income and cash flows.

2012 West Virginia Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation which allows the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred ENEC balances and other ENEC-related assets. In August 2012, APCo and WPCo filed a request with the WVPSC for a financing order to securitize a total of $422 million related to the December 2011 under-recovered ENEC deferral balance including other ENEC-related assets of $13 million and related future financing costs of $7 million. Upon completion of the securitization, APCo would offset its current ENEC rates by an amount to recover the securitized balance over the securitization period. In March 2013, APCo, WPCo and intervenors filed a settlement agreement with the WVPSC which recommended the WVPSC authorize APCo to securitize $376 million plus upfront financing costs. Hearings at the WVPSC on the securitization are scheduled for July 2013. As of June 30, 2013, APCo’s ENEC under-recovery balance of $287 million, net of 2012 and 2013 over-recovery, was recorded in Regulatory Assets on the balance sheet, excluding $3 million of unrecognized equity carrying costs and $15 million of other ENEC-related assets.

175

Virginia Storm Costs

WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting approval to merge WPCo into APCo. In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC. In April 2013, the FERC approved the WPCo merger into APCo. In May 2013, Virginia SCC staff filed testimony that included a recommendation that the Virginia SCC not approve the proposed merger as there is no qualitative benefit and the impact on Virginia rates cannot be determined. Hearings were held at the Virginia SCC in June 2013. In June 2013, the WVPSC issued an order consolidating this case with APCo’s plant asset transfer case. In June 2013, WVPSC staff filed testimony that included a recommendation that the WVPSC approve the proposed merger. Hearings were held at the WVPSC in July 2013. See the “Plant Transfers” section of APCo Rate Matters and the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.

PSO Rate Matters

Oklahoma Environmental Compliance Plan

In September 2012, based upon an agreement with the Federal EPA, the State of Oklahoma and other parties, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES) Unit 4 in 2016 and additional environmental controls on NES Unit 3 to continue operations through 2026. The plan requested approval for (a) an estimated $210 million of new environmental investment, excluding AFUDC and overheads of $ 46 million, that will be incurred prior to 2016 at NES Unit 3, (b) accelerated recovery through 2026 of the net book value of NES Units 3 and 4 (combined net book value of the two units is $231 million as of June 30, 2013), (c) an estimated $83 million of new investment incurred through 2016 at various gas units and (d) a new 15-year purchase power agreement (PPA) with a nonaffiliated entity, effective in 2016, with cost recovery through a rider, including an annual earnings component of $3 million. Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery in a future rate proceeding.

In March 2013, the OCC staff and the OOAG filed additional testimony revising the recommended cost cap on NES Unit 3 to $ 210 million, excluding AFUDC and overheads, and recommended conditional approval of the planned NES Unit 3 retirement subject to OCC approval in 2020 provided the planned retirement is consistent with environmental rules at that time.

Also, an intervenor representing some of PSO’s large industrial users opposed the majority of PSO’s plan, including recommending no cost recovery of NES Units 3 and 4 book value amounts not recovered at the time of their retirement and no recovery of the PPA costs, including earnings on the PPA. In February 2013, the OCC staff requested a stay in this proceeding, which was granted by the OCC in March 2013. In July 2013, the OCC staff filed a motion to lift the stay and dismiss PSO's environmental compliance plan case without prejudice. A hearing on the motion will be held in August 2013. If this case is dismissed, PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan.

176

I&M Rate Matters

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%. In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates from $85 million to $92 million. In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed a request for reconsideration with the IURC, which was denied. Also in March 2013, the OUCC filed an appeal of the order with the Indiana Court of Appeals. If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

Cook Plant Life Cycle Management Project (LCM Project)

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project. If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both of the units at the Rockport Plant with a Dry Sorbent Injection system. The estimated cost of the CCT Project was $285 million, excluding AFUDC, of which I&M’s ownership share is $ 142 million. The application requested deferral treatment of any unrecovered carrying costs incurred during construction and incremental post in-service depreciation expense and operation and maintenance expenses until such costs are recognized and recovered in a rider. I&M also requested cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism.

In July 2013, a settlement agreement was filed with the IURC. The settlement agreement includes the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s direct ownership share of $129 million. The settlement agreement specifies that 80% of the recoverable I&M direct ownership share of CCT Project costs will be recovered through a Federal Mandate Rider with the remaining 20% deferred until rates are established in a subsequent rate case. If the IURC approves the settlement agreement, I&M’s Indiana allocated share of the CCT Project costs received in the form of purchased power from AEGCo will be recovered in subsequent I&M rate cases. Hearings at the IURC are scheduled for August 2013. A decision is expected by November 2013. As of June 30, 2013, I&M has incurred costs of $39 million related to the CCT Project, including AFUDC. If I&M is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows.

177

FERC Rate Matters

Corporate Separation and Termination of Interconnection Agreement – Affecting APCo, I&M and OPCo

In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations. The filings requested approval to transfer at net book value approximately 9,200 MW of OPCo-owned generation assets to a new wholly-owned company, AEPGenCo. The AEP East Companies also requested FERC approval to transfer at net book value OPCo’s current two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer at net book value OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests (780 MW each). These transfers are proposed to be effective December 31, 2013. In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AEPGenCo, the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo and the merger of APCo and WPCo. In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo. OPCo has contested the petition for rehearing, which remains pending before the FERC. Similar asset transfer filings have been made at the Virginia SCC and the WVPSC. See the “Plant Transfers” section of APCo Rate Matters.

Additionally, the AEP East Companies requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Under the PCA, APCo and I&M would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo and I&M to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. Intervenors have opposed several of these filings. The AEP East Companies responded to intervenor comments and filed a revised PCA at the FERC in March 2013. The revised PCA included certain clarifying wording changes that have been agreed upon by intervenors. A decision is pending at the FERC.

If APCo and/or I&M experience decreases in revenues or increases in expenses as a result of changes to their relationship with affiliates 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.

4. COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2012 Annual Report should be read in conjunction with this report.

GUARANTEES

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

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

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

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AEP has two credit facilities totaling $3.5 billion, under which up to $1.2 billion may be issued as letters of credit. As of June 30, 2013, the maximum future payments for letters of credit issued under the credit facilities were as follows:

Company	Amount		Maturity
	(in thousands)
I&M	$	150	March 2014
OPCo		3,081	June 2014
SWEPCo		4,448	March 2014

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

			Bilateral		Maturity of
	Pollution		Letters		Bilateral Letters
Company	Control Bonds		of Credit		of Credit
	(in thousands)
APCo	$	229,650	$	232,293	March 2014 to March 2015
I&M		77,000		77,886	March 2015
OPCo		50,000		50,575	July 2014

Guarantees of Third-Party Obligations – Affecting SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million. Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2013, SWEPCo has collected approximately $62 million through a rider for final mine closure and reclamation costs, of which $12 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $50 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed balance sheets.

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

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

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of June 30, 2013, there were no material liabilities recorded for any indemnifications.

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

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Master Lease Agreements

The Registrant Subsidiaries lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of June 30, 2013, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:

	Maximum
Company	Potential Loss
	(in thousands)
APCo	$	3,639
I&M		2,495
OPCo		4,543
PSO		1,202
SWEPCo		2,442

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $13 million and $ 15 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2013.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 83% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are approximately $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss.

ENVIRONMENTAL CONTINGENCIES

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

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO 2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision. The petition was denied in January 2011. Plaintiffs refiled their complaint in federal district court. The court ordered all defendants to respond to the refiled complaints in October 2011. In March 2012, the court granted the defendants’ motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations. In May 2013, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court’s dismissal of the complaint. The plaintiffs may seek further review in the U.S. Supreme Court. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

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

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO 2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million. In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim. The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court. In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court’s decision, holding that the CAA displaced Kivalina’s claims for damages. Plaintiffs filed seeking further review in the U.S. Supreme Court. In May 2013, the U.S. Supreme Court denied the plaintiffs’ request for review.

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

Remediation – Affecting I&M

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

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

NUCLEAR CONTINGENCIES – AFFECTING I&M

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

Nuclear Incident Insurance

Prior to April 2013, I&M carried insurance coverage for a nuclear or nonnuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion. Effective April 2013, insurance coverage for a nonnuclear incident at the Cook Plant was reduced to $1.7 billion. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition.

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5. DISPOSITION AND IMPAIRMENT

DISPOSITION

2013

Conesville Coal Preparation Plant – Affecting OPCo

In April 2013, OPCo closed on the sale of its Conesville Coal Preparation Plant. This sale did not have a significant impact on OPCo’s financial statements.

IMPAIRMENT

2013

Muskingum River Plant, Unit 5 – Affecting OPCo

In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including OPCo’s 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant. Under the modification to the consent decree, OPCo has the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017. In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, management re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project which would have extended the useful life of MR5 is remote. As a result, management completed an impairment analysis and concluded that MR5 was impaired. Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit. In the second quarter of 2013, OPCo recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory. Management expects to retire the plant in 2015.

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6. BENEFIT PLANS

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

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and six months ended June 30, 2013 and 2012:

APCo
					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Service Cost	$	1,542	$	1,891	$	642	$	1,347
Interest Cost		6,915		7,553		3,364		4,615
Expected Return on Plan Assets		(9,260)		(10,486)		(4,537)		(4,188)
Amortization of Transition Obligation		-		-		-		200
Amortization of Prior Service Cost (Credit)		50		119		(2,513)		(715)
Amortization of Net Actuarial Loss		6,257		5,084		3,062		2,632
Net Periodic Benefit Cost	$	5,504	$	4,161	$	18	$	3,891

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Service Cost	$	3,085	$	3,782	$	1,283	$	2,694
Interest Cost		13,831		15,106		6,727		9,231
Expected Return on Plan Assets		(18,520)		(20,972)		(9,073)		(8,376)
Amortization of Transition Obligation		-		-		-		400
Amortization of Prior Service Cost (Credit)		99		238		(5,025)		(1,431)
Amortization of Net Actuarial Loss		12,513		10,169		6,124		5,263
Net Periodic Benefit Cost	$	11,008	$	8,323	$	36	$	7,781

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I&M
					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Service Cost	$	2,184	$	2,477	$	805	$	1,655
Interest Cost		6,025		6,561		2,055		3,197
Expected Return on Plan Assets		(8,206)		(9,392)		(3,296)		(3,212)
Amortization of Transition Obligation		-		-		-		33
Amortization of Prior Service Cost (Credit)		48		102		(2,355)		(596)
Amortization of Net Actuarial Loss		5,422		4,393		1,881		1,763
Net Periodic Benefit Cost (Credit)	$	5,473	$	4,141	$	(910)	$	2,840

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Service Cost	$	4,368	$	4,954	$	1,610	$	3,310
Interest Cost		12,050		13,122		4,110		6,393
Expected Return on Plan Assets		(16,413)		(18,783)		(6,592)		(6,423)
Amortization of Transition Obligation		-		-		-		66
Amortization of Prior Service Cost (Credit)		97		204		(4,710)		(1,192)
Amortization of Net Actuarial Loss		10,844		8,785		3,763		3,525
Net Periodic Benefit Cost (Credit)	$	10,946	$	8,282	$	(1,819)	$	5,679

OPCo
					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Service Cost	$	2,373	$	2,751	$	1,299	$	2,187
Interest Cost		10,292		11,299		4,447		6,048
Expected Return on Plan Assets		(15,142)		(17,101)		(6,239)		(5,639)
Amortization of Transition Obligation		-		-		-		26
Amortization of Prior Service Cost (Credit)		70		185		(3,230)		(968)
Amortization of Net Actuarial Loss		9,309		7,610		4,041		3,417
Net Periodic Benefit Cost	$	6,902	$	4,744	$	318	$	5,071

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Service Cost	$	4,745	$	5,502	$	2,599	$	4,374
Interest Cost		20,584		22,597		8,894		12,095
Expected Return on Plan Assets		(30,283)		(34,201)		(12,477)		(11,278)
Amortization of Transition Obligation		-		-		-		52
Amortization of Prior Service Cost (Credit)		141		371		(6,461)		(1,936)
Amortization of Net Actuarial Loss		18,618		15,220		8,082		6,834
Net Periodic Benefit Cost	$	13,805	$	9,489	$	637	$	10,141

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PSO
					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Service Cost	$	1,390	$	1,488	$	343	$	709
Interest Cost		2,749		3,075		948		1,450
Expected Return on Plan Assets		(3,919)		(4,504)		(1,522)		(1,481)
Amortization of Prior Service Cost (Credit)		74		(237)		(1,073)		(269)
Amortization of Net Actuarial Loss		2,461		2,051		869		797
Net Periodic Benefit Cost (Credit)	$	2,755	$	1,873	$	(435)	$	1,206

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Service Cost	$	2,781	$	2,976	$	686	$	1,418
Interest Cost		5,497		6,150		1,896		2,899
Expected Return on Plan Assets		(7,837)		(9,008)		(3,044)		(2,961)
Amortization of Prior Service Cost (Credit)		148		(474)		(2,145)		(539)
Amortization of Net Actuarial Loss		4,922		4,103		1,738		1,594
Net Periodic Benefit Cost (Credit)	$	5,511	$	3,747	$	(869)	$	2,411

SWEPCo
					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Service Cost	$	1,753	$	1,774	$	423	$	831
Interest Cost		2,863		3,135		1,076		1,668
Expected Return on Plan Assets		(4,128)		(4,716)		(1,720)		(1,698)
Amortization of Prior Service Cost (Credit)		88		(199)		(1,290)		(233)
Amortization of Net Actuarial Loss		2,554		2,082		982		914
Net Periodic Benefit Cost (Credit)	$	3,130	$	2,076	$	(529)	$	1,482

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Service Cost	$	3,506	$	3,549	$	846	$	1,662
Interest Cost		5,727		6,269		2,151		3,336
Expected Return on Plan Assets		(8,255)		(9,433)		(3,440)		(3,397)
Amortization of Prior Service Cost (Credit)		175		(397)		(2,578)		(466)
Amortization of Net Actuarial Loss		5,107		4,165		1,964		1,829
Net Periodic Benefit Cost (Credit)	$	6,260	$	4,153	$	(1,057)	$	2,964

7. BUSINESS SEGMENTS

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

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8. DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

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

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The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of June 30, 2013 and December 31, 2012:

Notional Volume of Derivative Instruments
June 30, 2013

Primary Risk			Unit of
Exposure			Measure	APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Commodity:
	Power		MWhs		99,667		68,875		140,924		9		10
	Coal		Tons		502		1,607		1,372		946		795
	Natural Gas		MMBtus		6,120		4,230		8,654		-		-
	Heating Oil and
		Gasoline	Gallons		883		435		1,039		442		543
	Interest Rate		USD	$	18,121	$	12,523	$	25,622	$	-	$	-

Interest Rate and
	Foreign Currency		USD	$	-	$	-	$	-	$	-	$	-

Notional Volume of Derivative Instruments
December 31, 2012

Primary Risk			Unit of
Exposure			Measure	APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Commodity:
	Power		MWhs		94,059		64,791		132,188		-		-
	Coal		Tons		1,401		2,711		3,033		1,980		1,312
	Natural Gas		MMBtus		10,077		6,922		14,163		-		-
	Heating Oil and
		Gasoline	Gallons		1,050		532		1,260		616		585
	Interest Rate		USD	$	24,146	$	16,584	$	33,934	$	-	$	-

Interest Rate and
	Foreign Currency		USD	$	-	$	200,000	$	-	$	-	$	-

Fair Value Hedging Strategies

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

Cash Flow Hedging Strategies

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

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

187

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

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

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

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

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

According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the June 30, 2013 and December 31, 2012 condensed balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

	June 30, 2013				December 31, 2012
	Cash Collateral		Cash Collateral		Cash Collateral		Cash Collateral
	Received		Paid		Received		Paid
	Netted Against		Netted Against		Netted Against		Netted Against
	Risk Management		Risk Management		Risk Management		Risk Management
Company	Assets		Liabilities		Assets		Liabilities
	(in thousands)
APCo	$	555	$	5,021	$	1,262	$	11,029
I&M		383		3,455		867		7,576
OPCo		784		7,081		1,774		15,500
PSO		-		35		-		-
SWEPCo		-		44		-		-

188

The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of June 30, 2013 and December 31, 2012:

APCo
Fair Value of Derivative Instruments
June 30, 2013

		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (c)
		(in thousands)
Current Risk Management Assets		$	86,770	$	995	$	-	$	87,765	$	(59,245)	$	28,520
Long-term Risk Management Assets			38,563		-		-		38,563		(14,955)		23,608
Total Assets			125,333		995		-		126,328		(74,200)		52,128

Current Risk Management Liabilities			75,377		679		-		76,056		(62,659)		13,397
Long-term Risk Management Liabilities			29,990		24		-		30,014		(16,007)		14,007
Total Liabilities			105,367		703		-		106,070		(78,666)		27,404

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	19,966	$	292	$	-	$	20,258	$	4,466	$	24,724

APCo
Fair Value of Derivative Instruments
December 31, 2012

		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (c)
		(in thousands)
Current Risk Management Assets		$	127,645	$	338	$	-	$	127,983	$	(97,023)	$	30,960
Long-term Risk Management Assets			60,498		215		-		60,713		(26,353)		34,360
Total Assets			188,143		553		-		188,696		(123,376)		65,320

Current Risk Management Liabilities			119,430		1,182		-		120,612		(103,914)		16,698
Long-term Risk Management Liabilities			47,281		424		-		47,705		(29,229)		18,476
Total Liabilities			166,711		1,606		-		168,317		(133,143)		35,174

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	21,432	$	(1,053)	$	-	$	20,379	$	9,767	$	30,146

189

I&M
Fair Value of Derivative Instruments
June 30, 2013

		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (c)
		(in thousands)
Current Risk Management Assets		$	59,657	$	686	$	-	$	60,343	$	(40,744)	$	19,599
Long-term Risk Management Assets			26,650		-		-		26,650		(10,335)		16,315
Total Assets			86,307		686		-		86,993		(51,079)		35,914

Current Risk Management Liabilities			52,025		455		-		52,480		(43,093)		9,387
Long-term Risk Management Liabilities			21,066		12		-		21,078		(11,058)		10,020
Total Liabilities			73,091		467		-		73,558		(54,151)		19,407

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	13,216	$	219	$	-	$	13,435	$	3,072	$	16,507

I&M
Fair Value of Derivative Instruments
December 31, 2012

		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (c)
		(in thousands)
Current Risk Management Assets		$	93,268	$	220	$	-	$	93,488	$	(66,514)	$	26,974
Long-term Risk Management Assets			41,553		148		-		41,701		(18,132)		23,569
Total Assets			134,821		368		-		135,189		(84,646)		50,543

Current Risk Management Liabilities			82,433		807		19,524		102,764		(71,247)		31,517
Long-term Risk Management Liabilities			33,714		292		-		34,006		(20,108)		13,898
Total Liabilities			116,147		1,099		19,524		136,770		(91,355)		45,415

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	18,674	$	(731)	$	(19,524)	$	(1,581)	$	6,709	$	5,128

190

OPCo
Fair Value of Derivative Instruments
June 30, 2013

		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (c)
		(in thousands)
Current Risk Management Assets		$	126,809	$	1,406	$	-	$	128,215	$	(87,070)	$	41,145
Long-term Risk Management Assets			54,528		-		-		54,528		(21,147)		33,381
Total Assets			181,337		1,406		-		182,743		(108,217)		74,526

Current Risk Management Liabilities			110,711		943		-		111,654		(91,885)		19,769
Long-term Risk Management Liabilities			42,403		29		-		42,432		(22,629)		19,803
Total Liabilities			153,114		972		-		154,086		(114,514)		39,572

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	28,223	$	434	$	-	$	28,657	$	6,297	$	34,954

OPCo
Fair Value of Derivative Instruments
December 31, 2012

		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (c)
		(in thousands)
Current Risk Management Assets		$	183,064	$	464	$	-	$	183,528	$	(139,215)	$	44,313
Long-term Risk Management Assets			85,023		303		-		85,326		(37,038)		48,288
Total Assets			268,087		767		-		268,854		(176,253)		92,601

Current Risk Management Liabilities			171,397		1,658		-		173,055		(148,900)		24,155
Long-term Risk Management Liabilities			66,448		596		-		67,044		(41,079)		25,965
Total Liabilities			237,845		2,254		-		240,099		(189,979)		50,120

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	30,242	$	(1,487)	$	-	$	28,755	$	13,726	$	42,481

191

PSO
Fair Value of Derivative Instruments
June 30, 2013

		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (c)
		(in thousands)
Current Risk Management Assets		$	1,289	$	6	$	-	$	1,295	$	(811)	$	484
Long-term Risk Management Assets			-		-		-		-		-		-
Total Assets			1,289		6		-		1,295		(811)		484

Current Risk Management Liabilities			2,910		37		-		2,947		(836)		2,111
Long-term Risk Management Liabilities			-		12		-		12		(10)		2
Total Liabilities			2,910		49		-		2,959		(846)		2,113

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(1,621)	$	(43)	$	-	$	(1,664)	$	35	$	(1,629)

PSO
Fair Value of Derivative Instruments
December 31, 2012

		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (c)
		(in thousands)
Current Risk Management Assets		$	1,657	$	42	$	-	$	1,699	$	(1,190)	$	509
Long-term Risk Management Assets			-		-		-		-		31		31
Total Assets			1,657		42		-		1,699		(1,159)		540

Current Risk Management Liabilities			7,021		17		-		7,038		(1,190)		5,848
Long-term Risk Management Liabilities			-		-		-		-		31		31
Total Liabilities			7,021		17		-		7,038		(1,159)		5,879

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(5,364)	$	25	$	-	$	(5,339)	$	-	$	(5,339)

192

SWEPCo
Fair Value of Derivative Instruments
June 30, 2013

		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (c)
		(in thousands)
Current Risk Management Assets		$	1,846	$	6	$	-	$	1,852	$	(1,454)	$	398
Long-term Risk Management Assets			-		-		-		-		-		-
Total Assets			1,846		6		-		1,852		(1,454)		398

Current Risk Management Liabilities			2,382		45		-		2,427		(1,486)		941
Long-term Risk Management Liabilities			-		15		-		15		(12)		3
Total Liabilities			2,382		60		-		2,442		(1,498)		944

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(536)	$	(54)	$	-	$	(590)	$	44	$	(546)

SWEPCo
Fair Value of Derivative Instruments
December 31, 2012

		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (c)
		(in thousands)
Current Risk Management Assets		$	2,804	$	41	$	-	$	2,845	$	(2,150)	$	695
Long-term Risk Management Assets			-		-		-		-		-		-
Total Assets			2,804		41		-		2,845		(2,150)		695

Current Risk Management Liabilities			3,261		17		-		3,278		(2,150)		1,128
Long-term Risk Management Liabilities			-		-		-		-		-		-
Total Liabilities			3,261		17		-		3,278		(2,150)		1,128

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(457)	$	24	$	-	$	(433)	$	-	$	(433)

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

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

(c)	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.

193

The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and six months ended June 30, 2013 and 2012:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2013

Location of Gain (Loss)		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	194	$	2,897	$	1,819	$	169	$	302
Sales to AEP Affiliates			-		-		-		-		-
Fuel and Other Consumables Used for
	Electric Generation		-		-		-		-		-
Regulatory Assets (a)			(974)		(1,585)		(4,492)		192		(373)
Regulatory Liabilities (a)			1,230		(880)		3,360		(1)		39
Total Gain (Loss) on Risk Management
	Contracts	$	450	$	432	$	687	$	360	$	(32)

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2012

Location of Gain (Loss)		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	(599)	$	2,579	$	2,538	$	165	$	303
Sales to AEP Affiliates			-		-		-		-		-
Fuel and Other Consumables Used for
	Electric Generation		-		-		-		-		-
Regulatory Assets (a)			(3,796)		(2,905)		(8,895)		(757)		(364)
Regulatory Liabilities (a)			4,711		392		7,178		(26)		(27)
Total Gain (Loss) on Risk Management
	Contracts	$	316	$	66	$	821	$	(618)	$	(88)

194

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Six Months Ended June 30, 2013

Location of Gain (Loss)		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	873	$	7,844	$	3,533	$	216	$	330
Sales to AEP Affiliates			-		-		-		-		-
Fuel and Other Consumables Used for
	Electric Generation		-		-		-		-		-
Regulatory Assets (a)			-		(1,099)		(5,697)		2,202		(102)
Regulatory Liabilities (a)			(210)		(6,062)		3,360		-		135
Total Gain (Loss) on Risk Management
	Contracts	$	663	$	683	$	1,196	$	2,418	$	363

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Six Months Ended June 30, 2012

Location of Gain (Loss)		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	(926)	$	5,392	$	11,031	$	160	$	252
Sales to AEP Affiliates			-		-		-		-		-
Fuel and Other Consumables Used for
	Electric Generation		-		-		-		-		-
Regulatory Assets (a)			(7,277)		(6,015)		(12,026)		(5,958)		(7,092)
Regulatory Liabilities (a)			11,120		7,118		7,178		1		(5)
Total Gain (Loss) on Risk Management
	Contracts	$	2,917	$	6,495	$	6,183	$	(5,797)	$	(6,845)

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

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

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

195

Accounting for Fair Value Hedging Strategies

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. During the three and six months ended June 30, 2013 and 2012, the Registrant Subsidiaries did not designate any fair value hedging strategies.

Accounting for Cash Flow Hedging Strategies

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

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2013 and 2012, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. During the three and six months ended June 30, 2013 and 2012, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2013, I&M designated interest rate derivatives as cash flow hedges. During the three and six months ended June 30, 2012, I&M and SWEPCo designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and six months ended June 30, 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and six months ended June 30, 2012, SWEPCo designated foreign currency derivatives as cash flow hedges.

During the three and six months ended June 30, 2013 and 2012, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2013 and 2012, see Note 2.

196

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of June 30, 2013 and December 31, 2012 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
June 30, 2013

	Hedging Assets (a)				Hedging Liabilities (a)				AOCI Gain (Loss) Net of Tax
			Interest Rate				Interest Rate				Interest Rate
			and Foreign				and Foreign				and Foreign
Company	Commodity		Currency		Commodity		Currency		Commodity		Currency
	(in thousands)
APCo	$	570	$	-	$	278	$	-	$	197	$	2,583
I&M		393		-		174		-		147		(16,796)
OPCo		805		-		371		-		289		7,415
PSO		2		-		45		-		(21)		6,081
SWEPCo		2		-		56		-		(26)		(14,437)

	Expected to be Reclassified to
	Net Income During the Next
	Twelve Months
					Maximum Term for
			Interest Rate		Exposure to
			and Foreign		Variability of Future
Company	Commodity		Currency		Cash Flows
	(in thousands)				(in months)
APCo	$	213	$	(1,013)		18
I&M		153		(1,640)		18
OPCo		308		1,359		18
PSO		(13)		759		18
SWEPCo		(17)		(2,267)		18

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 2012

	Hedging Assets (a)				Hedging Liabilities (a)				AOCI Gain (Loss) Net of Tax
			Interest Rate				Interest Rate				Interest Rate
			and Foreign				and Foreign				and Foreign
Company	Commodity		Currency		Commodity		Currency		Commodity		Currency
	(in thousands)
APCo	$	302	$	-	$	1,355	$	-	$	(644)	$	2,077
I&M		200		-		931		19,524		(446)		(19,647)
OPCo		416		-		1,903		-		(912)		8,095
PSO		25		-		-		-		21		6,460
SWEPCo		24		-		-		-		22		(15,571)

	Expected to be Reclassified to
	Net Income During the Next
	Twelve Months
			Interest Rate
			and Foreign
Company	Commodity		Currency
	(in thousands)
APCo	$	(507)	$	(1,013)
I&M		(355)		(1,600)
OPCo		(720)		1,359
PSO		21		759
SWEPCo		22		(2,267)

(a)

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

197

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

Credit Risk

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

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

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries’ fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of June 30, 2013 and December 31, 2012:

	June 30, 2013
	Liabilities for		Amount of Collateral the		Amount
	Derivative Contracts		Registrant Subsidiaries		Attributable to
	with Credit		Would Have Been		RTO and ISO
Company	Downgrade Triggers		Required to Post		Activities
	(in thousands)
APCo	$	937	$	6,147	$	6,074
I&M		647		4,248		4,197
OPCo		1,324		8,692		8,588
PSO		-		1,533		1,306
SWEPCo		-		1,810		1,542

	December 31, 2012
	Liabilities for		Amount of Collateral the		Amount
	Derivative Contracts		Registrant Subsidiaries		Attributable to
	with Credit		Would Have Been		RTO and ISO
Company	Downgrade Triggers		Required to Post		Activities
	(in thousands)
APCo	$	2,159	$	3,699	$	3,510
I&M		1,483		2,540		2,411
OPCo		3,034		5,198		4,933
PSO		-		1,509		1,429
SWEPCo		-		1,778		1,683

198

In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of June 30, 2013 and December 31, 2012:

	June 30, 2013
	Liabilities for				Additional
	Contracts with Cross				Settlement
	Default Provisions				Liability if Cross
	Prior to Contractual		Amount of Cash		Default Provision
Company	Netting Arrangements		Collateral Posted		is Triggered
	(in thousands)
APCo	$	31,949	$	-	$	24,748
I&M		22,079		-		17,102
OPCo		45,175		-		34,993
PSO		15		-		14
SWEPCo		18		-		17

	December 31, 2012
	Liabilities for				Additional
	Contracts with Cross				Settlement
	Default Provisions				Liability if Cross
	Prior to Contractual		Amount of Cash		Default Provision
Company	Netting Arrangements		Collateral Posted		is Triggered
	(in thousands)
APCo	$	49,465	$	1,822	$	30,160
I&M		53,499		1,252		40,240
OPCo		69,516		2,561		42,386
PSO		-		-		-
SWEPCo		-		-		-

9. FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The AEP System’s market risk oversight staff independently monitors its valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer.

199

For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

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

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

Fair Value Measurements of Long-term Debt

The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of June 30, 2013 and December 31, 2012 are summarized in the following table:

	June 30, 2013				December 31, 2012
Company	Book Value		Fair Value		Book Value		Fair Value
	(in thousands)
APCo	$	3,702,759	$	4,241,900	$	3,702,442	$	4,555,143
I&M		2,305,192		2,490,561		2,057,666		2,372,017
OPCo		3,504,794		4,002,270		3,860,440		4,560,337
PSO		949,841		1,107,094		949,871		1,175,759
SWEPCo		2,044,780		2,231,426		2,046,228		2,400,509

200

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

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

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

·	Maximum percentage invested in a specific type of investment.

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

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

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

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

The following is a summary of nuclear trust fund investments as of June 30, 2013 and December 31, 2012:

		June 30, 2013						December 31, 2012
		Estimated		Gross		Other-Than-		Estimated		Gross		Other-Than-
		Fair		Unrealized		Temporary		Fair		Unrealized		Temporary
		Value		Gains (Losses)		Impairments		Value		Gains		Impairments
		(in thousands)
Cash and Cash Equivalents		$	14,132	$	-	$	-	$	16,783	$	-	$	-
Fixed Income Securities:
	United States Government		604,850		37,609		(2,085)		647,918		58,268		(747)
	Corporate Debt		35,202		2,963		(1,592)		35,399		4,903		(1,352)
	State and Local Government		262,521		(1,661)		(2,832)		270,090		1,006		(863)
	Subtotal Fixed Income Securities		902,573		38,911		(6,509)		953,407		64,177		(2,962)
Equity Securities - Domestic			874,689		372,591		(82,148)		735,582		284,599		(76,557)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,791,394	$	411,502	$	(88,657)	$	1,705,772	$	348,776	$	(79,519)

201

The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Proceeds from Investment Sales	$	218,272	$	182,179	$	385,942	$	516,579
Purchases of Investments		227,470		192,104		411,769		544,981
Gross Realized Gains on Investment Sales		8,575		3,380		11,898		4,932
Gross Realized Losses on Investment Sales		7,397		803		9,712		2,219

The adjusted cost of fixed income securities was $ 862 million and $889 million as of June 30, 2013 and December 31, 2012, respectively. The adjusted cost of equity securities was $502 million and $451 million as of June 30, 2013 and December 31, 2012, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2013 was as follows:

	Fair Value of
	Fixed Income
	Securities
	(in thousands)
Within 1 year	$	78,832
1 year – 5 years		340,397
5 years – 10 years		238,064
After 10 years		245,280
Total	$	902,573

202

Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2013 and December 31, 2012. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.

APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2013

		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)		$	2,555	$	107,096	$	15,526	$	(73,619)	$	51,558
Cash Flow Hedges:
	Commodity Hedges (a)		-		995		-		(425)		570
Total Risk Management Assets		$	2,555	$	108,091	$	15,526	$	(74,044)	$	52,128

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	1,477	$	101,183	$	2,550	$	(78,084)	$	27,126
Cash Flow Hedges:
	Commodity Hedges (a)		-		703		-		(425)		278
Total Risk Management Liabilities		$	1,477	$	101,886	$	2,550	$	(78,509)	$	27,404

APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2012

		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)		$	4,161	$	166,916	$	17,058	$	(123,117)	$	65,018
Cash Flow Hedges:
	Commodity Hedges (a)		-		498		-		(196)		302
Total Risk Management Assets		$	4,161	$	167,414	$	17,058	$	(123,313)	$	65,320

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	1,959	$	158,665	$	6,079	$	(132,884)	$	33,819
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,551		-		(196)		1,355
Total Risk Management Liabilities		$	1,959	$	160,216	$	6,079	$	(133,080)	$	35,174

203

I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2013

			Level 1		Level 2		Level 3		Other		Total
Assets:			(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)			$	1,766	$	73,702	$	10,729	$	(50,676)	$	35,521
Cash Flow Hedges:
	Commodity Hedges (a)			-		686		-		(293)		393
Total Risk Management Assets				1,766		74,388		10,729		(50,969)		35,914

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (c)				2,939		-		-		11,193		14,132
Fixed Income Securities:
	United States Government			-		604,850		-		-		604,850
	Corporate Debt			-		35,202		-		-		35,202
	State and Local Government			-		262,521		-		-		262,521
		Subtotal Fixed Income Securities		-		902,573		-		-		902,573
Equity Securities - Domestic (d)				874,689		-		-		-		874,689
Total Spent Nuclear Fuel and Decommissioning Trusts				877,628		902,573		-		11,193		1,791,394

Total Assets			$	879,394	$	976,961	$	10,729	$	(39,776)	$	1,827,308

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)			$	1,021	$	70,200	$	1,762	$	(53,750)	$	19,233
Cash Flow Hedges:
	Commodity Hedges (a)			-		467		-		(293)		174
Total Risk Management Liabilities			$	1,021	$	70,667	$	1,762	$	(54,043)	$	19,407

204

I&M
		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		December 31, 2012

			Level 1		Level 2		Level 3		Other		Total
Assets:			(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)			$	2,858	$	120,242	$	11,717	$	(84,474)	$	50,343
Cash Flow Hedges:
	Commodity Hedges (a)			-		330		-		(130)		200
Total Risk Management Assets				2,858		120,572		11,717		(84,604)		50,543

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (c)				6,508		-		-		10,275		16,783
Fixed Income Securities:
	United States Government			-		647,918		-		-		647,918
	Corporate Debt			-		35,399		-		-		35,399
	State and Local Government			-		270,090		-		-		270,090
		Subtotal Fixed Income Securities		-		953,407		-		-		953,407
Equity Securities - Domestic (d)				735,582		-		-		-		735,582
Total Spent Nuclear Fuel and Decommissioning Trusts				742,090		953,407		-		10,275		1,705,772

Total Assets			$	744,948	$	1,073,979	$	11,717	$	(74,329)	$	1,756,315

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)			$	1,346	$	110,621	$	4,176	$	(91,183)	$	24,960
Cash Flow Hedges:
	Commodity Hedges (a)			-		1,061		-		(130)		931
	Interest Rate/Foreign Currency Hedges			-		19,524		-		-		19,524
Total Risk Management Liabilities			$	1,346	$	131,206	$	4,176	$	(91,313)	$	45,415

205

OPCo
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	June 30, 2013

		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Other Cash Deposits (e)		$	-	$	26	$	-	$	39	$	65

Risk Management Assets
Risk Management Commodity Contracts (a) (b)			3,613		155,550		21,953		(107,395)		73,721
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,405		-		(600)		805
Total Risk Management Assets			3,613		156,955		21,953		(107,995)		74,526

Total Assets		$	3,613	$	156,981	$	21,953	$	(107,956)	$	74,591

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	2,088	$	147,199	$	3,606	$	(113,692)	$	39,201
Cash Flow Hedges:
	Commodity Hedges (a)		-		971		-		(600)		371
Total Risk Management Liabilities		$	2,088	$	148,170	$	3,606	$	(114,292)	$	39,572

OPCo
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2012

		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Other Cash Deposits (e)		$	-	$	26	$	-	$	39	$	65

Risk Management Assets
Risk Management Commodity Contracts (a) (b)			5,848		238,254		23,973		(175,890)		92,185
Cash Flow Hedges:
	Commodity Hedges (a)		-		688		-		(272)		416
Total Risk Management Assets			5,848		238,942		23,973		(176,162)		92,601

Total Assets		$	5,848	$	238,968	$	23,973	$	(176,123)	$	92,666

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	2,753	$	226,536	$	8,544	$	(189,616)	$	48,217
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,175		-		(272)		1,903
Total Risk Management Liabilities		$	2,753	$	228,711	$	8,544	$	(189,888)	$	50,120

206

PSO
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	June 30, 2013

		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)		$	-	$	1,289	$	-	$	(807)	$	482
Cash Flow Hedges:
	Commodity Hedges (a)		-		6		-		(4)		2
Total Risk Management Assets		$	-	$	1,295	$	-	$	(811)	$	484

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	-	$	2,910	$	-	$	(842)	$	2,068
Cash Flow Hedges:
	Commodity Hedges (a)		-		49		-		(4)		45
Total Risk Management Liabilities		$	-	$	2,959	$	-	$	(846)	$	2,113

PSO
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2012

		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)		$	-	$	1,657	$	-	$	(1,142)	$	515
Cash Flow Hedges:
	Commodity Hedges (a)		-		42		-		(17)		25
Total Risk Management Assets		$	-	$	1,699	$	-	$	(1,159)	$	540

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	-	$	7,021	$	-	$	(1,142)	$	5,879
Cash Flow Hedges:
	Commodity Hedges (a)		-		17		-		(17)		-
Total Risk Management Liabilities		$	-	$	7,038	$	-	$	(1,159)	$	5,879

207

SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2013

		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Cash and Cash Equivalents (e)		$	10,078	$	-	$	-	$	1,762	$	11,840

Risk Management Assets
Risk Management Commodity Contracts (a) (b)			-		1,846		-		(1,450)		396
Cash Flow Hedges:
	Commodity Hedges (a)		-		7		-		(5)		2
Total Risk Management Assets			-		1,853		-		(1,455)		398

Total Assets		$	10,078	$	1,853	$	-	$	307	$	12,238

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	-	$	2,382	$	-	$	(1,494)	$	888
Cash Flow Hedges:
	Commodity Hedges (a)		-		61		-		(5)		56
Total Risk Management Liabilities		$	-	$	2,443	$	-	$	(1,499)	$	944

SWEPCo
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2012

		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)		$	-	$	2,804	$	-	$	(2,133)	$	671
Cash Flow Hedges:
	Commodity Hedges (a)		-		41		-		(17)		24
Total Risk Management Assets		$	-	$	2,845	$	-	$	(2,150)	$	695

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	-	$	3,261	$	-	$	(2,133)	$	1,128
Cash Flow Hedges:
	Commodity Hedges (a)		-		17		-		(17)		-
Total Risk Management Liabilities		$	-	$	3,278	$	-	$	(2,150)	$	1,128

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

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

(c)	Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

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

(e)	Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.

There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2013 and 2012.

208

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

Three Months Ended June 30, 2013		APCo		I&M		OPCo
		(in thousands)
Balance as of March 31, 2013		$	8,756	$	6,051	$	12,381
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(369)		(255)		(522)
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		-		2,390
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-
Purchases, Issuances and Settlements (c)			641		443		906
Transfers into Level 3 (d) (e)			243		168		344
Transfers out of Level 3 (e) (f)			(362)		(250)		(512)
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		4,067		2,810		3,360
Balance as of June 30, 2013		$	12,976	$	8,967	$	18,347

Three Months Ended June 30, 2012		APCo		I&M		OPCo
		(in thousands)
Balance as of March 31, 2012		$	7,981	$	5,614	$	11,767
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(3,210)		(2,258)		(4,734)
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		-		1,711
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		(11)		(8)		(16)
Purchases, Issuances and Settlements (c)			4,988		3,508		7,355
Transfers into Level 3 (d) (e)			1,301		915		1,919
Transfers out of Level 3 (e) (f)			(557)		(392)		(821)
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		2,372		1,670		1,788
Balance as of June 30, 2012		$	12,864	$	9,049	$	18,969

209

Six Months Ended June 30, 2013		APCo		I&M		OPCo
		(in thousands)
Balance as of December 31, 2012		$	10,979	$	7,541	$	15,429
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(3,532)		(2,439)		(4,990)
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		-		598
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-
Purchases, Issuances and Settlements (c)			2,859		1,977		4,045
Transfers into Level 3 (d) (e)			875		602		1,231
Transfers out of Level 3 (e) (f)			(941)		(648)		(1,326)
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		2,736		1,934		3,360
Balance as of June 30, 2013		$	12,976	$	8,967	$	18,347

Six Months Ended June 30, 2012		APCo		I&M		OPCo
		(in thousands)
Balance as of December 31, 2011		$	1,971	$	1,263	$	2,666
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(5,313)		(3,590)		(7,533)
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		-		7,035
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		52		34		71
Purchases, Issuances and Settlements (c)			11,499		7,811		16,397
Transfers into Level 3 (d) (e)			3,562		2,341		4,934
Transfers out of Level 3 (e) (f)			(4,676)		(3,028)		(6,388)
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		5,769		4,218		1,787
Balance as of June 30, 2012		$	12,864	$	9,049	$	18,969

(a)

Included in revenues on the condensed statements of income.

(b)

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

(c)

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

(d)

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

(e)

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

(f)

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

(g)

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

210

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of June 30, 2013:

APCo
	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	11,823	$	1,613	Discounted Cash Flow	Forward Market Price	$	11.48	$	70.90
FTRs		3,703		937	Discounted Cash Flow	Forward Market Price		(12.31)		11.19
Total	$	15,526	$	2,550

I&M
	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	8,170	$	1,115	Discounted Cash Flow	Forward Market Price	$	11.48	$	70.90
FTRs		2,559		647	Discounted Cash Flow	Forward Market Price		(12.31)		11.19
Total	$	10,729	$	1,762

OPCo
	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	16,717	$	2,282	Discounted Cash Flow	Forward Market Price	$	11.48	$	70.90
FTRs		5,236		1,324	Discounted Cash Flow	Forward Market Price		(12.31)		11.19
Total	$	21,953	$	3,606

(a)

Represents market prices in dollars per MWh.

10. INCOME TAXES

AEP System Tax Allocation Agreement

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

Federal and State Income Tax Audit Status

The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013. The completion of the federal audit did not result in a material impact on net income, cash flow or financial condition. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.

The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. Management believes that previously filed tax returns have positions that may be challenged by these tax authorities. However, management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2008.

211

11. FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first six months of 2013 are shown in the tables below:

		Principal			Interest
Company	Type of Debt	Amount (a)			Rate	Due Date
Issuances:		(in thousands)			(%)
I&M	Notes Payable	$	101,354		Variable	2017
I&M	Senior Unsecured Notes		250,000		3.20	2023
OPCo	Long-term Debt - Affiliated		200,000	(b)	Variable	2015
OPCo	Pollution Control Bonds		50,000		Variable	2014

(a)

Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.

(b)

Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility due in May 2015.

			Principal		Interest
Company		Type of Debt	Amount Paid		Rate	Due Date
Retirements and			(in thousands)		(%)
	Principal Payments:
APCo		Land Note	$	14	13.718	2026
I&M		Notes Payable		6,083	5.44	2013
I&M		Notes Payable		9,811	4.00	2014
I&M		Notes Payable		8,054	Variable	2015
I&M		Notes Payable		9,731	Variable	2016
I&M		Notes Payable		6,739	2.12	2016
I&M		Notes Payable		20,859	Variable	2016
I&M		Other Long-term Debt		454	6.00	2025
I&M		Other Long-term Debt		2,062	Variable	2015
I&M		Pollution Control Bonds		40,000	5.25	2025
OPCo		Pollution Control Bonds		56,000	5.10	2013
OPCo		Pollution Control Bonds		50,000	5.15	2026
OPCo		Senior Unsecured Notes		250,000	5.50	2013
OPCo		Senior Unsecured Notes		250,000	5.50	2013
PSO		Notes Payable		200	3.00	2027
SWEPCo		Notes Payable		1,625	4.58	2032

In July 2013, the $1 billion term credit facility due in May 2015 was terminated. In July 2013, AEPGenCo, APCo, KPCo and OPCo entered into a $1 billion term credit facility due in May 2015 to provide liquidity during the corporate separation process. Upon entering the new term credit facility, OPCo repaid the $200 million Long-term Debt – Affiliated and subsequently borrowed $200 million under the new credit facility. Under the credit facility, OPCo may assign borrowings to AEPGenCo upon the transfer of OPCo’s generation assets to AEPGenCo. Subject to regulatory approval, AEPGenCo may further assign a portion of the borrowings to APCo and KPCo, not to exceed $500 million and $250 million, respectively, upon AEPGenCo’s subsequent transfer of certain of those generation assets to APCo and KPCo.

In July 2013, I&M retired $12 million of Notes Payable related to DCC Fuel.

In July 2013, OPCo retired $65 million of 4.9% Pollution Control Bonds due in 2037 and issued $65 million of variable rate Pollution Control Bonds due in 2014.

As of June 30, 2013, trustees held on behalf of I&M and OPCo, $40 million and $464 million, respectively, of their reacquired Pollution Control Bonds.

212

Dividend Restrictions

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

Federal Power Act

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

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

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

Leverage Restrictions

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

Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds AEP’s majority of the nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of June 30, 2013 and December 31, 2012 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ condensed balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the six months ended June 30, 2013 are described in the following table:

									Net
									Loans to
	Maximum		Maximum		Average		Average		(Borrowings from)		Authorized
	Borrowings		Loans		Borrowings		Loans		the Utility		Short-term
	from the Utility		to the Utility		from the Utility		to the Utility		Money Pool as of		Borrowing
Company	Money Pool		Money Pool		Money Pool		Money Pool		June 30, 2013		Limit
	(in thousands)
APCo	$	217,174	$	23,871	$	100,093	$	23,478	$	(64,480)	$	600,000
I&M		23,135		355,659		8,308		198,197		273,117		500,000
OPCo		410,456		169,284		241,993		31,664		(281,672)		600,000
PSO		46,806		25,343		20,136		11,603		(25,276)		300,000
SWEPCo		15,386		153,830		4,473		49,757		14,806		350,000

213

The activity in the above table does not include short-term lending activity of OPCo’s wholly-owned subsidiary, AEPGenCo, which is a participant in the Nonutility Money Pool. The amounts of outstanding borrowings from the Nonutility Money Pool as of June 30, 2013 is included in Advances to Affiliates on OPCo’s condensed balance sheet. For the six months ended June 30, 2013, AEPGenCo had the following activity in the Nonutility Money Pool:

Maximum

Average

Borrowings

Loans

Borrowings

Loans

from the Nonutility

to the Nonutility

from the Nonutility

to the Nonutility

Money Pool as of

Money Pool

June 30, 2013

(in thousands)

1,047

1,027

115

208

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

	Six Months Ended June 30,
	2013		2012
Maximum Interest Rate	0.43	%	0.56	%
Minimum Interest Rate	0.32	%	0.45	%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the six months ended June 30, 2013 and 2012 are summarized for all Registrant Subsidiaries in the following table:

	Average Interest Rate				Average Interest Rate
	for Funds Borrowed				for Funds Loaned
	from the Utility Money Pool for				to the Utility Money Pool for
	Six Months Ended June 30,				Six Months Ended June 30,
Company	2013		2012		2013		2012
APCo	0.36	%	0.49	%	0.36	%	0.49	%
I&M	0.36	%	-	%	0.35	%	0.49	%
OPCo	0.35	%	0.47	%	0.37	%	0.51	%
PSO	0.34	%	-	%	0.38	%	0.48	%
SWEPCo	0.34	%	0.53	%	0.37	%	0.48	%

AEPGenCo's m aximum, minimum and average interest rates for funds either borrowed from or loaned to the Nonutility Money Pool for the six months ended June 30, 2013 are summarized in the following table:

Maximum

Minimum

Maximum

Minimum

Average

Interest Rate

for Funds

Six Months

Borrowed from

Loaned to

Borrowed from

Loaned to

Ended

the Nonutility

June 30,

Money Pool

2013

0.61

0.57

0.35

0.32

0.61

0.34

Short-term Debt

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

June 30, 2013

December 31, 2012

Outstanding

Interest

Outstanding

Interest

Company

Type of Debt

Amount

Rate (a)

Amount

Rate (a)

(in thousands)

SWEPCo

Line of Credit – Sabine

2,603

1.82

(a) Weighted average rate.

214

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 4.

Sale of Receivables – AEP Credit

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

In June 2013, AEP Credit amended its receivables securitization agreement. The agreement provides a commitment of $700 million from bank conduits to purchase receivables. AEP Credit amended a commitment of $385 million to now expire in June 2014. The remaining commitment of $315 million expires in June 2015.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of June 30, 2013 and December 31, 2012 was as follows:

	June 30,		December 31,
Company	2013		2012
	(in thousands)
APCo	$	146,352	$	153,719
I&M		139,932		123,447
OPCo		339,389		300,675
PSO		127,497		85,530
SWEPCo		166,278		132,449

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

	Three Months Ended June 30,				Six Months Ended June 30,
Company	2013		2012		2013		2012
	(in thousands)
APCo	$	1,459	$	1,556	$	3,015	$	3,686
I&M		1,530		1,521		2,982		3,064
OPCo		4,695		4,622		9,364		10,538
PSO		1,351		1,825		2,765		3,557
SWEPCo		1,384		1,548		2,764		2,934

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

	Three Months Ended June 30,				Six Months Ended June 30,
Company	2013		2012		2013		2012
	(in thousands)
APCo	$	342,984	$	295,879	$	741,177	$	642,405
I&M		361,417		320,415		713,247		659,996
OPCo		661,959		656,737		1,358,917		1,494,634
PSO		321,620		303,729		561,895		576,524
SWEPCo		389,076		379,114		721,012		700,722

215

12. VARIABLE INTEREST ENTITIES

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.

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

Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended June 30, 2013 and 2012 were $40 million and $36 million, respectively, and for the six months ended June 30, 2013 and 2012 were $84 million and $91 million, respectively. See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets.

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

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
June 30, 2013 and December 31, 2012
(in thousands)
	Sabine
ASSETS	2013		2012
Current Assets	$	65,744	$	56,535
Net Property, Plant and Equipment		163,078		170,436
Other Noncurrent Assets		65,952		55,076
Total Assets	$	294,774	$	282,047

LIABILITIES AND EQUITY
Current Liabilities	$	30,854	$	31,446
Noncurrent Liabilities		263,553		250,340
Equity		367		261
Total Liabilities and Equity	$	294,774	$	282,047

216

the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s condensed balance sheets.

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

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
June 30, 2013 and December 31, 2012
(in thousands)
	DCC Fuel
ASSETS	2013		2012
Current Assets	$	161,377	$	132,886
Net Property, Plant and Equipment		219,101		176,065
Other Noncurrent Assets		104,035		92,473
Total Assets	$	484,513	$	401,424

LIABILITIES AND EQUITY
Current Liabilities	$	142,829	$	120,873
Noncurrent Liabilities		341,684		280,551
Equity		-		-
Total Liabilities and Equity	$	484,513	$	401,424

DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended June 30, 2013 and 2012 were $13 million and $20 million, respectively, and for the six months ended June 30, 2013 and 2012 were $31 million and $34 million, respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheets.

SWEPCo’s investment in DHLC was:

	June 30, 2013				December 31, 2012
	As Reported on		Maximum		As Reported on		Maximum
	the Balance Sheet		Exposure		the Balance Sheet		Exposure
	(in thousands)
Capital Contribution from SWEPCo	$	7,643	$	7,643	$	7,643	$	7,643
Retained Earnings		974		974		946		946
SWEPCo's Guarantee of Debt		-		49,600		-		49,564

Total Investment in DHLC	$	8,617	$	58,217	$	8,589	$	58,153

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

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Total AEPSC billings to the Registrant Subsidiaries were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
Company	2013		2012		2013		2012
	(in thousands)
APCo	$	41,496	$	43,894	$	80,537	$	82,440
I&M		28,706		31,377		56,204		57,484
OPCo		57,351		67,490		111,420		120,935
PSO		19,807		21,301		37,969		38,897
SWEPCo		29,595		33,246		57,075		59,966

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


	June 30, 2013				December 31, 2012
	As Reported on the		Maximum		As Reported on the		Maximum
Company	Balance Sheet		Exposure		Balance Sheet		Exposure
	(in thousands)
APCo	$	12,440	$	12,440	$	29,819	$	29,819
I&M		7,764		7,764		17,911		17,911
OPCo		16,800		16,800		39,323		39,323
PSO		5,380		5,380		13,381		13,381
SWEPCo		8,801		8,801		19,669		19,669

AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo leases the Lawrenceburg Generating Station to OPCo. AEP guarantees all the debt obligations of AEGCo. I&M and OPCo are considered to have a significant interest in AEGCo due to these transactions. I&M and OPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M, OPCo and KPCo, this financing would be provided by AEP. For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 11 in the 2012 Annual Report.

Total billings from AEGCo were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
Company	2013		2012		2013		2012
	(in thousands)
I&M	$	53,191	$	53,917	$	111,726	$	112,739
OPCo		31,910		44,823		70,621		103,239

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



	June 30, 2013				December 31, 2012
	As Reported on		Maximum		As Reported on		Maximum
Company	the Balance Sheet		Exposure		the Balance Sheet		Exposure
	(in thousands)
I&M	$	20,126	$	20,126	$	25,498	$	25,498
OPCo		12,771		12,771		16,302		16,302

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13. SUSTAINABLE COST REDUCTIONS

In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings. Management selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate current employee benefit programs. The process resulted in involuntary severances and was completed by the end of the first quarter of 2013. The severance program provides two weeks of base pay for every year of service along with other severance benefits.

The Registrant Subsidiaries recorded charges to Other Operation expense in 2012 primarily related to severance benefits as a result of the sustainable cost reductions initiative. The total amount incurred in 2012 by Registrant Subsidiary was as follows:

Company	Total Cost Incurred
	(in thousands)
APCo	$	8,472
I&M		5,678
OPCo		13,498
PSO		3,675
SWEPCo		5,709

The Registrant Subsidiaries’ sustainable cost reduction activity for the six months ended June 30, 2013 is described in the following table:

			Expense		Incurred for							Remaining
	Balance as of		Allocation from		Registrant						Balance as of
Company	December 31, 2012		AEPSC		Subsidiaries		Settled		Adjustments		June 30, 2013
	(in thousands)
APCo	$	1,321	$	1,355	$	-	$	(1,908)	$	(735)	$	33
I&M		1,357		953		-		(1,882)		(379)		49
OPCo		3,450		1,834		6,114		(8,413)		(1,648)		1,337
PSO		652		487		-		(642)		(472)		25
SWEPCo		627		864		-		(1,789)		405		107

These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. Management does not expect additional costs to be incurred related to this initiative.

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COMBINED MANAGEMENT’S NARRATIVE DISCUSSION

AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the Registrant Subsidiaries’ management’s discussion and analysis. The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (a) Management’s Narrative Discussion and Analysis of Results of Operations, (b) financial statements, (c) footnotes and (d) the schedules of each individual registrant. The Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries section of the 2012 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

Customer Demand

In comparison to 2012, weather-normalized retail sales across the AEP System were down 2.7% and 2.1% for the three and six months ended June 30, 2013, respectively. Industrial sales across the AEP System declined 5.3% and 5.7%, respectively, partially due to Ormet, OPCo's large aluminum customer that lowered their production in the third quarter of 2012 by one-third and is currently in bankruptcy proceedings.

ENVIRONMENTAL ISSUES

The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with environmental control requirements. The Registrant Subsidiaries will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO 2 , NO x , PM and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.

The Registrant Subsidiaries are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of I&M’s nuclear units. AEP, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court. Management is also engaged in the development of possible future requirements including the items discussed below and reductions of CO 2 emissions to address concerns about global climate change. Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

See a complete discussion of these matters in the “Environmental Issues” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2012 Annual Report. Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Recovery in Ohio will be dependent upon prevailing market conditions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If the costs of environmental compliance are not recovered, it would reduce future net income and cash flows and impact financial condition.

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Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of June 30, 2013, the AEP System had a total generating capacity of 37,600 MWs, of which 23,700 MWs are coal-fired. Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the coal-fired generating facilities. For the Registrant Subsidiaries, management’s current ranges of estimates of environmental investments to comply with these proposed requirements are listed below:

	Through 2020
	Estimated Environmental Investment
Company	Low		High
	(in millions)
APCo	$	330	$	440
I&M		510		610
OPCo		840		1,080
PSO		310		380
SWEPCo		1,430		1,750

For APCo and I&M, the projected environmental investments above include the conversion of 470 MWs and 500 MWs, respectively, of coal generation to natural gas capacity. If natural gas conversion is not completed, the units could be closed sooner than planned.

The preceding discussion of environmental investments and plans for future years reflects the ownership of plants as of June 30, 2013. The AEP East Companies have filed with the FERC to terminate the Interconnection Agreement and for OPCo to transfer facilities to APCo, KPCo and AEPGenCo. Management expects the transfers will be effective December 31, 2013.

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

Subject to the factors listed above and based upon continuing evaluation, management intends 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
OPCo	Kammer Plant		630
OPCo	Muskingum River Plant, Units 1-5		1,440
OPCo	Picway Plant		100
PSO	Northeastern Station, Unit 4		470
SWEPCo	Welsh Plant, Unit 2		528

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In the second quarter of 2013, management re-evaluated potential courses of action with respect to the planned operation of Muskingum River Plant, Unit 5 and concluded that completion of a refueling project which would extend the unit’s useful life is remote. As a result, in the second quarter of 2013, management completed an impairment analysis and recorded a $154 million pretax ($99 million, net of tax) impairment charge for OPCo’s net book value of Muskingum River Plant, Unit 5. Management expects to retire the plant no later than 2015. See “Muskingum River Plant, Unit 5” section of Note 5.

In addition, management is in the process of obtaining permits and other necessary regulatory approvals for either the conversion of some coal units to natural gas or installing emission control equipment on certain units. The following table lists the plants or units that are either awaiting regulatory approval or are still being evaluated by management based on changes in emission requirements and demand for power:

		Generating
Company	Plant Name and Unit	Capacity
		(in MWs)
APCo	Clinch River Plant, Units 1-2		470
I&M/AEGCo/KPCo	Rockport Plant, Units 1-2		2,620
I&M	Tanners Creek Plant, Unit 4		500
PSO	Northeastern Station, Unit 3		460

As of June 30, 2013, the net book values including related inventory and CWIP balances of the plants in the table above were $1.2 billion.

Volatility in natural gas prices, pending environmental rules and other market factors could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of coal-fired units. For regulated plants that may close early, management is seeking regulatory recovery of remaining net book values. 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.

Modification of the New Source Review (NSR) Litigation Consent Decree

Clean Air Act Requirements

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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 SO 2 emissions from affected units in that state. The Arkansas SIP was disapproved and the state is developing a revised submittal. 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 SO 2 and NO x emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states. This rule is being challenged in the U.S. Court of Appeals for the District of Columbia Circuit and its fate is uncertain given developments in the CSAPR litigation.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for PM, SO 2 , NO x and lead, and is currently reviewing the NAAQS for ozone. States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for facilities as a result of those evaluations. Management cannot currently predict the nature, stringency or timing of those requirements.

Notable developments in significant CAA regulatory requirements affecting the Registrant Subsidiaries’ operations are discussed in the following sections.

Cross-State Air Pollution Rule (CSAPR)

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

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

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compliance is required within three years. The AEP System is participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed. In 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards. Revisions to the new source standards consistent with the proposed rule, except for the start-up and shut down provisions, were issued by the Federal EPA in March 2013. The Federal EPA has reopened the public comment period to consider additional changes to the start-up and shut down provisions.

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. Management is concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines. The AEP System is participating in petitions for review filed in the U.S. Court of Appeals for the District of Columbia Circuit by several organizations in which the Registrant Subsidiaries are members. Certain issues related to the standards for new coal-fired units have been severed from the main case and are being held in abeyance pending completion of the Federal EPA’s reconsideration proceeding. The case is proceeding on the remaining issues and briefing was completed in April 2013.

Regional Haze – Affecting PSO

In 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 NO x control measures in the SIP and disapprove the SO 2 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 SO 2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP. 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 November 2012, PSO notified the court that the parties had reached agreement on a settlement 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 Tenth Circuit Court of Appeals is holding the appeal in abeyance pending implementation of the settlement. A revised regional haze SIP has been adopted by the State of Oklahoma and submitted to the Federal EPA for review.

CO 2 Regulation

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In June 2013, President Obama issued a memorandum to the Administrator of the Federal EPA directing the agency to develop and issue a new proposal regulating carbon emissions from new electric generating units in September 2013. A proposal was sent to the Office of Management and Budget for interagency review the following week, but the details of the proposal are not known. The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from existing, modified and reconstructed electric generating units before June 2014, to finalize those standards by June 2015 and to require states to submit revisions to their implementation plans including such standards no later than June 2016. In developing this proposal, the President directed the Federal EPA to directly engage states, leaders in the power sector, labor leaders and other stakeholders, to tailor the regulations to reduce costs, to develop market-based instruments and allow regulatory flexibilities and “assure that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power.” Management cannot currently predict the impact these programs may have on future resource plans or the existing generating fleet, but the costs may be substantial.

The Federal EPA also finalized a rule in June 2012 that retains the current CO 2 emission 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. The AEP System’s generating units are large sources of CO 2 emissions and management will continue to evaluate the permitting obligations in light of these thresholds.

Coal Combustion Residual Rule

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

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Clean Water Act Regulations

In 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress. The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement. Compliance with this standard is required within eight years of the effective date of the final rule. The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment. The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling. Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority. Management is evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at the AEP System’s facilities. In June 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments. Management submitted comments in July 2012. Issuance of a final rule is not expected until November 2013. Management is preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

In addition, the Federal EPA issued an information collection request and is developing revised effluent limitation guidelines for electricity generating facilities. A proposed rule was signed in April 2013 with a final rule expected in 2014. The Federal EPA proposed eight options of increasing stringency and cost for fly ash and bottom ash transport water, scrubber wastewater, leachate from coal combustion byproduct landfills and impoundments and other wastewaters associated with coal-fired generating units, with four labeled preferred options. Certain of the Federal EPA's preferred options have already been implemented or are part of the AEP System’s long-term plans. Management will review the proposal in detail to evaluate whether the plants are currently meeting the proposed limitations, what technologies have been incorporated into the long-range plans and what additional costs might be incurred if the Federal EPA's most stringent options were adopted. Management plans to submit detailed comments to the Federal EPA.

Climate Change

National public policy makers and regulators in the 10 states the Registrant Subsidiaries serve have diverse views on climate change. Management is currently focused on responding to these emerging views with prudent actions, such as improving energy efficiency, investing in developing cost-effective and less carbon-intensive technologies and evaluating assets across a range of plausible scenarios and outcomes. Management is also active participants in a variety of public policy discussions at state and federal levels to assure that proposed new requirements are feasible and the economies of the states served are not placed at a competitive disadvantage.

Several states have adopted programs that directly regulate CO 2 emissions from power plants. The majority of the states where the Registrant Subsidiaries have generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements. Management is taking steps to comply with these requirements.

Certain groups have filed lawsuits alleging that emissions of CO 2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others. The Registrant Subsidiaries have been named in one remaining pending lawsuit, which management is defending. It is not possible to predict the outcome of this lawsuit or its impact on operations or financial condition. See “Carbon Dioxide Public Nuisance Claims” section of Note 4.

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Future federal and state legislation or regulations that mandate limits on the emission of CO 2 would result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force the Registrant Subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets. As a result, mandatory limits could reduce future net income and cash flows and impact financial condition.

For additional information on climate change, other environmental issues and the actions management is taking to address potential impacts, see Part I of the 2012 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters” and “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries.”

ACCOUNTING PRONOUNCEMENTS

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, management cannot determine the impact on the reporting of the Registrant Subsidiaries’ operations and financial position that may result from any such future changes. The FASB is currently working on several projects including revenue recognition, financial instruments, leases, insurance, hedge accounting and consolidation policy. The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.

Item 4. Controls and Procedures

During the second quarter of 2013, management, including the principal executive officer and principal financial officer of each of AEP, APCo, I&M, OPCo, PSO and SWEPCo (collectively, the Registrants), evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of June 30, 2013, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the second quarter of 2013 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 4 incorporated herein by reference.

Item 1A. Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2012 includes a detailed discussion of risk factors. The information presented below amends certain of those risk factors that have been updated and should be read in conjunction with the risk factors and information disclosed in the 2012 Annual Report on Form 10-K.

GENERAL RISKS OF OUR REGULATED OPERATIONS

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

In December 2012, SWEPCo placed the Turk Plant in Arkansas into commercial operation. SWEPCo holds a 73% ownership interest in the 600 MW coal-fired generating facility. SWEPCo had originally intended that the Arkansas jurisdictional share of the Turk Plant (approximately 20%) would become part of the rate base for its retail customers in Arkansas. Following a proceeding at the Arkansas Supreme Court, the APSC issued an order which reversed and set aside a previously granted Certificate of Environmental Compatibility and Public Need. The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the SPP market. SWEPCo has included a request to recover a portion of the costs of the Turk Plant in its base rate case filed in Texas. In addition, in February 2013, the LPSC granted recovery for a portion of the Turk Plant costs in a formula rate filing, subject to refund based on the staff review of the cost of service and prudence review of the Turk Plant. If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant either through retail rates or sales into the SPP market, it could reduce future net income and cash flows and impact financial condition.

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

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects for Cook Plant, Units 1 and 2 intended to ensure the safe and reliable operation of the plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. As of June 30, 2013, I&M has incurred $240 million related to the LCM Project, including AFUDC. In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project. If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

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

In July 2012, SWEPCo filed a request with the PUCT for an annual increase in Texas base rates. A portion of the increase seeks recovery for costs associated with the construction and operation of the Texas jurisdictional share (approximately 33%) of the Turk Plant. In May 2013, the Administrative Law Judge issued a proposal for decision, and added clarifications in July 2013, that made various recommendations including (a) a reduction to both the requested annual base rate increase and the requested return on common equity, (b) the disallowance of the Turk Plant capital costs in excess of the investment and committed costs as of June 2010 plus the cost to retrofit Welsh Plant, Unit 2 which, as of June 30, 2013, SWEPCo estimates could result in a write-off of approximately $74 million (in excess of the $62 million reserve previously recorded related to the Texas capital cost cap) and (c) the exclusion, until SWEPCo’s next Texas base rate case, of the Turk Plant transmission line investment that was not in service at the end of the test year. If SWEPCo cannot recover all of its Texas jurisdictional share of the investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

228

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

In February 2013, the IURC issued an order granting an annual increase in base rates. In March 2013, the Indiana Office of Utility Consumer Counselor filed an appeal of the order with the Indiana Court of Appeals. If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

Request for rate recovery in Kentucky may not be approved in its entirety. – Affecting AEP

In June 2013, KPCo filed a request with the KPSC for annual increases in Kentucky base rates. If the KPSC denies all or part of the requested rate recovery, it could reduce future net income and cash flows and impact financial condition.

RISKS RELATING TO STATE RESTRUCTURING

We are unable to fully predict the effects of the inter-company transfer of OPCo’s generation assets and terminating the Interconnection Agreement, – Affecting AEP, APCo, I&M and OPCo

In October 2012, we submitted several filings with the FERC seeking approval to fully separate OPCo’s generating assets from its distribution and transmission operations. The filings requested approval to transfer approximately 9,200 MW of OPCo-owned generation assets to a new competitive, unregulated generation affiliate. We also requested approval from the FERC and, as applicable, the KPSC, the Virginia SCC and the WVPSC to transfer 1,647 MW of OPCo-owned generation assets to APCo and 780 MW of OPCo-owned generation assets to KPCo. These transfers are proposed to be effective December 31, 2013. The transfer of generation units co-owned by third parties will require the consent and cooperation of those third parties. In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AEPGenCo, the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo and the merger of APCo and WPCo. In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo. OPCo has contested the petition for rehearing, which remains pending before the FERC. Additionally, we asked for FERC approval to terminate the existing Interconnection Agreement and to authorize a new Power Coordination Agreement among APCo, I&M and KPCo. Significant gaps could emerge if the Interconnection Agreement is terminated without approval of the generation asset transfers and/or the new Power Coordination Agreement. Surplus members would no longer automatically sell to deficit members, and they may not be able to otherwise sell that surplus in amounts or at rates equal to what they obtained under the Interconnection Agreement. Conversely, deficit members would no longer automatically purchase from surplus members, and they may not be able to otherwise purchase in amounts or at rates equal to what they obtained under the Interconnection Agreement. The possible loss of these sales by the surplus members and the potential increase in costs for the deficit members could reduce future net income and cash flows. In addition, we can give no assurance that the FERC or other state commissions will not impose material adverse terms as a condition to approving these arrangements and asset transfers. Further, third party co-owners may not consent to the transfers where applicable.

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

Under current Ohio law, electric generation is sold in a competitive market in Ohio and native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service. CRES providers are targeting retail customers by offering alternative generation service. As customer switching in Ohio continues, it could reduce future net income and cash flows and impact financial condition.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None

229

Item 4. Mine Safety Disclosures

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of DHLC, and OPCo, through its ownership of Conesville Coal Preparation Company (CCPC) and use of the Conner Run fly ash impoundment, are subject to the provisions of the Mine Act. OPCo sold CCPC in April 2013. Consequently, this will be the last quarterly report to make reference to CCPC.

The Dodd-Frank Wall Street Reform and Consumer Protection Act and its related regulations require companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 contains the notices of violation and proposed assessments received by DHLC, CCPC and Conner Run under the Mine Act for the quarter ended June 30, 2013.

Item 5. Other Information

None

Item 6. Exhibits

4 – Modification of $1 Billion Term Credit Agreement Dated July 2013

10 – Third Joint Modification to Consent Decree with Order Modifying Consent Decree Dated May 2013

12 – Computation of Consolidated Ratio of Earnings to Fixed Charges

31(a) – Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31(b) – Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32(a) – Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

32(b) – Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

95 – Mine Safety Disclosures

101.INS – XBRL Instance Document

101.SCH – XBRL Taxonomy Extension Schema

101.CAL – XBRL Taxonomy Extension Calculation Linkbase

101.DEF – XBRL Taxonomy Extension Definition Linkbase

101.LAB – XBRL Taxonomy Extension Label Linkbase

101.PRE – XBRL Taxonomy Extension Presentation Linkbase

230

SIGNATURE

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

AMERICAN ELECTRIC POWER COMPANY, INC.

By: /s/ Joseph M. Buonaiuto

Joseph M. Buonaiuto

Controller and Chief Accounting Officer

APPALACHIAN POWER COMPANY

INDIANA MICHIGAN POWER COMPANY

OHIO POWER COMPANY

PUBLIC SERVICE COMPANY OF OKLAHOMA

SOUTHWESTERN ELECTRIC POWER COMPANY

By: /s/ Joseph M. Buonaiuto

Joseph M. Buonaiuto

Controller and Chief Accounting Officer

Date: July 26, 2013

231

TABLE OF CONTENTS

Part I. Financial Informationprint Part II. Other Informationprint Item 1. Legal Proceedings 228print Item 1A. Risk Factors 228print Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds 229print Item 4. Mine Safety Disclosures 230print Item 5. Other Information 230print Item 6. Exhibits: 230print Item 4. Controls and Proceduresprint Item 1. Legal Proceedingsprint Item 1A. Risk Factorsprint Item 2. Unregistered Sales Of Equity Securities and Use Of Proceedsprint Item 4. Mine Safety Disclosuresprint Item 5. Other Informationprint Item 6. Exhibitsprint

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Consolidated Edison, Inc.	ED
FirstEnergy Corp.	FE
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PG&E Corporation	PCG
Pinnacle West Capital Corporation	PNW
PPL Corporation	PPL
Sempra Energy	SRE
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Xcel Energy Inc.	XEL

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Duke Energy Corporation	DUK
General Electric Company	GE
The Southern Company	SO
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Eaton Corporation plc	ETN
Honeywell International Inc.	HON
Union Pacific Corporation	UNP
CSX Corporation	CSX

AEP 10-Q Quarter ended June 30, 2013