AMERICAN ELECTRIC POWER CO INC (Form: 10-Q, Received: 07/26/2013 11:45:52)

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)

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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.

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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

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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.

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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.

178

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

184

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.

186

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		-		-

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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.

217

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

218

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

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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

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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

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Exhibit 4

U.S. $1,000,000,000

TERM CREDIT AGREEMENT

Dated as of July 17, 2013

among

OHIO POWER COMPANY

AEP GENERATION RESOURCES INC.

APPALACHIAN POWER COMPANY

KENTUCKY POWER COMPANY

as the Borrowers

AMERICAN ELECTRIC POWER COMPANY, INC.

as the Guarantor

THE LENDERS NAMED HEREIN

as Initial Lenders

and

WELLS FARGO BANK, NATIONAL ASSOCIATION

as Administrative Agent

WELLS FARGO SECURITIES, LLC

THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.

J.P. MORGAN SECURITIES LLC

CITIGROUP GLOBAL MARKETS INC.

KEYBANK NATIONAL ASSOCIATION

RBS SECURITIES INC.

Joint Lead Arrangers and Bookrunners

THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.

Syndication Agent

JPMORGAN CHASE BANK, N.A.

CITIBANK, N.A.

KEYBANK NATIONAL ASSOCIATION

THE ROYAL BANK OF SCOTLAND FINANCE (IRELAND)

Documentation Agents

	TABLE OF CONTENTS
		Page
Article I DEFINITIONS AND ACCOUNTING TERMS		1
	Section 1.01. Certain Defined Terms.	1
	Section 1.02. Computation of Time Periods.	20
	Section 1.03. Accounting Terms.	20
	Section 1.04. Other Interpretive Provisions.	20
Article II AMOUNTS AND TERMS OF THE ADVANCES		20
	Section 2.01. The Advances.	20
	Section 2.02. Making the Advances.	21
	Section 2.03. Fees.	22
	Section 2.04. Termination or Reduction of the Commitments.	23
	Section 2.05. Repayment of Advances.	23
	Section 2.06. Evidence of Indebtedness.	23
	Section 2.07. Interest on Advances.	24
	Section 2.08. Interest Rate Determination.	25
	Section 2.09. Optional Conversion of Advances.	25
	Section 2.10. Prepayments of Advances.	26
	Section 2.11. Increased Costs.	27
	Section 2.12. Illegality.	28
	Section 2.13. Payments and Computations.	28
	Section 2.14. Taxes.	29
	Section 2.15. Sharing of Payments, Etc.	33
	Section 2.16. Mitigation Obligations; Replacement of Lenders.	34
	Section 2.17. Assumption of Obligations.	35
Article III CONDITIONS PRECEDENT		36
	Section 3.01. Conditions Precedent to Effectiveness of this Agreement and Initial Advance.	36
	Section 3.02. Conditions Precedent to each Advance.	38
Article IV REPRESENTATIONS AND WARRANTIES		38
	Section 4.01. Representations and Warranties of the Loan Parties.	38
Article V COVENANTS OF THE LOAN PARTIES		41
	Section 5.01. Affirmative Covenants.	41
	Section 5.02. Negative Covenants.	44
	Section 5.03. Financial Covenant.	47
Article VI GUARANTY		47

	Section 6.01. Guaranty.	47
	Section 6.02. Guaranty Absolute and Unconditional.	47
	Section 6.03. Authorization; Other Agreements.	48
	Section 6.04. Independent Obligations.	48
	Section 6.05. Waivers.	48
	Section 6.06. Limitation of Parent Guaranty.	49
	Section 6.07. Termination.	50
	Section 6.08. Reliance.	50
Article VII EVENTS OF DEFAULT		50
	Section 7.01. Events of Default.	50
Article VIII THE ADMINISTRATIVE AGENT		53
	Section 8.01. Authorization and Action.	53
	Section 8.02. Agent’s Reliance, Etc.	53
	Section 8.03. Wells Fargo and its Affiliates.	54
	Section 8.04. Lender Credit Decision.	54
	Section 8.05. Indemnification.	54
	Section 8.06. Successor Agent.	55
Article IX MISCELLANEOUS		56
	Section 9.01. Amendments, Etc.	56
	Section 9.02. Notices, Etc.	56
	Section 9.03. No Waiver; Remedies.	58
	Section 9.04. Costs and Expenses.	58
	Section 9.05. Right of Set-off.	60
	Section 9.06. Binding Effect.	61
	Section 9.07. Assignments and Participations.	61
	Section 9.08. Confidentiality.	65
	Section 9.09. Governing Law.	65
	Section 9.10. Severability; Survival.	66
	Section 9.11. Execution in Counterparts.	66
	Section 9.12. Jurisdiction, Etc.	66
	Section 9.13. Waiver of Jury Trial.	67
	Section 9.14. USA Patriot Act.	67
	Section 9.15. No Fiduciary Duty.	67
	Section 9.16. Defaulting Lenders.	68

EXHIBITS AND SCHEDULES

EXHIBIT A -----------	Form of Notice of Borrowing
EXHIBIT B -----------	Form of Assignment and Assumption
EXHIBIT C -----------	Form of Opinion of Counsel for the Loan Parties
EXHIBIT D -----------	Form of Opinion of Counsel for the Administrative Agent
EXHIBIT E-1 -----------	Form of U.S. Tax Compliance Certificate (For Foreign Lenders That Are Not Partnerships For U.S. Federal Income Tax Purposes)
EXHIBIT E-2 -----------	Form of U.S. Tax Compliance Certificate (For Foreign Participants That Are Not Partnerships For U.S. Federal Income Tax Purposes)
EXHIBIT E-3 -----------	Form of U.S. Tax Compliance Certificate (For Foreign Participants That Are Partnerships For U.S. Federal Income Tax Purposes)
EXHIBIT E-4 -----------	Form of U.S. Tax Compliance Certificate (For Foreign Lenders That Are Partnerships For U.S. Federal Income Tax Purposes)
EXHIBIT F -----------	Form of Borrower Assumption Agreement


SCHEDULE I ----------	Schedule of Initial Lenders
SCHEDULE 4.01(m) ---	Schedule of Significant Subsidiaries

TERM CREDIT AGREEMENT

TERM CREDIT AGREEMENT, dated as of July 17, 2013 (this “ Agreement ”), among OHIO POWER COMPANY, an Ohio corporation (“ OPCo ”), AEP GENERATION RESOURCES INC., a Delaware corporation (“ AGR ”), APPALACHIAN POWER COMPANY, a Virginia corporation (“ APCo ”), KENTUCKY POWER COMPANY, a Kentucky corporation (“ KPCo ”, and collectively with OPCo, AGR and APCo, the “ Borrowers ” and each a “ Borrower ”), AMERICAN ELECTRIC POWER COMPANY, INC., a New York corporation (“ AEP ” or the “ Guarantor ”), the banks, financial institutions and other institutional lenders listed on the signatures pages hereof (the “ Initial Lenders ”) and WELLS FARGO BANK, NATIONAL ASSOCIATION (“ Wells Fargo ”), as administrative agent (in such capacity, the “ Administrative Agent ”) for the Lenders (as hereinafter defined).

PRELIMINARY STATEMENT:

The Borrowers have requested that the Lenders agree, on the terms and conditions set forth herein, to provide the Borrowers a $1,000,000,000 delayed draw term loan credit facility to be used for general corporate purposes, including, without limitation, the refinancing of existing Debt. The Lenders have indicated their willingness to provide such a facility on the terms and conditions of this Agreement.

NOW, THEREFORE, in consideration of the premises and of the mutual covenants and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS AND ACCOUNTING TERMS

SECTION 1.01. Certain Defined Terms.

As used in this Agreement, the following terms shall have the following meanings (such meanings to be equally applicable to both the singular and plural forms of the terms defined):

“ Administrative Agent ” has the meaning specified in the recital of parties to this Agreement.

“ Administrative Questionnaire ” means an administrative questionnaire in a form supplied by the Administrative Agent.

“ Advance ” means an advance by a Lender to OPCo as part of a Borrowing and refers to a Base Rate Advance or a Eurodollar Rate Advance, as such advance may be assumed by the other Borrowers from time to time pursuant to Section 2.17.

“ AEP ” has the meaning specified in the recital of parties to this Agreement.

“ Affiliate ” means, as to any Person, any other Person that, directly or indirectly, controls, is controlled by or is under common control with such Person or is a director or officer of such Person. For purposes of this definition, the term “control” (including the terms “controlling”, “controlled by” and “under common control with”) of a Person

means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of Voting Stock, by contract or otherwise.

“ Agent Parties ” has the meaning specified in Section 9.02(c).

“ Agent’s Account ” means the account of the Administrative Agent maintained by the Administrative Agent with Wells Fargo at its office located at 1525 West W.T. Harris Blvd, 1B1, Charlotte, North Carolina 28262, MAC D1109-019, ABA Number: 121000248, Account Name: AGENCY SERVICES CLEARING A/C, Account No. 01104331628807, Reference: Ohio Power Company, or such other account of the Administrative Agent as the Administrative Agent may from time to time designate in a written notice to the Lenders and the Borrowers.

“ AGR ” has the meaning specified in the recital of parties to this Agreement.

“ AGR Assumption ” has the meaning specified in Section 2.17(a).

“ AGR Transfer ” means the transfer from OPCo to AGR of certain generation assets with a generation capacity of approximately 9,200 MW, as described in FERC Docket No. EC13-26-000.

“ APCo ” has the meaning specified in the recital of parties to this Agreement.

“ APCo Assumption ” has the meaning specified in Section 2.17(b).

“ APCo Transfer ” means the transfer from AGR to APCo of (i) all AGR’s interest in the Amos Plant Unit 3 with a generation capacity of approximately 867 MW and (ii) 50% of its interest in Mitchell Plant with a generation capacity of approximately 780 MW.

“ Applicable Law ” means (i) all applicable common law and principles of equity and (ii) all applicable provisions of all (A) constitutions, statutes, rules, regulations and orders of governmental bodies, (B) Governmental Approvals and (C) orders, decisions, judgments and decrees of all courts (whether at law or in equity or admiralty) and arbitrators.

“ Applicable Lending Office ” means, with respect to each Lender, such Lender’s Domestic Lending Office in the case of a Base Rate Advance and such Lender’s Eurodollar Lending Office in the case of a Eurodollar Rate Advance.

“ Applicable Margin ” means, with respect to any Base Rate Advance and any Eurodollar Rate Advance owing by any Borrower, at all times during which any Applicable Rating Level of such Borrower set forth below is in effect, the rate per annum (except as provided below) for such Type of Advance set forth below next to such Applicable Rating Level of such Borrower:

Applicable Rating Level	Applicable Margin for Eurodollar Rate Advances	Applicable Margin for Base Rate Advances
1	0.875%	0.000%
2	0.875%	0.000%
3	1.000%	0.000%
4	1.250%	0.250%
5	1.500%	0.500%
6	1.875%	0.875%

provided , that the Applicable Margins set forth above shall be increased, for each Applicable Rating Level, upon the occurrence and during the continuance of any Event of Default by 2.00% per annum.

Any change in the Applicable Margin resulting from a change in the Applicable Rating Level shall become effective upon the date of announcement of any change in the Moody’s Rating or the S&P Rating that results in such change in the Applicable Rating Level.

“ Applicable Rating Level ” with respect to any Borrower at any time shall be determined in accordance with the then-applicable S&P Rating of such Borrower (other than with respect to AGR, whose Applicable Rating Level shall be determined in accordance with the then-applicable S&P Rating of AEP) and the then-applicable Moody’s Rating of such Borrower (other than with respect to AGR, whose Applicable Rating Level shall be determined in accordance with the then-applicable Moody’s Rating of AEP) as follows:

S&P Rating/Moody’s Rating	Applicable Rating Level
S&P Rating A or higher or Moody’s Rating A2 or higher	1
S&P Rating A- or Moody’s Rating A3	2
S&P Rating BBB+ or Moody’s Rating Baa1	3
S&P Rating BBB or Moody’s Rating Baa2	4
S&P Rating BBB- or Moody’s Rating Baa3	5
S&P Rating BB+ or below or Moody’s Rating Ba1 or below, or no S&P Rating or Moody’s Rating	6

The Applicable Rating Level for any day shall be determined based upon the higher of the S&P Rating and the Moody’s Rating in effect on such day. If the S&P Rating and the Moody’s Rating are not the same ( i.e. , a “split rating”), the higher of such ratings shall control, unless (i) the ratings differ by more than one level, in which case the rating one

level below the higher of the two ratings shall control, or (ii) either rating is below BBB- or Baa3 (as applicable), in which case the lower of the two ratings shall control.

“ Approval ” means, with respect to each Borrower, the approvals of FERC, the Public Utilities Commission of Ohio, the Virginia State Corporation Commission, the Kentucky Public Service Commission and the West Virginia Public Service Commission, as applicable.

“ Approved Fund ” means any Fund that is administered or managed by (i) a Lender, (ii) an Affiliate of a Lender or (iii) an entity or an Affiliate of an entity that administers or manages a Lender.

“ Assignment and Assumption ” means an assignment and assumption entered into by a Lender and an Eligible Assignee (with the consent of any party whose consent is required by Section 9.07), and accepted by the Administrative Agent, in substantially the form of Exhibit B hereto or any other form approved by the Administrative Agent.

“ Availability Termination Date ” means the earliest of (i) the date all Commitments have been fully advanced pursuant to Section 2.02, (ii) the date all Commitments have been terminated pursuant to Section 2.04 or 7.01, (iii) the date of the AGR Assumption and (iv) February 13, 2014.

“ Available Commitment ” means, for each Lender at any time on any day, the unused portion of such Lender’s Commitment, computed after giving effect to all Advances made or to be made on such day and the application of proceeds therefrom.

“ Available Commitments ” means the aggregate of the Lenders’ Available Commitments hereunder.

“ Bankruptcy Event ” means, with respect to any Person, such Person becomes the subject of a proceeding under any Debtor Relief Law, or has had a receiver, custodian, conservator, trustee, administrator, assignee for the benefit of creditors or similar Person charged with reorganization or liquidation of its business or assets (including the Federal Deposit Insurance Corporation or any other Governmental Authority acting in a similar capacity) appointed for it, or, in the good faith determination of the Administrative Agent, has taken any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any such proceeding or appointment; provided that, a Bankruptcy Event shall not result solely by virtue of any ownership interest, or acquisition of any equity interest, in such Person by a Governmental Authority so long as such ownership interest does not result in or provide such Person with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Person (or such Governmental Authority) to reject, repudiate, disavow or disaffirm obligations under any agreement in which it commits to extend credit.

“ Base Rate ” means a fluctuating interest rate per annum in effect from time to time, which rate per annum shall at all times be equal to the highest of the following rates then in effect:

(i)	the rate of interest announced publicly by Wells Fargo in Charlotte, North Carolina, from time to time, as Wells Fargo’s prime commercial lending rate or corporate base rate;

(ii)	1/2 of 1% per annum above the Federal Funds Rate; and

(iii)

the rate of interest per annum equal to the Eurodollar Rate as determined on such day (or if such day is not a Business Day, on the next preceding Business Day) that would be applicable to a Eurodollar Rate Advance having an Interest Period of one month, plus 1%.

“ Base Rate Advance ” means an Advance that bears interest as provided in Section 2.07(a).

“ Borrower Assumption Agreement ” means an assumption agreement in substantially the form of Exhibit F hereto or any other form approved by the Administrative Agent.

“ Borrowers ” has the meaning specified in the recital of parties to this Agreement.

“ Borrowing ” means a borrowing by a Borrower consisting of simultaneous Advances of the same Type, having the same Interest Period and ratably made or Converted on the same day by each of the Lenders pursuant to Section 2.02 or 2.09, as the case may be. All Advances to a Borrower of the same Type, having the same Interest Period and made or Converted on the same day shall be deemed a single Borrowing hereunder until repaid or next Converted.

“ Borrowing Date ” means the date of any Borrowing.

“ BTMU ” means The Bank of Tokyo-Mitsubishi UFJ, Ltd.

“ Business Day ” means a day of the year on which banks are not required or authorized by law to close in New York City and, if the applicable Business Day relates to any Eurodollar Rate Advances, Business Day also includes a day on which dealings are carried out in the London interbank market.

“ Change in Law ” means the occurrence, after the date of this Agreement, of any of the following: (a) the adoption or taking effect of any law, rule, regulation or treaty, (b) any change in any law, rule, regulation or treaty or in the administration, interpretation, implementation or application thereof by any Governmental Authority or (c) the making or issuance of any request, rule, guideline or directive (whether or not having the force of law) by any Governmental Authority; provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities,

in each case pursuant to Basel III, shall in each case be deemed to be a “Change in Law”, regardless of the date enacted, implemented, adopted or issued.

“ Closing Date ” means July 17, 2013.

“ Commitment ” means, for each Lender, the obligation of such Lender to make Advances to OPCo in an aggregate amount no greater than the amount set forth on Schedule I hereto or, if such Lender has entered into any Assignment and Assumption, set forth for such Lender in the Register maintained by the Administrative Agent pursuant to Section 9.07(c), in each such case as such amount may be reduced from time to time pursuant to Section 2.04.

“ Commitment Fee Rate ” means, at any time, the rate per annum set forth below next to the Applicable Rating Level of OPCo in effect at such time:

Applicable Rating Level	Commitment Fee Rate
1	0.125%
2	0.125%
3	0.150%
4	0.200%
5	0.250%
6	0.300%

A change in the Commitment Fee Rate resulting from a change in the Applicable Rating Level of OPCo shall become effective upon the date of public announcement of a change in the Moody’s Rating of OPCo or the S&P Rating of OPCo that results in a change in the Applicable Rating Level.

“ Commitment Percentage ” means, as to any Lender as of any date of determination, the percentage describing such Lender’s pro rata share of the Commitments set forth in the Register from time to time; provided that in the case of Section 9.16 when a Defaulting Lender shall exist, “ Commitment Percentage ” means the percentage of the total Commitments (disregarding any Defaulting Lender’s Commitment) represented by such Lender’s Commitment. If the Commitments have terminated or expired, the Commitment Percentages shall be determined based upon the Commitments most recently in effect, giving effect to any assignments and to any Lender’s status as a Defaulting Lender at the time of determination.

“ Commitments ” means the aggregate of the Lenders’ Commitments hereunder.

“ Communications ” has the meaning specified in Section 9.02(b).

“ Confidential Information ” means information that a Loan Party furnishes to the Administrative Agent, the Joint Lead Arrangers or any Lender in a writing designated as confidential, but does not include any such information that is or becomes generally

available to the public or that is or becomes available to the Administrative Agent, the Joint Lead Arrangers or such Lender from a source other than the Loan Parties.

“ Connection Income Taxes ” means Other Connection Taxes that are imposed on or measured by overall gross receipts or income, or net income (however denominated) or that are franchise Taxes, privilege Taxes, license Taxes or branch profits Taxes.

“ Consolidated Capital ” means, with respect to any Loan Party at any date of determination, the sum of (i) Consolidated Debt of such Loan Party and (ii) the consolidated equity of all classes of stock (whether common, preferred, mandatorily convertible preferred or preference) of such Loan Party and its Consolidated Subsidiaries, in each case determined in accordance with GAAP, but including Equity-Preferred Securities issued by such Loan Party and its Consolidated Subsidiaries and excluding the funded pension and other postretirement benefit plans, net of tax, components of accumulated other comprehensive income (loss).

“ Consolidated Debt ” of any Loan Party means the total principal amount of all Debt described in clauses (i) through (v) of the definition of Debt and Guaranties of such Debt of such Loan Party and its Consolidated Subsidiaries, excluding, however, (i) Debt of AEP Credit, Inc. that is non-recourse to such Loan Party, (ii) Stranded Cost Recovery Bonds, and (iii) Equity-Preferred Securities not to exceed 10% of Consolidated Capital of such Loan Party and its Consolidated Subsidiaries (calculated for purposes of this clause without reference to any Equity-Preferred Securities); provided that Guaranties of Debt included in the total principal amount of Consolidated Debt shall not be added to such total principal amount.

“ Consolidated Subsidiary ” means, with respect to any Person at any time, any Subsidiary or other Person the accounts of which would be consolidated with those of such first Person in its consolidated financial statements in accordance with GAAP.

“ Consolidated Tangible Net Assets ” means, on any date of determination and with respect to any Person at any time, the total of all assets (including revaluations thereof as a result of commercial appraisals, price level restatement or otherwise) appearing on the consolidated balance sheet of such Person and its Consolidated Subsidiaries most recently delivered to the Lenders pursuant to Section 5.01(i) as of such date of determination, net of applicable reserves and deductions, but excluding goodwill, trade names, trademarks, patents, unamortized debt discount and all other like intangible assets (which term shall not be construed to include such revaluations), less the aggregate of the consolidated current liabilities of such Person and its Consolidated Subsidiaries appearing on such balance sheet.

“ Convert ”, “ Conversion ” and “ Converted ” each refers to a conversion of Advances of one Type into Advances of the other Type, or the selection of a new, or the renewal of the same, Interest Period for Eurodollar Rate Advances, pursuant to Section 2.08 or 2.09.

“ Credit Party ” means the Administrative Agent or any Lender.

“ CGMI ” means Citigroup Global Markets Inc.

“ Debt ” of any Person means, without duplication, (i) all indebtedness of such Person for borrowed money, (ii) all obligations of such Person for the deferred purchase price of property or services (other than trade payables not overdue by more than 60 days incurred in the ordinary course of such Person’s business), (iii) all obligations of such Person evidenced by notes, bonds, debentures or other similar instruments, (iv) all obligations of such Person as lessee under leases that have been, in accordance with GAAP, recorded as capital leases, including, without limitation, the leases described in clause (iv) of Section 5.02(c), (v) all obligations of such Person in respect of reimbursement agreements with respect to acceptances, letters of credit (other than trade letters of credit) or similar extensions of credit, (vi) all Guaranties and (vii) all reasonably quantifiable obligations under indemnities or under support or capital contribution agreements, and other reasonably quantifiable obligations (contingent or otherwise) to purchase or otherwise to assure a creditor against loss in respect of, or to assure an obligee against loss in respect of, all Debt of others referred to in clauses (i) through (vi) above guaranteed directly or indirectly in any manner by such Person, or in effect guaranteed directly or indirectly by such Person through an agreement (A) to pay or purchase such Debt or to advance or supply funds for the payment or purchase of such Debt, (B) to purchase, sell or lease (as lessee or lessor) property, or to purchase or sell services, primarily for the purpose of enabling the debtor to make payment of such Debt or to assure the holder of such Debt against loss, (C) to supply funds to or in any other manner invest in the debtor (including any agreement to pay for property or services irrespective of whether such property is received or such services are rendered) or (D) otherwise to assure a creditor against loss.

“ Debtor Relief Laws ” means the Bankruptcy Code of the United States of America, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization, or similar debtor relief laws of the United States or other applicable jurisdictions from time to time in effect.

“ Default ” means any Event of Default or any event that would constitute an Event of Default but for the requirement that notice be given or time elapse or both.

“ Defaulting Lender ” means, subject to Section 9.16(b), any Lender that (i) has failed to (A) fund all or any portion of its Advances within two Business Days of the date such Advances were required to be funded hereunder unless such Lender notifies the Administrative Agent and the Borrowers in writing that such failure is the result of such Lender’s good faith determination that one or more conditions precedent to funding (each of which conditions precedent, together with any applicable Default, shall be specifically identified in such writing) has not been satisfied, or (B) pay to any Credit Party any other amount required to be paid by it hereunder within two Business Days of the date when due, (ii) has notified any Borrower or any Credit Party in writing that it does not intend to comply with its funding obligations hereunder or generally under other agreements in which it commits to extend credit, or has made a public statement to that effect (unless such writing or public statement relates to such Lender’s obligation to fund an Advance

hereunder and states that such position is based on such Lender’s good faith determination that a condition precedent to funding (which condition precedent, together with any applicable Default, shall be specifically identified in such writing or public statement) cannot be satisfied), (iii) has failed, within three Business Days after written request by the Administrative Agent or any Borrower, to confirm in writing to the Administrative Agent and such Borrower that it will comply with its prospective funding obligations hereunder ( provided that, such Lender shall cease to be a Defaulting Lender pursuant to this clause (iii) upon receipt of such written confirmation by the Administrative Agent and such Borrower), or (iv) has become the subject of a Bankruptcy Event. Any determination by the Administrative Agent that a Lender is a Defaulting Lender under any one or more of clauses (i) through (iv) above shall be conclusive and binding absent manifest error, and such Lender shall be deemed to be a Defaulting Lender (subject to Section 9.16(b)) upon delivery of written notice of such determination to the Borrowers and each Lender.

“ Disclosure Documents ” means (i) with respect to AEP, OPCo and APCo, AEP’s Annual Report on Form 10-K, as filed with the SEC, for the fiscal year ended December 31, 2012, Quarterly Report on Form 10-Q, as filed with the SEC, for the period ended March 31, 2013, and Current Reports on Form 8-K, as filed with the SEC after the date of filing of the Quarterly Report on Form 10-Q for the period ended March 31, 2013 but prior to the date hereof, and (ii) with respect to KPCo, its Annual Report for the fiscal year ended December 31, 2012 and its Quarterly Report for the period ended March 31, 2013, with, in each case, any accompanying notes, all prepared in accordance with GAAP and as filed on AEP’s website.

“ Dollars ” and the symbol “$” mean lawful currency of the United States of America.

“ Domestic Lending Office ” means, with respect to any Lender, the office of such Lender specified as its “Domestic Lending Office” on such Lender’s Administrative Questionnaire or in the Assignment and Assumption pursuant to which it became a Lender, or such other office of such Lender as such Lender may from time to time specify in writing to the Borrowers and the Administrative Agent.

“ Eligible Assignee ” means any Person that meets the requirements to be an assignee under Section 9.07(b)(iii), (v) and (vi) (subject to such consents, if any, as may be required under Section 9.07(b)(iii)).

“ Environmental Action ” means any action, suit, demand, demand letter, claim, notice of non-compliance or violation, notice of liability or potential liability, investigation, proceeding, consent order or consent agreement relating in any way to any Environmental Law, Environmental Permit or Hazardous Materials or arising from alleged injury or threat of injury to health, safety or the environment, including, without limitation, (i) by any Governmental Authority for enforcement, cleanup, removal, response, remedial or other actions or damages and (ii) by any Governmental Authority or any third party for damages, contribution, indemnification, cost recovery, compensation or injunctive relief.

“ Environmental Law ” means any federal, state, local or foreign statute, law, ordinance, rule, regulation, code, order, judgment, decree or judicial or agency interpretation, policy or guidance relating to pollution or protection of the environment, health, safety or natural resources, including, without limitation, those relating to the use, handling, transportation, treatment, storage, disposal, release or discharge of Hazardous Materials.

“ Environmental Permit ” means any permit, approval, identification number, license or other authorization required under any Environmental Law.

“ Equity-Preferred Securities ” means (i) debt or preferred securities that are mandatorily convertible or mandatorily exchangeable into common shares of a Loan Party and (ii) any other securities, however denominated, including but not limited to hybrid capital and trust originated preferred securities, (A) issued by a Loan Party or any Consolidated Subsidiary of a Loan Party, (B) that are not subject to mandatory redemption or the underlying securities, if any, of which are not subject to mandatory redemption, (C) that are perpetual or mature no less than 30 years from the date of issuance, (D) the indebtedness issued in connection with which, including any guaranty, is subordinate in right of payment to the unsecured and unsubordinated indebtedness of the issuer of such indebtedness or guaranty, and (E) the terms of which permit the deferral of the payment of interest or distributions thereon to a date occurring after the Termination Date.

“ ERISA ” means the Employee Retirement Income Security Act of 1974, as amended from time to time, and the regulations promulgated and rulings issued thereunder.

“ ERISA Affiliate ” means, with respect to any Person, each trade or business (whether or not incorporated) that is considered to be a single employer with such entity within the meaning of Section 414(b), (c), (m) or (o) the Internal Revenue Code.

“ ERISA Event ” means (i) the termination of or withdrawal from any Plan by a Loan Party or any of its ERISA Affiliates, (ii) the failure by a Loan Party or any of its ERISA Affiliates to comply with ERISA or the related provisions of the Internal Revenue Code with respect to any Plan or (iii) the failure by a Loan Party or any of its Subsidiaries to comply with Applicable Law with respect to any Foreign Plan.

“ Eurocurrency Liabilities ” has the meaning assigned to that term in Regulation D of the Board of Governors of the Federal Reserve System, as in effect from time to time.

“ Eurodollar Lending Office ” means, with respect to any Lender, the office of such Lender specified as its “Eurodollar Lending Office” on such Lender’s Administrative Questionnaire or in the Assignment and Assumption pursuant to which it became a Lender (or, if no such office is specified, its Domestic Lending Office), or such other office of such Lender as such Lender may from time to time specify in writing to the Borrowers and the Administrative Agent.

“ Eurodollar Rate ” means, for any Interest Period for each Eurodollar Rate Advance comprising part of the same Borrowing, an interest rate per annum equal to the rate of interest per annum (rounded upward to the nearest 1/16 of 1%) appearing on Reuters Screen LIBOR01 Page (or any successor page of such service, or any comparable page of another recognized interest rate reporting service then being used generally by the Administrative Agent to obtain such interest rate quotes) as the London interbank offered rate for deposits in Dollars at approximately 11:00 A.M. (London time) two Business Days before the first day of such Interest Period for a period equal to such Interest Period. If, for any reason, such rate is not available, the term “ Eurodollar Rate ” means an interest rate per annum equal to the average rate per annum (rounded upward to the nearest 1/16 of 1%) at which deposits in Dollars are offered by the Reference Banks to prime banks in the London interbank market at 11:00 A.M. (London time) two Business Days before the first day of such Interest Period in an amount substantially equal to the Reference Banks’ pro rata share of such Borrowing to be outstanding during such Interest Period and for a period equal to such Interest Period.

“ Eurodollar Rate Advance ” means an Advance that bears interest as provided in Section 2.07(b).

“ Eurodollar Rate Reserve Percentage ” of any Lender for any Interest Period for each Eurodollar Rate Advance means the reserve percentage applicable to such Lender during such Interest Period (or if more than one such percentage shall be so applicable, the daily average of such percentages for those days in such Interest Period during which any such percentage shall be so applicable) under regulations issued from time to time by the Board of Governors of the Federal Reserve System (or any successor) for determining the maximum reserve requirement (including, without limitation, any emergency, supplemental or other marginal reserve requirement) then applicable to such Lender with respect to liabilities or assets consisting of or including Eurocurrency Liabilities (or with respect to any other category of liabilities that includes deposits by reference to which the interest rate on Eurodollar Rate Advances is determined) having a term equal to such Interest Period.

“ Event of Default ” has the meaning specified in Section 7.01.

“ Exchange Act ” has the meaning specified in Section 7.01(f).

“ Excluded Taxes ” means any of the following Taxes imposed on or with respect to a Recipient or required to be withheld or deducted from a payment to a Recipient, (a) Taxes imposed on or measured by overall gross receipts or income, or net income (however denominated), franchise Taxes, privilege Taxes, license Taxes or branch profits Taxes, in each case, (i) imposed as a result of such Recipient being organized under the laws of, or having its principal office or, in the case of any Lender, its Applicable Lending Office located in, the jurisdiction imposing such Tax (or any political subdivision thereof) or (ii) that are Other Connection Taxes, (b) in the case of a Lender, U.S. federal withholding Taxes imposed on amounts payable to or for the account of such Lender with respect to an applicable interest in an Advance or Commitment pursuant to a law in effect on the date on which (i) such Lender acquires such interest in the Advance

or Commitment (other than pursuant to an assignment request by a Borrower under Section 2.16(b)) or (ii) such Lender changes its Applicable Lending Office, except in each case to the extent that, pursuant to Section 2.14, amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such Lender became a party hereto or to such Lender immediately before it changed its Applicable Lending Office, (c) Taxes attributable to such Recipient’s failure to comply with Section 2.14(g) and (d) any U.S. federal withholding Taxes imposed under FATCA.

“ Existing Credit Agreement ” means the Term Credit Agreement, dated as of February 13, 2013, among AEP, the lenders party thereto and Wells Fargo, as administrative agent.

“ FATCA ” means Sections 1471 through 1474 of the Internal Revenue Code, as of the date of this Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future regulations or official interpretations thereof, and any agreements entered into pursuant to Section 1471(b)(1) of the Internal Revenue Code.

“ Federal Funds Rate ” means, for any period, a fluctuating interest rate per annum equal for each day during such period to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published for such day (or, if such day is not a Business Day, for the next preceding Business Day) by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average of the quotations for such day on such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it.

“ FERC ” means the Federal Energy Regulatory Commission.

“ Foreign Lender ” means a Lender that is not a U.S. Person.

“ Foreign Plan ” has the meaning specified in Section 4.01(i).

“ Fraction ” means, for any Borrower at any time, a fraction, the numerator of which shall be the aggregate amount of outstanding Advances owing by such Borrower at such time, and the denominator of which shall be the sum of all outstanding Advances at such time.

“ Fund ” means any Person (other than a natural Person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its activities.

“ GAAP ” has the meaning specified in Section 1.03.

“ Governmental Approval ” means any authorization, consent, approval, license or exemption of, registration or filing with, or report or notice to, any Governmental Authority.

“ Governmental Authority ” means the government of the United States of America or any other nation, or of any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government (including any supra-national bodies such as the European Union or the European Central Bank).

“ Guarantor ” has the meaning specified in the recital of parties to this Agreement.

“ Guaranty ” of any Person means any obligation, contingent or otherwise, of such Person (i) to pay any Debt of any other Person or (ii) incurred in connection with the issuance by a third person of a Guaranty of Debt of any other Person (whether such obligation arises by agreement to reimburse or indemnify such third Person or otherwise).

“ Guaranteed Obligations ” shall have the meaning specified in Section 6.01.

“ Hazardous Materials ” means (i) petroleum and petroleum products, byproducts or breakdown products, radioactive materials, asbestos-containing materials, polychlorinated biphenyls and radon gas and (ii) any other chemicals, materials or substances designated, classified or regulated as hazardous or toxic or as a pollutant or contaminant under any Environmental Law.

“ Indemnified Party ” has the meaning specified in Section 9.04(b).

“ Indemnified Taxes ” means (a) Taxes, other than Excluded Taxes, imposed on or with respect to any payment made by or on account of any obligation of any Loan Party under any Loan Document and (b) to the extent not otherwise described in (a), Other Taxes.

“ Initial Lenders ” has the meaning specified in the recital of parties to this Agreement.

“ Interest Period ” means, for each Eurodollar Rate Advance comprising part of the same Borrowing, the period commencing on the date of such Eurodollar Rate Advance or the date of the Conversion of any Base Rate Advance into such Eurodollar Rate Advance and ending on the last day of the period selected by the applicable Borrower pursuant to the provisions below and, thereafter, with respect to Eurodollar Rate Advances, each subsequent period commencing on the last day of the immediately preceding Interest Period and ending on the last day of the period selected by such Borrower pursuant to the provisions below. The duration of each such Interest Period shall be one, two, three or six months (or, for any Borrowing, any period specified by the applicable Borrower that is shorter than one month, if all Lenders agree), as the applicable Borrower may, upon notice received by the Administrative Agent not later than 11:00 A.M. on the third Business Day prior to the first day of such Interest Period, select; provided, however, that:

(i)

no Borrower may select any Interest Period that ends after the Termination Date;

(ii)

Interest Periods commencing on the same date for Eurodollar Rate Advances comprising part of the same Borrowing shall be of the same duration;

(iii)

whenever the last day of any Interest Period would otherwise occur on a day other than a Business Day, the last day of such Interest Period shall be extended to occur on the next succeeding Business Day, provided, however, that, if such extension would cause the last day of such Interest Period to occur in the next following calendar month, the last day of such Interest Period shall occur on the next preceding Business Day; and

(iv)

whenever the first day of any Interest Period occurs on a day of an initial calendar month for which there is no numerically corresponding day in the calendar month that succeeds such initial calendar month by the number of months equal to the number of months in such Interest Period, such Interest Period shall end on the last Business Day of such succeeding calendar month.

“ Internal Revenue Code ” means the Internal Revenue Code of 1986, as amended from time to time, and the regulations promulgated and rulings issued thereunder.

“ IRS ” means the United States Internal Revenue Service.

“ Joint Lead Arrangers ” means Wells Fargo Securities, BTMU, JPMS, CGMI, KeyBank and RBSSI.

“ JPMCB ” means JPMorgan Chase Bank, N.A.

“ JPMS ” means J.P. Morgan Securities LLC.

“ KeyBank ” means KeyBank National Association.

“ KPCo ” has the meaning specified in the recital of parties to this Agreement.

“ KPCo Assumption ” has the meaning specified in Section 2.17(c).

“ KPCO Transfer ” means the transfer from AGR to KPCo of 50% of AGR’s interest in the Mitchell Plant with a generation capacity of approximately 780 MW.

“ Lenders ” means, at any time, collectively, (i) the Initial Lenders (other than any such Initial Lenders that have previously assigned all of their respective Advances and Commitments to other Persons in accordance with Section 9.07(b) at such time), and (ii) any other Persons that have become Lenders holding Advances and/or Commitments at such time in accordance with Section 9.07(b).

“ Lien ” means any lien, security interest or other charge or encumbrance of any kind, or any other type of preferential arrangement, including, without limitation, the lien or retained security title of a conditional vendor and any easement, right of way or other encumbrance on title to real property.

“ Loan Documents ” means, collectively, (i) the Commitment Letter, dated as of June 27, 2013, among OPCo, Wells Fargo Securities and Wells Fargo, (ii) the Fee Letter, dated as of June 27, 2013, among OPCo, Wells Fargo Securities and Wells Fargo, (iii) this Agreement, (iv) each promissory note issued pursuant to Section 2.06(d) and (v) each Borrower Assumption Agreement executed pursuant to Section 2.17, in each case, as any of the foregoing may be amended, supplemented or modified from time to time.

“ Loan Parties ” means the Borrowers and the Guarantor.

“ Margin Regulations ” means Regulations T, U and X of the Board of Governors of the Federal Reserve System, as in effect from time to time.

“ Margin Stock ” has the meaning specified in the Margin Regulations.

“ Material Adverse Change ” means, with respect to any Loan Party, any material adverse change (i) in the business, condition (financial or otherwise) or operations of such Loan Party and its Subsidiaries, taken as a whole, or (ii) that is reasonably likely to affect the legality, validity or enforceability of this Agreement against such Loan Party or the ability of such Loan Party to perform its obligations under this Agreement.

“ Material Adverse Effect ” means, with respect to any Loan Party, a material adverse effect (i) on the business, condition (financial or otherwise) or operations of such Loan Party and its Subsidiaries, taken as a whole, or (ii) that is reasonably likely to affect the legality, validity or enforceability of this Agreement against such Loan Party or the ability of such Loan Party to perform its obligations under this Agreement.

“ Moody’s ” means Moody’s Investors Service, Inc.

“ Moody’s Rating ” means, with respect to any Borrower on any date of determination, the debt rating most recently announced by Moody’s with respect to the long-term senior unsecured debt issued by such Borrower.

“ Multiemployer Plan ” has the meaning specified in Section 4.01(i).

“ Net Proceeds ” means, with respect to any Specified Debt Issuance, the cash proceeds received therefrom, net of attorneys’ fees, underwriting discounts, commissions, and other customary fees and expenses actually incurred and paid in connection therewith.

“ Non-Consenting Lender ” means any Lender that does not approve any consent, waiver or amendment that (i) requires the approval of all Lenders in accordance with the terms of Section 9.01 and (ii) has been approved by the Required Lenders.

“ Non-Defaulting Lender ” means, at any time, each Lender that is not a Defaulting Lender at such time.

“ Notice of Borrowing ” has the meaning specified in Section 2.02(a).

“ OPCo ” has the meaning specified in the recital of parties to this Agreement.

“ Other Connection Taxes ” means, with respect to any Recipient, Taxes imposed as a result of a present or former connection between such Recipient and the jurisdiction imposing such Tax (other than connections arising from such Recipient having executed, delivered, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, engaged in any other transaction pursuant to or enforced any Loan Document, or sold or assigned an interest in any Advance, Commitment or Loan Document).

“ Other Taxes ” means all present or future stamp, court or documentary, intangible, recording, filing or similar Taxes that arise from any payment made under, from the execution, delivery, performance, enforcement or registration of, from the receipt or perfection of a security interest under, or otherwise with respect to, any Loan Document, except any such Taxes that are Other Connection Taxes imposed with respect to an assignment (other than an assignment made pursuant to Section 2.16(b)).

“ Parent Guaranty ” shall have the meaning specified in Section 6.01.

“ Participant ” has the meaning specified in Section 9.07(d).

“ Participant Register ” has the meaning specified in Section 9.07(d).

“ Patriot Act ” has the meaning specified in Section 9.14.

“ Permitted Liens ” means, as to any Loan Party, such of the following as to which no enforcement, collection, execution, levy or foreclosure proceeding shall have been commenced: (i) Liens for taxes, assessments and governmental charges or levies to the extent not required to be paid under Section 5.01(g) hereof; (ii) Liens imposed by law, such as materialmen’s, mechanics’, carriers’, workmen’s and repairmen’s Liens, and other similar Liens arising in the ordinary course of business securing obligations that are not overdue for a period of more than 30 days or that are being contested in good faith by appropriate proceedings; (iii) Liens incurred or deposits made to secure obligations under workers’ compensation laws or similar legislation or to secure public or statutory obligations; (iv) easements, rights of way and other encumbrances on title to real property that do not render title to the property encumbered thereby unmarketable or materially adversely affect the use of such property for its present purposes; (v) any judgment Lien, unless an Event of Default under Section 7.01(g) shall have occurred and be continuing; (vi) any Lien on any asset of any Person existing at the time such Person is merged or consolidated with or into such Loan Party or any Significant Subsidiary thereof and not created in contemplation of such event; (vii) deposits made in the ordinary course of business to secure the performance of bids, trade contracts (other than for Debt), operating leases and surety bonds; (viii) Liens upon or in any real property or equipment

acquired, constructed, improved or held by such Loan Party or any Subsidiary thereof in the ordinary course of business to secure the purchase price of such property or equipment or to secure Debt incurred solely for the purpose of financing the acquisition, construction or improvement of such property or equipment, or Liens existing on such property or equipment at the time of its acquisition (other than any such Liens created in contemplation of such acquisition that were not incurred to finance the acquisition of such property); (ix) extensions, renewals or replacements of any Lien described in clause (iii), (vi), (vii) or (viii) for the same or a lesser amount, provided, however, that no such Lien shall extend to or cover any properties not theretofore subject to the Lien being extended, renewed or replaced; and (x) any other Lien not covered by the foregoing exceptions as long as immediately after the creation of such Lien the aggregate principal amount of Debt secured by all Liens created or assumed under this clause (x) does not exceed 10% of Consolidated Tangible Net Assets of such Loan Party.

“ Person ” means an individual, partnership, corporation (including a business trust), joint stock company, trust, unincorporated association, joint venture, limited liability company or other entity, or a government or any political subdivision or agency thereof.

“ Plan ” has the meaning specified in Section 4.01(i).

“ Platform ” has the meaning specified in Section 9.02(b).

“ RBSFI ” means The Royal Bank of Scotland Finance (Ireland).

“ RBSSI ” means RBS Securities Inc.

“ Recipient ” means (a) the Administrative Agent and (b) any Lender, as applicable.

“ Reference Banks ” means Wells Fargo and any other Lender as may be selected from time to time to act as a Reference Bank hereunder by the Administrative Agent and the Borrowers.

“ Register ” has the meaning specified in Section 9.07(c).

“ Related Parties ” means, with respect to any Person, such Person’s Affiliates and the partners, directors, officers, employees, agents, trustees, administrators, managers, advisors and representatives of such Person and of such Person’s Affiliates.

“ Required Lenders ” means at any time Lenders owed in excess of 50% of the then aggregate unpaid principal amount of the Advances owing to Lenders at such time, or, if no such principal amount is then outstanding, Lenders having in excess of 50% in interest of the Commitments in effect at such time. Subject to Section 9.01, the outstanding Advances and Commitments of any Defaulting Lender shall be disregarded in determining Required Lenders at any time.

“ Restructuring Law ” means Texas Senate Bill 7, as enacted by the Legislature of the State of Texas and signed into law on June 18, 1999, Ohio Senate Bill No. 3, as enacted by the General Assembly of the State of Ohio and signed into law on July 6, 1999, or any similar law applicable to a Loan Party or any Subsidiary of a Loan Party governing the deregulation or restructuring of the electric power industry.

“ RTO Transaction ” means the transfer of transmission facilities to a regional transmission organization or equivalent organization as approved or ordered by the Federal Energy Regulatory Commission.

“ S&P ” means Standard & Poor’s Ratings Group, a division of The McGraw-Hill Companies, Inc.

“ S&P Rating ” means, with respect to any Borrower on any date of determination, the rating most recently announced by S&P with respect to the long-term senior unsecured debt issued by such Borrower.

“ SEC” means the United States Securities and Exchange Commission.

“ Significant Subsidiary ” means, at any time, (i) with respect to AEP, any Subsidiary of AEP that constitutes at such time a “significant subsidiary” of AEP, as such term is defined in Regulation S-X of the SEC as in effect on the date hereof (17 C.F.R. Part 210) (other than AGR and any other Subsidiary of AEP (other than the Existing Utility Subsidiaries (as defined below)) to which generation assets are being transferred in connection with the corporate separation of OPCo’s generation assets); provided , however , that if AGR and the other Subsidiaries of AEP (excluding, solely for purposes of this calculation, the Existing Utility Subsidiaries) own, on an aggregate basis, generation assets exceeding 20% of AEP’s “total assets” as used in Regulation S-X, AGR and each such Subsidiary that otherwise constitutes a “significant subsidiary” of AEP under Regulation S-X will be considered Significant Subsidiaries, and (ii) with respect to any Borrower, any Subsidiary of such Borrower that constitutes at such time a “significant subsidiary” of such Borrower, as such term is defined in Regulation S-X of the SEC as in effect on the date hereof (17 C.F.R. Part 210); provided , however , in each case of clauses (i) and (ii) above, that “total assets” as used in Regulation S-X shall not include securitization transition assets, phase-in cost assets or similar assets on the balance sheet of any Subsidiary resulting from the issuance of transition bonds or other asset backed securities of a similar nature. As used in this definition, “ Existing Utility Subsidiaries ” means each of AEP Generating Company, APCo, Indiana Michigan Power Company, KPCo, Kingsport Power Company, OPCo, Public Service Company of Oklahoma, Southwestern Electric Power Company, Wheeling Power Company, AEP Texas North Company and AEP Texas Central Company.

“ Specified Debt Issuance ” means any issuance or sale of any debt securities or issuance, sale or incurrence of any other Debt, whether in capital markets transactions, bank or other commercial lending transactions, or similar transactions with any banks or other financial institutions or institutional lenders, in each case issued, sold or incurred by any Loan Party, and the proceeds of which are to be used to finance any portion of the

corporate separation of OPCo’s power generation assets; provided that, Specified Debt Issuances shall not include (i) refinancings of debt securities or other Debt issued, sold or incurred prior to the date of this Agreement, (ii) commercial paper issuances, (iii) issuances of pollution control revenue bonds, (v) capital leases and purchase money financing obligations, (vi) obligations arising under reimbursement agreements in respect of letters of credit, acceptances or similar extensions of credit or (vii) any phase-in-recovery bonds.

“ Stranded Cost Recovery Bonds ” means securities, however denominated, that are issued by a Loan Party or any Consolidated Subsidiary thereof that are (i) non-recourse to such Loan Party and its Significant Subsidiaries (other than for failure to collect and pay over the charges referred to in clause (ii) below) and (ii) payable solely from transition or similar charges authorized by law (including, without limitation, any “financing order”, as such term is defined in the Texas Utilities Code, the Ohio Revised Code or the West Virginia Code) to be invoiced to customers of such Loan Party or any Subsidiary of such Loan Party or to retail electric providers.

“ Subsidiary ” of any Person means any corporation, partnership, joint venture, limited liability company, trust or estate of which (or in which) more than 50% of (i) the issued and outstanding capital stock having ordinary voting power to elect a majority of the board of directors of such corporation (irrespective of whether at the time capital stock of any other class or classes of such corporation shall or might have voting power upon the occurrence of any contingency), (ii) the interest in the capital or profits of such limited liability company, partnership or joint venture or (iii) the beneficial interest in such trust or estate is at the time directly or indirectly owned or controlled by such Person, by such Person and one or more of its other Subsidiaries or by one or more of such Person’s other Subsidiaries.

“ Taxes ” means all present or future taxes, levies, imposts, duties, deductions, withholdings (including backup withholding), assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

“ Termination Date ” means the earlier to occur of (i) May 13, 2015, and (ii) the date of termination of the Commitments and/or declaration of all outstanding Advances to be due and payable (or automatically becoming due and payable) pursuant to Section 7.01.

“ Type ” refers to the distinction between Advances bearing interest at the Base Rate and Advances bearing interest at the Eurodollar Rate.

“ U.S. Person ” means any Person that is a “United States Person” as defined in Section 7701(a)(30) of the Internal Revenue Code.

“ U.S. Tax Compliance Certificate ” has the meaning assigned to such term in Section 2.14(g)(ii)(B)(iii).

“ Voting Stock ” means capital stock issued by a corporation, or equivalent interests in any other Person, the holders of which are ordinarily, in the absence of contingencies, entitled to vote for the election of directors (or Persons performing similar functions) of such Person, even if the right so to vote has been suspended by the happening of such a contingency.

“ Wells Fargo ” has the meaning specified in the recital of parties to this Agreement.

“ Wells Securities ” means Wells Fargo Securities, LLC.

“ Withholding Agent ” means any Loan Party and the Administrative Agent.

SECTION 1.02. Computation of Time Periods.

In this Agreement in the computation of periods of time from a specified date to a later specified date, the word “from” means “from and including” and the words “to” and “until” each mean “to but excluding”.

SECTION 1.03. Accounting Terms.

All accounting terms not specifically defined herein shall be construed in accordance with generally accepted accounting principles consistent with those applied in the preparation of the financial statements referred to in Section 4.01(f) (“ GAAP ”).

SECTION 1.04. Other Interpretive Provisions.

As used herein, except as otherwise specified herein, (i) references to any Person include its successors and assigns and, in the case of any Governmental Authority, any Person succeeding to its functions and capacities; (ii) references to any Applicable Law include amendments, supplements and successors thereto; (iii) references to specific sections, articles, annexes, schedules and exhibits are to this Agreement; (iv) words importing any gender include the other gender; (v) the singular includes the plural and the plural includes the singular; (vi) the words “including”, “include” and “includes” shall be deemed to be followed by the words “without limitation”; (vii) captions and headings are for ease of reference only and shall not affect the construction hereof; and (viii) references to any time of day shall be to New York City time unless otherwise specified.

ARTICLE II

AMOUNTS AND TERMS OF THE ADVANCES

SECTION 2.01. The Advances.

(a) Each Lender severally agrees, on the terms and conditions hereinafter set forth, to make Advances to OPCo from time to time on any Business Day during the period from the date hereof until the Availability Termination Date in an aggregate outstanding amount not to exceed at any time such Lender’s Available Commitment at such time. Within the limits of each Lender’s Commitment and as hereinabove and hereinafter provided, OPCo may request

Borrowings hereunder, and repay or prepay Advances pursuant to Section 2.10, provided , however , that (i) once repaid or prepaid, such amounts may not be reborrowed by OPCo and (ii) OPCo may request no more than ten Borrowings pursuant to this Section. Other than OPCo, no other Borrower may request Borrowings hereunder.

(b) In no event shall OPCo be entitled to request or receive any Borrowing that would cause the aggregate principal amount of all Borrowings (including such requested Borrowing) to exceed the Commitments.

(c) All Advances made by the Lenders under the Facility shall be made to OPCo, and the other Borrowers shall assume such Advances as set forth in Section 2.17.

SECTION 2.02. Making the Advances.

(a) Each Borrowing shall be in an amount not less than $10,000,000 (or, if less, the Available Commitments at such time) or an integral multiple of $1,000,000 in excess thereof and shall consist of Advances of the same Type made on the same day by the Lenders ratably according to their respective Commitment Percentages. Each Borrowing shall be made on notice, given not later than 11:00 A.M. on the third Business Day prior to the date of the proposed Borrowing in the case of a Borrowing consisting of Eurodollar Rate Advances, or not later than 9:30 A.M. on the date of the proposed Borrowing in the case of a Borrowing consisting of Base Rate Advances, by OPCo to the Administrative Agent, which shall give to each Lender prompt written notice. Each such notice of a Borrowing under this Section 2.02 (a “ Notice of Borrowing ”) shall be by telephone, confirmed immediately in writing, or fax in substantially the form of Exhibit A hereto, specifying therein the requested (i) Borrowing Date for such Borrowing, (ii) Type of Advances comprising such Borrowing, (iii) aggregate amount of such Borrowing, and (iv) in the case of a Borrowing consisting of Eurodollar Rate Advances, the initial Interest Period for each such Advance. Each Lender shall, before 12:00 noon on the applicable Borrowing Date, make available for the account of its Applicable Lending Office to the Administrative Agent at the Agent’s Account, in same day funds, such Lender’s ratable portion of the Borrowing to be made on such Borrowing Date. After the Administrative Agent’s receipt of such funds and upon fulfillment of the applicable conditions set forth in Article III, the Administrative Agent will promptly make such funds available to OPCo in such manner as the OPCo shall have specified in the applicable Notice of Borrowing and as shall be reasonably acceptable to the Administrative Agent.

(b) Anything in subsection (a) above to the contrary notwithstanding, OPCo may not select Eurodollar Rate Advances for any Borrowing if the aggregate amount of such Borrowing is less than $10,000,000 or if the obligation of the Lenders to make Eurodollar Rate Advances shall then be suspended pursuant to Section 2.08(c), 2.08(f) or 2.12.

(c) Each Notice of Borrowing shall be irrevocable and binding on OPCo. In the case of any Borrowing that the related Notice of Borrowing specifies is to comprise of Eurodollar Rate Advances, OPCo shall indemnify each Lender against any loss, cost or expense incurred by such Lender as a result of any failure to fulfill on or before the date specified in such Notice of Borrowing for such Borrowing the applicable conditions set forth in Article III, including, without limitation, any loss (including loss of anticipated profits), cost or expense incurred by

reason of the liquidation or reemployment of deposits or other funds acquired by such Lender to fund the Advance to be made by such Lender as part of such Borrowing when such Advance, as a result of such failure, is not made on such date.

(d) Unless the Administrative Agent shall have received notice by courier or fax from a Lender prior to any Borrowing Date or, in the case of a Base Rate Advance, prior to the time of Borrowing, that such Lender will not make available to the Administrative Agent such Lender’s Advance as part of the Borrowing to be made on such Borrowing Date, the Administrative Agent may assume that such Lender has made such portion available to the Administrative Agent on such Borrowing Date in accordance with subsection (a) of this Section 2.02, and the Administrative Agent may (but it shall not be required to), in reliance upon such assumption, make available to OPCo on such date a corresponding amount. If and to the extent that such Lender shall not have so made such Advance available to the Administrative Agent, such Lender and OPCo severally agree to repay to the Administrative Agent forthwith on demand such corresponding amount, together with interest thereon, for each day from the date such amount is made available to OPCo until the date such amount is repaid to the Administrative Agent, at (i) in the case of OPCo, the interest rate applicable at the time to Advances comprising such Borrowing and (ii) in the case of such Lender, the Federal Funds Rate. If such Lender shall repay to the Administrative Agent such corresponding amount, such amount so repaid shall constitute such Lender’s Advance as part of such Borrowing for purposes of this Agreement.

(e) The failure of any Lender to make the Advance to be made by it as part of any Borrowing shall not relieve any other Lender of its obligation, if any, hereunder to make its Advance on the date of such Borrowing, but no Lender shall be responsible for the failure of any other Lender to make the Advance to be made by such other Lender on the date of any Borrowing.

SECTION 2.03. Fees.

(a) OPCo agrees to pay to the Administrative Agent for the account of each Lender a commitment fee equal to the Commitment Fee Rate in effect from time to time, multiplied by the amount of such Lender’s Available Commitment (i) from the date hereof, in the case of each Initial Lender, and (ii) from the effective date specified in the Assignment and Assumption pursuant to which it became a Lender, in the case of each other Lender, in each case until the earlier to occur of the Termination Date and the Availability Termination Date, payable quarterly in arrears on the last day of each March, June, September and December, commencing September 30, 2013, and on the earlier to occur of the Termination Date and the Availability Termination Date.

(b) The Borrowers shall pay to the Administrative Agent such fees as may from time to time be agreed between the Borrowers and the Administrative Agent. After the Closing Date, such fees will be payable by OPCo and, after the AGR Assumption, APCo Assumption or KPCo Assumption, as the case may be, OPCo and the other Borrowers on a pro rata basis, determined on the basis of such Borrower’s Fraction.

SECTION 2.04. Termination or Reduction of the Commitments.

(a) OPCo shall have the right, upon at least three Business Days’ notice to the Administrative Agent, to terminate in whole or reduce ratably in part the Available Commitments, provided that each partial reduction shall be in a minimum amount of $5,000,000 or an integral multiple of $1,000,000 in excess thereof.

(b) OPCo may terminate the Available Commitment of any Lender that is a Defaulting Lender in accordance with Section 9.16(a)(iv).

(c) The Commitments shall automatically reduce by an amount equal to (i) the principal amount of all Advances made pursuant to Section 2.02, and (ii) without duplication, the Net Proceeds received in respect of all Specified Debt Issuances to the extent such Net Proceeds were not required to effect a mandatory prepayment of outstanding Advances pursuant to Section 2.10(b).

(d) Once terminated or reduced pursuant to this Section 2.04, none of the Commitments or any portions thereof may be reinstated.

(e) The Commitments shall automatically terminate on the Availability Termination Date or, if earlier, the Termination Date.

SECTION 2.05. Repayment of Advances.

(a) Each Borrower shall repay to the Administrative Agent for the account of each Lender on the Termination Date the aggregate principal amount of all Advances owing by such Borrower to such Lender then outstanding.

(b) If at any time the aggregate principal amount of all Advances owed at such time exceeds the aggregate Commitments then in effect, the Borrowers shall pay or prepay so much of the Borrowings as shall be necessary in order that the principal amount of all such Advances will not exceed such Commitments.

SECTION 2.06. Evidence of Indebtedness.

(a) Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of each Borrower to such Lender resulting from each Advance made by such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time under this Agreement.

(b) The Administrative Agent shall maintain accounts in which it will record (i) the amount of each Advance made hereunder, the Borrower thereof, the Type of each Advance made and the Interest Period applicable thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from such Borrower to each Lender hereunder and (iii) the amount of any sum received by the Administrative Agent hereunder from each Borrower and each Lender’s share thereof.

(c) The entries made in the accounts maintained pursuant to subsections (a) and (b) of this Section 2.06 shall, to the extent permitted by Applicable Law, be prima facie evidence of the existence and amounts of the obligations therein recorded; provided , however , that the failure of any Lender or the Administrative Agent to maintain such accounts or any error therein shall not in any manner affect the obligations of each Borrower to repay the Advances and interest thereon in accordance with their terms.

(d) Any Lender may request that any Advances made by it be evidenced by one or more promissory notes. In such event, each applicable Borrower shall prepare, execute and deliver to such Lender one or more promissory notes payable to such Lender (or, if requested by such Lender, to such Lender and its assignees) and in a form approved by the Administrative Agent. Thereafter, the Advances evidenced by such promissory notes and interest thereon shall at all times (including after assignment pursuant to Section 9.07) be represented by one or more promissory notes in such form payable to the payee named therein.

SECTION 2.07. Interest on Advances.

Each Borrower shall pay interest on the unpaid principal amount of each Advance owing by such Borrower to each Lender from the date of such Advance until such principal amount shall be paid in full, at the following rates per annum:

(a) Base Rate Advances . During such periods as such Advance is a Base Rate Advance, a rate per annum equal at all times to the sum of (x) the Base Rate plus (y) the Applicable Margin for Base Rate Advances in effect from time to time, payable in arrears quarterly on the last day of each March, June, September and December during such periods and on the date such Base Rate Advance shall be Converted or paid in full.

(b) Eurodollar Rate Advances . During such periods as such Advance is a Eurodollar Rate Advance, a rate per annum equal at all times during each Interest Period for such Advance to the sum of (x) the Eurodollar Rate for such Interest Period for such Advance plus (y) the Applicable Margin for Eurodollar Rate Advances in effect from time to time, payable in arrears on the last day of such Interest Period and, if such Interest Period has a duration of more than three months, on each day that occurs during such Interest Period every three months from the first day of such Interest Period and on the date such Eurodollar Rate Advance shall be Converted or paid in full.

(c) Additional Interest on Eurodollar Rate Advances . Each Borrower shall pay to each Lender, so long as such Lender shall be required under regulations of the Board of Governors of the Federal Reserve System to maintain reserves with respect to liabilities or assets consisting of or including Eurocurrency Liabilities, additional interest on the unpaid principal amount of each Eurodollar Rate Advance owing by such Borrower to such Lender, from the date of such Advance until such principal amount is paid in full, at an interest rate per annum equal at all times to the remainder obtained by subtracting (i) the Eurodollar Rate for the Interest Period for such Advance from (ii) the rate obtained by dividing such Eurodollar Rate by a percentage equal to 100% minus the Eurodollar Rate Reserve Percentage of such Lender for such Interest Period, payable on each date on which interest is payable on such Advance. Such additional interest shall be

determined by such Lender and notified to the applicable Borrower through the Administrative Agent.

SECTION 2.08. Interest Rate Determination.

(a) To the extent required hereunder, each Reference Bank agrees to furnish to the Administrative Agent timely information for the purpose of determining each Eurodollar Rate. If fewer than two Reference Banks furnish such timely information to the Administrative Agent for the purpose of determining any such rate, the Administrative Agent shall determine such interest rate on the basis of timely information furnished by the remaining Reference Bank.

(b) The Administrative Agent shall give prompt notice to the applicable Borrower and the Lenders of the applicable interest rate determined by the Administrative Agent for purposes of Section 2.07(a) or (b), and the applicable rate, if any, furnished by each Reference Bank for the purpose of determining the applicable interest rate under Section 2.07(b).

(c) If, with respect to any Eurodollar Rate Advances, (i) the Required Lenders notify the Administrative Agent that the Eurodollar Rate for any Interest Period for such Advances will not adequately reflect the cost to such Required Lenders of making, funding or maintaining their respective Eurodollar Rate Advances for such Interest Period, or (ii) the Reference Banks notify the Administrative Agent that adequate and fair means do not exist for ascertaining the applicable interest rate on the basis provided for in the definition of Eurodollar Rate, the Administrative Agent shall forthwith so notify the Borrowers and the Lenders, whereupon (A) each Eurodollar Rate Advance will automatically, on the last day of the then existing Interest Period therefor, Convert into a Base Rate Advance, and (B) the obligation of the Lenders to make, or to Convert Advances into, Eurodollar Rate Advances shall be suspended until the Administrative Agent shall notify the Borrowers and the Lenders that the circumstances causing such suspension no longer exist.

(d) If the applicable Borrower shall fail to select the duration of any Interest Period for any Eurodollar Rate Advances in accordance with the provisions contained in the definition of “Interest Period” in Section 1.01, the Administrative Agent will forthwith so notify such Borrower and the Lenders and such Advances will automatically, on the last day of the then existing Interest Period therefor, Convert into Base Rate Advances.

(e) On the date on which the aggregate unpaid principal amount of Eurodollar Rate Advances comprising any Borrowing shall be reduced, by payment or prepayment or otherwise, to less than $10,000,000, such Advances shall automatically Convert into Base Rate Advances.

(f) Upon the occurrence and during the continuance of any Event of Default, (i) each Eurodollar Rate Advance will automatically, on the last day of the then existing Interest Period therefor, Convert into a Base Rate Advance and (ii) the obligation of the Lenders to make, or to Convert Advances into, Eurodollar Rate Advances shall be suspended.

SECTION 2.09. Optional Conversion of Advances.

Any Borrower may on any Business Day, upon notice given to the Administrative Agent not later than 12:00 noon on the third Business Day prior to the date of the proposed Conversion

and subject to the provisions of Sections 2.08 and 2.12, Convert all or any part of Advances of one Type owing by such Borrower comprising the same Borrowing into Advances of the other Type or of the same Type but having a new Interest Period; provided , however , that any Conversion of Eurodollar Rate Advances into Base Rate Advances shall be made only on the last day of an Interest Period for such Eurodollar Rate Advances, any Conversion of Base Rate Advances into Eurodollar Rate Advances shall be in an amount not less than the minimum amount specified in Section 2.02(b) and no Conversion of any Advances shall result in more separate Borrowings than permitted under Section 2.02(b). Each such notice of a Conversion shall, within the restrictions specified above, specify (i) the date of such Conversion, (ii) the Advances to be Converted, and (iii) if such Conversion is into Eurodollar Rate Advances, the duration of the initial Interest Period for each such Advance. Each notice of Conversion shall be irrevocable and binding on such Borrower.

SECTION 2.10. Prepayments of Advances.

(a) Optional Prepayments of Advances . Any Borrower may, upon at least two Business Days’ notice, in the case of Eurodollar Rate Advances, and upon notice not later than 11:00 A.M. (New York time) on the date of prepayment, in the case of Base Rate Advances, to the Administrative Agent stating the proposed date and aggregate principal amount of the prepayment, and, if such notice is given, such Borrower shall prepay the outstanding principal amount of the Advances owing by such Borrower comprising part of the same Borrowing in whole or ratably in part, together with accrued interest to the date of such prepayment on the principal amount prepaid; provided , however , that (x) each partial prepayment shall be in a minimum amount of $5,000,000 or an integral multiple of $1,000,000 in excess thereof and (y) in the event of any such prepayment of a Eurodollar Rate Advance, such Borrower shall be obligated to reimburse the Lenders in respect thereof pursuant to Section 9.04(c).

(b) Mandatory Prepayments of Advances . (i) If AEP shall cease to own, directly or indirectly, 100% of the Voting Stock of AGR, AGR shall prepay all Advances, unpaid interest and other amounts owing by AGR under this Agreement and (ii) with respect to each Specified Debt Issuance, promptly after the later of (A) the date of receipt of the Net Proceeds from such Specified Debt Issuance and (B) the date any power generation assets owned as of the Closing Date by OPCo are transferred to another Borrower in connection with such Specified Debt Issuance, and in any event within 30 days following such later date (or, if such asset transfer will be accompanied by the AGR Assumption, the APCo Assumption or the KPCo Assumption, in any event prior to the applicable assumption of Advances to occur on such date), each applicable Loan Party shall prepay Advances owing by such Loan Party (or, in the case of AEP, Advances owing by AGR) in an amount equal to the Net Proceeds of such Specified Debt Issuance. All such prepayments shall be applied ratably to the outstanding Advances of such Loan Party (or, in the case of AEP, Advances owing by AGR), first , to all outstanding Base Rate Advances, and second , to all outstanding Eurodollar Rate Advances in the direct order of Interest Period maturity dates applicable to such Eurodollar Rate Advances, in each case together with accrued interest to the date of such prepayment on the principal amount prepaid and, in the case of any Eurodollar Rate Advances, any amounts due in respect thereof pursuant to Section 9.04(c).

SECTION 2.11. Increased Costs.

(a) Increased Costs Generally . If any Change in Law shall:

(i) impose, modify or deem applicable any reserve, special deposit, compulsory loan, insurance charge or similar requirement against assets of, deposits with or for the account of, or credit extended or participated in by, any Lender (except any reserve requirement reflected in the Eurodollar Rate Reserve Percentage, in the case of Eurodollar Rate Advances);

(ii) subject any Recipient to any Taxes (other than (A) Indemnified Taxes, (B) Taxes described in clauses (b) through (d) of the definition of Excluded Taxes and (C) Connection Income Taxes) on its loans, loan principal, commitments, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto; or

(iii) impose on any Lender or the London interbank market any other condition, cost or expense (other than Taxes) affecting this Agreement or Advances made by such Lender;

and the result of any of the foregoing shall be to increase the cost to such Lender or such other Recipient of making, converting to, continuing or maintaining any Advance or of maintaining its obligation to make any such Advance, or to reduce the amount of any sum received or receivable by such Lender or other Recipient hereunder (whether of principal, interest or any other amount) then, upon request of such Lender or other Recipient, each Borrower will pay to such Lender or other Recipient, as the case may be, such additional amount or amounts as will compensate such Lender or other Recipient, as the case may be, for such additional costs incurred or reduction suffered.

(b) Capital Requirements . If any Lender determines that any Change in Law affecting such Lender or any Applicable Lending Office of such Lender or such Lender’s holding company, if any, regarding capital or liquidity requirements, has or would have the effect of reducing the rate of return on such Lender’s capital or on the capital of such Lender’s holding company, if any, as a consequence of this Agreement, the Commitments of such Lender or the Advances made by such Lender, to a level below that which such Lender or such Lender’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s policies and the policies of such Lender’s holding company with respect to capital adequacy and liquidity), then from time to time each Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender or such Lender’s holding company for any such reduction suffered.

(c) Certificates for Reimbursement . A certificate of a Lender setting forth the amount or amounts necessary to compensate such Lender or its holding company, as the case may be, as specified in subsection (a) or (b) of this Section and delivered to each Borrower, shall be conclusive absent manifest error. Each Borrower shall pay such Lender the amount shown as due on any such certificate within ten days after receipt thereof.

(d) Delay in Requests . Failure or delay on the part of any Lender to demand compensation pursuant to this Section shall not constitute a waiver of such Lender’s right to demand such compensation; provided that the Borrowers shall not be required to compensate a Lender pursuant to this Section for any increased costs incurred or reductions suffered more than six months prior to the date that such Lender notifies the Borrowers of the Change in Law giving rise to such increased costs or reductions, and of such Lender’s intention to claim compensation therefor (except that, if the Change in Law giving rise to such increased costs or reductions is retroactive, then the six-month period referred to above shall be extended to include the period of retroactive effect thereof).

(e) Pro Rata Sharing of Payments . Each Borrower shall be liable for its pro rata share of each payment to be made by the Borrowers under subsections (a) and (b) of this Section 2.11, determined on the basis of such Borrower’s Fraction; provided , however , that if and to the extent that any such liabilities are reasonably determined by the Borrowers (subject to the approval of the Administrative Agent, which approval shall not be unreasonably withheld) to be directly attributable to Advances owing by a specific Borrower, then only such Borrower shall be liable for such payments.

SECTION 2.12. Illegality.

If due to any Change in Law it shall become unlawful or impossible for any Credit Party (or its Eurodollar Lending Office) to make, maintain or fund its Eurodollar Rate Advances, and such Credit Party shall so notify the Administrative Agent, the Administrative Agent shall forthwith give notice thereof to the other Credit Parties and the Borrowers, whereupon, until such Credit Party notifies the Borrowers and the Administrative Agent that the circumstances giving rise to such suspension no longer exist, the obligation of such Credit Party to make Eurodollar Rate Advances, or to Convert outstanding Advances into Eurodollar Rate Advances, shall be suspended. Before giving any notice to the Administrative Agent pursuant to this Section 2.12, such Credit Party shall use reasonable efforts (consistent with its internal policy and legal and regulatory restrictions applicable to such Credit Party) to designate a different Eurodollar Lending Office if such designation would avoid the need for giving such notice and would not, in the judgment of such Credit Party, be otherwise disadvantageous to such Credit Party. If such notice is given, each Eurodollar Rate Advance of such Credit Party then outstanding shall be converted to a Base Rate Advance either (i) on the last day of the then current Interest Period applicable to such Eurodollar Rate Advance if such Credit Party may lawfully continue to maintain and fund such Advance to such day or (ii) immediately if such Credit Party shall determine that it may not lawfully continue to maintain and fund such Advance to such day.

SECTION 2.13. Payments and Computations.

(a) Each Borrower shall make each payment to be made by it hereunder not later than 1:00 P.M. on the day when due in Dollars to the Administrative Agent at the Agent’s Account in same day funds without condition or deduction for any counterclaim, defense, recoupment or setoff. The Administrative Agent will promptly thereafter cause to be distributed like funds relating to the payment of principal or interest or commitment fees ratably (other than amounts payable pursuant to Section 2.07(c), 2.11, 2.14 or 9.04(c)) to the Lenders for the account of their respective Applicable Lending Offices, and like funds relating to the payment of any other

amount payable to any Lender to such Lender for the account of its Applicable Lending Office, in each case to be applied in accordance with the terms of this Agreement. Upon its acceptance of an Assignment and Assumption and recording of the information contained therein in the Register pursuant to Section 9.07(c), from and after the effective date specified in such Assignment and Assumption, the Administrative Agent shall make all payments hereunder in respect of the interest assigned thereby to the Lender assignee thereunder, and the parties to such Assignment and Assumption shall make all appropriate adjustments in such payments for periods prior to such effective date directly between themselves.

(b) Each Borrower hereby authorizes each Lender, if and to the extent payment owed to such Lender is not made when due hereunder, after any applicable grace period, to charge from time to time against any or all of such Borrower’s accounts with such Lender any amount so due.

(c) All computations of interest based on the rate referred to in clause (i) of the definition of the “Base Rate” contained in Section 1.01 shall be made by the Administrative Agent on the basis of a year of 365 or 366 days, as the case may be, and all computations of interest based on the Eurodollar Rate or the Federal Funds Rate and of commitment fees shall be made by the Administrative Agent on the basis of a year of 360 days, in each case for the actual number of days (including the first day but excluding the last day) occurring in the period for which such interest or commitment fees are payable. Each determination by the Administrative Agent of an interest rate hereunder shall be conclusive and binding for all purposes, absent manifest error.

(d) Whenever any payment hereunder shall be stated to be due on a day other than a Business Day, such payment shall be made on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of payment of interest or commitment fees, as the case may be; provided, however, that, if such extension would cause payment of interest on or principal of Eurodollar Rate Advances to be made in the next following calendar month or on a date after the Termination Date, such payment shall be made on the next preceding Business Day.

(e) Unless the Administrative Agent shall have received notice from any Borrower prior to the date on which any payment is due to a Lender hereunder that such Borrower will not make such payment in full, the Administrative Agent may assume that each Borrower has made such payment in full to the Administrative Agent on such date, and the Administrative Agent may, in reliance upon such assumption, cause to be distributed to each Lender on such due date an amount equal to the amount then due such Lender. If and to the extent that a Borrower shall not have so made such payment in full to the Administrative Agent, each Lender shall repay to the Administrative Agent forthwith on demand such amount distributed to such Lender together with interest thereon, for each day from the date such amount is distributed to such Lender until the date such Lender repays such amount to the Administrative Agent, at the Federal Funds Rate.

SECTION 2.14. Taxes.

(a) Defined Terms . For purposes of this Section 2.14, the term “Applicable Law” includes FATCA.

(b) Payments Free of Taxes . Any and all payments by or on account of any obligation of any Loan Party under any Loan Document shall be made without deduction or withholding for any Taxes, except as required by Applicable Law. If any Applicable Law (as determined in the good faith discretion of an applicable Withholding Agent) requires the deduction or withholding of any Tax from any such payment by a Withholding Agent, then the applicable Withholding Agent shall be entitled to make such deduction or withholding and shall timely pay the full amount deducted or withheld to the relevant Governmental Authority in accordance with Applicable Law and, if such Tax is an Indemnified Tax, then the sum payable by each applicable Loan Party shall be increased as necessary so that after such deduction or withholding has been made (including such deductions and withholdings applicable to additional sums payable under this Section) the applicable Recipient receives an amount equal to the sum it would have received had no such deduction or withholding been made.

(c) Payment of Other Taxes by the Loan Parties . Each Loan Party shall timely pay to the relevant Governmental Authority in accordance with Applicable Law, or at the option of the Administrative Agent timely reimburse it for the payment of, any Other Taxes.

(d) Indemnification by the Loan Parties . Each Loan Party shall indemnify each Recipient, within 10 days after demand therefor, for the full amount of any Indemnified Taxes (including Indemnified Taxes imposed or asserted on or attributable to amounts payable under this Section) payable or paid by such Recipient or required to be withheld or deducted from a payment to such Recipient and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to any Loan Party by a Lender (with a copy to the Administrative Agent), or by the Administrative Agent on its own behalf or on behalf of a Lender, shall be conclusive absent manifest error.

(e) Indemnification by the Lenders . Each Lender shall severally indemnify the Administrative Agent, within 10 days after demand therefor, for (i) any Indemnified Taxes attributable to such Lender (but only to the extent that a Loan Party has not already indemnified the Administrative Agent for such Indemnified Taxes and without limiting the obligation of the Loan Parties to do so), (ii) any Taxes attributable to such Lender’s failure to comply with the provisions of Section 9.07(d) relating to the maintenance of a Participant Register and (iii) any Excluded Taxes attributable to such Lender, in each case, that are payable or paid by the Administrative Agent in connection with any Loan Document, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to any Lender by the Administrative Agent shall be conclusive absent manifest error. Each Lender hereby authorizes the Administrative Agent to set off and apply any and all amounts at any time owing to such Lender under any Loan Document or otherwise payable by the Administrative Agent to the Lender from any other source against any amount due to the Administrative Agent under this subsection (e).

(f) Evidence of Payments . As soon as practicable after any payment of Taxes by any Loan Party to a Governmental Authority pursuant to this Section 2.14, such Loan Party shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such

Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(g) Status of Lenders . (i) Any Lender that is entitled to an exemption from or reduction of withholding Tax with respect to payments made under any Loan Document shall deliver to the Loan Parties and the Administrative Agent, at the time or times reasonably requested by the Loan Parties or the Administrative Agent, such properly completed and executed documentation reasonably requested by the Loan Parties or the Administrative Agent as will permit such payments to be made without withholding or at a reduced rate of withholding. In addition, any Lender, if reasonably requested by the Loan Parties or the Administrative Agent, shall deliver such other documentation prescribed by Applicable Law or reasonably requested by the Loan Parties or the Administrative Agent as will enable the Loan Parties or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements. Notwithstanding anything to the contrary in the preceding two sentences, the completion, execution and submission of such documentation (other than such documentation set forth in Section 2.14(g)(ii)(A), (ii)(B) and (ii)(D) below) shall not be required if in the Lender’s reasonable judgment such completion, execution or submission would subject such Lender to any material unreimbursed cost or expense or would materially prejudice the legal or commercial position of such Lender.

(ii) Without limiting the generality of the foregoing,

(A) any Lender that is a U.S. Person shall deliver to the Loan Parties and the Administrative Agent on or prior to the date on which such Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Loan Parties or the Administrative Agent), executed originals of IRS Form W-9 certifying that such Lender is exempt from U.S. federal backup withholding tax;

(B) any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Loan Parties and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Loan Parties or the Administrative Agent), whichever of the following is applicable:

(i) in the case of a Foreign Lender claiming the benefits of an income tax treaty to which the United States is a party (x) with respect to payments of interest under any Loan Document, executed originals of IRS Form W-8BEN establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “interest” article of such tax treaty and (y) with respect to any other applicable payments under any Loan Document, IRS Form W-8BEN establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “business profits” or “other income” article of such tax treaty;

(ii) executed originals of IRS Form W-8ECI;

(iii) in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Internal Revenue

Code, (x) a certificate substantially in the form of Exhibit E-1 to the effect that such Foreign Lender is not a “bank” within the meaning of Section 881(c)(3)(A) of the Internal Revenue Code, a “10 percent shareholder” of any Loan Party within the meaning of Section 881(c)(3)(B) of the Internal Revenue Code, or a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Internal Revenue Code (a “ U.S. Tax Compliance Certificate ”) and (y) executed originals of IRS Form W-8BEN; or

(iv) to the extent a Foreign Lender is not the beneficial owner, executed originals of IRS Form W-8IMY, accompanied by IRS Form W-8ECI, IRS Form W-8BEN, a U.S. Tax Compliance Certificate substantially in the form of Exhibit E-2 or Exhibit E-3, IRS Form W-9, and/or other certification documents from each beneficial owner, as applicable; provided that, if the Foreign Lender is a partnership and one or more direct or indirect partners of such Foreign Lender are claiming the portfolio interest exemption, such Foreign Lender may provide a U.S. Tax Compliance Certificate substantially in the form of Exhibit E-4 on behalf of each such direct and indirect partner;

(C) any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Loan Parties and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Loan Parties or the Administrative Agent), executed originals of any other form prescribed by Applicable Law as a basis for claiming exemption from or a reduction in U.S. federal withholding Tax, duly completed, together with such supplementary documentation as may be prescribed by Applicable Law to permit the Loan Party or the Administrative Agent to determine the withholding or deduction required to be made; and

(D) if a payment made to a Lender under any Loan Document would be subject to U.S. federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Internal Revenue Code, as applicable), such Lender shall deliver to the Loan Parties and the Administrative Agent at the time or times prescribed by law and at such time or times reasonably requested by the Loan Parties or the Administrative Agent such documentation prescribed by Applicable Law (including as prescribed by Section 1471(b)(3)(C)(i) of the Internal Revenue Code) and such additional documentation reasonably requested by the Loan Parties or the Administrative Agent as may be necessary for the Loan Parties and the Administrative Agent to comply with their obligations under FATCA and to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment. Solely for purposes of this clause (D), “FATCA” shall include any amendments made to FATCA after the date of this Agreement.

Each Lender agrees that if any form or certification it previously delivered expires or becomes obsolete or inaccurate in any respect, it shall update such form or certification or

promptly notify the Loan Parties and the Administrative Agent in writing of its legal inability to do so.

(h) Treatment of Certain Refunds . If any party determines, in its sole discretion exercised in good faith, that it has received a refund of any Taxes as to which it has been indemnified pursuant to this Section 2.14 (including by the payment of additional amounts pursuant to this Section 2.14), it shall pay to the indemnifying party an amount equal to such refund (but only to the extent of indemnity payments made under this Section with respect to the Taxes giving rise to such refund), net of all out-of-pocket expenses (including Taxes) of such indemnified party and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund). Such indemnifying party, upon the request of such indemnified party, shall repay to such indemnified party the amount paid over pursuant to this subsection (h) (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) in the event that such indemnified party is required to repay such refund to such Governmental Authority. Notwithstanding anything to the contrary in this subsection (h), in no event will the indemnified party be required to pay any amount to an indemnifying party pursuant to this subsection (h) the payment of which would place the indemnified party in a less favorable net after-Tax position than the indemnified party would have been in if the Tax subject to indemnification and giving rise to such refund had not been deducted, withheld or otherwise imposed and the indemnification payments or additional amounts with respect to such Tax had never been paid. This subsection shall not be construed to require any indemnified party to make available its Tax returns (or any other information relating to its Taxes that it deems confidential) to the indemnifying party or any other Person.

(i) Survival . Each party’s obligations under this Section 2.14 shall survive the resignation or replacement of the Administrative Agent or any assignment of rights by, or the replacement of, a Lender, the termination of the Commitments and the repayment, satisfaction or discharge of all obligations under any Loan Document.

SECTION 2.15. Sharing of Payments, Etc.

(a) If any Lender shall obtain any payment (whether voluntary, involuntary, through the exercise of any right of set-off, or otherwise) on account of the Advances owing to it (other than pursuant to Section 2.07(c), 2.11, 2.14 or 9.04(c) or in respect of Eurodollar Rate Advances converted into Base Rate Advances pursuant to Section 2.12) by the Borrowers in excess of its ratable share of payments on account of the Advances to the Borrowers obtained by all the Lenders, such Lender shall forthwith purchase from the other Lenders such participations in such Advances owing to them as shall be necessary to cause such purchasing Lender to share the excess payment ratably with each of them; provided , however , that if all or any portion of such excess payment is thereafter recovered from such purchasing Lender, such purchase from each Lender shall be rescinded and such Lender shall repay to the purchasing Lender the purchase price to the extent of such recovery together with an amount equal to such Lender’s ratable share (according to the proportion of (i) the amount of such Lender’s required repayment to (ii) the total amount so recovered from the purchasing Lender) of any interest or other amount paid or payable by the purchasing Lender in respect of the total amount so recovered. Each Borrower agrees that any Lender so purchasing a participation from another Lender pursuant to this Section 2.15 may, to the fullest extent permitted by law, exercise all its rights of payment

(including the right of set-off) with respect to such participation as fully as if such Lender were the direct creditor of such Borrower in the amount of such participation.

(b) If any Lender shall fail to make any payment required to be made by it pursuant to Section 2.02(d) or 8.05, then the Administrative Agent may, in its discretion and notwithstanding any contrary provision hereof, (i) apply any amounts thereafter received by the Administrative Agent for the account of such Lender for the benefit of the Administrative Agent to satisfy such Lender’s obligations to it or them under such Section until all such unsatisfied obligations are fully paid, and/or (ii) hold any such amounts in a segregated account as cash collateral for, and application to, any future funding obligations of such Lender under any such Section, in the case of each of clauses (i) and (ii) above, in any order as determined by the Administrative Agent in its discretion.

SECTION 2.16. Mitigation Obligations; Replacement of Lenders.

(a) Designation of a Different Lending Office . If any Lender requests compensation under Section 2.11, or requires any Borrower to pay any Indemnified Taxes or additional amounts to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.14, then such Lender shall (at the request of the Borrowers) use reasonable efforts to designate a different Applicable Lending Office or to assign its rights and obligations hereunder to another of its offices, branches or Affiliates, if, in the judgment of such Lender, such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Section 2.11 or 2.14, as the case may be, in the future, and (ii) would not subject such Lender to any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender. Each Borrower hereby agrees to pay all reasonable costs and expenses incurred by any Lender in connection with any such designation or assignment.

(b) Replacement of Lenders . If any Lender delivers a notice or certificate pursuant to Section 2.12, requests compensation under Section 2.11, or if any Borrower is required to pay any Indemnified Taxes or additional amounts to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.14 and, in each case, such Lender has declined or is unable to designate a different Applicable Lending Office in accordance with Section 2.16(a), or if any Lender is a Defaulting Lender or a Non-Consenting Lender, then the Borrowers may, at their sole expense and effort, upon notice to such Lender and the Administrative Agent, require such Lender to assign and delegate, without recourse (in accordance with and subject to the restrictions contained in, and consents required by, Section 9.07), all of its interests, rights (other than its existing rights to payments pursuant to Section 2.11 or 2.14) and obligations under this Agreement and the related Loan Documents to an Eligible Assignee that shall assume such obligations (which assignee may be another Lender, if such Lender accepts such assignment); provided that:

(i) the Borrowers shall have paid to the Administrative Agent the assignment fee (if any) specified in Section 9.07(b)(iv);

(ii) such Lender shall have received payment of an amount equal to the outstanding principal of its Advances, accrued interest thereon, accrued commitment fees and all other amounts payable to it hereunder and under the other Loan Documents

(including any amounts under Section 9.04(c)) from the assignee (to the extent of such outstanding principal and accrued interest and commitment fees) or the Borrowers (in the case of all other amounts);

(iii) in the case of any such assignment resulting from a claim for compensation under Section 2.11 or payments required to be made pursuant to Section 2.14, such assignment will result in a reduction in such compensation or payments thereafter;

(iv) no Default shall have occurred and be continuing;

(v) such assignment does not conflict with Applicable Law; and

(vi) in the case of any assignment resulting from a Lender becoming a Non-Consenting Lender, the applicable assignee shall have consented to the applicable amendment, waiver or consent.

A Lender shall not be required to make any such assignment or delegation if, prior thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the Borrowers to require such assignment and delegation cease to apply.

SECTION 2.17. Assumption of Obligations.

(a) On the date of the AGR Transfer, AGR shall assume all outstanding Advances and all other obligations of OPCo under this Agreement and the other Loan Documents (the “ AGR Assumption ”), pursuant to a Borrower Assumption Agreement. Upon the effectiveness of the AGR Assumption, (i) OPCo shall no longer be a Borrower under this Agreement or any other Loan Document, nor have any rights or obligations of a Borrower hereunder or thereunder, and shall be released from any and all obligations under the Loan Documents, except for those obligations that expressly survive the repayment of all amounts under the Loan Documents or termination of the Commitments, and (ii) the Parent Guaranty will automatically become effective. Any promissory notes issued by OPCo under Section 2.06(d) of the Credit Agreement shall be returned to OPCo for cancellation upon such assumption.

(b) Following the AGR Assumption and substantially concurrently with the APCo Transfer, APCo may assume a portion of the outstanding Advances of AGR, in an aggregate principal amount not to exceed $500,000,000, and the related obligations of AGR under this Agreement and the other Loan Documents (the “ APCo Assumption ”), pursuant to a Borrower Assumption Agreement. Upon the effectiveness of the APCo Assumption, AGR will be released from liability for the Advances assumed by APCo, and AEP shall be released from its Guaranteed Obligations with respect to such assumed Advances.

(c) Following the AGR Assumption and substantially concurrently with the KPCo Transfer, KPCo may assume a portion of the outstanding Advances of AGR, in an aggregate principal amount not to exceed $250,000,000, and the related obligations of AGR under this Agreement and the other Loan Documents (the “ KPCo Assumption ”), pursuant to a Borrower Assumption Agreement. Upon the effectiveness of the KPCo Assumption, AGR will be released

from liability for the Advances assumed by KPCo, and AEP shall be released from its Guaranteed Obligations with respect to such assumed Advances.

(d) Each of the AGR Assumption, the APCo Assumption and the KPCo Assumption shall be subject to the following conditions precedent: (i) the receipt by the Administrative Agent of the applicable Borrower Assumption Agreement, (ii) the receipt by the Administrative Agent of a certificate signed by a duly authorized officer of each Loan Party that is a party to such Borrower Assumption Agreement, stating that both before and after giving effect to such assumption (A) all representations and warranties of such Loan Party contained in Section 4.01 are true and correct in all material respects on and as of such date, as though made on and as of such date, and (B) no event has occurred and is continuing that constitutes a Default, (iii) the receipt by the Administrative Agent of a certificate of the Secretary or Assistant Secretary of each Loan Party that is a party to such Borrower Assumption Agreement, certifying (A) that attached are true and correct copies of (x) the resolutions of the board of directors of such Loan Party approving the applicable assumption, and of all documents evidencing other necessary corporate action, and (y) all Governmental Approvals required to be obtained by such Loan Party for such assumption and (B) the names and true signatures of the officers of such Loan Party authorized to sign the applicable Borrower Assumption Agreement and the other documents to be delivered in connection therewith, (iv) the receipt by the Administrative Agent of an opinion of counsel to the Loan Parties that are a party to such Borrower Assumption Agreement, as to such matters related to the foregoing as the Administrative Agent or the Lenders through the Administrative Agent may reasonably request and (v) the receipt by the Administrative Agent of evidence that the AGR Transfer (in the case of the AGR Assumption), the APCo Transfer (in the case of the APCo Assumption) or the KPCo Transfer (in the case of the KPCo Assumption) shall have been completed.

ARTICLE III

CONDITIONS PRECEDENT

SECTION 3.01. Conditions Precedent to Effectiveness of this Agreement and Initial Advance.

The effectiveness of this Agreement and the obligation of each Lender to make the initial Advance to be made by it hereunder shall be subject to the satisfaction of the following conditions precedent:

(a) The Administrative Agent shall have received on or before the date of such effectiveness the following, each dated such day, in form and substance reasonably satisfactory to the Administrative Agent in sufficient copies for each Lender:

(i) Certified copies of the resolutions of the board of directors of each Loan Party approving this Agreement, and of all documents evidencing other necessary corporate action and Governmental Approvals, if any, with respect to this Agreement.

(ii) A certificate of the Secretary or Assistant Secretary of each Loan Party certifying the names and true signatures of the officers of such Loan Party

authorized to sign this Agreement and the other documents to be delivered by such Loan Party hereunder.

(iii) A favorable opinion of counsel for the Loan Parties (which may be an attorney of American Electric Power Service Corporation), substantially in the form of Exhibit C hereto and as to such other matters as any Lender through the Administrative Agent may reasonably request.

(iv) A favorable opinion of King & Spalding LLP, counsel for the Administrative Agent, in the form of Exhibit D hereto.

(b) On such date, the following statements shall be true and the Administrative Agent shall have received for the account of each Lender a certificate signed by a duly authorized officer of each Loan Party, dated such date, stating that:

(i) The representations and warranties of such Loan Party contained in Section 4.01 are true and correct in all material respects on and as of such date, as though made on and as of such date, and

(ii) No event has occurred and is continuing that constitutes a Default.

(c) The Borrowers shall have paid all fees and expenses of the Administrative Agent, the Joint Lead Arrangers and the Lenders then due and payable in accordance with the terms of the Loan Documents (including the fees and expenses of counsel to the Administrative Agent to the extent then due and payable).

(d) The Administrative Agent shall have received counterparts of this Agreement, executed and delivered by the Loan Parties and the Lenders.

(e) The Administrative Agent shall have received all promissory notes (if any) requested by the Lenders pursuant to Section 2.06(d), duly completed and executed by the Borrowers and payable to such Lenders.

(f) The Administrative Agent shall have received copies of the Disclosure Documents.

(g) All amounts outstanding under the Existing Credit Agreement, whether for principal, interest, fees or otherwise, shall have been paid in full, all commitments to lend thereunder shall have been terminated, and the Existing Credit Agreement shall have been terminated.

(h) The Administrative Agent shall have received all documentation and information required by regulatory authorities under applicable “know your customer” and anti-money laundering rules and regulations, including, without limitation, the Patriot Act, to the extent such documentation or information is requested by the Administrative Agent on behalf of the Lenders prior to the date hereof.

(i) The Administrative Agent shall have received copies or other evidence of such other approvals and such other opinions or documents as the Administrative Agent or any Lender through the Administrative Agent may reasonably request.

SECTION 3.02. Conditions Precedent to each Advance.

The obligation of each Lender to make an Advance to OPCo on the occasion of each Borrowing (including the initial Borrowing) shall be subject to the satisfaction of the conditions precedent set forth in Section 3.01 and on the date of such Borrowing:

(a) The following statements shall be true (and each of the giving of the applicable Notice of Borrowing and the acceptance by OPCo of the proceeds of such Borrowing shall constitute a representation and warranty by OPCo that on the date of such Borrowing such statements are true):

(i) The representations and warranties of OPCo contained in Section 4.01 (other than the representation and warranty in Section 4.01(e) and the representation and warranty set forth in the last sentence of Section 4.01(f)) are true and correct in all material respects on and as of the date of such Borrowing, before and after giving effect to such Borrowing and to the application of the proceeds therefrom, as though made on and as of such date, and

(ii) No event has occurred and is continuing or would result from such Borrowing or from the application of the proceeds therefrom, that constitutes a Default.

(b) The Administrative Agent shall have received copies or other evidence of such other approvals and such other opinions or documents as the Administrative Agent or any Lender through the Administrative Agent may reasonably request.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES

SECTION 4.01. Representations and Warranties of the Loan Parties.

Each Loan Party represents and warrants as follows:

(a) Such Loan Party is a corporation duly organized, validly existing and in good standing under the laws of the jurisdiction in which it is incorporated, and each Significant Subsidiary of such Loan Party is duly organized, validly existing and in good standing under the laws of the jurisdiction in which it is incorporated or otherwise organized.

(b) The execution, delivery and performance by such Loan Party of each Loan Document to which it is, or is to become a party, and the consummation of the transactions contemplated hereby, are within such Loan Party’s corporate powers, have been duly authorized by all necessary action, and do not contravene (i) such Loan Party’s certificate of incorporation or by-laws, (ii) law binding or affecting such Loan Party or (iii) any contractual restriction binding on or affecting such Loan Party or any of its properties.

(c) Each Loan Document to which it is, or is to become, a party has been duly executed and delivered by such Loan Party. This Agreement is, and, upon execution and delivery thereof, each other Loan Document will be the legal, valid and binding obligation of such Loan Party enforceable against such Loan Party in accordance with its terms, except as the enforceability thereof may be limited by bankruptcy, insolvency, fraudulent conveyance or other similar laws affecting the enforcement of creditors’ rights in general, and except as the availability of the remedy of specific performance is subject to general principles of equity (regardless of whether such remedy is sought in a proceeding in equity or at law) and subject to requirements of reasonableness, good faith and fair dealing.

(d) No authorization or approval or other action by, and no notice to or filing with, any Governmental Authority or any other third party is required for the due execution, delivery and performance by such Loan Party of any Loan Document to which it is, or is to become, party other than with respect to each Borrower (i) such Approvals, if any, that have been duly issued and are in full force and effect and (ii) such Approvals that may be required to be obtained by such Borrower in connection with the AGR Assumption, APCo Assumption or KPCo Assumption, each of which will have been obtained and will be in full force on or prior to the date of the AGR Assumption, APCo Assumption or KPCo Assumption, as applicable.

(e) There is no pending or threatened action, suit, investigation, litigation or proceeding, including, without limitation, any Environmental Action, affecting such Loan Party or any of its Significant Subsidiaries before any Governmental Authority or arbitrator that is reasonably likely to have a Material Adverse Effect, except as disclosed in the Disclosure Documents.

(f) The consolidated balance sheets of such Loan Party (other than AGR) and its Consolidated Subsidiaries as at December 31, 2012 and March 31, 2013, and the related consolidated statements of income and cash flows of such Loan Party (other than AGR) and its Consolidated Subsidiaries for the fiscal periods then ended, accompanied by (in the case of such financial statements for the fiscal year ended December 31, 2012) an opinion of Deloitte & Touche LLP, an independent registered public accounting firm, copies of each of which have been furnished to each Lender, fairly present (subject, in the case of such financial statements for the fiscal quarter ended March 31, 2013, to year-end adjustments) the consolidated financial condition of such Loan Party (other than AGR) and its Consolidated Subsidiaries as at such dates and the consolidated results of the operations of such Loan Party (other than AGR) and its Consolidated Subsidiaries for the periods ended on such dates, all in accordance with generally accepted accounting principles consistently applied. Since December 31, 2012, there has been no Material Adverse Change as to any Loan Party.

(g) No written statement, information, report, financial statement, exhibit or schedule furnished by or on behalf of such Loan Party to the Administrative Agent or any Lender in connection with the syndication or negotiation of this Agreement or included herein or delivered pursuant hereto contained, contains, or will contain any material misstatement of fact or intentionally omitted, omits, or will omit to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were, are, or will be made, not misleading.

(h) Except as disclosed in the Disclosure Documents, such Loan Party and each Significant Subsidiary of such Loan Party is in material compliance with all laws (including ERISA and Environmental Laws) rules, regulations and orders of any Governmental Authority applicable to it.

(i) No failure to satisfy the minimum funding standard applicable to a Plan for a plan year (as described in Section 302 of ERISA and Section 412 of the Internal Revenue Code) that could reasonably be expected to have a Material Adverse Effect, whether or not waived, has occurred with respect to any Plan. Such Loan Party has not incurred, and does not presently expect to incur, any withdrawal liability under Title IV of ERISA with respect to any Multiemployer Plan that could reasonably be expected to have a Material Adverse Effect. Such Loan Party and each of its ERISA Affiliates have complied in all material respects with ERISA and the Internal Revenue Code. Such Loan Party and each of its Subsidiaries have complied in all material respects with foreign law applicable to its Foreign Plans, if any. As used herein, the term “ Plan ” means an “employee pension benefit plan” (as defined in Section 3 of ERISA) which is and has been established or maintained, or to which contributions are or have been made or should be made according to the terms of the plan, by such Loan Party or any of its ERISA Affiliates. The term “ Multiemployer Plan ” means any Plan which is a “multiemployer plan” (as such term is defined in Section 4001(a)(3) of ERISA). The term “ Foreign Plan ” means any pension, profit-sharing, deferred compensation, or other employee benefit plan, program or arrangement maintained by any Subsidiary which, under applicable local foreign law, is required to be funded through a trust or other funding vehicle.

(j) Such Loan Party and its Subsidiaries have filed or caused to be filed all material Federal, state and local tax returns that are required to be filed by them, and have paid or caused to be paid all material taxes shown to be due and payable on such returns or on any assessments received by them (to the extent that such taxes and assessments have become due and payable) other than those taxes contested in good faith and for which adequate reserves have been established in accordance with GAAP.

(k) Such Loan Party is not engaged in the business of extending credit for the purpose of buying or carrying Margin Stock, and no proceeds of any Advance will be used to buy or carry any Margin Stock or to extend credit to others for the purpose of buying or carrying any Margin Stock. Not more than 25% of the assets of such Loan Party and its Significant Subsidiaries that are subject to the restrictions of Section 5.02(a), (c) or (d) constitute Margin Stock.

(l) Neither such Loan Party nor any of its Significant Subsidiaries is an “investment company,” or an “affiliated person” of, or “promoter” or “principal underwriter” for, an “investment company”, as such terms are defined in the Investment Company Act of 1940, as amended. Neither the making, assuming or guaranteeing of any Borrowing, as applicable, the application of the proceeds or repayment thereof by such Loan Party nor the consummation of the other transactions contemplated hereby will violate any provision of such Act or any rule, regulation or order of the SEC thereunder.

(m) All Significant Subsidiaries of such Loan Party as of the date hereof are listed on Schedule 4.01(m) hereto under the name of such Loan Party.

ARTICLE V

COVENANTS OF THE LOAN PARTIES

SECTION 5.01. Affirmative Covenants.

So long as any Advance or any other amount payable hereunder shall remain unpaid or any Lender shall have any Commitment hereunder, each Loan Party will:

(a) Preservation of Existence, Etc. Preserve and maintain, and cause each Significant Subsidiary of such Loan Party to preserve and maintain, its corporate, partnership or limited liability company (as the case may be) existence and all material rights (charter and statutory) and franchises; provided , however , that such Loan Party and any Significant Subsidiary thereof may consummate any merger or consolidation permitted under Section 5.02(a); and provided further that neither such Loan Party nor any Significant Subsidiary thereof shall be required to preserve any right or franchise if (i) the board of directors of such Loan Party or such Significant Subsidiary, as the case may be, shall determine that the preservation thereof is no longer desirable in the conduct of the business of such Loan Party or such Significant Subsidiary, as the case may be, and that the loss thereof is not disadvantageous in any material respect to such Loan Party or such Significant Subsidiary, as the case may be, or to the Lenders; (ii) required in connection with or pursuant to any Restructuring Law; or (iii) required in connection with the RTO Transaction; and provided further, that no Significant Subsidiary of a Loan Party shall be required to preserve and maintain its corporate existence if (x) the loss thereof is not disadvantageous in any material respect to such Loan Party or to the Lenders or (y) required in connection with or pursuant to any Restructuring Law or (z) required in connection with the RTO Transaction.

(b) Compliance with Laws, Etc. Comply, and cause each Significant Subsidiary of such Loan Party to comply, in all material respects, with Applicable Law, with such compliance to include, without limitation, compliance with ERISA and Environmental Laws.

(c) Performance and Compliance with Other Agreements . Perform and comply, and cause each Significant Subsidiary of such Loan Party to perform and comply, with the provisions of each indenture, credit agreement, contract or other agreement by which it is bound, the non-performance or non-compliance with which would result in a Material Adverse Change.

(d) Inspection Rights . At any reasonable time and from time to time, permit the Administrative Agent or any Lender or any agents or representatives thereof to examine and make copies of and abstracts from the records and books of account of, and visit the properties of, such Loan Party and any Significant Subsidiary of such Loan Party and to discuss the affairs, finances and accounts of such Loan Party and any Significant Subsidiary of such Loan Party with any of their officers or directors and with their independent certified public accountants.

(e) Maintenance of Properties, Etc. Maintain and preserve, and cause each Significant Subsidiary of such Loan Party to maintain and preserve, all of its properties that are used or useful in the conduct of its business in good working order and condition, ordinary wear and tear excepted and except as required in connection with or pursuant to any Restructuring Law or in connection with RTO Transaction.

(f) Maintenance of Insurance . Maintain, and cause each Significant Subsidiary of such Loan Party to maintain, insurance with responsible and reputable insurance companies or associations in such amounts and covering such risks as is usually carried by companies engaged in similar businesses and owning similar properties; provided , however , that such Loan Party and each Significant Subsidiary thereof may self-insure to the same extent as other companies engaged in similar businesses and owning similar properties and to the extent consistent with prudent business practice.

(g) Payment of Taxes, Etc. Pay and discharge, and cause each of its Subsidiaries to pay and discharge, before the same shall become delinquent, (i) all taxes, assessments and governmental charges or levies imposed upon it or upon its property and (ii) all lawful claims that, if unpaid, might by law become a Lien upon its property; provided , however , that neither such Loan Party nor any of its Subsidiaries shall be required to pay or discharge any such tax, assessment, charge or claim that is being contested in good faith and by proper proceedings and as to which adequate reserves are being maintained in accordance with GAAP, unless and until any Lien resulting therefrom attaches to its property and becomes enforceable against its other creditors.

(h) Keeping of Books . Keep, and cause each Significant Subsidiary of such Loan Party to keep, proper books of record and account, in which full and correct entries shall be made of all financial transactions and the assets and business of such Loan Party and each such Significant Subsidiary in accordance with GAAP.

(i) Reporting Requirements . Furnish to the Lenders:

(i) as soon as available and in any event within 60 days after the end of each of the first three quarters of each fiscal year of such Loan Party, (A) with respect to AEP, OPCo and APCo, a copy of AEP’s Quarterly Report on Form 10-Q for such quarter, as filed with the SEC, which shall contain a consolidated balance sheet of such Loan Party and its Subsidiaries as of the end of such quarter and consolidated statements of income and cash flows of such Loan Party and its Subsidiaries for the period commencing at the end of the previous fiscal year and ending with the end of such quarter, duly certified (subject to year-end audit adjustments) by the chief financial officer, chief accounting officer, treasurer or assistant treasurer of AEP as having been prepared in accordance with generally accepted accounting principles, and (B) with respect to KPCo, a copy of the consolidated balance sheet of KPCo as of the end of such quarter and consolidated statements of income and cash flows of KPCo for the period commencing at the end of the previous fiscal year and ending with the end of such quarter, duly certified (subject to year-end audit adjustments) by the chief

financial officer, chief accounting officer, treasurer or assistant treasurer of KPCo as having been prepared in accordance with generally accepted accounting principles, and with respect to each such Loan Party, a certificate of the chief financial officer, chief accounting officer, treasurer or assistant treasurer of such Loan Party as to compliance with the terms of this Agreement and (1) certifying that (x) there has been no Specified Debt Issuance effected in such quarter (other than any such Specified Debt Issuance that resulted in a mandatory prepayment of Advances having been made during such period pursuant to Section 2.10(b)), and (y) there have been no Subsidiaries that have become Significant Subsidiaries of such Loan Party at any time during such period, or any Subsidiaries that have ceased to be Significant Subsidiaries of such Loan Party at any time during such period, in each case except as expressly identified in such certificate, and (2) setting forth in reasonable detail the calculations necessary to demonstrate compliance with Section 5.03, provided that in the event of any change in GAAP used in the preparation of such financial statements, such Loan Party shall also provide, if necessary for the determination of compliance with Section 5.03, a statement of reconciliation conforming such financial statements to GAAP in effect on the date hereof;

(ii) as soon as available and in any event within 120 days after the end of each fiscal year of such Loan Party, (A) with respect to AEP, OPCo and APCo, a copy of AEP’s Annual Report on Form 10-K for such year, as filed with the SEC, which shall contain a copy of the annual audit report for such year for such Loan Party and its Subsidiaries, containing a consolidated balance sheet of such Loan Party and its Subsidiaries as of the end of such fiscal year and consolidated statements of income and cash flows of such Loan Party and its Subsidiaries for such fiscal year, in each case accompanied by an opinion by Deloitte & Touche LLP or another independent registered public accounting firm acceptable to the Required Lenders, and consolidating statements of income and cash flows of such Loan Party and its Subsidiaries for such fiscal year, and (B) with respect to KPCo, a copy of the annual report for such year for KPCo, containing a consolidated balance sheet of KPCo as of the end of such fiscal year and consolidated statements of income and cash flows of KPCo for such fiscal year, in each case accompanied by an opinion by Deloitte & Touche LLP or another independent registered public accounting firm acceptable to the Required Lenders, and consolidating statements of income and cash flows of KPCo for such fiscal year, and with respect to each such Loan Party, a certificate of the chief financial officer, chief accounting officer, treasurer or assistant treasurer of such Loan Party as to compliance with the terms of this Agreement and (1) certifying that (x) there has been no Specified Debt Issuance effected in such year (other than any such Specified Debt Issuance that resulted in a mandatory prepayment of Advances having been made during such period pursuant to Section 2.10(b)), and (y) there have been no Subsidiaries that have become Significant Subsidiaries of such Loan Party at any time during such period, or any Subsidiaries that have ceased to be Significant Subsidiaries of such Loan Party at any time during such period, in each case except as expressly identified in such certificate, and (2) setting forth in reasonable detail the calculations necessary to demonstrate

compliance with Section 5.03, provided that in the event of any change in GAAP used in the preparation of such financial statements, such Loan Party shall also provide, if necessary for the determination of compliance with Section 5.03, a statement of reconciliation conforming such financial statements to GAAP in effect on the date hereof;

(iii) as soon as possible and in any event within five days after the chief financial officer or treasurer of such Loan Party obtains knowledge of the occurrence of each Default continuing on the date of such statement, a statement of the chief financial officer or treasurer of such Loan Party setting forth details of such Default and the action that such Loan Party has taken and proposes to take with respect thereto;

(iv) promptly after the sending or filing thereof, copies of all Reports on Form 8-K that such Loan Party or any Significant Subsidiary of such Loan Party files with the SEC or any national securities exchange;

(v) promptly after the commencement thereof, notice of all actions and proceedings before any Governmental Authority or arbitrator affecting such Loan Party or any Significant Subsidiary of such Loan Party of the type described in Section 4.01(e);

(vi) as soon as possible and in any event not later than one Business Day after each Specified Debt Issuance, written notice of such Specified Debt Issuance and the estimated amount of any mandatory prepayment required pursuant to Section 2.10(b) in respect of such Specified Debt Issuance; and

(vii) such other information respecting such Loan Party or any of its Subsidiaries as any Lender through the Administrative Agent may from time to time reasonably request.

Notwithstanding the foregoing, the information required to be delivered pursuant to clauses (i), (ii) and (iv) shall be deemed to have been delivered if such information shall be available on the website of the SEC at http://www.sec.gov (or any successor website) or on AEP’s website; provided that the compliance certificates required under clauses (i) and (ii) shall be delivered in the manner specified in Section 9.02(b).

SECTION 5.02. Negative Covenants.

So long as any Advance or any other amount payable hereunder shall remain unpaid or any Lender shall have any Commitment hereunder, each Loan Party agrees that it will not:

(a) Mergers, Etc. Merge or consolidate with or into any Person, or permit any Significant Subsidiary of such Loan Party to do so, except that (i) any Subsidiary of such Loan Party may merge or consolidate with or into any other Subsidiary of such Loan Party, (ii) any Subsidiary of such Loan Party may merge into such Loan Party, (iii) any Significant Subsidiary of such Loan Party may merge with or into any other Person so long as such Significant Subsidiary continues to be a Significant Subsidiary of such

Loan Party and (iv) such Loan Party may merge with any other Person so long as the successor entity (if other than such Loan Party) (A) assumes, in form reasonably satisfactory to the Administrative Agent, all of the obligations of such Loan Party under this Agreement and the other Loan Documents and (B)(1) in the case of a merger of AGR, has all its obligations under this Agreement and the other Loan Documents guaranteed by AEP, in form reasonably satisfactory to the Administrative Agent or (2) in the case of a merger of any other Loan Party has long-term senior unsecured debt ratings issued (and confirmed after giving effect to such merger) by S&P or Moody’s of at least BBB- and Baa3, respectively (or if no such ratings have been issued, commercial paper ratings issued (and confirmed after giving effect to such merger) by S&P and Moody’s of at least A-3 and P-3, respectively); provided , in each case of clause (iv), that no Default shall have occurred and be continuing at the time of such proposed transaction or would result therefrom.

(b) Stock of Significant Subsidiaries. Sell, lease, transfer or otherwise dispose of, other than (i) in connection with an RTO Transaction, but only if no Default or Event of Default has occurred and is continuing or would result from such RTO Transaction, (ii) pursuant to the requirements of any Restructuring Law or (iii) in connection with, and solely to the extent necessary to consummate, the AGR Transfer, the APCo Transfer or the KPCo Transfer ( provided , in each case of this clause (iii), that no Default shall have occurred and be continuing at the time of such proposed transaction or would result therefrom), equity interests in any Significant Subsidiary of such Loan Party (other than AEP Resources, Inc., AEP Energy Services, Inc. or CSW Energy, Inc.) if such Significant Subsidiary would cease to be a Subsidiary of a Loan Party as a result of such sale, lease, transfer or disposition.

(c) Sales, Etc. of Assets . Sell, lease, transfer or otherwise dispose of, or permit any Significant Subsidiary of such Loan Party (other than AEP Resources, Inc., AEP Energy Services, Inc. or CSW Energy, Inc.) to sell, lease, transfer or otherwise dispose of, any assets, or grant any option or other right to purchase, lease or otherwise acquire any assets, except (i) sales in the ordinary course of its business, (ii) sales, leases, transfers or dispositions of assets to any Person that is not a wholly-owned Subsidiary of such Loan Party that in the aggregate do not exceed 20% of the Consolidated Tangible Net Assets of such Loan Party and its Subsidiaries, whether in one transaction or a series of transactions, (iii) other sales, leases, transfers and dispositions made in connection with an RTO Transaction or pursuant to the requirements of any Restructuring Law or to a wholly owned Subsidiary of such Loan Party, (iv) sales of pollution control assets to a state or local government or any political subdivision or agency thereof in connection with any transaction with such Person pursuant to which such Person sells or otherwise transfers such pollution control assets back to such Loan Party or a Subsidiary of such Loan Party under an installment sale, loan or similar agreement, in each case in connection with the issuance of pollution control or similar bonds, or (v) the AGR Transfer, the APCo Transfer or the KPCo Transfer; provided , in each case of this clause (v), that no Default shall have occurred and be continuing at the time of such proposed transaction or would result therefrom.

(d) Liens, Etc. Create or suffer to exist, or permit any Significant Subsidiary of such Loan Party to create or suffer to exist, any Lien on or with respect to any of its properties, including, without limitation, on or with respect to equity interests in any Subsidiary of such Loan Party, whether now owned or hereafter acquired, or assign, or permit any Significant Subsidiary of such Loan Party to assign, any right to receive income (other than in connection with Stranded Cost Recovery Bonds and the sale of accounts receivable by such Loan Party), other than (i) Permitted Liens, (ii) the Liens existing on the date hereof, (iii) Liens securing first mortgage bonds issued by such Loan Party (excluding AEP) or any Subsidiary of such Loan Party (including Subsidiaries of AEP) the rates or charges of which are regulated by the Federal Energy Regulatory Commission or any state governmental authority, provided that the aggregate principal amount of such first mortgage bonds of any such Loan Party (excluding AEP) or such Subsidiary do not exceed 66-2/3% of the net value of plant, property and equipment of such Loan Party (excluding AEP) or such Subsidiary, as applicable, and (iv) the replacement, extension or renewal of any Lien permitted by clauses (ii) and (iii) above upon or in the same property theretofore subject thereto or the replacement, extension or renewal (without increase in the amount or change in any direct or contingent obligor) of the Debt secured thereby.

(e) Restrictive Agreements . Enter into, or permit any Significant Subsidiary of such Loan Party to enter into (except in connection with or pursuant to any Restructuring Law), any agreement after the date hereof, or amend, supplement or otherwise modify any agreement existing on the date hereof, that imposes any restriction on the ability of any Significant Subsidiary of such Loan Party to make payments, directly or indirectly, to its shareholders by way of dividends, advances, repayment of loans or intercompany charges, expenses and accruals or other returns on investments that is more restrictive than any such restriction applicable to such Significant Subsidiary on the date hereof; provided , however , that any Significant Subsidiary of such Loan Party may agree to a financial covenant limiting its ratio of Consolidated Debt to Consolidated Capital to no more than 0.675 to 1.000.

(f) ERISA . (i) Terminate or withdraw from, or permit any of its ERISA Affiliates to terminate or withdraw from, any Plan with respect to which such Loan Party or any of its ERISA Affiliates may have any liability by reason of such termination or withdrawal, if such termination or withdrawal could have a Material Adverse Effect, (ii) incur a full or partial withdrawal, or permit any ERISA Affiliate to incur a full or partial withdrawal, from any Multiemployer Plan with respect to which such Loan Party or any of its ERISA Affiliates may have any liability by reason of such withdrawal, if such withdrawal could have a Material Adverse Effect, (iii) otherwise fail, or permit any of its ERISA Affiliates to fail, to comply in all material respects with ERISA or the related provisions of the Internal Revenue Code if such noncompliances, singly or in the aggregate, could have a Material Adverse Effect, or (iv) fail, or permit any of its Subsidiaries to fail, to comply with Applicable Law with respect to any Foreign Plan if such noncompliances, singly or in the aggregate, could have a Material Adverse Effect.

(g) Use of Proceeds . Use the proceeds of any Borrowing to buy or carry Margin Stock.

SECTION 5.03. Financial Covenant.

So long as any Advance shall remain unpaid or any Lender shall have any Commitment hereunder, each Loan Party will maintain a ratio of Consolidated Debt to Consolidated Capital, as of the last day of each March, June, September and December, of not greater than 0.675 to 1.000.

ARTICLE VI

GUARANTY

SECTION 6.01. Guaranty.

Effective as of the date of the AGR Assumption, the Guarantor hereby irrevocably, absolutely and unconditionally guarantees (this “ Parent Guaranty ”) the full and prompt payment, as and when due, of all of the obligations of AGR to each Credit Party under the Loan Documents, including, without limitation, the payment of any and all amounts payable by AGR under the Loan Documents, whether for principal, interest, fees, indemnities or otherwise (the “ Guaranteed Obligations ”). The Guarantor agrees that, in the event that AGR fails to timely pay when due any Guaranteed Obligations to any Credit Party, then the Guarantor will immediately upon notice by the Administrative Agent pay such Guaranteed Obligations in the place and stead of AGR in the manner set forth for such Guaranteed Obligations in the Loan Documents. The Guarantor agrees that this Parent Guaranty constitutes a guaranty of payment when due and not of collection. The Guarantor agrees to pay all reasonable and documented out of pocket costs and expenses incurred by each Credit Party in enforcing its rights hereunder. Notwithstanding any to the contrary above, the Guarantor shall be released from its Guaranteed Obligations with respect to Advances that are assumed from AGR by APCo or KPCo pursuant to Section 2.17.

SECTION 6.02. Guaranty Absolute and Unconditional.

The obligations of the Guarantor under this Article VI shall remain in full force and effect without regard to, and shall not be affected or impaired by any of the following, any of which may be taken without the consent of, or notice to, the Guarantor:

(a) any exercise or non-exercise by any Credit Party of any right or privilege under the Loan Documents;

(b) any extension (including without limitation extensions of time for payment), renewal, amendment, restructuring or restatement of, or any acceptance of late or partial payments under, or increase in the principal amount of Debt under, or other modification of terms under, the Loan Documents;

(c) any bankruptcy, insolvency, reorganization, dissolution, liquidation or similar proceeding relating to AGR or any Affiliate of AGR;

(d) the existence of any facts or circumstances that cause (or result in) any of the representations or warranties of any Loan Party under the Loan Documents to be inaccurate;

(e) any merger, consolidation, restructuring or termination of the corporate existence of AGR or the Guarantor; or

(f) the illegality, invalidity or unenforceability of any of all or any part of the Guaranteed Obligations.

This Article VI shall continue to be effective or be reinstated, as the case may be, if at any time any payment of any of the Guaranteed Obligations is rescinded or must otherwise be returned by any Credit Party or any other Person upon the insolvency, bankruptcy or reorganization of the Guarantor, AGR or otherwise, all as though such payment had not been made.

SECTION 6.03. Authorization; Other Agreements.

The Credit Parties are hereby authorized, without notice to or demand upon the Guarantor and without discharging or otherwise affecting the obligations of the Guarantor hereunder and without incurring any liability hereunder, from time to time, to do each of the following:

(a) (i) modify, amend, supplement or otherwise change, (ii) accelerate or otherwise change the time of payment or (iii) waive or otherwise consent to noncompliance with, any Guaranteed Obligation or any Loan Document;

(b) apply to the Guaranteed Obligations any sums by whomever paid or however realized to any Guaranteed Obligation in such order as provided in the Loan Documents;

(d) add, release or substitute the Guarantor or any makers or endorsers of any Guaranteed Obligation or any part thereof;

(e) otherwise deal in any manner with AGR and the Guarantor, any maker or endorser of any Guaranteed Obligation or any part thereof; and

(f) settle, release, compromise, collect or otherwise liquidate the Guaranteed Obligations.

SECTION 6.04. Independent Obligations.

The obligations of the Guarantor under this Article VI are independent of the obligations of AGR and, in the event of any default with respect to this Parent Guaranty, a separate action or actions may be brought and prosecuted against the Guarantor whether or not AGR is joined therein or a separate action or actions are brought against AGR. All remedies of the Credit Parties are cumulative.

SECTION 6.05. Waivers.

The Guarantor unconditionally and irrevocably waives:

(a) except as expressly provided in Section 6.01, demands, protests or notices as the same pertain to AGR;

(b) any right to require the Credit Parties to proceed against AGR, or to exhaust any security held by the Credit Parties or to pursue any other remedy;

(c) any right to assert against any Credit Party, as a defense, counterclaim, set-off, recoupment or cross claim in respect of the Guaranteed Obligations, any defense (legal or equitable) or other claim that the Guarantor may now or at any time hereafter have against AGR or any other Person (other than payment of the Obligations in full);

(d) any defense based upon an election of remedies by any Credit Party, unless the same would excuse performance by AGR under the Loan Documents;

(e) any duty of any Credit Party to advise the Guarantor of any information known to such Credit Party regarding AGR or its ability to perform under the Loan Documents; and

(f) any other circumstance that might otherwise constitute a defense available to, or a discharge of, the Guarantor.

SECTION 6.06. Limitation of Parent Guaranty.

Any term or provision of this Parent Guaranty or any other Loan Document to the contrary notwithstanding, the maximum aggregate amount for which the Guarantor shall be liable hereunder shall not exceed the maximum amount for which the Guarantor can be liable without rendering this Parent Guaranty subject to avoidance under applicable requirements of law relating to fraudulent conveyance or fraudulent transfer (including the Uniform Fraudulent Conveyance Act, the Uniform Fraudulent Transfer Act and Section 548 of title 11 of the United States Code or any applicable provisions of comparable requirements of law). If any obligation under this Article VI shall be declared invalid or unenforceable in accordance with this Section 6.06, it is the stated intention of the parties hereto that any balance of the obligation created by such provision and all other obligations of the Guarantor under this Article VI to each Credit Party shall remain valid and enforceable and that all sums not in excess of those permitted under applicable law shall remain fully collectable by the Credit Parties.

SECTION 6.07. Subrogation.

The Guarantor hereby unconditionally and irrevocably agrees not to exercise any rights that it may now have or hereafter acquire against AGR that arise from the existence, payment, performance or enforcement of the Guaranteed Obligations under or in respect of any Loan Document, including, without limitation, any right of subrogation, reimbursement, exoneration, contribution or indemnification and any right to participate in any claim or remedy of any Credit Party against AGR, whether or not such claim, remedy or right arises in equity or under contract, statute or common law, including, without limitation, the right to take or receive from AGR, directly or indirectly, in cash or other property or by set-off or in any other manner, payment or security on account of such claim, remedy or right, unless and until all of the Guaranteed Obligations and all other amounts payable under the Loan Documents shall have been paid in full in cash and the Commitments shall have expired or been terminated. If any amount shall be

paid to the Guarantor in violation of the immediately preceding sentence at any time prior to the later of (x) the payment in full in cash of the Guaranteed Obligations and all other amounts payable under the Loan Documents and (y) the Termination Date, such amount shall be received and held in trust for the benefit of the Credit Parties, shall be segregated from other property and funds of the Guarantor and shall forthwith be paid or delivered to the Administrative Agent in the same form as so received (with any necessary endorsement or assignment) to be credited and applied to the Guaranteed Obligations and all other amounts payable under the Loan Documents, whether matured or unmatured, in accordance with the terms of the Loan Documents, or to be held as collateral for any Guaranteed Obligations or other amounts payable under the Loan Documents thereafter arising. If (i) the Guarantor shall make payment to any Credit Party of all or any part of the Guaranteed Obligations, (ii) all of the Guaranteed Obligations and all other amounts payable under the Loan Documents shall have been paid in full in cash, and (iii) the Termination Date shall have occurred, the Credit Parties will, at the Guarantor’s request and expense, execute and deliver to the Guarantor appropriate documents, without recourse and without representation or warranty, necessary to evidence the transfer by subrogation to the Guarantor of an interest in the Guaranteed Obligations resulting from such payment made by the Guarantor pursuant to the Loan Documents.

SECTION 6.08. Termination.

Subject to the last sentence of Section 6.01, this Parent Guaranty shall constitute a continuing guaranty and shall continue in full force and effect until such time as the Guaranteed Obligations (other than contingent indemnity obligations) shall have been fully paid or otherwise extinguished under the Loan Documents.

SECTION 6.09. Reliance.

The Guarantor hereby assumes responsibility for keeping itself informed of the financial condition of AGR and any other guarantor, maker or endorser of any Guaranteed Obligation or any part thereof, and of all other circumstances bearing upon the risk of nonpayment of any Guaranteed Obligation or any part thereof that diligent inquiry would reveal, and the Guarantor hereby agrees that no Credit Party shall have any duty to advise the Guarantor of information known to it regarding such condition or any such circumstances. In the event any Credit Party, in its sole discretion, undertakes at any time or from time to time to provide any such information to the Guarantor, such Credit Party shall be under no obligation to (i) undertake any investigation not a part of its regular business routine, (ii) disclose any information that such Credit Party, pursuant to accepted or reasonable commercial finance or banking practices, wishes to remain confidential, or (iii) make any future disclosures of such information or any other information to the Guarantor.

ARTICLE VII

EVENTS OF DEFAULT

SECTION 7.01. Events of Default.

If any of the following events shall occur and be continuing with respect to any Loan Party (as to such Loan Party, an “ Event of Default ”); provided , that the occurrence of an event

described in Section 7.01(e) as to AEP shall also be an Event of Default as to AGR and the occurrence of an event described in Section 7.01(i) shall be an Event of Default solely as to AEP and AGR:

(a) Such Loan Party shall fail to pay any principal of any Advance when the same becomes due and payable, or shall fail to pay any interest on any Advance or make any other payment of fees or other amounts payable under this Agreement within five days after the same becomes due and payable; or

(b) Any representation or warranty made by such Loan Party herein or by such Loan Party (or any of its officers) in connection with this Agreement shall prove to have been incorrect in any material respect when made; or

(c) (i) Such Loan Party shall fail to perform or observe any term, covenant or agreement contained in Section 5.01(a), 5.01(i)(iii) or 5.02 (other than Section 5.02(f)), or (ii) such Loan Party shall fail to perform or observe any other term, covenant or agreement contained in this Agreement or any other Loan Document if such failure shall remain unremedied for 30 days after written notice thereof shall have been given to such Loan Party by the Administrative Agent or any Lender; or

(d) Any event shall occur or condition shall exist under any agreement or instrument relating to Debt of such Loan Party (but excluding Debt outstanding hereunder) or any Significant Subsidiary of such Loan Party outstanding in a principal or notional amount of at least $50,000,000 in the aggregate if the effect of such event or condition is to accelerate or require early termination of the maturity or tenor of such Debt, or any such Debt shall be declared to be due and payable, or required to be prepaid or redeemed (other than by a regularly scheduled required prepayment or redemption), terminated, purchased or defeased, or an offer to prepay, redeem, purchase or defease such Debt shall be required to be made, in each case prior to the stated maturity or the original tenor thereof; or

(e) Such Loan Party or any Significant Subsidiary of such Loan Party shall generally not pay its debts as such debts become due, or shall admit in writing its inability to pay its debts generally, or shall make a general assignment for the benefit of creditors; or any proceeding shall be instituted by or against such Loan Party or any Significant Subsidiary of such Loan Party seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee, custodian or other similar official for it or for any substantial part of its property and, in the case of any such proceeding instituted against it (but not instituted by it), either such proceeding shall remain undismissed or unstayed for a period of 60 days, or any of the actions sought in such proceeding (including, without limitation, the entry of an order for relief against, or the appointment of a receiver, trustee, custodian or other similar official for, it or for any substantial part of its property) shall occur; or such Loan Party or any Significant Subsidiary of such Loan Party shall

take any corporate action to authorize any of the actions set forth above in this subsection (e); or

(f) (i) Any entity, person (within the meaning of Section 14(d) of the Securities Exchange Act of 1934, as amended (the “ Exchange Act ”)) or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) that as of the date hereof was beneficial owner (as defined in Rule 13d-3 under the Exchange Act) of less than 30% of the Voting Stock of AEP shall acquire a beneficial ownership (within the meaning of Rule 13d-3 of the SEC under the Exchange Act), directly or indirectly, of Voting Stock of AEP (or other securities convertible into such Voting Stock) representing 30% or more of the combined voting power of all Voting Stock of AEP; (ii) during any period of up to 24 consecutive months, commencing after the date hereof, individuals who at the beginning of such 24-month period were directors of AEP shall cease for any reason to constitute a majority of the board of directors of AEP, provided that any person becoming a director subsequent to the date hereof, whose election, or nomination for election by AEP’s shareholders, was approved by a vote of at least a majority of the directors of the board of directors of AEP as comprised as of the date hereof (other than the election or nomination of an individual whose initial assumption of office is in connection with an actual or threatened election contest relating to the election of the directors of AEP) shall be, for purposes of this provision, considered as though such person were a member of the board as of the date hereof; or (iii) AEP shall cease to own, directly or indirectly, 100% of the Voting Stock of OPCo, APCo or KPCo, to the extent such Borrower has any outstanding Advances or unpaid interest or other amounts owing under this Agreement at such time; or

(g) Any judgment or order for the payment of money in excess of $50,000,000 in the case of such Loan Party or any Significant Subsidiary of such Loan Party to the extent not paid or insured shall be rendered against such Loan Party or any Significant Subsidiary of such Loan Party and either (i) enforcement proceedings shall have been commenced by any creditor upon such judgment or order or (ii) there shall be any period of 30 consecutive days during which a stay of enforcement of such judgment or order, by reason of a pending appeal or otherwise, shall not be in effect; or

(h) (i) The termination of or withdrawal from the United Mine Workers’ of America 1974 Pension Trust by such Loan Party or any of its ERISA Affiliates shall have occurred and the liability of such Loan Party and its ERISA Affiliates related to such termination or withdrawal exceeds $75,000,000 in the aggregate; or (ii) any other ERISA Event shall have occurred and the liability of such Loan Party and its ERISA Affiliates related to such ERISA Event exceeds $50,000,000; or

(i) the Parent Guaranty shall cease to be in full force and effect while AGR is a Borrower or has any obligations under this Agreement, or the Guarantor shall deny or disaffirm in writing its obligations under the Guaranty;

then, and in any such event, the Administrative Agent (i) shall at the request, or may with the consent, of the Required Lenders, by notice to OPCo, declare the obligation of each Lender to make Advances to OPCo to be terminated, whereupon the same shall forthwith terminate, and

(ii) shall at the request, or may with the consent, of the Required Lenders, by notice to the defaulting Borrower (or in the case of an Event of Default with respect to AEP, AGR), declare the outstanding Advances owing by such Borrower, all interest thereon and all other amounts payable under this Agreement to be forthwith due and payable, whereupon such outstanding Advances, all such interest and all such amounts shall become and be forthwith due and payable by such Borrower, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by such Borrower; provided , however , that in the event of an actual or deemed entry of an order for relief with respect to any Loan Party or any Significant Subsidiary of such Loan Party under the Federal Bankruptcy Code, (A) the obligation of each Lender to make Advances to OPCo shall automatically be terminated and (B) the outstanding Advances owing by the defaulting Borrower (or in the case of an Event of Default with respect to AEP, AGR), all interest thereon and all other amounts payable under this Agreement shall automatically become and be due and payable, without presentment, demand, protest or any notice of any kind, all of which are hereby expressly waived by such Borrower.

ARTICLE VIII

THE ADMINISTRATIVE AGENT

SECTION 8.01. Authorization and Action.

Each Lender hereby appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers and discretion under this Agreement as are delegated to the Administrative Agent by the terms hereof, together with such powers and discretion as are reasonably incidental thereto. As to any matters expressly provided for in this Agreement as being subject to the discretion of the Administrative Agent, such matters shall be subject to the sole discretion of the Administrative Agent, its directors, officers, agents and employees. As to any matters not expressly provided for by this Agreement (including, without limitation, enforcement or collection of the outstanding Borrowings), the Administrative Agent shall not be required to exercise any discretion or take any action, but shall be required to act or to refrain from acting (and shall be fully protected in so acting or refraining from acting) upon the instructions of the Required Lenders, and such instructions shall be binding upon all Lenders; provided , however , that the Administrative Agent shall not be required to take any action that exposes the Administrative Agent to personal liability or that is contrary to this Agreement or Applicable Law. The Administrative Agent agrees to give to each Lender prompt notice of each notice given to it by the Borrowers pursuant to the terms of this Agreement.

SECTION 8.02. Agent’s Reliance, Etc.

Neither the Administrative Agent nor any of its directors, officers, agents or employees shall be liable for any action taken or omitted to be taken by it or them under or in connection with this Agreement, except for its or their own gross negligence or willful misconduct as determined in a final, non-appealable judgment by a court of competent jurisdiction. Without limitation of the generality of the foregoing, the Administrative Agent: (i) may treat each Lender recorded in the Register as the owner of the Commitment recorded for such Lender in the Register until the Administrative Agent receives and accepts an Assignment and Assumption entered into by such Lender, as assignor, and an Eligible Assignee, as assignee, as provided in Section 9.07 and except as provided otherwise in Section 9.16; (ii) may consult with legal

counsel (including counsel for the Loan Parties), independent public accountants and other experts selected by it and shall not be liable for any action taken or omitted to be taken in good faith by it in accordance with the advice of such counsel, accountants or experts; (iii) makes no warranty or representation to any Lender and shall not be responsible to any Lender for any statements, warranties or representations (whether written or oral) made in or in connection with this Agreement; (iv) shall not have any duty to ascertain or to inquire as to the performance or observance of any of the terms, covenants or conditions of this Agreement on the part of any Lender or to inspect the property (including the books and records) of any Lender; (v) shall not be responsible to any Lender for the due execution, legality, validity, enforceability, genuineness, sufficiency or value of, this Agreement or any other instrument or document furnished pursuant thereto; (vi) shall incur no liability under or in respect of this Agreement by acting upon any notice, consent, certificate or other instrument or writing (which may be by fax) believed by it to be genuine and signed or sent by the proper party or parties; and (vii) shall not have any fiduciary duty to any other Lender.

SECTION 8.03. Wells Fargo and its Affiliates.

With respect to its Commitments and the Advances made by it, Wells Fargo shall have the same rights and powers under this Agreement as any other Lender and may exercise the same as though it were not the Administrative Agent; and the term “Lender” or “Lenders” shall, unless otherwise expressly indicated, include Wells Fargo in its individual capacity. Wells Fargo and its Affiliates may accept deposits from, lend money to, act as trustee under indentures of, accept investment banking engagements from and generally engage in any kind of business with, any Lender, any of its Subsidiaries and any Person who may do business with or own securities of any Lender or any such Subsidiary, all as if Wells Fargo were not the Administrative Agent and without any duty to account therefor to the Lenders.

SECTION 8.04. Lender Credit Decision.

Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent or any other Lender and based on the financial statements referred to in Section 4.01 and such other documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement.

SECTION 8.05. Indemnification.

Each Lender severally agrees to indemnify the Administrative Agent (to the extent not promptly reimbursed by the Loan Parties and without limiting the Loan Parties’ obligation to do so) from and against such Lender’s ratable share (determined as provided below) of any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever that may be imposed on, incurred by, or asserted against the Administrative Agent in any way relating to or arising out of this Agreement or any action taken or omitted by the Administrative Agent under this Agreement; provided , however , that no Lender shall be liable for any portion of such liabilities, obligations, losses, damages,

penalties, actions, judgments, suits, costs, expenses or disbursements resulting from the Administrative Agent’s gross negligence or willful misconduct as determined in a final, non-appealable judgment by a court of competent jurisdiction. Without limitation of the foregoing, each Lender agrees to reimburse the Administrative Agent promptly upon demand for its ratable share of any costs and expenses (including, without limitation, fees and reasonable expenses of counsel) payable by the Loan Parties under Section 9.04, to the extent that the Administrative Agent is not promptly reimbursed for such costs and expenses by the Loan Parties after request therefor and without limiting the Loan Parties’ obligation to do so. For purposes of this Section 8.05, the Lenders’ respective ratable shares of any amount shall be determined, at any time, according to the sum of (i) the aggregate principal amount of the Advances outstanding at such time and owing to the respective Lenders and (ii) the aggregate unused portions of their respective Commitments at such time. In the event that any Lender shall have failed to make any Advance as required hereunder, such Lender’s Commitment shall be considered to be unused for purposes of this Section 8.05 to the extent of the amount of such Advance. The failure of any Lender to reimburse the Administrative Agent promptly upon demand for its ratable share of any amount required to be paid by the Lender to the Administrative Agent as provided herein shall not relieve any other Lender of its obligation hereunder to reimburse the Administrative Agent for its ratable share of such amount, but no Lender shall be responsible for the failure of any other Lender to reimburse the Administrative Agent for such other Lender’s ratable share of such amount. Without prejudice to the survival of any other agreement of any Lender hereunder, the agreement and obligations of each Lender contained in this Section 8.05 shall survive the payment in full of principal, interest and all other amounts payable hereunder.

SECTION 8.06. Successor Agent.

The Administrative Agent may resign at any time by giving written notice thereof to the Lenders and the Borrowers. Upon any such resignation, the Required Lenders shall have the right to appoint a successor Agent to the Administrative Agent that has resigned. If no successor Administrative Agent shall have been so appointed by the Required Lenders, and shall have accepted such appointment, within 30 days after the retiring Administrative Agent’s giving of notice of resignation, then such retiring Administrative Agent may, on behalf of the Lenders, appoint a successor Administrative Agent, which shall be a Lender or an Affiliate of a Lender that is commercial bank organized under the laws of the United States or of any State thereof and having a combined capital and surplus of at least $500,000,000. Upon the acceptance of any appointment as Administrative Agent hereunder by a successor Agent, such successor Administrative Agent shall succeed to and become vested with all the rights, powers, discretion, privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent shall be discharged from its duties and obligations under this Agreement. After any retiring Administrative Agent’s resignation hereunder as Administrative Agent, the provisions of this Article VII shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Administrative Agent under this Agreement.

ARTICLE IX

MISCELLANEOUS

SECTION 9.01. Amendments, Etc.

Subject to Section 9.16(a)(i), no amendment or waiver of any provision of this Agreement, nor consent to any departure by any Loan Party therefrom, shall in any event be effective unless the same shall be in writing and signed by the Required Lenders and the Loan Parties, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given; provided, however , that no amendment, waiver or consent shall (a) unless in writing and signed by all the Lenders (other than, in the case of the following clauses (i) through (v), any Defaulting Lender), do any of the following: (i) amend Section 3.01 or 3.02 or waive any of the conditions specified therein, (ii) increase the aggregate amount of the Commitments, (iii) change the definition of Required Lenders or the percentage of the Commitments or of the aggregate unpaid principal amount of the outstanding Borrowings, or the number or percentage of the Lenders, that shall be required for the Lenders or any of them to take any action hereunder, (iv) amend or waive this Section 9.01 or any provision of this Agreement that requires pro rata treatment of the Lenders or (v) release AEP from its obligations under Article VI; or (b) unless in writing and signed by each Lender that is directly affected thereby, do any of the following: (1) increase the amount or extend the termination date of such Lender’s Commitment, or subject such Lender to any additional obligations, (2) reduce the principal of, or interest on, or rate of interest applicable to, the outstanding Advances of such Lender or any fees or other amounts payable to such Lender hereunder, or (3) postpone any date fixed for any payment of principal of, or interest on, the outstanding Advances or any fees or other amounts payable to such Lender hereunder; and provided further that (x) no amendment, waiver or consent shall, unless in writing and signed by the Administrative Agent in addition to the Lenders required above to take such action, affect the rights or duties of the Administrative Agent under this Agreement, and (y) no amendment, waiver or consent shall, unless in writing and signed by the Administrative Agent and the Required Lenders, amend or waive Section 9.16. Notwithstanding the foregoing, any provision of this Agreement may be amended by an agreement in writing entered into by the Loan Parties, the Required Lenders and the Administrative Agent if (i) by the terms of such agreement the Commitment of each Lender not consenting to the amendment provided for therein shall terminate (but such Lender shall continue to be entitled to the benefits of Sections 2.11, 2.14 and 9.04) upon the effectiveness of such amendment and (ii) at the time such amendment becomes effective, each Lender not consenting thereto receives payment in full of the principal outstanding amount of and interest accrued on each Advance made by it, and all other amounts owing to it or accrued for its account under this Agreement and is released from its obligations hereunder.

SECTION 9.02. Notices, Etc.

(a) Each Loan Party hereby agrees that any notice that is required to be delivered to it hereunder shall be delivered to such Loan Party as set forth in this Section 9.02. All notices and other communications provided for hereunder shall be in writing (including fax) and mailed, faxed or delivered, if to any Loan Party, to it in care of AEP at its address at 1 Riverside Plaza, Columbus, Ohio 43215, Attention: Treasurer (fax: 614-716-2807; telephone: 614-716-2885; email: jsloat@aep.com), with a copy to the General Counsel (fax: 614-716-1687; telephone: 614-

716-2929); if to any Initial Lender, at its Domestic Lending Office specified in its Administrative Questionnaire; if to any other Lender, at its Domestic Lending Office specified in the Assignment and Assumption pursuant to which it became a Lender; if to the Administrative Agent, at its address at (i) 1525 W. W.T. Harris Blvd, 1st Floor, Charlotte, North Carolina 28262-8522, MAC D1109-019, Attention: Robert Fernandez, Wells Fargo Bank, National Association (fax: 704-715-0017; telephone: 704-427-3920; email: robert.fernandez@wellsfargo.com), (ii) for notices and communications relating to compliance with the covenants hereunder, 301 S. College St, 15th Floor, Charlotte, North Carolina 28202-6000, MAC D1053-150, Attention: Shawn Young, Wells Fargo Bank, National Association (fax: 704-383-6647; telephone: 704-715-1707; email: shawn.young@wellsfargo.com), with a copy to 1525 W. W.T. Harris Blvd, 1st Floor, Charlotte, North Carolina 28262-8522, MAC D1109-019, Attention: Robert Fernandez, Wells Fargo Bank, National Association (fax: 704-715-0017; telephone: 704-427-3920; email: robert.fernandez@wellsfargo.com); or, as to each Loan Party or the Administrative Agent, at such other address as shall be designated by such party in a written notice to the other parties and, as to each other party, at such other address as shall be designated by such party in a written notice to the Loan Parties and the Administrative Agent. All such notices and communications shall be effective when delivered or received at the appropriate address or number to the attention of the appropriate individual or department, except that notices and communications to the Administrative Agent pursuant to Article II, III or VII shall not be effective until received by the Administrative Agent. Delivery by fax of an executed counterpart of any amendment or waiver of any provision of this Agreement or of any Exhibit hereto to be executed and delivered hereunder shall be effective as delivery of a manually executed counterpart thereof.

(b) Each Loan Party and each Lender hereby agrees that the Administrative Agent may make any information required to be delivered under Section 5.01(i)(i), (ii), (iv) and (v) (the “ Communications ”) available to the Lenders by posting the Communications on SyndTrak or a substantially similar electronic transmission systems (the “ Platform ”). Each Loan Party and each Lender hereby acknowledges that the distribution of material through an electronic medium is not necessarily secure and that there are confidentiality and other risks associated with such distribution.

(c) THE PLATFORM IS PROVIDED “AS IS” AND “AS AVAILABLE”. THE AGENT PARTIES (AS DEFINED BELOW) DO NOT WARRANT THE ACCURACY OR COMPLETENESS OF THE COMMUNICATIONS, OR THE ADEQUACY OF THE PLATFORM AND EXPRESSLY DISCLAIM LIABILITY FOR ERRORS OR OMISSIONS IN THE COMMUNICATIONS. NO WARRANTY OF ANY KIND, EXPRESS, IMPLIED OR STATUTORY, INCLUDING, WITHOUT LIMITATION, ANY WARRANTY OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, NON-INFRINGEMENT OF THIRD-PARTY RIGHTS OR FREEDOM FROM VIRUSES OR OTHER CODE DEFECTS, IS MADE BY THE AGENT PARTIES IN CONNECTION WITH THE COMMUNICATIONS OR THE PLATFORM. IN NO EVENT SHALL THE ADMINISTRATIVE AGENT OR ANY OF ITS RELATED PARTIES (COLLECTIVELY, “ AGENT PARTIES ”) HAVE ANY LIABILITY TO ANY LOAN PARTY, ANY LENDER OR ANY OTHER PERSON OR ENTITY FOR DAMAGES OF ANY KIND, INCLUDING, WITHOUT LIMITATION, DIRECT OR INDIRECT, SPECIAL, INCIDENTAL OR CONSEQUENTIAL DAMAGES, LOSSES OR EXPENSES (WHETHER IN TORT,

CONTRACT OR OTHERWISE) ARISING OUT OF ANY LOAN PARTY’S OR THE ADMINISTRATIVE AGENT’S TRANSMISSION OF COMMUNICATIONS THROUGH THE INTERNET, EXCEPT TO THE EXTENT THE LIABILITY OF ANY AGENT PARTY IS FOUND IN A FINAL, NON-APPEALABLE JUDGMENT BY A COURT OF COMPETENT JURISDICTION TO HAVE RESULTED PRIMARILY FROM SUCH AGENT PARTY’S GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.

The Administrative Agent agrees that the receipt of the Communications by the Administrative Agent at its e-mail address set forth above shall constitute effective delivery of the Communications to the Administrative Agent for purposes of the Loan Documents. Each Lender agrees that notice to it (as provided in the next sentence) specifying that the Communications have been posted to the Platform shall constitute effective delivery of the Communications to such Lender for purposes of the Loan Documents. Each Lender agrees (i) to notify the Administrative Agent in writing (including by electronic communication) from time to time of such Lender’s e-mail address to which the foregoing notice may be sent by electronic transmission and (ii) that the foregoing notice may be sent to such e-mail address.

Nothing herein shall prejudice the right of the Administrative Agent or any Lender to give any notice or other communication pursuant to any Loan Document in any other manner specified in such Loan Document.

SECTION 9.03. No Waiver; Remedies.

No failure on the part of any Lender or the Administrative Agent to exercise, and no delay in exercising, any right hereunder shall operate as a waiver thereof; nor shall any single or partial exercise of any such right preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law.

SECTION 9.04. Costs and Expenses.

(a) Each Borrower agrees to pay promptly upon demand all reasonable out-of-pocket costs and expenses of the Administrative Agent in connection with the preparation, execution, delivery, administration, modification and amendment of this Agreement and the other documents to be delivered hereunder, including, without limitation, (i) all due diligence, syndication (including printing, distribution and bank meetings), transportation, computer, duplication, appraisal, consultant, and audit expenses and (ii) the reasonable fees and expenses of counsel for the Administrative Agent with respect thereto and with respect to advising the Administrative Agent as to its rights and responsibilities under this Agreement. Each Borrower further agrees to pay promptly upon demand all costs and expenses of the Administrative Agent and the Lenders, if any (including, without limitation, counsel fees and expenses), in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this Agreement and the other documents to be delivered hereunder, including, without limitation, reasonable fees and expenses of counsel for the Administrative Agent and the Lenders in connection with the enforcement of rights under this Section 9.04(a).

(b) Each Borrower agrees to indemnify and hold harmless each Lender and the Administrative Agent and each of their respective Related Parties (each, an “ Indemnified Party ”) from and against any and all claims, damages, losses and liabilities, joint or several, to which any such Indemnified Party may become subject, in each case arising out of or in connection with or relating to (including, without limitation, in connection with any investigation, litigation or proceeding or preparation of a defense in connection therewith) (i) this Agreement, any of the transactions contemplated herein or the actual or proposed use of the proceeds of the Advances (ii) any error or omission in connection with posting of the data required to be delivered pursuant to Section 5.01(i)(i), (ii) or (iv) on the website of the SEC or any successor website or (iii) the actual or alleged presence of Hazardous Materials on any property of such Borrower or any of its Subsidiaries or any Environmental Action relating in any way to such Borrower or any of its Subsidiaries, and to reimburse any Indemnified Party for any and all reasonable expenses (including, without limitation, reasonable fees and expenses of counsel) as they are incurred in connection with the investigation of or preparation for or defense of any pending or threatened claim or any action or proceeding arising therefrom, whether or not such Indemnified Party is a party and whether or not such claim, action or proceeding is initiated or brought by or on behalf of such Borrower or any of its Affiliates and whether or not any of the transactions contemplated hereby are consummated or this Agreement is terminated, except to the extent such claim, damage, loss, liability or expense is found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from such Indemnified Party’s gross negligence or willful misconduct. In the case of an investigation, litigation or other proceeding to which the indemnity in this Section 9.04(b) applies, such indemnity shall be effective whether or not such investigation, litigation or proceeding is brought by a Borrower, its directors, shareholders or creditors or an Indemnified Party or any other Person or any Indemnified Party is otherwise a party thereto and whether or not the transactions contemplated hereby are consummated. Each Loan Party agrees not to assert any claim against any Indemnified Party on any theory of liability, for special, indirect, consequential or punitive damages arising out of or otherwise relating to this Agreement, any of the transactions contemplated herein or the actual or proposed use of the proceeds of the Advances.

(c) If any payment of principal of, or Conversion of, any Eurodollar Rate Advance is made by any Borrower to or for the account of a Lender other than on the last day of the Interest Period for such Advance, as a result of a payment or Conversion pursuant to Section 2.05, 2.08(e), 2.11 or 2.13, acceleration of the maturity of the outstanding Borrowings pursuant to Section 7.01, the assignment of any such Advance pursuant to Section 2.16(b) or for any other reason (in the case of any such payment or Conversion), such Borrower shall, promptly upon demand by such Lender (with a copy of such demand to the Administrative Agent), pay to the Administrative Agent for the account of such Lender any amounts required to compensate such Lender for any additional losses, costs or expenses that it may reasonably incur as a result of such payment or Conversion, including, without limitation, any loss (other than loss of Applicable Margin), cost or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by any Lender to fund or maintain such Advance.

(d) Without prejudice to the survival of any other agreement of the Borrowers hereunder, the agreements and obligations of the Borrowers contained in Sections 2.11 and 9.04 shall survive the payment in full of principal, interest and all other amounts payable hereunder.

(e) Each Borrower agrees that no Indemnified Party shall have any liability (whether direct or indirect, in contract or tort or otherwise) to such Borrower or its security holders or creditors related to or arising out of or in connection with this Agreement, the Advances or the use or proposed use of the proceeds thereof, any of the transactions contemplated by any of the foregoing or in the loan documentation or the performance by an Indemnified Party of any of the foregoing (including the use by unintended recipients of any information or other materials distributed through telecommunications, electronic or other information transmission systems in connection with this Agreement or the other Loan Documents) except to the extent that any loss, claim, damage, liability or expense is found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from such Indemnified Party’s gross negligence or willful misconduct.

(f) In the event that an Indemnified Party is requested or required to appear as a witness in any action brought by or on behalf of or against any Borrower or any of its Affiliates in which such Indemnified Party is not named as a defendant, each Borrower agrees to reimburse such Indemnified Party for all reasonable expenses incurred by it in connection with such Indemnified Party’s appearing and preparing to appear as such a witness, including, without limitation, the fees and disbursements of its legal counsel.

(g) Each Borrower shall be liable for its pro rata share of any payment to be made by the Borrowers under this Section 9.04, such pro rata share to be determined on the basis of such Borrower’s Fraction; provided , however , that if and to the extent that any such liabilities are reasonably determined by the Borrowers (subject to the approval of the Administrative Agent which approval shall not be unreasonably withheld) to be directly attributable to a specific Borrower, only such Borrower shall be liable for such payments.

SECTION 9.05. Right of Set-off.

Upon (i) the occurrence and during the continuance of any Event of Default and (ii) the making of the request or the granting of the consent specified by Section 7.01 to authorize the Administrative Agent to declare the outstanding Borrowings due and payable pursuant to the provisions of Section 7.01, each Credit Party and each of its Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by such Credit Party or such Affiliate to or for the credit or the account of the a Loan Party against any and all of the obligations of such Loan Party now or hereafter existing under this Agreement held by such Credit Party, whether or not such Credit Party shall have made any demand under this Agreement and although such obligations may be unmatured; provided that, in the event that any Defaulting Lender shall exercise any such right of setoff, (x) all amounts so set off shall be paid over immediately to the Administrative Agent for further application in accordance with the provisions of Section 9.16 and, pending such payment, shall be segregated by such Defaulting Lender from its other funds and deemed held in trust for the benefit of the Administrative Agent and the Lenders, and (y) the Defaulting Lender shall provide promptly to the Administrative Agent a statement describing in reasonable detail the obligations of the Borrowers owing to such Defaulting Lender as to which it exercised such right of setoff. Each Credit Party agrees promptly to notify the applicable Loan Party after any such set-off and application, provided that the failure to give such notice shall not affect the validity of

such set-off and application. The rights of each Credit Party and its Affiliates under this Section are in addition to other rights and remedies (including, without limitation, other rights of set-off) that such Credit Party and its Affiliates may have.

SECTION 9.06. Binding Effect.

This Agreement shall become effective upon satisfaction of the conditions precedent specified in Section 3.01 and thereafter shall be binding upon and inure to the benefit of the Loan Parties, the Administrative Agent and each Lender and their respective successors and assigns, except that no Loan Party shall not have the right to assign its rights hereunder or any interest herein without the prior written consent of all of the Lenders. None of the Joint Lead Arrangers nor any Person designated as a “Documentation Agent” or a “Syndication Agent” with respect to this Agreement shall have any duties under this Agreement.

SECTION 9.07. Assignments and Participations.

(a) Successors and Assigns of Lenders Generally . Except as otherwise expressly provided herein, no Loan Party may assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of the Administrative Agent and each Lender. No Lender may assign or otherwise transfer any of its rights or obligations hereunder except (i) to an assignee in accordance with the provisions of subsection (b) of this Section, (ii) by way of participation in accordance with the provisions of subsection (d) of this Section, or (iii) by way of pledge or assignment of a security interest subject to the restrictions of subsection (e) of this Section (and any other attempted assignment or transfer by any party hereto shall be null and void). Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby, Participants to the extent provided in subsection (d) of this Section and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b) Assignments by Lenders . Any Lender may at any time assign to one or more assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and the Advances at the time owing to it); provided that any such assignment shall be subject to the following conditions:

(i) Minimum Amounts .

(A) in the case of an assignment of the entire remaining amount of the assigning Lender’s Commitment and/or the Advances at the time owing to it or contemporaneous assignments to related Approved Funds that equal at least the amount specified in subsection (b)(i)(B) of this Section in the aggregate or in the case of an assignment to a Lender, an Affiliate of a Lender or an Approved Fund, no minimum amount need be assigned; and

(B) in any case not described in subsection (b)(i)(A) of this Section, the aggregate amount of the Commitment (which for this purpose includes Advances outstanding thereunder) or, if the applicable Commitment is not then in

effect, the principal outstanding balance of the Advances of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent or, if the “Trade Date” is specified in the Assignment and Assumption, as of the Trade Date) shall not be less than $10,000,000, or an integral multiple of $1,000,000 in excess thereof, unless each of the Administrative Agent and, so long as no Default has occurred and is continuing, the Borrowers otherwise consent (each such consent not to be unreasonably withheld or delayed).

(ii) Proportionate Amounts . Each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement with respect to the Advances or the Commitment assigned.

(iii) Required Consents . No consent shall be required for any assignment except to the extent required by subsection (b)(i)(B) of this Section and, in addition:

(A) the consent of the Borrowers (such consent not to be unreasonably withheld or delayed) shall be required unless (x) a Default has occurred and is continuing (with respect to any Loan Party) at the time of such assignment, or (y) such assignment is to a Lender, an Affiliate of a Lender or an Approved Fund; provided that the Borrowers shall be deemed to have consented to any such assignment unless it shall object thereto by written notice to the Administrative Agent within ten Business Days after having received notice thereof; and

(B) the consent of the Administrative Agent (such consent not to be unreasonably withheld or delayed) shall be required for assignments if such assignment is to a Person that is not a Lender, an Affiliate of such Lender or an Approved Fund with respect to such Lender.

(iv) Assignment and Assumption . The parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500 (to be paid by the assigning Lender, or, in the case of an assignment pursuant to Section 2.16(b), the Borrowers); provided that the Administrative Agent may, in its sole discretion, elect to waive such processing and recordation fee in the case of any assignment. The assignee, if it is not a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire.

(v) No Assignment to Certain Persons . No such assignment shall be made to (A) any Borrower or any Borrower’s Affiliates or Subsidiaries or (B) to any Defaulting Lender or any of its Subsidiaries, or any Person who, upon becoming a Lender hereunder, would constitute any of the foregoing Persons described in this clause (B).

(vi) No Assignment to Natural Persons . No such assignment shall be made to a natural Person.

(vii) Certain Additional Payments . In connection with any assignment of rights and obligations of any Defaulting Lender hereunder, no such assignment shall be

effective unless and until, in addition to the other conditions thereto set forth herein, the parties to the assignment shall make such additional payments to the Administrative Agent in an aggregate amount sufficient, upon distribution thereof as appropriate (which may be outright payment, purchases by the assignee of participations or subparticipations, or other compensating actions, including funding, with the consent of the Borrowers and the Administrative Agent, the applicable pro rata share of Advances previously requested but not funded by the Defaulting Lender, to each of which the applicable assignee and assignor hereby irrevocably consent), to (x) pay and satisfy in full all payment liabilities then owed by such Defaulting Lender to the Administrative Agent and each Lender hereunder (and interest accrued thereon), and (y) acquire (and fund as appropriate) its full pro rata share of all Advances and Commitments in accordance with its Commitment Percentage. Notwithstanding the foregoing, in the event that any assignment of rights and obligations of any Defaulting Lender hereunder shall become effective under Applicable Law without compliance with the provisions of this subsection, then the assignee of such interest shall be deemed to be a Defaulting Lender for all purposes of this Agreement until such compliance occurs.

Subject to acceptance and recording thereof by the Administrative Agent pursuant to subsection (c) of this Section, from and after the effective date specified in each Assignment and Assumption, the assignee thereunder shall be a party to this Agreement and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto) but shall continue to be entitled to the benefits of Sections 2.11, 2.14 and 9.04 with respect to facts and circumstances occurring prior to the effective date of such assignment; provided , that except to the extent otherwise expressly agreed in writing by the affected parties, no assignment by a Defaulting Lender will constitute a waiver or release of any claim of any party hereunder arising from that Lender’s having been a Defaulting Lender. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this subsection shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with subsection (d) of this Section.

(c) Register . The Administrative Agent, acting solely for this purpose as a non-fiduciary agent of the Borrowers, shall maintain at one of its offices referred to in Section 9.02 a copy of each Assignment and Assumption delivered to it and a register in which it shall record the names and addresses of the Lenders, and the Commitments of, and principal amounts (and stated interest) of the Advances owing to, each Lender pursuant to the terms hereof from time to time (the “ Register ”). The entries in the Register shall be conclusive absent manifest error, and the Borrowers, the Administrative Agent and the Lenders shall treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement. The Register shall be available for inspection by the Borrowers and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

(d) Participations . Any Lender may at any time, without the consent of, or notice to, any Borrower or the Administrative Agent, sell participations to any Person (other than a natural

Person or a Borrower or any Borrower’s Affiliates or Subsidiaries) (each, a “ Participant ”) in all or a portion of such Lender’s rights and/or obligations under this Agreement (including all or a portion of its Commitment and/or the Advances owing to it); provided that (i) such Lender’s obligations under this Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, and (iii) the Borrowers, the Administrative Agent and Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. For the avoidance of doubt, each Lender shall be responsible for the indemnity under Section 8.05 with respect to any payments made by such Lender to its Participant(s).

Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in clauses (ii), (iii) or (iv) of the first sentence of Section 9.01 that affects such Participant. Each Borrower agrees that each Participant shall be entitled to the benefits of Sections 2.11, 2.14, 9.04(b) and 9.04(c) (subject to the requirements and limitations therein, including the requirements under Section 2.14(g) (it being understood that the documentation required under Section 2.14(g) shall be delivered to the participating Lender)) to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to subsection (b) of this Section; provided that such Participant (A) agrees to be subject to the provisions of Sections 2.16(b) as if it were an assignee under subsection (b) of this Section; and (B) shall not be entitled to receive any greater payment under Sections 2.11 or 2.14, with respect to any participation, than its participating Lender would have been entitled to receive, except to the extent such entitlement to receive a greater payment results from a Change in Law that occurs after the Participant acquired the applicable participation. Each Lender that sells a participation agrees, at the Borrowers’ request and expense, to use reasonable efforts to cooperate with the Borrowers to effectuate the provisions of Section 2.16(b) with respect to any Participant. To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 9.05 as though it were a Lender; provided that such Participant agrees to be subject to Section 2.15 as though it were a Lender. Each Lender that sells a participation shall, acting solely for this purpose as a non-fiduciary agent of the Borrowers, maintain a register on which it enters the name and address of each Participant and the principal amounts (and stated interest) of each Participant’s interest in the Commitments, Advances or other obligations under the Loan Documents (the “ Participant Register ”); provided that no Lender shall have any obligation to disclose all or any portion of the Participant Register (including the identity of any Participant or any information relating to a Participant’s interest in any commitments, loans or its other obligations under any Loan Document) to any Person except to the extent that such disclosure is necessary to establish that such commitment, loan or other obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations. The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary. For the avoidance of doubt, the Administrative Agent (in its capacity as Administrative Agent) shall have no responsibility for maintaining a Participant Register.

(e) Certain Pledges . Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank or other central banking authority; provided that no such pledge or assignment shall release such Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

SECTION 9.08. Confidentiality.

Each of the Administrative Agent and the Lenders agree to maintain the confidentiality of the Confidential Information, except that Confidential Information may be disclosed (a) to its Affiliates and to its Related Parties (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Confidential Information and instructed to keep such Confidential Information confidential); (b) to the extent required or requested by any regulatory authority purporting to have jurisdiction over such Person or its Related Parties (including any state, federal or foreign authority or examiner regulating banks, banking or other financial institutions and any self-regulatory authority, such as the National Association of Insurance Commissioners); (c) to the extent required by Applicable Law or by any subpoena or similar legal process; (d) to any other party hereto; (e) in connection with the exercise of any remedies hereunder or under any other Loan Document or any action or proceeding relating to this Agreement or any other Loan Document or the enforcement of rights hereunder or thereunder; (f) subject to an agreement containing provisions substantially the same as those of this Section, to (i) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights and obligations under this Agreement, (ii) any actual or prospective party (or its Related Parties) to any swap, derivative or other transaction under which payments are to be made by reference to any Borrower and its obligations, this Agreement or payments hereunder or (iii) any credit insurance provider relating to any Borrower and its obligations; (g) on a confidential basis to (i) any rating agency in connection with rating any Borrower or its Subsidiaries or this Agreement or (ii) the CUSIP Service Bureau or any similar agency in connection with the issuance and monitoring of CUSIP numbers with respect to this Agreement; (h) with the consent of the Borrowers; or (i) to the extent such Confidential Information (x) becomes publicly available other than as a result of a breach of this Section, or (y) becomes available to the Administrative Agent, any Lender or any of their respective Affiliates on a nonconfidential basis from a source other than the Borrowers. Any Person required to maintain the confidentiality of Confidential Information as provided in this Section shall be considered to have complied with its obligation to do so if such Person has exercised the same degree of care to maintain the confidentiality of such Confidential Information as such Person would accord to its own confidential information.

SECTION 9.09. Governing Law.

THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

SECTION 9.10. Severability; Survival.

(a) In the event any one or more of the provisions contained in this Agreement should be held invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not in any way be affected or impaired hereby.

(b) All covenants, agreements, representations and warranties made by the Borrowers herein and in the certificates or other instruments delivered in connection with or pursuant to this Agreement shall be considered to have been relied upon by the other parties hereto and shall survive the execution and delivery of this Agreement and the making of any Advances, regardless of any investigation made by any such other party or on its behalf and notwithstanding that the Administrative Agent or any Lender may have had notice or knowledge of any Default or incorrect representation or warranty at the time any credit is extended hereunder, and shall continue in full force and effect as long as the principal of or any accrued interest on any Advance or any fee or any other amount payable under this Agreement is outstanding and unpaid and so long as the Commitments have not expired or terminated.

SECTION 9.11. Execution in Counterparts.

This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page to this Agreement by fax shall be effective as delivery of a manually executed counterpart of this Agreement.

SECTION 9.12. Jurisdiction, Etc.

(a) EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY AND UNCONDITIONALLY SUBMITS, FOR ITSELF AND ITS PROPERTY, TO THE EXCLUSIVE JURISDICTION OF ANY NEW YORK STATE COURT OR FEDERAL COURT OF THE UNITED STATES OF AMERICA SITTING IN NEW YORK CITY, THE COUNTY OF NEW YORK, AND ANY APPELLATE COURT FROM ANY THEREOF, IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT, OR FOR RECOGNITION OR ENFORCEMENT OF ANY JUDGMENT, AND EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY AND UNCONDITIONALLY AGREES THAT ALL CLAIMS IN RESPECT OF ANY SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN ANY SUCH NEW YORK STATE COURT OR, TO THE EXTENT PERMITTED BY LAW, IN SUCH FEDERAL COURT. EACH OF THE PARTIES HERETO AGREES THAT A FINAL JUDGMENT IN ANY SUCH ACTION OR PROCEEDING SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY LAW. NOTHING IN THIS AGREEMENT SHALL AFFECT ANY RIGHT THAT ANY PARTY MAY OTHERWISE HAVE TO BRING ANY ACTION OR PROCEEDING RELATING TO THIS AGREEMENT IN THE COURTS OF ANY JURISDICTION.

(b) EACH OF THE PARTIES HERETO IRREVOCABLY AND UNCONDITIONALLY WAIVES, TO THE FULLEST EXTENT IT MAY LEGALLY AND EFFECTIVELY DO SO, ANY OBJECTION THAT IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY SUIT, ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT IN ANY NEW YORK STATE OR FEDERAL COURT. EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE OF SUCH ACTION OR PROCEEDING IN ANY SUCH COURT.

SECTION 9.13. Waiver of Jury Trial.

EACH BORROWER, THE ADMINISTRATIVE AGENT AND EACH LENDER HEREBY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM (WHETHER BASED ON CONTRACT, TORT OR OTHERWISE) ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE ACTIONS OF THE ADMINISTRATIVE AGENT, ANY BORROWER OR ANY LENDER IN THE NEGOTIATION, ADMINISTRATION, PERFORMANCE OR ENFORCEMENT THEREOF.

SECTION 9.14. USA Patriot Act.

Each of the Lenders hereby notifies the Borrowers that pursuant to the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law as of October 26, 2001)) (as amended, restated, modified or otherwise supplemented from time to time, the “ Patriot Act ”), it is required to obtain, verify and record information that identifies the Borrowers, which information includes the name and address of the Borrowers and other information that will allow such Lender to identify the Borrowers in accordance with the Patriot Act.

SECTION 9.15. No Fiduciary Duty.

Each of the Administrative Agent, each Lender and each of their respective Affiliates and their officers, directors, controlling persons, employees, agents and advisors (collectively, solely for purposes of this Section 9.15, the “ Lenders ”) may have economic interests that conflict with those of the Borrowers. Each Borrower agrees that nothing in the Loan Documents or otherwise will be deemed to create an advisory, fiduciary or agency relationship or fiduciary or other implied duty between the Lenders and such Borrower, its stockholders or its Affiliates. The Borrowers acknowledge and agree that (i) the transactions contemplated by the Loan Documents are arm’s-length commercial transactions between the Lenders, on the one hand, and the Borrowers, on the other, (ii) in connection therewith and with the process leading to such transaction each of the Lenders is acting solely as a principal and not the agent or fiduciary of any Borrower, its management, stockholders, creditors or any other person, (iii) no Lender has assumed an advisory or fiduciary responsibility in favor of any Borrower with respect to the transactions contemplated hereby or the process leading thereto (irrespective of whether any Lender or any of its Affiliates has advised or is currently advising any Borrower on other matters) or any other obligation to any Borrower except the obligations expressly set forth in the Loan Documents and (iv) each Borrower has consulted its own legal and financial advisors to the

extent it deemed appropriate. Each Borrower further acknowledges and agrees that it is responsible for making its own independent judgment with respect to such transactions and the process leading thereto. Each Borrower agrees that it will not claim that any Lender has rendered advisory services of any nature or respect, or owes a fiduciary or similar duty to such Borrower, in connection with such transaction or the process leading thereto.

SECTION 9.16. Defaulting Lenders.

(a) Defaulting Lender Adjustments . Notwithstanding anything to the contrary contained in this Agreement, if any Lender becomes a Defaulting Lender, then, until such time as such Lender is no longer a Defaulting Lender, to the extent permitted by Applicable Law:

(i) Waivers and Amendments . Such Defaulting Lender’s right to approve or disapprove any amendment, waiver or consent with respect to this Agreement shall be restricted as set forth in the definition of Required Lenders and in Section 9.01.

(ii) Defaulting Lender Waterfall . Any payment of principal, interest, fees or other amounts received by the Administrative Agent for the account of such Defaulting Lender (whether voluntary or mandatory, at maturity, pursuant to Article VI or otherwise) or received by the Administrative Agent from a Defaulting Lender pursuant to Section 9.05 shall be applied at such time or times as may be determined by the Administrative Agent as follows: first , to the payment of any amounts owing by such Defaulting Lender to the Administrative Agent hereunder; second , as the Borrowers may request (so long as no Default exists), to the funding of any Advance in respect of which such Defaulting Lender has failed to fund its portion thereof as required by this Agreement, as determined by the Administrative Agent; third , if so determined by the Administrative Agent and the Borrowers, to be held in a deposit account and released pro rata in order to satisfy such Defaulting Lender’s potential future funding obligations with respect to Advances under this Agreement; fourth , to the payment of any amounts owing to the Lenders as a result of any judgment of a court of competent jurisdiction obtained by any Lender against such Defaulting Lender as a result of such Defaulting Lender’s breach of its obligations under this Agreement; fifth , so long as no Default exists, to the payment of any amounts owing to any Borrower as a result of any judgment of a court of competent jurisdiction obtained by any Borrower against such Defaulting Lender as a result of such Defaulting Lender's breach of its obligations under this Agreement; and sixth , to such Defaulting Lender or as otherwise directed by a court of competent jurisdiction; provided that, if (x) such payment is a payment of the principal amount of any Advances in respect of which such Defaulting Lender has not fully funded its appropriate share, and (y) such Advances were made at a time when the conditions set forth in Section 3.02 were satisfied or waived, such payment shall be applied solely to pay the Advances of all Non-Defaulting Lenders on a pro rata basis prior to being applied to the payment of any Advances of such Defaulting Lender until such time as all Advances are held by the Lenders pro rata in accordance with the Commitments. Any payments, prepayments or other amounts paid or payable to a Defaulting Lender that are applied (or held) to pay amounts owed by a Defaulting Lender pursuant to this Section 9.16(a)(ii) shall be deemed paid to and redirected by such Defaulting Lender, and each Lender irrevocably consents hereto.

(iii) Certain Fees . No Defaulting Lender shall be entitled to receive any commitment fee pursuant to Section 2.03(a) for any period during which that Lender is a Defaulting Lender (and the Borrowers shall not be required to pay any such fee that otherwise would have been required to have been paid to that Defaulting Lender).

(iv) Reduction of Available Commitments . The Borrowers may terminate the Available Commitment of any Lender that is a Defaulting Lender upon not less than three Business Days’ prior notice to the Administrative Agent (which shall promptly notify the Lenders thereof), and in such event the provisions of Section 9.16(a)(ii) will apply to all amounts thereafter paid by the Borrowers for the account of such Defaulting Lender under this Agreement (whether on account of principal, interest, fees, indemnity or other amounts); provided that (i) no Event of Default shall have occurred and be continuing, and (ii) such termination shall not be deemed to be a waiver or release of any claim the any Borrower, the Administrative Agent or any Lender may have against such Defaulting Lender.

(b) Defaulting Lender Cure . If the Borrowers and the Administrative Agent agree in writing that a Lender is no longer a Defaulting Lender, the Administrative Agent will so notify the parties hereto, whereupon as of the effective date specified in such notice and subject to any conditions set forth therein, that Lender will, to the extent applicable, purchase at par that portion of outstanding Advances of the other Lenders or take such other actions as the Administrative Agent may determine to be necessary to cause the Advances to be held pro rata by the Lenders in accordance with the Commitments, whereupon such Lender will cease to be a Defaulting Lender; provided that no adjustments will be made retroactively with respect to commitment fees accrued or payments made by or on behalf of the Borrowers while that Lender was a Defaulting Lender; and provided , further , that except to the extent otherwise expressly agreed in writing by the affected parties, no change hereunder from Defaulting Lender to Lender will constitute a waiver or release of any claim of any party hereunder arising from that Lender’s having been a Defaulting Lender.

[Remainder of page intentionally left blank.]

IN WITNESS WHEREOF, each of the parties hereto has caused a counterpart of this Agreement to be duly executed and delivered as of the date first above written.

OHIO POWER COMPANY

as a Borrower

By /s/ Julia A. Sloat

Julia A. Sloat

Treasurer

AEP GENERATION RESOURCES INC.

as a Borrower

By /s/ Julia A. Sloat

Julia A. Sloat

Treasurer

APPALACHIAN POWER COMPANY

as a Borrower

By /s/ Julia A. Sloat

Julia A. Sloat

Treasurer

KENTUCKY POWER COMPANY

as a Borrower

By /s/ Julia A. Sloat

Julia A. Sloat

Treasurer

S-1

AMERICAN ELECTRIC POWER

COMPANY, INC.

as Guarantor

By /s/ Julia A. Sloat

Julia A. Sloat

Treasurer

S-2

WELLS FARGO BANK, NATIONAL ASSOCIATION

as Administrative Agent and as Lender

By /s/ Sara Olesen

Sara Olesen

Assistant Vice President

S-3

THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.

as Lender

By /s/ Chi-Cheng Chen

Chi-Cheng Chen

Vice President

S-4

JPMORGAN CHASE BANK, N.A.

as Lender

By /s/ Bridget Killackey

Bridget Killackey

Vice President

S-5

CITIBANK, N.A.

as Lender

By /s/ Amit Vasani

Amit Vasani

Vice President

S-6

KEYBANK NATIONAL ASSOCIATION

as Lender

By /s/ Sherrie I. Manson

Sherrie I. Manson

Senior Vice President

S-7

THE ROYAL BANK OF SCOTLAND FINANCE (IRELAND)

as Lender

By /s/ L. O’Connell

L. O’Connell

Director

By /s/ B. Murray

B. Murray

Director

S-8

BNP PARIBAS

as Lender

By /s/ Francis DeLaney

Francis DeLaney

Managing Director

By /s/ Pasquale Perraglia

Pasquale Perraglia

Director

S-9

COMPASS BANK

as Lender

By /s/ Michael Dixon

Michael Dixon

Vice President

S-10

CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK

as Lender

By /s/ Darrell Stanley

Darrell Stanley

Managing Director

By /s/ Michael Willis

Michael Willis

Managing Director

S-11

FIFTH THIRD BANK

as Lender

By /s/ Michael J. Schultz, Jr.

Michael J. Schultz, Jr.

Vice President

S-12

GOLDMAN SACHS BANK USA

as Lender

By /s/ Mark Walton

Mark Walton

Authorized Signatory

S-13

MIZUHO BANK, LTD.

as Lender

By /s/ Leon Mo

Leon Mo

Authorized Signatory

S-14

PNC BANK, NATIONAL ASSOCIATION

as Lender

By /s/ Dale A. Stein

Dale A. Stein

Senior Vice President

S-15

ROYAL BANK OF CANADA

as Lender

By /s/ Frank Lambrinos

Frank Lambrinos

Authorized Signatory

S-16

SUMITOMO MITSUI BANKING CORPORATION

as Lender

By /s/ James D. Weinstein

James D. Weinstein

Managing Director

S-17

SUNTRUST BANK

as Lender

By /s/ Shannon Juhan

Shannon Juhan

Vice President

S-18

THE BANK OF NEW YORK MELLON

as Lender

By /s/ Hussam S. Alsahlani

Hussam S. Alsahlani

Vice President

S-19

THE BANK OF NOVA SCOTIA

as Lender

By /s/ Thane Rattew

Thane Rattew

Managing Director

S-20

THE HUNTINGTON NATIONAL BANK

as Lender

By /s/ Amanda M. Sigg

Amanda M. Sigg

Vice President

S-21

U.S. BANK

as Lender

By /s/ Eric J. Cosgrove

Eric J. Cosgrove

Vice President

S-22

EXHIBIT A

(to the Term Credit Agreement)

FORM OF NOTICE OF BORROWING

Wells Fargo Bank, National Association, as Administrative Agent

for the Lenders party

to the Credit Agreement

referred to below

Attention: Bank Loan Syndications

[Date]

Ladies and Gentlemen:

The undersigned, Ohio Power Company, refers to the Term Credit Agreement, dated as of July 17, 2013 (as amended or modified from time to time, the “ Credit Agreement ,” the terms defined therein being used herein as therein defined), among the undersigned, AEP Generation Resources Inc., Appalachian Power Company and Kentucky Power Company, as the Borrowers, American Electric Power Company, Inc., as the Guarantor, certain Lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent for said Lenders, and hereby gives you notice, irrevocably, pursuant to Section 2.02(a) of the Credit Agreement that the undersigned hereby requests a Borrowing under the Credit Agreement, and in that connection sets forth below the information relating to such Borrowing (the “ Proposed Borrowing ”) as required by Section 2.02(a) of the Credit Agreement:

(i) The Business Day of the Proposed Borrowing is __________________, 20__.

(ii) The Type of Advances comprising the Proposed Borrowing is [Base Rate Advances][Eurodollar Rate Advances].

(iii) The aggregate amount of the Proposed Borrowing is $___________________.

[(iv) The initial Interest Period for each Eurodollar Rate Advance made as part of the Proposed Borrowing is [[one][two][three][six] month[s]] [OTHER PERIOD OF LESS THAN ONE MONTH AGREED TO BY ALL LENDERS].]

The undersigned hereby certifies that the following statements are true on the date hereof, and will be true on the date of the Proposed Borrowing:

(A) the representations and warranties of such Borrower contained in Section 4.01 of the Credit Agreement (other than Section 4.01(e) and the last sentence of Section

4.01(f)) are true and correct in all material respects on and as of the date hereof, before and after giving effect to the Proposed Borrowing and to the application of the proceeds therefrom, as though made on the date hereof; and

(B) no event has occurred and is continuing, or would result from the Proposed Borrowing or from the application of the proceeds therefrom, that constitutes a Default.

Very truly yours,

OHIO POWER COMPANY

Name:

Title:

A-2

EXHIBIT B

(to the Term Credit Agreement)

FORM OF ASSIGNMENT AND ASSUMPTION

This Assignment and Assumption (the “ Assignment and Assumption ”) is dated as of the Effective Date set forth below and is entered into by and between [the][each] 1 Assignor identified in item 1 below ([the][each, an] “ Assignor ”) and [the][each] 2 Assignee identified in item 2 below ([the][each, an] “ Assignee ”). [It is understood and agreed that the rights and obligations of [the Assignors][the Assignees] 3 hereunder are several and not joint.] 4 Capitalized terms used but not defined herein shall have the meanings given to them in the Credit Agreement identified below (as amended, the “ Credit Agreement ”), receipt of a copy of which is hereby acknowledged by [the][each] Assignee. The Standard Terms and Conditions set forth in Annex 1 attached hereto are hereby agreed to and incorporated herein by reference and made a part of this Assignment and Assumption as if set forth herein in full.

For an agreed consideration, [the][each] Assignor hereby irrevocably sells and assigns to [the Assignee][the respective Assignees], and [the][each] Assignee hereby irrevocably purchases and assumes from [the Assignor][the respective Assignors], subject to and in accordance with the Standard Terms and Conditions and the Credit Agreement, as of the Effective Date inserted by the Administrative Agent as contemplated below (i) all of [the Assignor’s][the respective Assignors’] rights and obligations in [its capacity as a Lender][their respective capacities as Lenders] under the Credit Agreement and any other documents or instruments delivered pursuant thereto to the extent related to the amount and percentage interest identified below of all of such outstanding rights and obligations of [the Assignor][the respective Assignors] under the Credit Agreement, and (ii) to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other right of [the Assignor (in its capacity as a Lender)][the respective Assignors (in their respective capacities as Lenders)] against any Person, whether known or unknown, arising under or in connection with the Credit Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including, but not limited to, contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above (the rights and obligations sold and assigned by [the][any] Assignor to [the][any] Assignee pursuant to clauses (i) and (ii) above being referred to herein collectively as [the][an] “ Assigned Interest ”). Each such sale and assignment is without recourse to [the][any] Assignor and, except as expressly provided in this Assignment and Assumption, without representation or warranty by [the][any] Assignor.

______________________________

1	For bracketed language here and elsewhere in this form relating to the Assignor(s), if the assignment is from a single Assignor, choose the first bracketed language. If the assignment is from multiple Assignors, choose the second bracketed language.

2	For bracketed language here and elsewhere in this form relating to the Assignee(s), if the assignment is to a single Assignee, choose the first bracketed language. If the assignment is to multiple Assignees, choose the second bracketed language.

3	Select as appropriate.

4	Include bracketed language if there are either multiple Assignors or multiple Assignees.

1.	Assignor[s]: ______________________________

______________________________

[Assignor [is] [is not] a Defaulting Lender]

2.	Assignee[s]: ______________________________

______________________________

[for each Assignee, indicate [Affiliate][Approved Fund] of [ identify Lender ]

Borrower(s):

Ohio Power Company; AEP Generation Resources Inc.; Appalachian Power Company and Kentucky Power Company

Administrative Agent:

Wells Fargo Bank, National Association, as the Administrative Agent under the Credit Agreement

Credit Agreement:

The $1,000,000,000 Term Credit Agreement dated as of July 17, 2013 among Ohio Power Company, AEP Generation Resources Inc., Appalachian Power Company and Kentucky Power Company, as the Borrowers, American Electric Power Company, Inc., as the Guarantor, the Lenders parties thereto and Wells Fargo Bank, National Association, as Administrative Agent

6.	Assigned Interest[s]:

Assignor[s] 5	Assignee[s] 6	Aggregate Amount of Commitment/Advances for all Lenders 7	Amount of Commitment/Advances Assigned 8	Percentage Assigned of Commitment/Advances 8	CUSIP Number
		$	$	%
		$	$	%
		$	$	%

[7. Trade Date: ______________] 9

[Page break]

_________________________________

5	L ist each Assignor, as appropriate.
6	List each Assignee, as appropriate.
7	Amount to be adjusted by the counterparties to take into account any payments or prepayments made between the Trade Date and the Effective Date.
8	Set forth, to at least 9 decimals, as a percentage of the Commitment/Advances of all Lenders thereunder.
9	To be completed if the Assignor and the Assignee(s) intend that the minimum assignment amount is to be determined as of the Trade Date.

B-2

Effective Date: _____________ ___, 20___ [TO BE INSERTED BY ADMINISTRATIVE AGENT AND WHICH SHALL BE THE EFFECTIVE DATE OF RECORDATION OF TRANSFER IN THE REGISTER THEREFOR.]

The terms set forth in this Assignment and Assumption are hereby agreed to:

ASSIGNOR[S] 10

[NAME OF ASSIGNOR]

By:

Title:

[NAME OF ASSIGNOR]

By:

Title:

ASSIGNEE[S] 11

[NAME OF ASSIGNEE]

By:

Title:

[NAME OF ASSIGNEE]

By:

Title:

______________________________

10	Add additional signature blocks as needed.

11 Add additional signature blocks as needed.

B-3

[Consented to and] 12 Accepted:

WELLS FARGO BANK, NATIONAL ASSOCIATION, as

Administrative Agent

By:

Title:

[Consented to:

OHIO POWER COMPANY

By:

Title:

AEP GENERATION RESOURCES INC.

By:

Title:

APPALACHIAN POWER COMPANY

By:

Title:

KENTUCKY POWER COMPANY

By:

Title:] 13

______________________________

12	To be added only if the consent of the Administrative Agent is required by the terms of the Credit Agreement.

13	To be added only if the consent of the Borrowers is required by the terms of the Credit Agreement.

B-4

ANNEX 1

$1,000,000,000 Term Credit Agreement dated as of July 17, 2013 among Ohio Power Company, AEP Generation Resources Inc., Appalachian Power Company and Kentucky Power Company, as the Borrowers, American Electric Power Company, Inc., as the Guarantor, the Lenders parties thereto and Wells Fargo Bank, National Association, as Administrative Agent

STANDARD TERMS AND CONDITIONS FOR

ASSIGNMENT AND ASSUMPTION

1.	Representations and Warranties .

1.1.

Assignor[s] . [The][Each] Assignor (a) represents and warrants that (i) it is the legal and beneficial owner of [the][the relevant] Assigned Interest, (ii) [the][such] Assigned Interest is free and clear of any lien, encumbrance or other adverse claim, (iii) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and (iv) it is [not] a Defaulting Lender; and (b) assumes no responsibility with respect to (i) any statements, warranties or representations made in or in connection with the Credit Agreement or any other Loan Document, (ii) the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents or any collateral thereunder, (iii) the financial condition of the Borrowers, any of their Subsidiaries or Affiliates or any other Person obligated in respect of any Loan Document or (iv) the performance or observance by the Borrowers, any of their Subsidiaries or Affiliates or any other Person of any of their respective obligations under any Loan Document.

1.2.

Assignee[s] . [The][Each] Assignee (a) represents and warrants that (i) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and to become a Lender under the Credit Agreement, (ii) it meets all the requirements to be an assignee under Section 9.07(b)(iii), (v) and (vi) of the Credit Agreement (subject to such consents, if any, as may be required under Section 9.07(b)(iii) of the Credit Agreement), (iii) from and after the Effective Date, it shall be bound by the provisions of the Credit Agreement as a Lender thereunder and, to the extent of [the][the relevant] Assigned Interest, shall have the obligations of a Lender thereunder, (iv) it is sophisticated with respect to decisions to acquire assets of the type represented by the Assigned Interest and either it, or the Person exercising discretion in making its decision to acquire the Assigned Interest, is experienced in acquiring assets of such type, (v) it has received a copy of the Credit Agreement, and has received or has been accorded the opportunity to receive copies of the most recent financial statements delivered pursuant to clauses (i) and (ii) of Section 5.01(i) thereof, as applicable, and such other documents and information as it deems appropriate to make its own credit analysis and decision to enter into this Assignment and Assumption and to purchase [the][such] Assigned Interest, (vi) it has, independently and without

reliance upon the Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Assignment and Assumption and to purchase [the][such] Assigned Interest, and (vii) attached to the Assignment and Assumption is any documentation required to be delivered by it pursuant to the terms of the Credit Agreement, duly completed and executed by [the][such] Assignee; (b) agrees that (i) it will, independently and without reliance on the Administrative Agent, [the][any] Assignor or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents, and (ii) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender and (c) appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers and discretion under the Credit Agreement as are delegated to the Administrative Agent by the terms thereof, together with such powers and discretion as are reasonably incidental thereto.

Payments . From and after the Effective Date, the Administrative Agent shall make all payments in respect of [the][each] Assigned Interest (including payments of principal, interest, fees and other amounts) to [the][the relevant] Assignee whether such amounts have accrued prior to, on or after the Effective Date. The Assignor[s] and the Assignee[s] shall make all appropriate adjustments in payments by the Administrative Agent for periods prior to the Effective Date or with respect to the making of this assignment directly between themselves. Notwithstanding the foregoing, the Administrative Agent shall make all payments of interest, fees or other amounts paid or payable in kind from and after the Effective Date to [the][the relevant] Assignee.

General Provisions . This Assignment and Assumption shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and assigns. This Assignment and Assumption may be executed in any number of counterparts, which together shall constitute one instrument. Delivery of an executed counterpart of a signature page of this Assignment and Assumption by fax shall be effective as delivery of a manually executed counterpart of this Assignment and Assumption. This Assignment and Assumption shall be governed by, and construed in accordance with, the law of the State of New York.

B-A1-2

EXHIBIT C

(to the Term Credit Agreement)

FORM OF OPINION OF COUNSEL FOR THE LOAN PARTIES

To each of the Lenders

party to the Term Credit Agreement referred to below

and to Wells Fargo Bank, National Association, as Administrative Agent thereunder

July 17, 2013

Ladies and Gentlemen:

This opinion is furnished to you pursuant to Section 3.01(a)(iii) of the Term Credit Agreement, dated as of July 17, 2013 (the “Credit Agreement”) among American Electric Power Company, Inc. (“AEP”), Appalachian Power Company (“APCo”), AEP Generation Resources Inc. (“AGR”), Kentucky Power Company (“KPCo”) and Ohio Power Company (collectively, the “Loan Parties”), the Initial Lenders named therein, and Wells Fargo Bank, National Association, as Administrative Agent. Terms defined in the Credit Agreement are used herein as therein defined.

I am an Associate General Counsel for American Electric Power Service Corporation, an affiliate of the Loan Parties, and have acted as counsel to the Loan Parties in connection with the preparation, execution and delivery of the Credit Agreement. I am generally familiar with each Loan Party’s corporate history, properties, operations and charter (including amendments, restatements and supplements thereto).

In connection with this opinion, I, or attorneys over whom I exercise supervision, have examined:

(1)	The Credit Agreement.

(2)	The documents furnished by each Loan Party pursuant to Article III of the Credit Agreement.

(3)	The certificate of incorporation of each Loan Party and all amendments thereto.

(4)	The by-laws of each Loan Party and all amendments thereto.

(5)	Certificates of the Secretary of State or equivalent officer of the state in which each Loan Party is incorporated or otherwise formed, dated as of a recent date, attesting to the continued existence and good standing of such Loan Party incorporated or otherwise formed in that State.

C-2

In addition, I, or attorneys over whom I exercise supervision, have examined the originals, or copies certified to my satisfaction, of such other corporate records of the Loan Parties, certificates of public officials and of officers of the Loan Parties, and agreements, instruments and other documents, as I have deemed necessary as a basis for the opinions expressed below.

In my examination, I, or attorneys over whom I exercise supervision, have assumed the genuineness of all signatures, the legal capacity of natural persons, the authenticity of all documents submitted to us as originals and the conformity with the originals of all documents submitted to us as copies. In making our examination of documents and instruments executed or to be executed by persons other than the Loan Parties, I, or attorneys over whom I exercise supervision, have assumed that each such other person had the requisite power and authority to enter into and perform fully its obligations thereunder, the due authorization by each such other person for the execution, delivery and performance thereof and the due execution and delivery thereof by or on behalf of such person of each such document and instrument. In the case of any such person that is not a natural person, I, or attorneys over whom I exercise supervision, have also assumed, insofar as it is relevant to the opinions set forth below, that each such other person is duly organized, validly existing and in good standing under the laws of the jurisdiction in which it was created and is duly qualified and in good standing in each other jurisdiction where the failure to be so qualified could reasonably be expected to have a material effect upon its ability to execute, deliver and/or perform its obligations under any such document or instrument. I, or attorneys over whom I exercise supervision, have further assumed that each document, instrument, agreement, record and certificate reviewed by us for purposes of rendering the opinions expressed below has not been amended by any oral agreement, conduct or course of dealing between the parties thereto.

As to questions of fact material to the opinions expressed herein, I have relied upon certificates and representations of officers of the Loan Parties (including but not limited to those contained in the Credit Agreement and certificates delivered upon the execution and delivery of the Credit Agreement) and of appropriate public officials, without independent verification of such matters except as otherwise described herein.

Whenever my opinions herein with respect to the existence or absence of facts are stated to be to my knowledge or awareness, it is intended to signify that no information has come to my attention or the attention of other counsel working under my direction in connection with the preparation of this opinion letter that would give me or them actual knowledge of the existence or absence of such facts. However, except to the extent expressly set forth herein, neither I nor they have undertaken any independent investigation to determine the existence or absence of such facts, and no inference as to my or their knowledge of the existence or absence of such facts should be assumed.

I am a member of the Bar of the States of New York and Ohio and do not purport to be expert on the laws of any jurisdiction other than the laws of the States of New York and Ohio and the Federal laws of the United States, and, for

C-3

purposes of this opinion only, the corporation law of the States of Delaware, Kentucky and Virginia. My opinions expressed below are limited to the law of the States of New York and Ohio and the Federal law of the United States, and, for purposes of this opinion only, the corporation law of the States of Delaware, Kentucky and Virginia.

Based upon the foregoing and upon such investigation as I have deemed necessary, and subject to the limitations, qualifications and assumptions set forth herein, I am of the following opinion:

Each Loan Party (a) is a corporation duly organized, validly existing and in good standing under the laws of its state of incorporation or formation; (b) has the corporate power and authority, and the legal right, to own and operate its property, to lease the property which it operates as lessee and to conduct the business in which it is currently engaged and in which it proposes to be engaged after the date hereof; (c) is duly qualified as a foreign corporation and is in good standing under the laws of each jurisdiction where its ownership, lease or operation of property or the conduct of its business requires such qualification, except any such jurisdiction where the failure to so qualify could not, in the aggregate, reasonably be expected to result in a Material Adverse Change; (d) owns or possesses all material licenses and permits necessary for the operation by it of its business as currently conducted; and (e) is in compliance with all Requirements of Law, except as disclosed in the Disclosure Documents referenced in Section 4.01(f) of the Credit Agreement or to the extent that the failure to comply therewith could not, in the aggregate, reasonably be expected to have a Material Adverse Effect. The term “Requirements of Law” means the laws of the State of Ohio and the laws, rules and regulations of the United States of America (including, without limitation, ERISA and Environmental Laws) and orders of any governmental authority applicable to the Loan Parties.

Each Loan Party has the corporate power and authority, and the legal right, to execute and deliver the Credit Agreement and to perform under, and, solely with respect to the Borrowers, to borrow under, the Credit Agreement. Each Loan Party has taken all necessary corporate action to authorize the execution, delivery and performance of the Credit Agreement and the incurrence of Advances by the Borrowers or the issuance of the guaranty by AEP, as the case may be, on the terms and conditions of the Credit Agreement, and the Credit Agreement has been duly executed and delivered by each of the Loan Parties.

The execution, delivery and performance of the Credit Agreement and the Advances and guaranty made thereunder will not violate any Requirements of Law, any Loan Party’s certificate of incorporation or by-laws, or any material contractual restriction binding on or affecting any Loan Party or any of its properties.

No approval or authorization or other action by, and notice to or filing with, any governmental agency or regulatory body or other third person is required in connection with the due execution and delivery of the Credit Agreement and the performance, validity or enforceability of the Credit Agreement, other than with respect to each Borrower (i) such Approvals, if any, that have been duly issued

C-4

and are in full force and effect and (ii) such Approvals that may be required to be obtained by such Borrower in connection with the AGR Assumption, APCo Assumption or KPCo Assumption.

Except as described in Section 4.01(e) of the Credit Agreement, no action, suit, investigation, litigation, or proceeding, including, without limitation, any Environmental Action, affecting any Loan Party or any of its respective Significant Subsidiaries before any court, government agency or arbitrator is pending or, to my knowledge, threatened, that is reasonably likely to have a Material Adverse Effect.

No Loan Party nor any of their respective Significant Subsidiaries is an “investment company”, or an “affiliated person” of, or “promoter” or “principal underwriter” for, an “investment company”, as such terms are defined in the Investment Company Act of 1940, as amended. Neither the making or assuming of any Advances, as applicable, the application of the proceeds or repayment thereof by the Borrowers, the issuance of the guaranty by AEP nor the consummation of the other transactions contemplated by the Credit Agreement will violate any provision of such Act or any rule, regulation or order of the Securities and Exchange Commission thereunder.

In any action or proceeding arising out of or relating to the Credit Agreement in any court of the State of Ohio or in any Federal court sitting in the State of Ohio, such court would recognize and give effect to the provisions of Section 9.09 of the Credit Agreement, wherein the parties thereto agree that the Credit Agreement shall be governed by, and construed in accordance with, the laws of the State of New York. However, if a court of the State of Ohio or a Federal court sitting in the State of Ohio were to hold that the Credit Agreement is governed by, and to be construed in accordance with, the laws of the State of Ohio, the Credit Agreement would be, under the State of Ohio, the legal, valid and binding obligation of each Loan Party enforceable against each Loan Party in accordance with its terms.

The opinion set forth above in the last sentence of paragraph 7 above is subject to the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditor’s rights generally and to general principles of equity, including (without limitation) concepts of materiality, reasonableness, good faith and fair dealing (regardless of whether considered in a proceeding in equity or at law.)

I express no opinion as to (i) Section 9.05 of the Credit Agreement; (ii) the effect of the law of any jurisdiction (other than the State of Ohio) wherein any Lender may be located which limits the rates of interest which may be charged or collected by such Lender; and (iii) whether a Federal or state court outside of the States of New York or Ohio would give effect to the choice of New York law provided for in the Credit Agreement.

C-5

This opinion has been rendered solely for your benefit in connection with the Credit Agreement and the transactions contemplated thereby and may not be used, circulated, quoted, relied upon or otherwise referred to by any other Person (other than your respective counsel, auditors and any regulatory agency having jurisdiction over you or as otherwise required pursuant to legal process or other requirements of law) for any other purpose without my prior written consent; provided that, (i) King & Spalding LLP, special counsel for the Administrative Agent, may rely on the opinions expressed in this opinion letter in connection with the opinion to be furnished by them in connection with the transactions contemplated by the Credit Agreement and (ii) any Person that becomes a Lender after the date hereof may rely on the opinions expressed in this opinion letter as though addressed to such Person. I undertake no responsibility to update or supplement this opinion in response to changes in law or future events or circumstances.

Very truly yours,

Thomas G. Berkemeyer

C-6

EXHIBIT D

(to the Term Credit Agreement)

FORM OF OPINION OF COUNSEL

FOR THE ADMINISTRATIVE AGENT

July 17, 2013

To each of the Lenders party to the

Credit Agreement referred to below

and to Wells Fargo Bank, National Association, as Administrative Agent

Ohio Power Company

Ladies and Gentlemen:

We have acted as special New York counsel to Wells Fargo Bank, National Association, individually and as Administrative Agent, in connection with the preparation, execution and delivery of the Term Credit Agreement, dated as of July 17, 2013 (the “ Credit Agreement ”), among Ohio Power Company (“ OPCo ”), AEP Generation Resources Inc. (“ AGR ”), Appalachian Power Company (“ APCo ”) and Kentucky Power Company (“ KPCo ”, and collectively with OPCo, AGR and APCo, the “ Borrowers ” and each a “ Borrower ”), American Electric Power Company, Inc., as the Guarantor (together with the Borrowers, the “ Loan Parties ”), the Lenders named therein and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders. This opinion is furnished to you pursuant to Section 3.01(a)(iv) of the Credit Agreement. Unless otherwise indicated, terms defined in the Credit Agreement are used herein as therein defined.

In that connection, we have examined the following documents:

(1) Counterparts of the Credit Agreement, executed by each Loan Party, the Administrative Agent and the Lenders; and

(2) The other documents furnished by the Loan Parties pursuant to Section 3.01 of the Credit Agreement, including (without limitation) the opinion of Jeffrey D. Cross, Deputy General Counsel for American Electric Power Service Corporation, an affiliate of the Loan Parties (the “ Opinion ”).

In our examination of the documents referred to above, we have assumed the authenticity of all such documents submitted to us as originals, the genuineness of all signatures, the due authority of the parties executing such documents and the conformity to the originals of all such documents submitted to us as copies. We have assumed that you independently evaluated, and are satisfied with, the creditworthiness of the Loan Parties and the business terms reflected in the Credit Agreement. We have also assumed that each of the Lenders and the Administrative Agent

has duly executed and delivered, with all necessary power and authority (corporate and otherwise), the Credit Agreement.

To the extent that our opinions expressed below involve conclusions as to matters governed by law other than the law of the State of New York, we have relied upon the Opinion and have assumed without independent investigation the correctness of the matters set forth therein, our opinions expressed below being subject to the assumptions, qualifications and limitations set forth in the Opinion. We note that we do not represent the Loan Parties and, accordingly, are not privy to the nature or character of their businesses. Accordingly, we have also assumed that the Loan Parties are subject only to statutes, rules, regulations, judgments, orders, and other requirements of law of general applicability to corporations doing business in the State of New York. As to matters of fact, we have relied solely upon the documents we have examined.

Based upon the foregoing, and subject to the qualifications set forth below, we are of the opinion that:

(i) The Credit Agreement is the legal, valid and binding obligation of each Loan Party enforceable against each Loan Party in accordance with its terms.

(ii) While we have not independently considered the matters covered by the Opinion to the extent necessary to enable us to express the conclusions stated therein, the Opinion and the other documents referred to in item (2) above are substantially responsive to the corresponding requirements set forth in Section 3.01 of the Credit Agreement pursuant to which the same have been delivered.

Our opinions are subject to the following qualifications:

(a) Our opinion in paragraph (i) above is subject to the effect of any applicable bankruptcy, insolvency, reorganization, fraudulent conveyance, moratorium or similar law affecting creditors’ rights generally.

(b) Our opinion in paragraph (i) above is subject to the effect of general principles of equity, including (without limitation) concepts of materiality, reasonableness, good faith and fair dealing (regardless of whether considered in a proceeding in equity or at law). Such principles of equity are of general obligation, and, in applying such principles, a court, among other things, might not allow a contracting party to exercise remedies in respect of a default deemed immaterial, or might decline to order an obligor to perform covenants.

(c) We note further that, in addition to the application of equitable principles described above, courts have imposed an obligation on contracting parties to act reasonably and in good faith in the exercise of their contractual rights and remedies, and may also apply public policy considerations in limiting the right of parties seeking to obtain indemnification under circumstances where the conduct of such parties in the circumstances in question is determined to have constituted negligence.

D-2

(d) We express no opinion herein as to (i) Section 9.05 of the Credit Agreement, (ii) the enforceability of provisions purporting to grant to a party conclusive rights of determination, (iii) the availability of specific performance or other equitable remedies, (iv) the enforceability of rights to indemnity under Federal or state securities laws and (v) the enforceability of waivers by parties of their respective rights and remedies under law.

(e) In connection with any provision of the Credit Agreement whereby the Loan Parties submit to the jurisdiction of any court of competent jurisdiction, we note the limitations of 28 U.S.C. §§ 1331 and 1332 on Federal court jurisdiction.

(f) Our opinions expressed above are limited to the law of the State of New York, and we do not express any opinion herein concerning any other law. Without limiting the generality of the foregoing, we express no opinion as to the effect of the law of any jurisdiction other than the State of New York wherein any Lender may be located or wherein enforcement of the Credit Agreement may be sought that limits the rates of interest legally chargeable or collectible.

This opinion letter speaks only as of the date hereof, and we expressly disclaim any responsibility to advise you of any development or circumstance, including changes of law of fact, that may occur after the date of this opinion letter that might affect the opinions expressed herein. This opinion letter is furnished to the addressees hereof solely in connection with the transactions contemplated by the Credit Agreement, is solely for the benefit of the addressees hereof and may not be relied upon by any other Person or for any other purpose without our prior written consent. Notwithstanding the foregoing, this opinion letter may be relied upon by any Person that becomes a Lender after the date hereof in accordance with the provisions of the Credit Agreement as if this opinion letter were addressed and delivered to such Person on the date hereof. Any such reliance must be actual and reasonable under the circumstances existing at the time such Person becomes a Lender, taking into account any changes in law or facts and any other developments known to or reasonably knowable by such Person at such time.

Very truly yours,

RSL:kty:mgj

D-3

EXHIBIT E-1

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Not Partnerships

For U.S. Federal Income Tax Purposes)

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Not Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Term Credit Agreement, dated as of July 17, 2013 (as amended, supplemented or otherwise modified from time to time, the “ Credit Agreement ”), among Ohio Power Company, AEP Generation Resources Inc., Appalachian Power Company and Kentucky Power Company (collectively, the “ Borrowers ”), American Electric Power Company, Inc., as the Guarantor (together with the Borrowers, the “ Loan Parties ”), the Lenders named therein and Wells Fargo Bank, National Association, as the administrative agent (the “ Administrative Agent ”) for the Lenders.

Pursuant to the provisions of Section 2.14 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record and beneficial owner of the Advance(s) and Commitment (as well as any promissory note(s) evidencing such Advance(s) and Commitment) in respect of which it is providing this certificate, (ii) it is not a bank within the meaning of Section 881(c)(3)(A) of the Internal Revenue Code, (iii) it is not a ten percent shareholder of any Loan Party within the meaning of Section 871(h)(3)(B) of the Internal Revenue Code and (iv) it is not a controlled foreign corporation related to any Loan Party as described in Section 881(c)(3)(C) of the Internal Revenue Code.

The undersigned has furnished the Administrative Agent and the Borrowers with a certificate of its non-U.S. Person status on IRS Form W-8BEN. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform the Administrative Agent and the Borrowers, and (2) the undersigned shall have at all times furnished the Administrative Agent and the Borrowers with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF LENDER]

By: _________________

Name:

Title:

Date: ________ __, 20[ ]

EXHIBIT E-2

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Not Partnerships

For U.S. Federal Income Tax Purposes)

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Not Partnerships For U.S. Federal Income Tax Purposes)

Pursuant to the provisions of Section 2.14 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record and beneficial owner of the participation in respect of which it is providing this certificate, (ii) it is not a bank within the meaning of Section 881(c)(3)(A) of the Internal Revenue Code, (iii) it is not a ten percent shareholder of any Loan Party within the meaning of Section 871(h)(3)(B) of the Internal Revenue Code, and (iv) it is not a controlled foreign corporation related to any Loan Party as described in Section 881(c)(3)(C) of the Internal Revenue Code.

The undersigned has furnished its participating Lender with a certificate of its non-U.S. Person status on IRS Form W-8BEN. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform such Lender in writing, and (2) the undersigned shall have at all times furnished such Lender with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF PARTICIPANT]

By: _________________

Name:

Title:

Date: ________ __, 20[ ]

EXHIBIT E-3

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Partnerships

For U.S. Federal Income Tax Purposes)

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Partnerships For U.S. Federal Income Tax Purposes)

Pursuant to the provisions of Section 2.14 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record owner of the participation in respect of which it is providing this certificate, (ii) its direct or indirect partners/members are the sole beneficial owners of such participation, (iii) with respect such participation, neither the undersigned nor any of its direct or indirect partners/members is a bank extending credit pursuant to a loan agreement entered into in the ordinary course of its trade or business within the meaning of Section 881(c)(3)(A) of the Internal Revenue Code, (iv) none of its direct or indirect partners/members is a ten percent shareholder of any Loan Party within the meaning of Section 871(h)(3)(B) of the Internal Revenue Code and (v) none of its direct or indirect partners/members is a controlled foreign corporation related to any Loan Party as described in Section 881(c)(3)(C) of the Internal Revenue Code.

The undersigned has furnished its participating Lender with IRS Form W-8IMY accompanied by one of the following forms from each of its partners/members that is claiming the portfolio interest exemption: (i) an IRS Form W-8BEN or (ii) an IRS Form W-8IMY accompanied by an IRS Form W-8BEN from each of such partner’s/member’s beneficial owners that is claiming the portfolio interest exemption. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform such Lender and (2) the undersigned shall have at all times furnished such Lender with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF PARTICIPANT]

By: __________________

Name:

Title:

Date: ________ __, 20[ ]

E-3-2

EXHIBIT E-4

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Partnerships

For U.S. Federal Income Tax Purposes)

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Partnerships For U.S. Federal Income Tax Purposes)

Pursuant to the provisions of Section 2.14 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record owner of the Advance(s) and Commitment (as well as any promissory note(s) evidencing such Advance(s) and Commitment) in respect of which it is providing this certificate, (ii) its direct or indirect partners/members are the sole beneficial owners of such Advance(s) and Commitment (as well as any promissory note(s) evidencing such Advance(s) and Commitment), (iii) with respect to the extension of credit pursuant to the Credit Agreement or any other Loan Document, neither the undersigned nor any of its direct or indirect partners/members is a bank extending credit pursuant to a loan agreement entered into in the ordinary course of its trade or business within the meaning of Section 881(c)(3)(A) of the Internal Revenue Code, (iv) none of its direct or indirect partners/members is a ten percent shareholder of any Loan Party within the meaning of Section 871(h)(3)(B) of the Internal Revenue Code and (v) none of its direct or indirect partners/members is a controlled foreign corporation related to any Loan Party as described in Section 881(c)(3)(C) of the Internal Revenue Code.

The undersigned has furnished the Administrative Agent and the Borrowers with IRS Form W-8IMY accompanied by one of the following forms from each of its partners/members that is claiming the portfolio interest exemption: (i) an IRS Form W-8BEN or (ii) an IRS Form W-8IMY accompanied by an IRS Form W-8BEN from each of such partner’s/member’s beneficial owners that is claiming the portfolio interest exemption. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform the Administrative Agent and the Borrowers, and (2) the undersigned shall have at all times furnished the Administrative Agent and the Borrowers with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF LENDER]

By: __________________

Name:

Title:

Date: ________ __, 20[ ]

E-4-2

EXHIBIT F

(to the Term Credit Agreement)

FORM OF BORROWER ASSUMPTION AGREEMENT

This Borrower Assumption Agreement (the “ Borrower Assumption Agreement ”) is dated as of [______ __, 2013] and is entered into by and between [OHIO POWER COMPANY][AEP GENERATION RESOURCES INC.] (the “ Assignor ”) and [AEP GENERATION RESOURCES INC.][APPALACHIAN POWER COMPANY][KENTUCKY POWER COMPANY] (the “ Assignee ”). Capitalized terms used but not defined herein shall have the meanings given to them in the Term Credit Agreement, dated as of July 17, 2013 (as amended, restated, amended and restated, supplemented or otherwise modified, the “ Credit Agreement ”), among Ohio Power Company, AEP Generation Resources Inc., Appalachian Power Company and Kentucky Power Company, as the Borrowers, American Electric Power Company, Inc., as the Guarantor, the Lenders parties thereto and Wells Fargo Bank, National Association, as Administrative Agent.

Assumption . For an agreed consideration, the Assignor hereby irrevocably sells and assigns to the Assignee, and the Assignee hereby irrevocably purchases and assumes from the Assignor, subject to and in accordance with Section 2.17 of the Credit Agreement, as of the date first set forth above, (i) all of the Assignor’s rights and obligations in its capacity as a Borrower under the Credit Agreement and each other Loan Document [to the extent related to outstanding Advances in an aggregate principal amount equal to $[_________],] 1 and (ii) to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other right of the Assignor (in its capacity as a Borrower) against any Person, whether known or unknown, arising under or in connection with the Credit Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including, but not limited to, contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above (the rights and obligations sold and assigned by the Assignor to the Assignee pursuant to clauses (i) and (ii) above being referred to herein collectively as the “ Assigned Interest ”). Each such sale and assignment is without recourse to the Assignor and without representation or warranty by the Assignor. Without limiting the generality of the foregoing, the Assignee hereby assumes and agrees punctually to pay, perform and discharge when due all of the Advances constituting a part of the Assigned Interest and the related obligations under the Loan Documents and each agreement made or to be performed by a Borrower under the Loan Documents.

Release of Certain Obligations . [Upon the effectiveness of the AGR Assumption pursuant to Section 2.17 of the Credit Agreement, (i) the Assignor shall no longer be a Borrower under the Credit Agreement or any other Loan Document, nor have any rights or obligations of a Borrower thereunder, and shall be released from any and all

_________________________

1 To be excluded only for the AGR Assumption

obligations under the Loan Documents, except for those obligations that expressly survive the repayment of all amounts under the Loan Documents or termination of the Commitments, and (ii) the Parent Guaranty will automatically become effective.] 2 [Upon the effectiveness of the APCo Assumption pursuant to Section 2.17 of the Credit Agreement, the Assignor will be released from liability for all of the Advances constituting a part of the Assigned Interest, and the Guarantor shall be released from its Guaranteed Obligations with respect to such assumed Advances.] 3 [Upon the effectiveness of the KPCo Assumption pursuant to Section 2.17 of the Credit Agreement, the Assignor will be released from liability for all of the Advances constituting a part of the Assigned Interest, and the Guarantor shall be released from its Guaranteed Obligations with respect to such assumed Advances.] 4

3.	Ratification . The Assignee hereby ratifies and agrees to be bound by, all of the terms and conditions contained in the applicable Loan Documents.

General Provisions . This Borrower Assumption Agreement shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and assigns. This Borrower Assumption Agreement may be executed in any number of counterparts, which together shall constitute one instrument. Delivery of an executed counterpart of a signature page of this Borrower Assumption Agreement by fax shall be effective as delivery of a manually executed counterpart of this Borrower Assumption Agreement. This Borrower Assumption Agreement shall be governed by, and construed in accordance with, the law of the State of New York.

_________________________

2 To be included only for the AGR Assumption

3 To be included only for the APCo Assumption

4 To be included only for the KPCo Assumption

F-2

The terms set forth in this Borrower Assumption Agreement are hereby agreed to:

ASSIGNOR

[OHIO POWER COMPANY]

[AEP GENERATION RESOURCES INC.]

By:

_________________________________

Title:

ASSIGNEE

[AEP GENERATION RESOURCES INC.]

[APPALACHIAN POWER COMPANY]

[KENTUCKY POWER COMPANY]

By:

_________________________________

Title:

AGREED AND ACKNOWLEDGED:

AMERICAN ELECTRIC POWER COMPANY, INC., as the Guarantor

By: __________________________________

Title:

F-3

Schedule I

Schedule of Initial Lenders

Lender Name	Commitment
Wells Fargo Bank, National Association	$75,000,000.00
The Bank of Tokyo-Mitsubishi UFJ, Ltd.	$75,000,000.00
Citibank, N.A.	$75,000,000.00
JPMorgan Chase Bank, N.A.	$75,000,000.00
KeyBank National Association	$75,000,000.00
The Royal Bank of Scotland Finance (Ireland)	$75,000,000.00
BNP Paribas	$40,000,000.00
Compass Bank	$40,000,000.00
Credit Agricole Corporate and Investment Bank	$40,000,000.00
Fifth Third Bank	$40,000,000.00
Goldman Sachs Bank USA	$40,000,000.00
Mizuho Bank, Ltd.	$40,000,000.00
PNC Bank, National Association	$40,000,000.00
Royal Bank of Canada	$40,000,000.00
Sumitomo Mitsui Banking Corporation	$40,000,000.00
SunTrust Bank	$40,000,000.00
The Bank of New York Mellon	$40,000,000.00
The Bank of Nova Scotia	$40,000,000.00
The Huntington National Bank	$40,000,000.00
U.S. Bank National Association	$30,000,000.00

Total	$1,000,000,000

Schedule 4.01(m)

Significant Subsidiaries

Ohio Power Company

None.

AEP Generation Resources Inc.

None.

Appalachian Power Company

None.

Kentucky Power Company

None.

American Electric Power Company, Inc.

Appalachian Power Company

Ohio Power Company

Indiana Michigan Power Company

AEP Utilities, Inc.

Southwestern Electric Power Company

Exhibit 10

IN THE UNITED STATES DISTRICT COURT

FOR THE SOUTHERN DISTRICT OF OHIO

EASTERN DIVISION

_____________________________________

UNITED STATES OF AMERICA

Plaintiff,

and

STATE OF NEW YORK, ET AL.,

	Consolidated Cases:
Plaintiff-Intervenors,	Civil Action No. C2-99-1182
	Civil Action No. C2-99-1250
v.	JUDGE EDMUND A. SARGUS, JR.
	M agistrate Judge Terence P. Kemp

AMERICAN ELECTRIC POWER SERVICE

CORP., ET AL.,

Defendants.

_____________________________________

OHIO CITIZEN ACTION, ET AL.,

Plaintiffs,	Civil Action No. C2-04-1098
	JUDGE EDMUND A. SARGUS, JR.
v.	Magistrate Judge Norah McCann King

AMERICAN ELECTRIC POWER SERVICE

CORP., ET AL.,

Defendants.

UNITED STATES OF AMERICA

Plaintiff,
	Civil Action No. C2-05-360
v.	JUDGE EDMUND A. SARGUS, JR.
	Magistrate Judge Norah McCann King

AMERICAN ELECTRIC POWER SERVICE

CORP., ET AL . ,

Defendants.

_____________________________________

THIRD JOINT MODIFICATION TO CONSENT DECREE

WITH ORDER MODIFYING CONSENT DECREE

WHEREAS On December 10, 2007, this Court entered a Consent Decree in the above-captioned matters (Case No. 99-1250, Docket # 363; Case No. 99-1182, Docket # 508).

WHEREAS Paragraph 199 of the Consent Decree provides that the terms of the Consent Decree may be modified only by a subsequent written agreement signed by the Plaintiffs and Defendants. Material modifications shall be effective only upon written approval by the Court.

WHEREAS pursuant to Paragraph 87 of the Consent Decree, as modified by a Joint Modification to Consent Decree With Order Modifying Consent Decree, filed on April 5, 2010 (Case No. 99-1250, Docket # 371), and as modified by a second Joint Modification to Consent Decree With Order Modifying Consent Decree, filed on December 28, 2010 (Case No. 99-1250, Docket # 372), the Defendants are required, inter alia , to install and continuously operate a Flue Gas Desulfurization System (FGD) no later than December 31, 2015 on Big Sandy Unit 2, December 31, 2015 on Muskingum River Unit 5, December 31, 2017 on Rockport Unit 1, and December 31, 2019 on Rockport Unit 2.

WHEREAS, on October 31, 2012, the Defendants filed an Application for Judicial Interpretation of Consent Decree in Case No. 99-1182 (Docket # 528) and the related cases.

WHEREAS, the United States, the States and Citizen Plaintiffs filed a Memorandum in Opposition (Case No. 99-1182, Docket # 534), and Citizen Plaintiffs filed a Supplemental Memorandum in Opposition (Case No. 99-1250, Docket # 381) to the Defendants’ Application.

WHEREAS all Parties made additional filings and the Application was scheduled for a hearing on December 17, 2012.

WHEREAS, the Parties have engaged in settlement discussions and have reached

agreement on a modification to the Consent Decree as set forth herein.

WHEREAS, the Parties have agreed, and this Court by entering this Third Joint Modification finds, that this Third Joint Modification has been negotiated in good faith and at arm’s length; that this settlement is fair, reasonable, and in the public interest, and consistent with the goals of the Clean Air Act, 42 U.S.C. §7401, et seq .; and that entry of this Third Joint Modification without further litigation is the most appropriate means of resolving this matter.

WHEREAS, the Parties agree and acknowledge that final approval of the United States and entry of this Third Joint Modification is subject to the procedures set forth in 28 CFR § 50.7, which provides for notice of this Third Joint Modification in the Federal Register, an opportunity for public comment, and the right of the United States to withdraw or withhold consent if the comments disclose facts or considerations which indicate that the Third Joint Modification is inappropriate, improper, or inadequate. No Party will oppose entry of this Third Joint Modification by this Court or challenge any provision of this Third Joint Modification unless the United States has notified the Parties, in writing, that the United States no longer supports entry of the Third Joint Modification.

NOW THEREFORE, for good cause shown, without admission of any issue of fact or law raised in the Application or the underlying litigation, the Parties hereby seek to modify the Consent Decree in this matter, and upon the filing of a Motion to Enter by the United States, move that the Court sign and enter the following Order:

1. Add a definition of “Cease Burning Coal” as new Paragraph 8A of the Consent Decree as follows:

8A . “ Cease Burning Coal” means that Defendants shall permanently cease burning coal for purposes of generating electricity from a Unit, and shall submit all necessary notifications or

requests for permit amendments to reflect the permanent cessation of coal firing at the Unit.

2. Modify the definition of “Continuously Operate” in Paragraph 14 of the Consent Decree as follows:

14 . “C ontinuously Operate” or “Continuous Operation” means that when an SCR, FGD, DSI, ESP, or Other NOx Pollution Controls are used at a Unit, except during a Malfunction, they shall be operated at all times such Unit is in operation, consistent with the technological limitations, manufacturer’s specifications, and good engineering and maintenance practices for such equipment and the Unit so as to minimize emissions to the greatest extent practicable.

3. Add a new definition of “Dry Sorbent Injection” or “DSI” as new Paragraph18A of the Consent Decree as follows:

18A . “Dry Sorbent Injection” or “DSI” means a pollution control system in which a sorbent is injected into the flue gas path prior to the particulate pollution control device for the purpose of reducing SO 2 emissions. For purposes of the DSI systems required to be installed at the Rockport Units only, the DSI systems shall utilize a sodium based sorbent and be designed to inject at least 10 tons per hour of a sodium based sorbent. Defendants may utilize a different sorbent at the Rockport Units provided they obtain prior approval from Plaintiffs pursuant to Paragraph 148 of the Consent Decree.

4. Modify the definition of “Improved Unit” in Paragraph 28 of the Consent Decree as follows:

28. An “Improved Unit” for SO 2 means an AEP Eastern System Unit equipped with an FGD or scheduled under this Consent Decree to be equipped with an FGD, or required to be Retired, Retrofitted, Re-Powered , or Refueled .

The remainder of Paragraph 28 shall remain the same.

5. Add a definition of “Plant-Wide Annual Tonnage Limitation for SO 2 at Rockport” as new Paragraph 48A of the Consent Decree, as follows:

48 A. “P lant-Wide Annual Tonnage Limitation for SO 2 at Rockport” means the sum of the tons of SO 2 emitted during all periods of operation from the Rockport Plant, including, without limitation, all SO 2 emitted during periods of startup, shutdown, and Malfunction, during the relevant calendar year ( i.e. , January 1 – December 31).

6. Add a definition of “Refuel” as new Paragraph 53A of the Consent Decree, as follows:

53A. “Refuel ” means, solely for purposes of this Consent Decree, the modification of a unit as necessary such that the modified unit generates electricity solely through the combustion of natural gas rather than coal, including the installation and Continuous Operation of the NO x controls required by Section IV of this Consent Decree. Nothing herein shall prevent the reuse of any equipment at any existing unit or new emissions unit, provided that AEP applies for, and obtains, all required permits, including, if applicable, a PSD or Nonattainment NSR permit.

7. Modify the definition of “Retrofit” in Paragraph 56 of the Consent Decree as follows:

56. “Retrofit” means that the Unit must install and Continuously Operate both an SCR and an FGD, as defined in the Consent Decree. For purposes of the requirements in Paragraph 87 for the Rockport Units, “Retrofit” also means that the Unit will be equipped with a post-combustion wet- or dry-FGD system with a control technology vendor guaranteed design removal efficiency of 98% or more, and subject upon installation to a 30-Day Rolling Average Emissions Rate of 0.100 lb/mmBTU for SO 2 , if the Unit burns coal with an uncontrolled SO 2 emissions rate of 3.0 lb/mmBTU or higher, or a 30-day Rolling Average Emission Rate of 0.060 lb/mmBTU if the

Unit burns coal with an uncontrolled SO 2 emissions rate below 3.0 lb/mmBTU. For the 600 MW listed in the table in Paragraph 68 and 87, “Retrofit” means that the Unit must meet a federally-enforceable 30-Day Rolling Average Emission Rate of 0.100 lb/mmBTU for NOx and a 30-Day Rolling Average Emission Rate of 0.100 lb/mmBTU for SO2, measured in accordance with the requirements of this Consent Decree.

8. Modify the Eastern System-Wide Annual Tonnage Limitations for SO 2 in the table in Paragraph 86 of the Consent Decree as follows:

86. Notwi thstanding any other provision of this Consent Decree, except Section XIV (Force Majeure), during each calendar year specified in the table below, all Units in the AEP Eastern System, collectively, shall not emit SO 2 in excess of the following Eastern System-Wide Annual Tonnage Limitations:

Calendar Year(s)	Eastern System-Wide Annual Tonnage Limitations for SO 2	Modified Eastern System-Wide Annual Tonnage Limitations for SO 2
2016	260,000 tons	145,000 tons
2017	235,000 tons	145,000 tons
2018	184,000 tons	145,000 tons
2019 , and each year thereafter - 2021	174,000 tons	113,000 tons per year
2022 - 2025	174,000 tons	110,000 tons per year
2026 - 2028	174,000 tons	102,000 tons per year
2029, and each year thereafter	174,000 tons	94,000 tons per year

The remainder of the table in Paragraph 86 shall remain the same.

9. Modify the SO 2 pollution control requirements and compliance dates listed in the

table in Paragraph 87 of the Consent Decree for Big Sandy Unit 2, Muskingum River Unit 5, Rockport Units 1 and 2, and Tanners Creek Unit 4 as follows:

87. No later than the dates set forth in the table below, Defendants shall install and Continuously Operate an FGD on each Unit identified therein, or, if indicated in the table, Retire, Retrofit, or Re-power , or Refuel such Unit:

Unit	SO 2 Pollution Control	Modified SO 2 Pollution Control	Date	Modified Date
Big Sandy Unit 2	FGD	Retrofit, Retire, Re-power, or Refuel	December 31, 2015	NA
Muskingum River Unit 5	FGD	Cease Burning Coal and Retire Or Cease Burning Coal and Refuel	December 31, 2015	December 15, 2015 December 31, 2015, unless the Refueling project is not completed in which case the unit will be taken out of service no later than December 31, 2015 and will not restart until the Refueling project is completed. The Refueling project must be completed by June 30, 2017.
First Rockport Unit	FGD	Dry Sorbent Injection, and Retrofit, Retire, Re-power, or Refuel	December 31, 2017	April 16, 2015 December 31, 2025.
Second Rockport Unit	FGD	Dry Sorbent Injection, and	December 31, 2019	April 16, 2015 and

Unit	SO 2 Pollution Control	Modified SO 2 Pollution Control	Date	Modified Date
		Retrofit, Retire, Re-power, or Refuel		December 31, 2028.
Tanners Creek Unit 4	NA	Retire or Refuel	NA	June 1, 2015

The remainder of the table in Paragraph 87 of the Consent Decree shall remain the same, including the Joint Modifications previously made to the compliance deadlines for Amos Units 1 and 2.

10. Add a new Paragraph 89A establishing the Plant-Wide Annual Tonnage Limitations for SO 2 at Rockport, as follows:

89A. For each of the calendar years set forth in the table below, Defendants shall limit their total annual SO 2 emissions from Rockport Units 1 and 2 to Plant-Wide Annual Tonnage Limitations for SO 2 as follows:

Calendar Years	Plant-Wide Annual Tonnage Limitations for SO 2
2016 - 2017	28,000 tons per year
2018 - 2019	26,000 tons per year
2020 - 2025	22,000 tons per year
2026 - 2028	18,000 tons per year
2029, and each year thereafter	10,000 tons per year

11. Modify Paragraph 92 of the Consent Decree as follows:

92. Except as may be necessary to comply with this Section and Section XIII (Stipulated Penalties), Defendants may not use any SO 2 Allowances to comply with any requirements of this

Consent Decree, including by claiming compliance with any emission limitation, Eastern System-Wide Annual Tonnage Limitation, Plant-Wide Annual Rolling Average Tonnage Limitation for SO 2 at Clinch River, Plant-Wide Annual Tonnage Limitation for SO 2 at Kammer, or Plant-Wide Annual Tonnage Limitations for SO 2 at Rockport required by this Consent Decree by using, tendering, or otherwise applying SO 2 Allowances to achieve compliance or offset any emission above the limits specified in this Consent Decree.

12. Modify Paragraph 100 of the Consent Decree as follows:

100. To the extent an Emission Rate, 30-Day Rolling Average Removal Efficiency, Eastern System-Wide Annual Tonnage Limitation, or Plant-Wide Annual Tonnage Limitation for SO 2 is required under this Consent Decree, Defendants shall use CEMS in accordance with the reference methods specified in 40 C.F.R. Part 75 to determine the Emission Rate or annual emissions.

13. Modify Paragraph 104 of the Consent Decree as follows:

104. On or before the date established by this Consent Decree for Defendants to achieve and maintain 0.030 lb/mmBTU at Cardinal Unit 1, Cardinal Unit 2, and Muskingum River Unit 5, Defendants shall conduct a performance test for PM that demonstrates compliance with the PM Emission Rate required by this Consent Decree. Within forty-five (45) days of each such performance test, Defendants shall submit the results of the performance test to Plaintiffs pursuant to Section XVIII (Notices) of this Consent Decree. On and after the date that Muskingum River Unit 5 complies with the requirement to Cease Burning Coal pursuant to Paragraph 87 of this Consent Decree, Defendants shall no longer be obligated to comply with the performance testing requirements for Muskingum River Unit 5 contained in this Paragraph.

14. Modify Paragraph 105 of the Consent Decree as follows:

105. Beginning in calendar year 2010 for Cardinal Unit 1 and Cardinal Unit 2, and calendar year 2013 for Muskingum River Unit 5, and continuing in each calendar year thereafter, Defendants shall conduct a stack test for PM on each stack servicing Cardinal Unit 1, Cardinal Unit 2, and Muskingum River Unit 5. The annual stack test requirement imposed by this Paragraph may be satisfied by stack tests conducted by Defendants as required by their permits from the State of Ohio for any year that such stack tests are required under the permits. On and after the date that Muskingum River Unit 5 complies with the requirement to Cease Burning Coal pursuant to Paragraph 87 of this Consent Decree, Defendants shall no longer be obligated to comply with the stack testing requirements for Muskingum River Unit 5 contained in this Paragraph.

15. Modify Paragraph 119 of the Consent Decree as follows:

119. Defendants shall implement the Environmental Mitigation Projects described in Appendix A to this Consent Decree, shall fund the categories of Projects described in Subsection B, below, and shall implement the Citizen Plaintiffs’ Renewable Energy Project and Citizen Plaintiffs’ Mitigation Projects described in Subsection C, below , (collectively, the “Projects”) in compliance with the approved plans and schedules for such Projects and other terms of this Consent Decree.

The remainder of Paragraph 119 shall remain the same.

16. Add a new Subsection C after Paragraph 128 of the Consent Decree as follows:

C . C itizen Plaintiffs’ Renewable Energy Project and Citizen Plaintiffs’ Mitigation Projects.

128A. Citizen Plaintiffs’ Renewable Energy Project. Defendants shall implement a renewable

energy project as described below during the period from 2013 through 2019.

a . If , during the period from 2013-2015, a renewable energy production tax credit of at least 2.2 cents/kwh for ten years is available for new wind electricity production facilities upon which construction is commenced within one year or more after enactment of the tax credit (or an alternative tax benefit is available that provides sufficient economic value so that the levelized cost to customers does not exceed the weighted average cost of any existing contracts with Indiana Michigan Power Company (“I&M”) for 50 MW or greater of wind capacity, adjusted for inflation) I&M will secure 200 MW of new wind energy capacity from facilities located in Indiana or Michigan that qualify for the production tax credit or alternative tax benefit within two years after enactment. For the avoidance of doubt, so long as the energy production tax credit contained in the American Taxpayer Relief Act of 2012 allows projects that have commenced construction by December 31, 2013, and that are placed in service by December 31, 2014, to qualify for the energy production tax credit provided in that Act, then I&M shall be obligated to secure new renewable energy purchase agreements for 200 MW of new wind energy capacity.

b. If a renewable energy production tax credit or alternative tax benefit as described in subparagraph a., above, is not available during 2013-2015, but becomes available during 2016-2019 for new wind electricity production facilities on which construction is commenced within one year or more after the production tax credit or alternative tax benefit is enacted, I&M will use commercially reasonable efforts to secure 200 MW of new wind energy capacity from facilities located in Indiana or Michigan that qualify for the production tax credit or alternative tax benefit within two years after enactment.

c. If a renewable energy production tax credit or alternative tax benefit as described in subparagraph a., above, is not available during the period from 2013 – 2019 for new wind electricity production facilities on which construction is commenced within one year or more after the production tax credit or alternative tax benefit is enacted, I&M shall be relieved of its obligations to secure new wind energy capacity under this Paragraph 119A.

128B. Citizen Plaintiffs’ Mitigation Projects. I&M will provide $2.5 million in mitigation funding as directed by the Citizen Plaintiffs for projects in Indiana that include diesel retrofits, health and safety home repairs, solar water heaters, outdoor wood boilers, land acquisition projects, and small renewable energy projects (less than 0.5 MW) located on customer premises that are eligible for net metering or similar interconnection arrangements on or before December 31, 2014. I&M shall make payments to fund such Projects within seventy-five (75) days after being notified by the Citizen Plaintiffs in writing of the nature of the Project, the amount of funding requested, the identity and mailing address of the recipient of the funds, payment instructions, including taxpayer identification numbers and routing instructions for electronic payments, and any other information necessary to process the requested payments. Defendants shall not have approval rights for the Projects or the amount of funding requested, but in no event shall the cumulative amount of funding provided pursuant to this Paragraph 128B exceed $2.5 million.

17. Modify Paragraph 127 of the Consent Decree as follows:

127. The States , by and through their respective Attorneys General, shall jointly submit to Defendants Projects within the categories identified in this Subsection B for funding in amounts not to exceed $4.8 million per calendar year for no less than five (5) years following the Date of Entry of this Consent Decree beginning as early as calendar year 2008 , and for an additional

amount not to exceed $6.0 million in 2013. The funds for these Projects will be apportioned by and among the States, and Defendants shall not have approval rights for the Projects or the apportionment. Defendants shall pay proceeds as designated by the States in accordance with the Projects submitted for funding each year within seventy-five (75) days after being notified by the States in writing. Notwithstanding the maximum annual funding limitations above, if the total costs of the projects submitted in any one or more years is less than the maximum annual amount, the difference between the amount requested and the maximum annual amount for that year will be available for funding by the Defendants of new and previously submitted projects in the following years, except that all amounts not requested by and paid to the States within eleven (11) years after the Date of Entry of this Consent Decree shall expire.

18. Modify Paragraph 133 of the Consent Decree as follows:

133. Claims Based on Modifications after the Date of Lodging of This Consent Decree. Entry of this Consent Decree shall resolve all civil claims of the United States against Defendants that arise based on a modification commenced before December 31, 2018, or, solely for the first Rockport Unit, before December 31, 2025, or, solely for the second Rockport Unit, before December 31, 2028, for all pollutants, except Particulate Matter, regulated under Parts C or D of Subchapter I of the Clean Air Act, and under regulations promulgated thereunder, as of the Date of Lodging of this Consent Decree, and:

a. where such modification is commenced at any AEP Eastern System Unit after the Date of Lodging of this Consent Decree; or

b. where such modification is one this Consent Decree expressly directs Defendants to undertake.

The remainder of Paragraph 133 shall remain the same.

19. Modify the table in Paragraph 150 of the Consent Decree as follows:

Consent Decree Violation	Stipulated Penalty (Per Day, Per Violation, Unless Otherwise Specified)
x. Failure to comply with the Plant-Wide Annual Tonnage Limitation for SO 2 at Rockport	$40,000 per ton, plus the surrender, pursuant to the procedures set forth in Paragraphs 95 and 96, of SO 2 Allowances in an amount equal to two times the number of tons by which the limitation was exceeded
y. Failure to fund a Citizen Plaintiffs’ Mitigation Project as required by Paragraph 119B of this Consent Decree	$1,000 per day per violation during the first 30 days, $5,000 per day per violation thereafter
z. Failure to implement the Citizen Plaintiffs’ Renewable Energy Project required by Paragraph 128A of this Consent Decree	$10,000 per day per violation during the first 30 days, $32,500 per day per violation thereafter

The remainder of the table in Paragraph 150 shall remain the same.

20. In addition to the requirements reflected in Appendix B (Reporting Requirements) to the Consent Decree, Defendants shall include in their Annual Report to Plaintiffs the following information:

O. Plant -Wide Annual Tonnage Limitation for SO 2 at Rockport

Beginning on March 31, 2017, and continuing annually thereafter, Defendants shall report: (a) the actual tons of SO 2 emitted from Units 1 and 2 at the Rockport Plant for the prior calendar year; (b) the Plant-Wide Annual Tonnage Limitation for SO 2 at the Rockport Plant for the prior calendar year as set forth in Paragraph 89A of the Consent Decree; and (c) for the annual reports for calendar years 2015 – 2028, Defendants shall report the daily average SO 2 emissions from the Rockport Plant expressed in lb/mmBTU, and the daily sorbent deliveries to the Rockport Plant by weight.

P . Citizen Plaintiffs’ Renewable Energy Project

Beginning on March 31, 2014, and continuing each year thereafter until completion of the Citizen Plaintiffs’ Renewable Energy Project, Defendants shall include a written report detailing the progress of the implementation of the Citizen Plaintiffs’ Renewable Energy Project required by Paragraph 119A of the Consent Decree.

Q. Citizen Plaintiffs’ Mitigation Projects

Beginning on March 31, 2013, and continuing each year until March 31, 2015, Defendants shall include a written report detailing the progress of implementation of the Citizen

Plaintiffs’ Mitigation Projects required by Paragraph 119B of the Consent Decree.

R. By March 31, 2015, Defendants shall notify Plaintiffs of their intent to Retire or Refuel Muskingum River 5.

S. By March 31, 2024, Defendants shall notify Plaintiffs of their decision to Retrofit, Retire, Re-Power or Refuel the first Rockport Unit. If Defendants elect to Retrofit the Unit, Defendants shall provide with such notification, information regarding the removal efficiency guarantee requested from and obtained from the control technology vendor and the sulfur content of the fuel used to design the FGD, including any non-confidential information regarding the SO 2 control technology filed by Defendants with the public utility regulator.

T. By March 31, 2027, Defendants shall notify Plaintiffs of their decision to Retrofit, Retire, Re-power or Refuel the second Rockport Unit. If Defendants elect to Retrofit the Unit, Defendants shall provide with such notification, information regarding the removal efficiency guarantee requested from and obtained from the control technology vendor and the sulfur content of the fuel used to design the FGD, including any non-confidential information regarding the SO 2 control technology filed by Defendants with the public utility regulator.

U. If Defendants elect to Retrofit one or both of the Rockport Units, beginning in the annual reports submitted for calendar years 2026 and/or 2029, as applicable, Defendants shall report a 30-Day Rolling Average SO 2 Emission Rate for the Unit(s) that is (are) Retrofit in accordance with Paragraph 5 of the Consent Decree. In addition, Defendants shall report a 30-Day Rolling Average Uncontrolled Emission Rate for SO 2 for the Unit(s) that is(are) Retrofit based on daily as burned coal sampling and analysis or an inlet SO 2 CEMs upstream of the FGD.

The remainder of Appendix B shall remain the same.

21. Except as specifically provided in this Order, all other terms and conditions of the Consent Decree remain unchanged and in full effect.

SO ORDERED, THIS 14 th DAY OF May, 2013.

/s/ Edmund A. Sargus, Jr.

HONORABLE EDMUND A. SARGUS, JR.

UNITED STATES DISTRICT COURT JUDGE

Respectfully submitted,

FOR THE UNITED STATES OF AMERICA:

/s/ Ignacia S. Moreno

IGNACIA S. MORENO

Assistant Attorney General

Environmental and Natural Resources Division

United States Department of Justice

/s/ Myles E. Flint, II

MYLES E. FLINT, II

Senior Counsel

Environmental Enforcement Section

Environmental and Natural Resources Division

United States Department of Justice

P.O. Box 7611

Washington, D.C. 20530

(202) 307-1859

FOR THE UNITED STATES OF AMERICA:

/s/ Susan Shinkman

SUSAN SHINKMAN

Director

Office of Civil Enforcement

United States Environmental Protection Agency

/s/ Phillip A. Brooks

PHILLIP A. BROOKS

Director, Air Enforcement Division

Office of Civil Enforcement

United States Environmental Protection Agency

/s/ Seema Kakade

SEEMA KAKADE

Attorney-Advisor

Air Enforcement Division

Office of Civil Enforcement

United States Environmental Protection Agency

FOR THE COMMONWEALTH OF MASSACHUSETTS:

MARTHA COAKLEY

Attorney General

By: /s/ Frederick D. Augenstern

FREDERICK D. AUGENSTERN

Assistant Attorney General

Environmental Protection Division

1 Ashburton Place, 18th Floor

Boston, Massachusetts 02108

FOR THE STATE OF CONNECTICUT:

GEORGE JEPSON

Attorney General

By: /s/ Kimberly Massicote

KIMBERLY MASSICOTE

Assistant Attorney General

55 Elm Street, P.O. Box 120

Hartford, Connecticut 06140-0120

FOR THE STATE OF MARYLAND:

DOUGLAS F. GANSLER

Attorney General

By: /s/ Matthew Zimmerman

MATTHEW ZIMMERMAN

Assistant Attorney General

Office of the Attorney General

1800 Washington Blvd.

Baltimore, Maryland 21230

FOR THE STATE OF NEW HAMPSHIRE:

MICHAEL A. DELANEY

Attorney General

By: /s/ K. Allen Brooks

K. ALLEN BROOKS

Assistant Attorney General

33 Capitol Street

Concord, New Hampshire 03301

FOR THE STATE OF NEW JERSEY:

JEFFREY S. CHIESA

Attorney General

By: /s/ Jon C. Martin

JON C. MARTIN

Deputy Attorney General

New Jersey Dept. of Law & Public Safety

25 Market St., P.O. Box 093

Trenton, NJ 08625-0093

FOR THE STATE OF NEW YORK:

ERIC T. SCHNEIDERMAN

Attorney General

By: /s/ Michael J. Myers

MICHAEL J. MYERS

Assistant Attorney General

Environmental Protection Bureau

The Capitol

Albany, New York 12224

FOR THE STATE OF RHODE ISLAND:

PETER F. KILMARTIN

Attorney General

By: /s/ Gregory S. Schultz

GREGORY S. SCHULTZ

Special Assistant Attorney General

150 South Main Street

Providence, Rhode Island 02903

FOR THE STATE OF VERMONT:

WILLIAM H. SORRELL

Attorney General

By: /s/ Thea Schwartz

THEA SCHWARTZ

Assistant Attorney General

Environmental Division

109 State Street

Montpelier, Vermont 05609-1001

FOR NATURAL RESOURCES DEFENSE COUNCIL, INC.:

By: /s/ Nancy S. Marks

NANCY S. MARKS

Natural Resources Defense Council, Inc.

40 West 20th Street

New York, NY 10011

FOR OHIO CITIZEN ACTION, CITIZENS ACTION COALITION OF INDIANA, HOSIER ENVIRONMENTAL COUNCIL, OHIO VALLEY ENVIRONMENTAL COALITION, WEST VIRGINIA ENVIRONMENTAL COUNSIL, CLEAN AIR COUNCIL, IZAAK WALTON LEAGUE OF AMERICA, ENRIVONMENTAL AMERICA 1 , NATIONAL WILDLIFE FEDERAION, INDIANA WILDLIFE FEDERATION AND LEAGUE OF OHIO SPORTSMEN:

By: /s/ Faith Bugel

FAITH BUGEL

Environmental Law and Policy Center

35 East Wacker Drive, Suite 1300

Chicago, Illinois 60601-2110

By: /s/ Peter Precario

PETER PRECARIO

326 S. High Street

Suite 100

Columbus, Ohio 43215-4525

1 Environment America is the same entity that signed on to the original Consent Decree as United States Public Interest Research Group.

FOR SIERRA CLUB:

By: /s/ Shannon Fisk

SHANNON FISK

Earthjustice

1617 John F. Kennedy Blvd., Suite 1675

Philadelphia, PA 19103

FOR DEFENDANTS AMERICAN ELECTRIC POWER SERVICE CORPORATION, ET AL.:

By: /s/ David M. Feinberg

DAVID M. FEINBERG

General Counsel

American Electric Power Service Corporation

1 Riverside Plaza

Columbus, Ohio 43215

EXHIBIT 12

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIAIRIES

Computation of Consolidated Ratios of Earnings to Fixed Charges

(in millions except ratio data)

															Twelve		Six
															Months		Months
	Years Ended December 31,														Ended		Ended
	2008			2009			2010			2011			2012		6/30/2013		6/30/2013
EARNINGS
Income Before Income Tax Expense and Equity Earnings	$	2,015		$	1,938		$	1,849		$	2,367		$	1,822	$	1,647	$	938
Fixed Charges (as below)		1,240			1,237			1,254			1,209			1,257		1,237		579
Preferred Security Dividend Requirements of Consolidated Subsidiaries		(4	)		(4	)		(4	)		(8	)		-		-		-
Total Earnings	$	3,251		$	3,171		$	3,099		$	3,568		$	3,079	$	2,884	$	1,517

FIXED CHARGES
Interest Expense	$	957		$	973		$	999		$	933		$	988	$	984	$	460
Credit for Allowance for Borrowed Funds Used During Construction		75			67			53			63			69		53		19
Estimated Interest Element in Lease Rentals		204			193			198			205			200		200		100
Preferred Security Dividend Requirements of Consolidated Subsidiaries		4			4			4			8			-		-		-
Total Fixed Charges	$	1,240		$	1,237		$	1,254		$	1,209		$	1,257	$	1,237	$	579

Ratio of Earnings to Fixed Charges		2.62			2.56			2.47			2.95			2.44		2.33		2.62

EXHIBIT 12

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

Computation of Consolidated Ratios of Earnings to Fixed Charges

(in thousands except ratio data)

											Twelve		Six
											Months		Months
	Years Ended December 31,										Ended		Ended
		2008	2009		2010		2011		2012		6/30/2013		6/30/2013
EARNINGS
Income Before Income Taxes	$	166,801	$	201,263	$	2 10,898	$	252,618	$	423,030	$	366,514	$	167,319
Fixed Charges (as below)		225,573		215,640		217, 500		217,280		210,421		204,210		101,086
Total Earnings	$	392,374	$	416,903	$	428,398	$	469,898	$	633,451	$	570,724	$	268,405

FIXED CHARGES
Interest Expense	$	209,733	$	202,426	$	207,649	$	204,623	$	202,074	$	195,154	$	96,332
Credit for Allowance for Borrowed Funds Used During Construction		9,040		6,014		2,251		6,257		1,347		2,056		1,254
Estimated Interest Element in Lease Rentals		6,800		7,200		7,600		6,400		7,000		7,000		3,500
Total Fixed Charges	$	225,573	$	215,640	$	217,500	$	217,280	$	210,421	$	204,210	$	101,086

Ratio of Earnings to Fixed Charges		1.73		1.93		1.96		2.16		3.01		2.79		2.65

EXHIBIT 12

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

Computation of Consolidated Ratios of Earnings to Fixed Charges

(in thousands except ratio data)

											Twelve		Six
											Months		Months
	Years Ended December 31,										Ended		Ended
		2008		2009	2010		2011		2012		6/30/2013		6/30/2013
EARNINGS
Income Before Income Taxes	$	190,133	$	297,347	$	189,517	$	201,434	$	157,801	$	185,349	$	125,360
Fixed Charges (as below)		164,660		173,293		174,965		168,003		168,656		169,336		84,336
Total Earnings	$	354,793	$	470,640	$	364,482	$	369,437	$	326,457	$	354,685		209,696

FIXED CHARGES
Interest Expense	$	89,851	$	101,145	$	104,465	$	97,665	$	102,739		100,960		48,647
Credit for Allowance for Borrowed Funds Used During Construction		4,609		8,348		8,500		7,838		4,717		7,176		5,089
Estimated Interest Element in Lease Rentals		70,200		63,800		62,000		62,500		61,200		61,200		30,600
Total Fixed Charges	$	164,660	$	173,293	$	174,965	$	168,003	$	168,656		169,336		84,336

Ratio of Earnings to Fixed Charges		2.15		2.71		2.08		2.19		1.93		2.09		2.48

EXHIBIT 12

OHIO POWER COMPANY AND SUBSIDIARY

Computation of Consolidated Ratios of Earnings to Fixed Charges

(in thousands except ratio data)

												Twelve		Six
												Months		Months
	Years Ended December 31,											Ended		Ended
	2008		2009		2010		2011		2012			6/30/2013		6/30/2013
EARNINGS
Income Before Income Taxes	$	693,946	$	890,471	$	842,922	$	678,690	$	487,817	$	336,854	$	232,002
Fixed Charges (as below)		318,684		283,540		269,886		248,026		245,446		235,481		114,039
Total Earnings	$	1,012,630	$	1,174,011	$	1,112,808	$	926,716	$	733,263	$	572,335	$	346,041

FIXED CHARGES
Interest Expense	$	265,938	$	241,134	$	242,000	$	221,976	$	213,100	$	203,109	$	97,417
Credit for Allowance for Borrowed Funds Used During Construction		27,946		16,506		3,786		2,350		9,046		9,072		4,972
Estimated Interest Element in Lease Rentals		24,800		25,900		24,100		23,700		23,300		23,300		11,650
Total Fixed Charges	$	318,684	$	283,540	$	269,886	$	248,026	$	245,446	$	235,481	$	114,039

Ratio of Earnings to Fixed Charges		3.17		4.14		4.12		3.73		2.98		2.43		3.03

EXHIBIT 12

PUBLIC SERVICE COMPANY OF OKLAHOMA

Computation of Ratios of Earnings to Fixed Charges

(in thousands except ratio data)

												Twelve		Six
												Months		Months
	Years Ended December 31,											Ended		Ended
	2008		2009		2010		2011		2012			6/30/2013		6/30/2013
EARNINGS
Income (Loss) Before Income Taxes	$	120,761	$	119,523	$	122,887	$	192 ,257	$	180 ,835	$	172,145	$	68,686
Fixed Charges (as below)		81,584		62,235		65,834		58,822		58,984		57,630		28,918
Total Earnings	$	202,345	$	181,758	$	188,721	$	251,079	$	239,819	$	229,775	$	97,604

FIXED CHARGES
Interest Expense	$	76,910	$	59,093	$	63,362	$	54,700	$	55,286	$	53,408	$	26,599
Credit for Allowance for Borrowed Funds Used During Construction		2,174		1,142		572		822		1,098		1,622		1,019
Estimated Interest Element in Lease Rentals		2,500		2,000		1,900		3,300		2,600		2,600		1,300
Total Fixed Charges	$	81,584	$	62,235	$	65,834	$	58,822	$	58,984	$	57,630	$	28,918

Ratio of Earnings to Fixed Charges		2.48		2.92		2.86		4.26		4.06		3.98		3.37

EXHIBIT 12

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

Computation of Consolidated Ratios of Earnings to Fixed Charges

(in thousands except ratio data)

												Twelve		Six
												Months		Months
	Years Ended December 31,											Ended		Ended
	2008				2009	2010		2011		2012		6 /30/2013		6 /30/2013
EARNINGS
Income Before Income Taxes and Equity Earnings	$	129,489		$	140,035	$	208,484	$	219,283	$	245,862	$	194,638	$	62,725
Fixed Charges (as below)		119,516			109,146		132,106		134,285		147,817		148,830		74,374
Total Earnings	$	249,005		$	249,181	$	340,590	$	353,568	$	393,679	$	343,468	$	137,099

FIXED CHARGES
Interest Expense	$	93,150		$	70,500	$	86,538	$	81,781	$	88,318	$	112,143	$	67,537
Credit for Allowance for Borrowed Funds Used During Construction		19,800			29,546		33,668		40,904		48,499		25,687		1,337
Trust Dividends		(134	)		-		-		-		-		-		-
Estimated Interest Element in Lease Rentals		6,700			9,100		11,900		11,600		11,000		11,000		5,500
Total Fixed Charges	$	119,516		$	109,146	$	132,106	$	134,285	$	147,817	$	148,830	$	74,374

Ratio of Earnings to Fixed Charges		2.08			2.28		2.57		2 .63		2.66		2.30		1.84

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.	I have reviewed this report on Form 10-Q of American Electric Power Company, Inc.;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 26, 2013

By:

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Appalachian Power Company;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 26, 2013

By:

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Indiana Michigan Power Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 26, 2013

By:

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Ohio Power Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 26, 2013

By:

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Public Service Company of Oklahoma;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 26, 2013

By:

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Southwestern Electric Power Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 26, 2013

By:

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.	I have reviewed this report on Form 10-Q of American Electric Power Company, Inc.;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 26, 2013

By:

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Appalachian Power Company;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 26, 2013

By:

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Indiana Michigan Power Company;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 26, 2013

By:

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Ohio Power Company;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 26, 2013

By:

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Public Service Company of Oklahoma;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 26, 2013

By:

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Southwestern Electric Power Company;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 26, 2013

By:

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section. This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of American Electric Power Company, Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

July 26, 2013

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Appalachian Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

July 26, 2013

A signed original of this written statement required by Section 906 has been provided to Appalachian Power Company and will be retained by Appalachian Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Indiana Michigan Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

July 26, 2013

A signed original of this written statement required by Section 906 has been provided to Indiana Michigan Power Company and will be retained by Indiana Michigan Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Ohio Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

July 26, 2013

A signed original of this written statement required by Section 906 has been provided to Ohio Power Company and will be retained by Ohio Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Public Service Company of Oklahoma (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

July 26, 2013

A signed original of this written statement required by Section 906 has been provided to Public Service Company of Oklahoma and will be retained by Public Service Company of Oklahoma and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Southwestern Electric Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

July 26, 2013

A signed original of this written statement required by Section 906 has been provided to Southwestern Electric Power Company and will be retained by Southwestern Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of American Electric Power Company, Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

July 26, 2013

Exhibit 32(b)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Appalachian Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

July 26, 2013

Exhibit 32(b)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Indiana Michigan Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

July 26, 2013

Exhibit 32(b)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Ohio Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

July 26, 2013

Exhibit 32(b)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Public Service Company of Oklahoma (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

July 26, 2013

Exhibit 32(b)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Southwestern Electric Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

July 26, 2013

Exhibit 95

MINE SAFETY INFORMATION

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. DHLC, CCPC and Conner Run received the following notices of violation and proposed assessments under the Mine Act for the quarter ended June 30, 2013:

			DHLC		CCPC		Conner Run
Number of Citations for Violations of Mandatory Health or
	Safety Standards under 104 *			-		-		-
Number of Orders Issued under 104(b) *				-		-		-
Number of Citations and Orders for Unwarrantable Failure
	to Comply with Mandatory Health or Safety Standards under
	104(d) *			-		-		-
Number of Flagrant Violations under 110(b)(2) *				-		-		-
Number of Imminent Danger Orders Issued under 107(a) *				-		-		-
Total Dollar Value of Proposed Assessments**			$	1,801	$	-	$	-
Number of Mining-related Fatalities				-		-		-

*		References to sections under the Mine Act.
**		Assessments relate to citations issued during the fourth quarter of 2012 and the first quarter of 2013.

DHLC currently has four legal actions pending before the Federal Mine Safety and Health Review Commission. Two actions are challenging four violations issued by Mine Safety and Health Administration following an employee fatality in March 2009. The third legal action is challenging a citation issued in August 2010 related to a dragline boom issue. The fourth legal action is challenging a citation issued in July 2010 related to an oil leak on a drive conveyor gear box.