AEP 10-Q Quarterly Report March 31, 2014

AMERICAN ELECTRIC POWER CO INC

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10-Q 1 q114aep10q.htm AMERICAN ELECTRIC POWER 1Q2014 10-Q Unassociated Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended March 31, 2014

[ ] 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 April 23, 2014

American Electric Power Company, Inc.			488,083,018
			($6.50 par value)
Appalachian Power Company			13,499,500
			(no par value)
Indiana Michigan Power Company			1,400,000
			(no par value)
Ohio Power Company			27,952,473
			(no par value)
Public Service Company of Oklahoma			9,013,000
			($15 par value)
Southwestern Electric Power Company			7,536,640
			($18 par value)

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF QUARTERLY REPORTS ON FORM 10-Q

March 31, 2014

			Page
			Number
Glossary of Terms			i

Forward-Looking Information			iv

Part I. FINANCIAL INFORMATION

		Items 1, 2, 3 and 4 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Controls and Procedures:

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		29
	Index of Condensed Notes to Condensed Consolidated Financial Statements		35

Appalachian Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations		74
	Condensed Consolidated Financial Statements		78
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		84

Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations		86
	Condensed Consolidated Financial Statements		90
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		96

Ohio Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations		98
	Condensed Consolidated Financial Statements		103
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		109

Public Service Company of Oklahoma:
	Management’s Narrative Discussion and Analysis of Results of Operations		111
	Condensed Financial Statements		114
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		120

Southwestern Electric Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations		122
	Condensed Consolidated Financial Statements		125
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		131

Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries			132

Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries			186

Controls and Procedures			192

Part II. OTHER INFORMATION

	Item 1.	Legal Proceedings		193
	Item 1A.	Risk Factors		193
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		194
	Item 4.	Mine Safety Disclosures		194
	Item 5.	Other Information		194
	Item 6.	Exhibits:		194
			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				195

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.
AEP System		American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP Transmission Holdco		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.
AGR		AEP Generation Resources Inc., a nonregulated AEP subsidiary in the Generation & Marketing segment.
AFUDC		Allowance for Funds Used During Construction.
AOCI		Accumulated Other Comprehensive Income.
APCo		Appalachian Power Company, an AEP electric utility subsidiary.
Appalachian Consumer Rate Relief Funding		Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
ASU		Accounting Standards Update.
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 provider		Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation 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, DCC Fuel V LLC and DCC Fuel VI 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.
ENEC		Expanded Net Energy Charge.
ERCOT		Electric Reliability Council of Texas regional transmission organization.

Term		Meaning

ESP		Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETT		Electric Transmission Texas, LLC, an equity interest joint venture between AEP and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FAC		Fuel Adjustment Clause.
FASB		Financial Accounting Standards Board.
Federal EPA		United States Environmental Protection Agency.
FERC		Federal Energy Regulatory Commission.
FGD		Flue Gas Desulfurization or scrubbers.
FTR		Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP		Accounting Principles Generally Accepted in the United States of America.
I&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 which defined the sharing of costs and benefits associated with their respective generation plants. This agreement was terminated January 1, 2014.
IRS		Internal Revenue Service.
IURC		Indiana Utility Regulatory Commission.
KGPCo		Kingsport Power Company, an AEP electric utility subsidiary.
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.
NSR		New Source Review.
OCC		Corporation Commission of the State of Oklahoma.
Ohio Phase-in-Recovery Funding		Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.
OPCo		Ohio Power Company, an AEP electric utility subsidiary.
OPEB		Other Postretirement Benefit Plans.
OTC		Over the counter.
OVEC		Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PIRR		Phase-In Recovery Rider.
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.

Term		Meaning

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 generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
RPM		Reliability Pricing Model.
RSR		Retail Stability Rider.
RTO		Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine		Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC		U.S. Securities and Exchange Commission.
SEET		Significantly Excessive Earnings Test.
SIA		System Integration Agreement, effective June 15, 2000, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF		Spent Nuclear Fuel.
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 534 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.
Texas Restructuring Legislation		Legislation enacted in 1999 to restructure the electric utility industry in Texas.
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 Legislation.
Transource Energy		Transource Energy, LLC, a consolidated variable interest entity formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.
Transource Missouri		A 100% wholly-owned subsidiary of Transource Energy.
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 2013 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.
·	Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·	Availability of necessary generation capacity and the performance of our generation plants.
·	Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·	Our ability to build or acquire generation 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.
·	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, cost recovery and/or profitability of our generation 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, alternative or distributed sources of generation.
·	Our ability to recover through rates or market prices any remaining unrecovered investment in generation 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 and the allocation of costs within regional transmission organizations, including PJM and SPP.

·	The transition to market for generation in Ohio, including the implementation of ESPs.
·	Our ability to successfully and profitably manage our separate competitive generation assets.
·	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 of such volatility 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 2013 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

Ohio Electric Security Plan Filing

2009 – 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. As of March 31, 2014, OPCo’s net deferred fuel balance was $426 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 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. This ruling was generally upheld in PUCO 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 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 OPCo RPM price, which includes reserve margins, is approximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. 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, including the RSR. As of March 31, 2014, OPCo’s incurred deferred capacity costs balance was $348 million, including debt carrying costs.

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. In February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 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. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 – 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC.

Proposed June 2015 – May 2018 ESP

application identifies OPCo’s intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. Management intends to file this application in the second quarter of 2014. A hearing at the PUCO in the ESP case is scheduled for June 2014.

If OPCo is ultimately not permitted to fully collect its ESP rates, including the RSR, its deferred fuel balance and its deferred capacity cost, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filing” section of Note 4.

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) wholesale sales, (c) deferral of unrecovered capacity costs, (d) RSR collections and (e) revenues from AEP Energy. AEP Energy is our CRES provider and part of our Generation & Marketing segment which targets retail customers, both within and outside of our retail service territory.

Customer Demand

In comparison to 2013, heating degree days in 2014 were up 40% in our western region and 24% in our eastern region. Our weather-normalized retail sales volumes for the first quarter of 2014 increased by 1.5% from their levels for the first quarter of 2013. First quarter 2014 weather-adjusted residential and commercial customer sales were up 4.4% and 2.9%, respectively, from their levels for the first quarter of 2013. Residential and commercial customer counts grew 0.4% and 0.8% in the first quarter of 2014, respectively, from the first quarter of 2013.

Our industrial sales volumes in the first quarter 2014 decreased 2.9% from the first quarter of 2013 due mainly to the closure of Ormet, a large aluminum company. Ormet had a contract to purchase power from OPCo through 2018. In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down its operations effective immediately. Excluding Ormet, our first quarter 2014 industrial sales volumes increased 2.2% over the first quarter of 2013. The loss of Ormet's load will not have a material impact on future gross margin because power previously sold to Ormet will be available for sale into generally higher priced wholesale markets.

PJM Capacity Market

Through May 2015, AGR will provide generation capacity to OPCo for both switched and non-switched OPCo generation customers. AGR is required to offer all of its remaining generation capacity in the PJM RPM auction, which is conducted three years in advance of the actual delivery year. AGR generation assets are subject to PJM capacity prices for periods after May 2015. For switched customers, OPCo pays AGR $188.88/MW day. For non-switched OPCo generation customers, OPCo pays AGR for capacity. AGR’s non-OPCo load is subject to the PJM RPM auction. Shown below are the current auction prices for capacity, as announced/settled by PJM:

	PJM Base
PJM Auction Period	Auction Price
	(per MW day)
June 2013 through May 2014	$	27.73
June 2014 through May 2015		125.99
June 2015 through May 2016		136.00
June 2016 through May 2017		59.37

Due to the volatility and uncertainty in prices, we formed a coalition with other utility companies to address mutual concerns related to the PJM capacity auction process, including: (a) import limits for power without firm transmission, (b) placing bidding caps on available demand response resources in comparison to base generation capacity, (c) modification and enforcement of the timing of demand response requirements to better reflect real-time capacity requirements and (d) tightened rules for incremental auctions in which speculative bidders currently can sell resources in the base auction and buy back that capacity in an incremental auction, resulting in no additional capacity and lower auction prices. PJM has made four FERC filings related to those issues. In January 2014, FERC

accepted without modification PJM's filed recommendations on placing bidding caps on certain demand response products that are available only during the summer period. We expect to receive FERC decisions on the other filings prior to the next RPM auction in May 2014.

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 non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional 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 4.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC. As of March 31, 2014, SWEPCo has incurred $48 million in costs related to these projects. SWEPCo will seek to recover these project costs from its state commissions and FERC customers.

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years. In April 2014, the OCC Staff and intervenors filed testimony with various recommendations. A hearing at the OCC is scheduled for June 2014. See the "2014 Oklahoma Base Rate Case" section of Note 4.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a generation and distribution base rate biennial review with the Virginia SCC. In accordance with a Virginia statute, APCo did not request an increase in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to the change in the expected service life of certain plants. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to certain deferred costs. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 Virginia Biennial Base Rate Case” section of Note 4.

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 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 March 31, 2014, I&M has incurred costs of $405 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 I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates. 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. See “Cook Plant Life Cycle Management Project (LCM Project)” section of Note 4.

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 4 – Rate Matters, Note 6 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2013 Annual Report. Additionally, see Note 4 – Rate Matters and Note 5 – 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.

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted our motion to transfer this case to the U.S. District Court for the Southern District of Ohio. Our motion to dismiss the case, filed in October 2013, is pending. We will continue to defend against the claims. We are unable to determine a range of potential losses that are reasonably possible of occurring.

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 2013 Annual Report. We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. 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 March 31, 2014, 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, investment to meet these proposed requirements ranges from approximately $3 billion to $3.5 billion through 2020. These amounts include investments to convert some of our coal generation 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. In addition, we are continuing to evaluate the economic feasibility of environmental investments on nonregulated plants.

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/AGR	Sporn Plant, Units 1-4		600
I&M	Tanners Creek Plant, Units 1-4		995
KPCo	Big Sandy Plant, Unit 2		800
AGR	Kammer Plant		630
AGR	Muskingum River Plant, Units 1-5		1,440
AGR	Picway Plant		100
PSO	Northeastern Station, Unit 4		470
SWEPCo	Welsh Plant, Unit 2		528
Total			6,533

As of March 31, 2014, the net book value of the AGR units listed above was zero. The net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the regulated plants in the table above was $974 million.

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 unit that is 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)
KPCo	Big Sandy Plant, Unit 1		278

As of March 31, 2014, the net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the unit in the table above was $88 million.

PSO received Federal EPA approval of the Oklahoma SIP, in February 2014, related to the environmental compliance plan for Northeastern Station, Unit 3.

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.

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 the Clean Air Interstate Rule (CAIR) in 2005 requiring specific reductions in SO 2 and NO x emissions from power plants. In 2008, the District of Columbia Circuit Court of Appeals issued a decision remanding CAIR to the Federal EPA. The Federal EPA issued the Cross-State Air Pollution Rule (CSAPR) (discussed in detail below) in August 2011 to replace CAIR. The CSAPR was challenged in the courts. The U.S. Court of Appeals for the District of Columbia Circuit issued an order in 2011 staying the effective date of the rule pending judicial review. In 2012, a panel of the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing CAIR until a replacement rule is finalized. That decision has been appealed to the U.S. Supreme Court. Nearly all of the states in which our power plants are located are covered by CAIR.

The Federal EPA issued the final maximum achievable control technology (MACT) standards for coal and oil-fired power plants in 2012. See “Mercury and Other Hazardous Air Pollutants (HAPs) Regulation” section below.

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas. BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. CAVR will be implemented through individual state implementation plans (SIPs) or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs). The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas. 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 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.

In 2009, the Federal EPA issued a final mandatory reporting rule for CO 2 and other greenhouse gases covering a broad range of facilities emitting in excess of 25,000 tons of CO 2 emissions per year. The Federal EPA issued a final endangerment finding for greenhouse gas emissions from new motor vehicles in 2009. The Federal EPA determined that greenhouse gas emissions from stationary sources will be subject to regulation under the CAA beginning January 2011 and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO 2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, SIP calls and FIPs. The Federal EPA has proposed to include CO 2 emissions in standards that apply to new electric utility units and will consider whether such standards are appropriate for other source categories in the future.

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 2011, the Federal EPA issued CSAPR. Certain revisions to the rule were finalized in 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 is 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 2011, the court granted the motions for stay. In 2012, the court issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the CAIR 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

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. The Federal EPA issued revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions in March 2013. The Federal EPA is still considering 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 participated 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. In April 2014, the appellate court issued a decision denying all of the petitions for review of the April 2012 final rule.

CO 2 Regulation

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. The new proposal was issued in September 2013 and requires new large natural gas units to meet 1,000 pounds of CO 2 per MWh of electricity generated and small natural gas units to meet 1,100 pounds of CO 2 per MWh. New coal-fired units are required to meet the 1,100 pounds of CO 2 per MWh limit, with the option to meet the tighter limits if they choose to average emissions over multiple years. This proposal was published in the Federal Register in January 2014.

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. The President directed the Federal EPA, in developing this proposal, 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. The U.S. Supreme Court granted several petitions for review and will determine whether the Federal EPA made a reasonable determination that adoption of the motor vehicle standards trigger PSD and Title V permitting obligations for stationary sources. A decision is expected by June 2014.

The Federal EPA also finalized a rule in June 2012 that retains the current 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 and also FGD gypsum generated at some coal fired plants. 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 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. In 2013, the Federal EPA also issued a notice of data availability requesting comments on a narrow set of issues.

Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule. The Federal EPA opposed the petition and sought additional time to coordinate the issuance of a final rule with the issuance of new effluent limitations under the Clean Water Act (CWA) for utility facilities. In October 2013, the U.S. District Court for the District of Columbia issued a final order partially ruling in favor of the Federal EPA for dismissal of two counts, ruling in favor of the environmental organizations on one count and directing the Federal EPA to provide the court with a proposed schedule for completion of the rulemaking. In January 2014, the parties filed a motion with the court to establish December 2014 as the Federal EPA’s deadline for publication of the rule. The court will establish a deadline for the final rule following a comment period for interested parties.

In February 2014, the Federal EPA completed a risk evaluation of the beneficial uses of coal fly ash in concrete and flue gas desulfurization gypsum in wallboard and concluded that the Federal EPA supports these beneficial uses. 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. We 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 expected in 2014. 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 September 2015. 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 continue to 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 submitted detailed comments to the Federal EPA in September 2013 and participated in comments filed by various organizations of which we are members.

In March 2014, the Federal EPA and the U.S. Army Corps of Engineers jointly announced that they will be issuing a proposed rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases and released a pre-publication version of the proposed rule. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This proposed jurisdictional definition will apply to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are: permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. We agree that clarity and efficiency in the permitting process is needed. We are concerned that the proposed rule introduces new concepts and could subject more of our operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. We will continue to evaluate the rule and its financial impact on the AEP System. We plan to submit comments and also participate in the preparation of comments to be filed by various organizations of which we are members.

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.

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 2013 Form 10-K under the headings entitled “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 Vertically Integrated Utilities 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.

During the fourth quarter of 2013, we changed the structure of our internal organization which resulted in a change in the composition of our reportable segments. In accordance with authoritative accounting guidance for segment reporting, prior period financial information has been recast in the financial statements and footnotes to be comparable to the current year presentation of reportable segments.

Our reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

	·	Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
	·	OPCo purchases energy to serve standard service offer customers, and provides capacity for all connected load.

AEP Transmission Holdco

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

Generation & Marketing

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

AEP River Operations

Commercial barging operation that transports liquids, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.

The table below presents Net Income (Loss) by segment for the three months ended March 31, 2014 and 2013.

		Three Months Ended March 31,
		2014		2013
		(in millions)
Vertically Integrated Utilities		$	279	$	181
Transmission and Distribution Utilities			97		87
AEP Transmission Holdco			24		12
Generation & Marketing			163		85
AEP River Operations			3		(2)
Corporate and Other (a)			(5)		1
Net Income		$	561	$	364

(a)	While not considered a reportable segment, Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

AEP CONSOLIDATED

First Quarter of 2014 Compared to First Quarter of 2013

Net Income increased from $364 million in 2013 to $561 million in 2014 primarily due to:

·	Successful rate proceedings in our various jurisdictions.
·	An increase in weather-related usage.
·	Higher market prices and increased sales volumes.

Our results of operations are discussed below by operating segment.

VERTICALLY INTEGRATED UTILITIES

	Three Months Ended
	March 31,
Vertically Integrated Utilities	2014		2013
	(in millions)
Revenues	$	2,586	$	2,515
Fuel and Purchased Electricity		1,094		1,201
Gross Margin		1,492		1,314
Other Operation and Maintenance		576		578
Depreciation and Amortization		263		235
Taxes Other Than Income Taxes		96		91
Operating Income		557		410
Interest and Investment Income		1		3
Carrying Costs Income (Expense)		(1)		1
Allowance for Equity Funds Used During Construction		10		9
Interest Expense		(131)		(136)
Income Before Income Tax Expense		436		287
Income Tax Expense		157		106
Net Income	$	279	$	181

Summary of KWh Energy Sales for Vertically Integrated Utilities

			Three Months Ended March 31,
			2014		2013
			(in millions of KWhs)
Retail:
	Residential			10,905		9,789
	Commercial			6,115		5,845
	Industrial			8,332		8,261
	Miscellaneous			555		549
Total Retail				25,907		24,444

Wholesale (a)				10,184		NM	(b)

(a)		Includes Off-system Sales, Municipalities and Cooperatives, Unit Power and Other Wholesale Customers.
(b)		2014 is not comparable to 2013 due to the 2013 asset transfers related to corporate separation as well as the termination of the pool agreement on December 31, 2013.
NM		Not meaningful.

Heating degree days and cooling 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 Vertically Integrated Utilities

		Three Months Ended March 31,
		2014		2013
		(in degree days)

Eastern Region
Actual - Heating (a)			2,128		1,705
Normal - Heating (b)			1,593		1,595

Actual - Cooling (c)			-		-
Normal - Cooling (b)			5		5

Western Region
Actual - Heating (a)			1,186		915
Normal - Heating (b)			887		890

Actual - Cooling (c)			6		10
Normal - Cooling (b)			24		24

(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 and Western Region cooling degree days are calculated on a 65 degree temperature base.

First Quarter of 2014 Compared to First Quarter of 2013


Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income from Vertically Integrated Utilities
(in millions)

First Quarter of 2013	$	181

Changes in Gross Margin:
Retail Margins		90
Off-system Sales		85
Transmission Revenues		10
Other Revenues		(7)
Total Change in Gross Margin		178

Changes in Expenses and Other:
Other Operation and Maintenance		2
Depreciation and Amortization		(28)
Taxes Other Than Income Taxes		(5)
Interest and Investment Income		(2)
Carrying Costs Income		(2)
Allowance for Equity Funds Used During Construction		1
Interest Expense		5
Total Change in Expenses and Other		(29)

Income Tax Expense		(51)

First Quarter of 2014	$	279

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 $90 million primarily due to the following:
	·	Successful rate proceedings in our service territories which include:
		·	A $26 million increase primarily due to changes in rates in West Virginia.
		·	A $24 million rate increase for SWEPCo.
		·	A $22 million rate increase for I&M.
		·	A $13 million rate increase for KPCo.
		For the rate increases described above, $26 million relates to riders/trackers which have corresponding increases in other expense items below.
	·	A $55 million increase in weather-related usage in our eastern and western regions primarily due to increases of 25% and 30%, respectively, in heating degree days.
	These increases were partially offset by:
	·	A $42 million increase in PJM expenses net of recovery or offsets.
·	Margins from Off-system Sales increased $85 million primarily due to higher market prices.
·	Transmission Revenues increased $10 million primarily due to increased investment in the PJM and SPP regions. These increased revenues are partially offset in Other Operation and Maintenance expenses below.
·	Other Revenues decreased $7 million primarily due to a decrease in barging. This decrease in barging is a result of the River Transportation Division (RTD) no longer serving Ohio plants transferred to AGR as a result of corporate separation. The decrease in RTD revenue was offset by a decrease in Other Operation and Maintenance expenses for barging.

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

·	Other Operation and Maintenance expenses decreased $2 million primarily due to the following:
	·	A $30 million write-off in 2013 of previously deferred Virginia storm costs resulting from the 2013 enactment of a Virginia law.
	·	A $12 million decrease in storm-related expenses primarily in APCo's service territory.
	These decreases were partially offset by:
	·	A $25 million increase due to a favorable settlement of an insurance claim in the first quarter of 2013.
	·	A $17 million increase in PJM and other transmission expenses.
·	Depreciation and Amortization expenses increased $28 million primarily due to overall higher depreciable property balances.
·	Interest Expense decreased $5 million primarily due to a decrease in interest on long-term debt.
·	Income Tax Expense increased $51 million primarily due to an increase in pretax book income.

TRANSMISSION AND DISTRIBUTION UTILITIES

	Three Months Ended
	March 31,
Transmission and Distribution Utilities	2014		2013
	(in millions)
Revenues	$	1,215	$	1,134
Fuel and Purchased Electricity		403		449
Amortization of Generation Deferrals		31		-
Gross Margin		781		685
Other Operation and Maintenance		293		244
Depreciation and Amortization		161		133
Taxes Other Than Income Taxes		119		104
Operating Income		208		204
Interest and Investment Income		3		1
Carrying Costs Income		7		3
Allowance for Equity Funds Used During Construction		3		2
Interest Expense		(70)		(75)
Income Before Income Tax Expense		151		135
Income Tax Expense		54		48
Net Income	$	97	$	87

Summary of KWh Energy Sales for Transmission and Distribution Utilities

			Three Months Ended March 31,
			2014		2013
Retail:
	Residential			7,527		6,466
	Commercial			5,902		5,706
	Industrial			5,143		5,500
	Miscellaneous			171		160
Total Retail (a)				18,743		17,832

Wholesale (b)				700		NM	(c)

(a)		Represents energy delivered to distribution customers.
(b)		Includes Off-system Sales, Municipalities and Cooperatives, Unit Power and Other Wholesale Customers.
(c)		2014 is not comparable to 2013 due to the 2013 asset transfers related to corporate separation as well as the termination of the pool agreement on December 31, 2013.
NM		Not meaningful.

Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities

		Three Months Ended March 31,
		2014		2013
		(in degree days)

Eastern Region
Actual - Heating (a)			2,409		1,971
Normal - Heating (b)			1,880		1,885

Actual - Cooling (c)			-		-
Normal - Cooling (b)			3		3

Western Region
Actual - Heating (a)			300		135
Normal - Heating (b)			196		201

Actual - Cooling (d)			70		137
Normal - Cooling (b)			108		105

(a)	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 70 degree temperature base.

First Quarter of 2014 Compared to First Quarter of 2013


Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income from Transmission and Distribution Utilities
(in millions)

First Quarter of 2013	$	87

Changes in Gross Margin:
Retail Margins		73
Transmission Revenues		14
Other Revenues		9
Total Change in Gross Margin		96

Changes in Expenses and Other:
Other Operation and Maintenance		(49)
Depreciation and Amortization		(28)
Taxes Other Than Income Taxes		(15)
Interest and Investment Income		2
Carrying Costs Income		4
Allowance for Equity Funds Used During Construction		1
Interest Expense		5
Total Change in Expenses and Other		(80)

Income Tax Expense		(6)

First Quarter of 2014	$	97

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:

·	Retail Margins increased $73 million primarily due to the following:
	·	A $29 million increase for TCC and TNC primarily due to a 325% and 39% increase in heating degree days, respectively.
	·	An $17 million increase primarily due to increased connected load for OPCo and corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
	·	A $15 million increase in revenues associated with the Distribution Investment Recovery Rider and Universal Service Fund (USF) surcharge. Of these increases, $10 million relate to riders/trackers which have corresponding increases in other expense items below.
·	Transmission Revenues increased $14 million primarily due to increased transmission revenues from Ohio customers who switched to alternative CRES providers and rate increases for customers in the PJM region.
·	Other Revenues increased $9 million primarily due to increased Texas securitization revenues.

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

·	Other Operation and Maintenance expenses increased $49 million primarily due to the following:
	·		A $27 million increase primarily due to PJM and ERCOT expenses. This increase is offset by an increase in Retail Margins above.
	·		An $8 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 is offset by an increase in Retail Margins above.
	·		An $8 million increase in distribution expenses.
	·		A $5 million increase in storm-related expenses primarily in OPCo's service territory.
·	Depreciation and Amortization expenses increased $28 million primarily related to the following:
	·	A $19 million increase in amortization related to TCC and OPCo securitizations.
	·	A $4 million increase for OPCo due to carrying charge adjustments as a result of expensing certain gridSMART ® capital projects.
	·	A $3 million increase due to an increase in depreciable base of transmission and distribution assets.
·	Taxes Other Than Income Taxes increased $15 million primarily due to increased property taxes.
·	Income Tax Expense increased $6 million primarily due to an increase in pretax book income.

AEP TRANSMISSION HOLDCO

First Quarter of 2014 Compared to First Quarter of 2013

Net Income from our AEP Transmission Holdco segment increased from $12 million in 2013 to $24 million in 2014 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT.

GENERATION & MARKETING

		Three Months Ended
		March 31,
	Generation & Marketing	2014		2013
		(in millions)
Revenues		$	1,251	$	920
Fuel, Purchased Electricity and Other			805		568
Gross Margin			446		352
Other Operation and Maintenance			116		124
Depreciation and Amortization			57		62
Taxes Other Than Income Taxes			12		16
Operating Income			261		150
Interest and Investment Income			1		-
Interest Expense			(12)		(19)
Income Before Income Tax Expense			250		131
Income Tax Expense			87		46
Net Income		$	163	$	85

Summary of MWhs Generated for Generation & Marketing

		Three Months Ended March 31,
		2014		2013
		(in millions of MWhs)
Fuel Type:
	Coal		12		10
	Natural Gas		2		2
Total MWhs			14		12

First Quarter of 2014 Compared to First Quarter of 2013


Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income from Generation & Marketing
(in millions)

First Quarter of 2013	$	85

Changes in Gross Margin:
Generation		97
Retail, Trading and Marketing		(3)
Total Change in Gross Margin		94

Changes in Expenses and Other:
Other Operation and Maintenance		8
Depreciation and Amortization		5
Taxes Other Than Income Taxes		4
Interest and Investment Income		1
Interest Expense		7
Total Change in Expenses and Other		25

Income Tax Expense		(41)

First Quarter of 2014	$	163

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, purchased electricity and certain costs of service for retail operations were as follows:

·	Generation increased $94 million primarily due to increases in demand and market prices driven by cold temperatures in 2014.

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

·	Other Operation and Maintenance expenses decreased $8 million primarily due to a reduction in employee related expenses.
·	Depreciation and Amortization expenses decreased $5 million primarily due to the cessation of depreciation on Muskingum River Plant, Unit 5.
·	Interest Expense decreased $7 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·	Income Tax Expense increased $41 million primarily due to an increase in pretax book income.

AEP RIVER OPERATIONS

First Quarter of 2014 Compared to First Quarter of 2013

Net Income from our AEP River Operations segment increased from a loss of $2 million in 2013 to income of $3 million in 2014, due to improvements in river conditions as well as improvements in grain export demand.

CORPORATE AND OTHER

First Quarter of 2014 Compared to First Quarter of 2013

Net Income from Corporate and Other decreased from income of $1 million in 2013 to a loss of $5 million in 2014 primarily due to an increase in net interest.

AEP SYSTEM INCOME TAXES

First Quarter of 2014 Compared to First Quarter of 2013

Income Tax Expense increased $112 million primarily due to an increase in pretax book income.

FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

	March 31, 2014				December 31, 2013
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	18,087	50.5	%	$	18,377	52.2	%
Short-term Debt		1,332	3.7			757	2.1
Total Debt		19,419	54.2			19,134	54.3
AEP Common Equity		16,416	45.8			16,085	45.7
Noncontrolling Interests		3	-			1	-

Total Debt and Equity Capitalization	$	35,838	100.0	%	$	35,220	100.0	%

Our ratio of debt-to-total capital declined from 54.3% as of December 31, 2013 to 54.2% as of March 31, 2014 primarily due to an increase in our common equity from 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 March 31, 2014, we had $3.5 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.

Commercial Paper Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. As of March 31, 2014, our available liquidity was approximately $3 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
Total			3,500
Cash and Cash Equivalents			292
Total Liquidity Sources			3,792
Less:	AEP Commercial Paper Outstanding		632
	Letters of Credit Issued		130

Net Available Liquidity		$	3,030

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 three months of 2014 was $691 million. The weighted-average interest rate for our commercial paper during 2014 was 0.28%.

Other Credit Facilities

In January 2014, we issued letters of credit under an $85 million uncommitted facility signed in October 2013. As of March 31, 2014, the maximum future payment for letters of credit issued under the uncommitted facility was $75 million with a maturity in July 2014. An uncommitted facility gives the issuer of the facility the right to accept or decline each request we make under the facility.

Securitized Accounts Receivable

Our receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2014. The remaining commitment of $315 million expires in June 2015. We intend to extend or replace the agreement expiring in June 2014 on or before its maturity.

Debt Covenants and Borrowing Limitations

Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually defined in our credit agreements. Debt as defined in the revolving credit agreements excludes securitization bonds and debt of AEP Credit. As of March 31, 2014, this contractually-defined percentage was 50.6%. Nonperformance under these covenants could result in an event of default under these credit agreements. As of March 31, 2014, 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. This condition also applies in a majority of our non-exchange traded commodity contracts and would similarly allow 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 credit agreements.

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

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders. As of March 31, 2014, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.50 per share in April 2014. 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 primarily 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.

	Three Months Ended
	March 31,
	2014		2013
	(in millions)
Cash and Cash Equivalents at Beginning of Period	$	118	$	279
Net Cash Flows from Operating Activities		1,133		756
Net Cash Flows Used for Investing Activities		(981)		(772)
Net Cash Flows from (Used for) Financing Activities		22		(84)
Net Increase (Decrease) in Cash and Cash Equivalents		174		(100)
Cash and Cash Equivalents at End of Period	$	292	$	179

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

Operating Activities


	Three Months Ended
	March 31,
	2014		2013
	(in millions)
Net Income	$	561	$	364
Depreciation and Amortization		491		420
Other		81		(28)
Net Cash Flows from Operating Activities	$	1,133	$	756

Net Cash Flows from Operating Activities were $1.1 billion in 2014 consisting primarily of Net Income of $561 million and $491 million of noncash Depreciation and Amortization partially offset by $137 million of fuel cost deferrals and $56 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. The reduction in Fuel, Material and Supplies balances reflects a decrease in fuel inventory due to the cold winter weather and increased generation.

Net Cash Flows from Operating Activities were $756 million in 2013 consisting primarily of Net Income of $364 million and $420 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. Net cash outflows for Accrued Taxes were a result of recording the estimated federal tax loss for tax/book temporary differences.

Investing Activities


	Three Months Ended
	March 31,
	2014		2013
	(in millions)
Construction Expenditures	$	(907)	$	(843)
Acquisitions of Nuclear Fuel		(49)		(47)
Acquisitions of Assets/Businesses		(43)		(2)
Insurance Proceeds Related to Cook Plant Fire		-		72
Other		18		48
Net Cash Flows Used for Investing Activities	$	(981)	$	(772)

Net Cash Flows Used for Investing Activities were $981 million in 2014 primarily due to Construction Expenditures for environmental, distribution and transmission investments. We also purchased transmission assets for $38 million.

Net Cash Flows Used for Investing Activities were $772 million in 2013 primarily due to Construction Expenditures for environmental, distribution and transmission investments.

Financing Activities


	Three Months Ended
	March 31,
	2014		2013
	(in millions)
Issuance of Common Stock, Net	$	15	$	15
Issuance of Debt, Net		281		139
Dividends Paid on Common Stock		(245)		(230)
Other		(29)		(8)
Net Cash Flows from (Used for) Financing Activities	$	22	$	(84)

Net Cash Flows from Financing Activities in 2014 were $22 million. Our net debt issuances were $281 million. The net issuances included issuances of $76 million of other debt notes and an increase in short-term borrowing of $575 million offset by retirements of $258 million of senior unsecured and other debt notes and $112 million of securitization bonds. We paid common stock dividends of $245 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 2013 were $84 million. Our net debt issuances were $139 million. The net issuances included issuances of $475 million of senior unsecured notes, a $200 million draw on a $1 billion term credit facility and an increase in short-term borrowing of $326 million offset by retirements of $753 million of senior unsecured and other debt notes and $105 million of securitization bonds. We paid common stock dividends of $230 million.

In April 2014, I&M retired $13 million of Notes Payable related to DCC Fuel.

BUDGETED CONSTRUCTION EXPENDITURES

In April 2014, we increased our forecast for construction expenditures by $250 million to approximately $4.1 billion for 2014. The increase is primarily for transmission investment in the AEP Transmission Holdco, Vertically Integrated Utilities and Transmission and Distribution Utilities segments.

OFF-BALANCE SHEET ARRANGEMENTS

Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that we enter in the normal course of business. The following identifies significant off-balance sheet arrangements:

	March 31,		December 31,
	2014		2013
	(in millions)
Rockport Plant, Unit 2 Future Minimum Lease Payments	$	1,330	$	1,330
Railcars Maximum Potential Loss from Lease Agreement		19		19

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 2013 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2013 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 2013 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

Pronouncements Effective in the Future

The FASB issued ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. We plan to adopt ASU 2014-08 effective January 1, 2015.

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 Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through its transactions in power, coal, natural gas 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 Transmission and Distribution Utilities segment is exposed to FTR price risk as it relates to congestion during the June 2012 – May 2015 Ohio ESP period. Additional risk includes interest rate risk.

Our Generation & 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. In addition, our Generation & Marketing segment is also exposed to certain market risks as a major power producer and through its transactions in wholesale electricity, natural gas and coal trading and marketing contracts.

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, natural gas and, to a lesser extent, heating oil, gasoline 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, Energy Supply, 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 (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, and Chief Risk Officer in addition to AEP Energy Supply’s President and Vice President. When commercial activities exceed predetermined limits, we modify the positions to reduce the risk to be within the limits unless specifically approved by the respective committee.

The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2013:

	MTM Risk Management Contract Net Assets (Liabilities)
	Three Months Ended March 31, 2014

				Transmission
		Vertically		and		Generation
		Integrated		Distribution		and
		Utilities		Utilities		Marketing		Total
		(in millions)
Total MTM Risk Management Contract Net Assets
	as of December 31, 2013	$	32	$	3	$	157	$	192
Gain from Contracts Realized/Settled During
	the Period and Entered in a Prior Period		(6)		(3)		(16)		(25)
Fair Value of New Contracts at Inception When Entered
	During the Period (a)		-		-		5		5
Net Option Premiums Paid for Unexercised or Unexpired
	Option Contracts Entered During the Period		-		-		1		1
Changes in Fair Value Due to Market Fluctuations
	During the Period (b)		-		-		11		11
Changes in Fair Value Allocated to Regulated
	Jurisdictions (c)		10		4		-		14
Total MTM Risk Management Contract Net Assets
	as of March 31, 2014	$	36	$	4	$	158		198

Commodity Cash Flow Hedge Contracts									8
Interest Rate and Foreign Currency Cash Flow Hedge
	Contracts								(2)
Fair Value Hedge Contracts									(8)
Collateral Deposits									(2)
Total MTM Derivative Contract Net Assets as of
	March 31, 2014							$	194

(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 March 31, 2014, our credit exposure net of collateral to sub investment grade counterparties was approximately 9.2%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss). As of March 31, 2014, 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		$	528	$	10	$	518		2	$	256
Split Rating			-		-		-		-		-
Noninvestment Grade			1		1		-		-		-
No External Ratings:
	Internal Investment Grade		70		-		70		4		41
	Internal Noninvestment Grade		70		11		59		3		43
Total as of March 31, 2014		$	669	$	22	$	647		9	$	340

Total as of December 31, 2013		$	787	$	18	$	769		9	$	381

In addition, we are exposed to credit risk related to our participation in RTOs. For each of the RTOs in which we participate, this risk is generally determined based on our proportionate share of member gross activity over a specified period of time.

Value at Risk (VaR) Associated with Risk Management Contracts

We use a risk measurement model, which calculates VaR, to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of March 31, 2014, 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

Three Months Ended								Twelve Months Ended
March 31, 2014								December 31, 2013
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	1	$	3	$	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 several 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, Regulated Risk Committee, or Competitive Risk Committee as appropriate.

Interest Rate Risk

We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which our interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. As calculated on debt outstanding as of March 31, 2014 and December 31, 2013, the estimated EaR on our debt portfolio for the following twelve months was $33 million and $32 million, respectively.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2014 and 2013
(in millions, except per-share and share amounts)
(Unaudited)

		Three Months Ended March 31,
		2014		2013
REVENUES
Vertically Integrated Utilities		$	2,549	$	2,356
Transmission and Distribution Utilities			1,161		1,090
Generation & Marketing			821		258
Other Revenues			117		122
TOTAL REVENUES			4,648		3,826
EXPENSES
Fuel and Other Consumables Used for Electric Generation			1,168		1,031
Purchased Electricity for Resale			638		371
Other Operation			780		738
Maintenance			292		293
Depreciation and Amortization			491		420
Taxes Other Than Income Taxes			238		218
TOTAL EXPENSES			3,607		3,071

OPERATING INCOME			1,041		755

Other Income (Expense):
Interest and Investment Income			1		3
Carrying Costs Income			6		4
Allowance for Equity Funds Used During Construction			22		15
Interest Expense			(220)		(232)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS			850		545

Income Tax Expense			307		195
Equity Earnings of Unconsolidated Subsidiaries			18		14

NET INCOME			561		364

Net Income Attributable to Noncontrolling Interests			1		1

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	560	$	363

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING			487,867,089		485,823,668

TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
	SHAREHOLDERS	$	1.15	$	0.75

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING			488,271,167		486,344,036

TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
	SHAREHOLDERS	$	1.15	$	0.75

CASH DIVIDENDS DECLARED PER SHARE		$	0.50	$	0.47

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 35.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2014 and 2013
(in millions)
(Unaudited)

		Three Months Ended March 31,
		2014		2013
Net Income		$	561	$	364

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $3 and $13 in 2014 and 2013, Respectively			5		24
Securities Available for Sale, Net of Tax of $- and $1 in 2014 and 2013, Respectively			-		1
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $- and $3 in 2014
	and 2013, Respectively		1		6

TOTAL OTHER COMPREHENSIVE INCOME			6		31

TOTAL COMPREHENSIVE INCOME			567		395

Total Comprehensive Income Attributable to Noncontrolling Interests			1		1

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
	COMMON SHAREHOLDERS	$	566	$	394

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 35.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Three Months Ended March 31, 2014 and 2013
(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, 2012		506	$	3,289	$	6,049	$	6,236	$	(337)	$	-	$	15,237

Issuance of Common Stock				2		13								15
Common Stock Dividends								(229)				(1)		(230)
Other Changes in Equity						4								4
Net Income								363				1		364
Other Comprehensive Income										31				31
TOTAL EQUITY – MARCH 31, 2013		506	$	3,291	$	6,066	$	6,370	$	(306)	$	-	$	15,421

TOTAL EQUITY – DECEMBER 31, 2013		508	$	3,303	$	6,131	$	6,766	$	(115)	$	1	$	16,086

Issuance of Common Stock				2		13								15
Common Stock Dividends								(244)				(1)		(245)
Other Changes in Equity								(6)				2		(4)
Net Income								560				1		561
Other Comprehensive Income										6				6
TOTAL EQUITY – MARCH 31, 2014		508	$	3,305	$	6,144	$	7,076	$	(109)	$	3	$	16,419

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 35.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2014 and December 31, 2013
(in millions)
(Unaudited)

			March 31,		December 31,
			2014		2013
CURRENT ASSETS
Cash and Cash Equivalents			$	292	$	118
Other Temporary Investments
	(March 31, 2014 and December 31, 2013 Amounts Include $293 and $335, Respectively, Related to Transition Funding, Phase-in-Recovery Funding, Consumer Rate Relief Funding and EIS)			310		353
Accounts Receivable:
	Customers			785		746
	Accrued Unbilled Revenues			143		157
	Pledged Accounts Receivable - AEP Credit			1,015		945
	Miscellaneous			66		72
	Allowance for Uncollectible Accounts			(66)		(60)
		Total Accounts Receivable		1,943		1,860
Fuel				490		701
Materials and Supplies				724		722
Risk Management Assets				125		160
Regulatory Asset for Under-Recovered Fuel Costs				175		80
Margin Deposits				117		70
Prepayments and Other Current Assets				159		246
TOTAL CURRENT ASSETS				4,335		4,310

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			25,174		25,074
	Transmission			11,014		10,893
	Distribution			16,518		16,377
Other Property, Plant and Equipment (Including Plant to be Retired, Coal Mining
	and Nuclear Fuel)			5,552		5,470
Construction Work in Progress				2,836		2,471
Total Property, Plant and Equipment				61,094		60,285
Accumulated Depreciation and Amortization				19,564		19,288
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				41,530		40,997

OTHER NONCURRENT ASSETS
Regulatory Assets				4,384		4,376
Securitized Assets				2,308		2,373
Spent Nuclear Fuel and Decommissioning Trusts				1,962		1,932
Goodwill				91		91
Long-term Risk Management Assets				266		297
Deferred Charges and Other Noncurrent Assets				2,162		2,038
TOTAL OTHER NONCURRENT ASSETS				11,173		11,107

TOTAL ASSETS			$	57,038	$	56,414

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 35.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 2014 and December 31, 2013
(dollars in millions)
(Unaudited)

					March 31,		December 31,
					2014		2013
CURRENT LIABILITIES
Accounts Payable					$	1,213	$	1,266
Short-term Debt:
	Securitized Debt for Receivables - AEP Credit					700		700
	Other Short-term Debt					632		57
		Total Short-term Debt				1,332		757
Long-term Debt Due Within One Year
	(March 31, 2014 and December 31, 2013 Amounts Include $449 and $416, Respectively, Related to Transition Funding, DCC Fuel, Phase-in-Recovery Funding, Consumer Rate Relief Funding and Sabine)					1,612		1,549
Risk Management Liabilities						60		90
Customer Deposits						302		299
Accrued Taxes						803		822
Accrued Interest						220		245
Regulatory Liability for Over-Recovered Fuel Costs						60		119
Other Current Liabilities						917		965
TOTAL CURRENT LIABILITIES						6,519		6,112

NONCURRENT LIABILITIES
Long-term Debt
	(March 31, 2014 and December 31, 2013 Amounts Include $2,388 and $2,532, Respectively, Related to Transition Funding, DCC Fuel, Phase-in-Recovery Funding, Consumer Rate Relief Funding, Transource Energy and Sabine)					16,475		16,828
Long-term Risk Management Liabilities						137		177
Deferred Income Taxes						10,446		10,300
Regulatory Liabilities and Deferred Investment Tax Credits						3,765		3,694
Asset Retirement Obligations						1,853		1,835
Employee Benefits and Pension Obligations						456		415
Deferred Credits and Other Noncurrent Liabilities						968		967
TOTAL NONCURRENT LIABILITIES						34,100		34,216

TOTAL LIABILITIES						40,619		40,328

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

EQUITY
Common Stock – Par Value – $6.50 Per Share:
			2014	2013
	Shares Authorized		600,000,000	600,000,000
	Shares Issued		508,397,086	508,113,964
(20,336,592 Shares were Held in Treasury as of March 31, 2014 and December 31, 2013)						3,305		3,303
Paid-in Capital						6,144		6,131
Retained Earnings						7,076		6,766
Accumulated Other Comprehensive Income (Loss)						(109)		(115)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY						16,416		16,085

Noncontrolling Interests						3		1

TOTAL EQUITY						16,419		16,086

TOTAL LIABILITIES AND EQUITY					$	57,038	$	56,414

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 35.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2014 and 2013
(in millions)
(Unaudited)

			Three Months Ended March 31,
			2014		2013
OPERATING ACTIVITIES
Net Income			$	561	$	364
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			491		420
	Deferred Income Taxes			299		246
	Carrying Costs Income			(6)		(4)
	Allowance for Equity Funds Used During Construction			(22)		(15)
	Mark-to-Market of Risk Management Contracts			6		34
	Amortization of Nuclear Fuel			38		34
	Property Taxes			(54)		(51)
	Fuel Over/Under-Recovery, Net			(137)		(4)
	Deferral of Ohio Capacity Costs, Net			(56)		(49)
	Change in Other Noncurrent Assets			(25)		36
	Change in Other Noncurrent Liabilities			77		17
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		(83)		(4)
		Fuel, Materials and Supplies		209		(1)
		Accounts Payable		33		(3)
		Accrued Taxes, Net		(16)		(69)
		Other Current Assets		(51)		(16)
		Other Current Liabilities		(131)		(179)
Net Cash Flows from Operating Activities				1,133		756

INVESTING ACTIVITIES
Construction Expenditures				(907)		(843)
Change in Other Temporary Investments, Net				44		75
Purchases of Investment Securities				(165)		(196)
Sales of Investment Securities				148		168
Acquisitions of Nuclear Fuel				(49)		(47)
Acquisitions of Assets/Businesses				(43)		(2)
Insurance Proceeds Related to Cook Plant Fire				-		72
Other Investing Activities				(9)		1
Net Cash Flows Used for Investing Activities				(981)		(772)

FINANCING ACTIVITIES
Issuance of Common Stock, Net				15		15
Issuance of Long-term Debt				76		671
Commercial Paper and Credit Facility Borrowings				-		17
Change in Short-term Debt, Net				575		329
Retirement of Long-term Debt				(370)		(858)
Commercial Paper and Credit Facility Repayments				-		(20)
Principal Payments for Capital Lease Obligations				(33)		(16)
Dividends Paid on Common Stock				(245)		(230)
Other Financing Activities				4		8
Net Cash Flows from (Used for) Financing Activities				22		(84)

Net Increase (Decrease) in Cash and Cash Equivalents				174		(100)
Cash and Cash Equivalents at Beginning of Period				118		279
Cash and Cash Equivalents at End of Period			$	292	$	179

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	234	$	253
Net Cash Paid (Received) for Income Taxes				(6)		(19)
Noncash Acquisitions Under Capital Leases				20		24
Construction Expenditures Included in Current Liabilities as of March 31,				387		300

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 35.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Page
	Number

Significant Accounting Matters	36
New Accounting Pronouncement	37
Comprehensive Income	37
Rate Matters	39
Commitments, Guarantees and Contingencies	46
Benefit Plans	49
Business Segments	50
Derivatives and Hedging	52
Fair Value Measurements	58
Income Taxes	65
Financing Activities	66
Variable Interest Entities	68

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. SIGNIFICANT ACCOUNTING MATTERS

General

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

In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods. Net income for the three months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2013 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 25, 2014.

Revenue Recognition

Electricity Supply and Delivery Activities – Transactions with PJM

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. For regulated and nonregulated operations, we recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.

APCo, I&M and KPCo sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary’s retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenue on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices.

AEP’s nonregulated subsidiaries also purchase power from PJM and sell power to PJM. With the exception of certain dedicated load bilateral power supply contracts, these transactions are reported as gross purchases and sales.

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 table presents our basic and diluted EPS calculations included on our condensed statements of income:

		Three Months Ended March 31,
		2014				2013
		(in millions, except per share data)
				$/share				$/share
Earnings Attributable to AEP Common Shareholders		$	560			$	363

Weighted Average Number of Basic Shares Outstanding			487.9	$	1.15		485.8	$	0.75
Weighted Average Dilutive Effect of:
	Restricted Stock Units		0.4		-		0.5		-
Weighted Average Number of Diluted Shares Outstanding			488.3	$	1.15		486.3	$	0.75

There were no antidilutive shares outstanding as of March 31, 2014 and 2013.

2. NEW ACCOUNTING PRONOUNCEMENT

Upon issuance of final pronouncements, we review the new accounting literature to determine its relevance, if any, to our business. The following summary of a final pronouncement will impact our financial statements.

ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08)

In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of our financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. We plan to adopt ASU 2014-08 effective January 1, 2015.

3. COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 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 March 31, 2014

		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, 2013		$	-	$	(23)	$	7	$	(99)	$	(115)
Change in Fair Value Recognized in AOCI			(14)		-		-		-		(14)
Amounts Reclassified from AOCI			18		1		-		1		20
Net Current Period Other
	Comprehensive Income		4		1		-		1		6
Balance in AOCI as of March 31, 2014		$	4	$	(22)	$	7	$	(98)	$	(109)

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 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			18		3		1		-		22
Amounts Reclassified from AOCI			2		1		-		6		9
Net Current Period Other
	Comprehensive Income		20		4		1		6		31
Balance in AOCI as of March 31, 2013		$	12	$	(26)	$	5	$	(297)	$	(306)

Reclassifications from Accumulated Other Comprehensive Income

The following table provides details of reclassifications from AOCI for the three months ended March 31, 2014 and 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 March 31, 2014 and 2013

		Amount of (Gain) Loss
		Reclassified from AOCI

		Three Months Ended March 31,
		2014		2013
Gains and Losses on Cash Flow Hedges		(in millions)
Commodity:
	Vertically Integrated Utilities Revenues	$	-	$	-
	Generation & Marketing Revenues		-		(3)
	Purchased Electricity for Resale		31		6
	Property, Plant and Equipment		-		-
	Regulatory Assets/(Liabilities), Net (a)		(3)		-
Subtotal - Commodity			28		3

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

Reclassifications from AOCI, before Income Tax (Expense) Credit			30		5
Income Tax (Expense) Credit			11		2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit			19		3

Gains and Losses on Securities Available for Sale
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			-		-

Pension and OPEB
Amortization of Prior Service Cost (Credit)			(5)		(5)
Amortization of Actuarial (Gains)/Losses			7		14
Reclassifications from AOCI, before Income Tax (Expense) Credit			2		9
Income Tax (Expense) Credit			1		3
Reclassifications from AOCI, Net of Income Tax (Expense) Credit			1		6

Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	20	$	9

(a)

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

4. RATE MATTERS

As discussed in the 2013 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2013 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 2014 and updates the 2013 Annual Report.

Regulatory Assets Not Yet Being Recovered

		March 31,		December 31,
		2014		2013
Noncurrent Regulatory Assets		(in millions)
Regulatory assets not yet being recovered pending future proceedings:

Regulatory Assets Currently Earning a Return
	Storm Related Costs	$	21	$	22
	Ohio Economic Development Rider		-		14
	Other Regulatory Assets Not Yet Being Recovered		-		4
Regulatory Assets Currently Not Earning a Return
	Storm Related Costs		104		161
	Indiana Under-Recovered Capacity Costs		28		22
	IGCC Pre-Construction Costs		21		-
	Expanded Net Energy Charge - Coal Inventory		19		21
	Mountaineer Carbon Capture and Storage Product Validation Facility		13		13
	Ormet Special Rate Recovery Mechanism		10		36
	Other Regulatory Assets Not Yet Being Recovered		34		37
Total Regulatory Assets Not Yet Being Recovered		$	250	$	330

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 Filings

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 March 31, 2014, OPCo’s net deferred fuel balance was $426 million, excluding unrecognized equity carrying costs. In February 2014, the Supreme Court of Ohio affirmed the PUCO’s decision and rejected all appeals filed by the OCC and the IEU. In February 2014, the IEU filed for reconsideration of the Supreme Court of Ohio decision.

In August 2012, the PUCO issued an order in a separate proceeding which implemented a 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 related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate. In November 2012, the IEU and the OCC filed appeals regarding

the PUCO decision in the PIRR proceeding. These appeals principally argued that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo’s net deferred fuel balance up to the total balance. These intervenors’ appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of March 31, 2014, could reduce carrying costs by $30 million including $16 million of unrecognized equity carrying costs. 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

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

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. As of March 31, 2014, OPCo’s incurred deferred capacity costs balance of $348 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

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 expenses 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, including the RSR.

In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. As ordered, in February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 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. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 – 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC.

Proposed June 2015 – May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider, effective June 2015 through May 2018. This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to market. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation

through OPCo. Additionally, the application identifies OPCo’s intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. Management intends to file this application in the second quarter of 2014. A hearing at the PUCO in the ESP case is scheduled for June 2014.

Significantly Excessive Earnings Test (SEET) Filings

In January 2011, the PUCO issued an order on the 2009 SEET filing. The 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. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In November 2013, OPCo filed its 2011 SEET filing with the PUCO. OPCo was required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. In March 2014, the PUCO approved a stipulation agreement between OPCo and the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2011 for CSPCo or OPCo.

In November 2013, OPCo filed its 2012 SEET filing with the PUCO. In April 2014, OPCo entered into a stipulation agreement with the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2012 for OPCo. A hearing at the PUCO related to the 2012 SEET filing is scheduled for April 2014. Management does not believe that there were significantly excessive earnings in 2013 for OPCo.

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 and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo’s generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition.

Storm Damage Recovery Rider (SDRR)

In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates to recover 2012 incremental storm distribution expenses over twelve months starting with the effective date as approved by the PUCO. In December 2013, a stipulation agreement was reached between OPCo, the PUCO staff and all intervenors except the OCC. The stipulation agreement recommended approval to recover $55 million related to 2012 storm costs over a 12-month period which included a $6 million reduction in the amount of 2012 storm expenses to be recovered. The agreement also provided that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period. In April 2014, the PUCO approved the settlement agreement. Compliance tariffs were filed with the PUCO and new rates were implemented in April 2014.

2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo’s 2009 FAC 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. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 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. 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 with the use of a weighted average cost of capital (WACC). The PUCO subsequently ruled in the PIRR proceeding that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes. Hearings at the PUCO were held in November 2013. 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. See the 2009 – 2011 ESP section of the “Ohio Electric Security Plan Filing” related to the PUCO order in the PIRR proceeding.

2012 – 2013 Fuel Adjustment Clause Audits

In April 2014, the PUCO-selected outside consultant provided its preliminary draft report related to their 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. If the PUCO orders a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition.

Ormet

Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware. In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down operations effective immediately. Based upon previous PUCO rulings providing rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider (EDR), except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet’s October and November 2012 power bills. OPCo expects that any additional unpaid generation usage by Ormet will be recoverable as a regulatory asset through the EDR. In February 2014, a stipulation agreement between OPCo and Ormet was filed with the PUCO. The stipulation recommends approval of OPCo’s right to fully recover approximately $49 million of foregone revenues through the EDR which, as of March 31, 2014, is recorded in regulatory assets on the balance sheet. Also in February 2014, intervenor comments were filed objecting to full recovery of these foregone revenues. In March 2014, the PUCO issued an order in OPCo’s EDR filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement is scheduled for May 2014.

In addition, in the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. 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. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.

To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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 March 31, 2014, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting that OPCo refund all collected pre-construction costs to Ohio ratepayers with interest.

Management cannot predict the outcome of this proceeding concerning the Ohio IGCC plant or what effect, if any, this proceeding 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

2012 Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In October 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of March 31, 2014, the net book value of Welsh Plant, Unit 2 was $86 million, before cost of removal, including materials and supplies inventory and CWIP.

Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase is approximately $52 million. In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling. This order became final and appealable in April 2014.

If any part of the PUCT order is overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs of Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

2013 Texas Transmission Cost Recovery Factor Filing

In December 2013, SWEPCo filed an application to implement its initial transmission cost recovery factor (TCRF) requesting additional annual revenue of $10 million. The TCRF is designed to recover increases from the amounts included in SWEPCo’s Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC. SWEPCo’s application included Turk Plant transmission-related costs. In March 2014, the Administrative Law Judge (ALJ) dismissed this case without prejudice. The ALJ concluded that SWEPCo’s application was premature as the PUCT had not completed its ruling on the motions for rehearing of the order in the SWEPCo Texas Base Rate Case in which the baseline values to be used in the TCRF calculation would be established.

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. The rates are subject to refund based on the staff review of the cost of service and the prudency 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 non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional 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.

2014 Louisiana Formula Rate Filing

purchase power agreement attributable to Louisiana customers. These increases are subject to LPSC staff review. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

APCo and WPCo Rate Matters

Plant Transfer

In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo. In April 2014, APCo and WPCo also filed a request with the FERC for approval to transfer AGR’s one-half interest in the Mitchell Plant to WPCo. Upon transfer of the Mitchell Plant to WPCo, WPCo will no longer purchase power from AGR.

APCo IGCC Plant

As of March 31, 2014, 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. In March 2014, APCo submitted a request to the Virginia SCC as part of the 2014 Virginia Biennial Base Rate Case to amortize the Virginia jurisdictional share of these costs over two years. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Transmission Rate Adjustment Clause (transmission RAC)

In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually to be effective May 2014. In March 2014, the Virginia SCC issued an order approving a stipulation agreement between APCo and the Virginia SCC staff increasing the transmission RAC revenues by $49 million annually, subject to true-up, effective May 2014. Pursuant to the order, the Virginia SCC staff will audit APCo’s transmission RAC under-recoveries and report its findings and recommendations in testimony in APCo’s next transmission RAC proceeding in 2015.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a generation and distribution base rate biennial review with the Virginia SCC. In accordance with a Virginia statute, APCo did not request a change in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to changes in the expected service lives of various generating units and the extended recovery through 2040 of the net book value of certain planned 2015 plant retirements. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to certain deferred costs. A hearing at the Virginia SCC is scheduled for September 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

PSO Rate Matters

2014 Oklahoma Base Rate Case

recommendations did not support the advanced metering rider or the expansion of the transmission rider. A hearing at the OCC is scheduled for June 2014. If the OCC were to disallow any portion of this base rate request, it could reduce future net income and cash flows and impact financial condition.

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% and adjusted the authorized annual increase in base rates to $92 million in March 2013. In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the order with the Indiana Court of Appeals. In March 2014, the Indiana Court of Appeals upheld the February 2013 IURC order. In April 2014, the OUCC filed an appeal to the Indiana Supreme Court related to the inclusion of a prepaid pension asset in rate base. If any part of the IURC order is overturned by the Indiana Supreme Court, it could reduce future net income and cash flows.

Cook Plant Life Cycle Management Project (LCM Project)

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 I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC.

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.

Tanners Creek Plant, Units 1 - 4

In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations. In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas. I&M is currently recovering depreciation and a return on the net book value of the Tanners Creek Plant in base rates and plans to seek recovery of all of the plant’s retirement related costs in its next Indiana and Michigan base rate cases.

In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015. Upon the retirement of the Tanners Creek Plant, I&M proposes that the net book value of the Tanners Creek Plant will be recovered over the remaining life of the Rockport Plant. I&M requested to have the impact of these new depreciation rates incorporated into the rates set in its next rate case. The new depreciation rates are expected to result in a decrease in I&M’s Michigan jurisdictional electric depreciation expense which I&M proposes to implement in the month following a MPSC order in the revised depreciation case. A hearing at the MPSC is scheduled for September 2014.

As of March 31, 2014, the net book value of the Tanners Creek Plant was $334 million, before cost of removal, including materials and supplies inventory and CWIP. If I&M is ultimately not permitted to fully recover its net book value of the Tanners Creek Plant and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition.

KPCo Rate Matters

Plant Transfer

In October 2012, the AEP East Companies submitted several filings with the FERC. 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. KPCo also requested that costs related to the Big Sandy Plant, Unit 2 FGD project be established as a regulatory asset. As of March 31, 2014, the net book value of Big Sandy Plant, Unit 2 was $247 million, before cost of removal, including materials and supplies inventory and CWIP.

In October 2013, the KPSC issued an order approving a modified settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club. The modified settlement approved the transfer of a one-half interest in the Mitchell Plant to KPCo at net book value on December 31, 2013 with the limitation that the net book value of the Mitchell Plant transfer not exceed the amount to be determined by a WVPSC order. The WVPSC order was subsequently issued in December 2013, but the WVPSC deferred a decision on the transfer of the one-half interest in the Mitchell Plant to APCo. The settlement also included the implementation of an Asset Transfer Rider to collect $44 million annually effective January 2014, subject to true-up, and allowed KPCo to retain any off-system sales margins above the $15.3 million annual level in base rates. Additionally, the settlement allows for KPCo to file a Certificate of Public Convenience and Necessity to convert Big Sandy Plant, Unit 1 to natural gas, provided the cost is approximately $60 million, and addressed potential greenhouse gas initiatives on the Mitchell Plant. The settlement also approved recovery, including a return, of coal-related retirement costs related to Big Sandy Plant over 25 years when base rates are set in the next base rate case (no earlier than June 2015), but rejected KPCo’s request to defer FGD project costs for Big Sandy Plant, Unit 2. As a result of this order, in 2013, KPCo recorded a pretax regulatory disallowance of $33 million in Asset Impairments and Other Related Charges on the statement of income. In December 2013, the Attorney General filed an appeal with the Franklin County Circuit Court. In December 2013, KPCo filed motions with the Franklin County Circuit Court to dismiss the appeal. A hearing on the motions to dismiss was held in January 2014. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed. If any part of the KPSC order is overturned, it could reduce future net income and cash flows and impact financial condition.

5. 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 2013 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 revolving credit facilities totaling $3.5 billion, under which we may issue up to $1.2 billion as letters

of credit. As of March 31, 2014, the maximum future payments for letters of credit issued under the revolving credit facilities were $130 million with maturities ranging from June 2014 to April 2015.

We have $352 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $356 million. The letters of credit have maturities ranging from July 2014 to March 2017.

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 March 31, 2014, SWEPCo has collected approximately $62 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $46 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. As of March 31, 2014, 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 March 31, 2014, the maximum potential loss for these lease agreements was approximately $21 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 March 31, 2014.

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

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 generation 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 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 $8 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.

OPERATIONAL CONTINGENCIES

Rockport Plant Litigation

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. That motion was denied. We are considering seeking a review of this issue by the U.S. Supreme Court. Defendants in these cases, including AEP, previously filed a petition seeking further review with the U.S. Supreme Court on the preemption issue, which is pending. We will continue to defend the cases. We believe the provision we have is adequate. We are unable to determine a range of potential losses that are reasonably possible of occurring.

Wage and Hours Lawsuit

In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount.

In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. We will continue to defend the case. We are unable to determine a range of potential losses that are reasonably possible of occurring.

6. BENEFIT PLANS

Components of Net Periodic Benefit Cost

The following table provides the components of our net periodic benefit cost (credit) for the plans for the three months ended March 31, 2014 and 2013:

					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended March 31,				Three Months Ended March 31,
	2014		2013		2014		2013
	(in millions)
Service Cost	$	18	$	17	$	4	$	6
Interest Cost		55		50		17		18
Expected Return on Plan Assets		(66)		(69)		(28)		(27)
Amortization of Prior Service Cost (Credit)		1		1		(17)		(17)
Amortization of Net Actuarial Loss		31		46		5		16
Net Periodic Benefit Cost (Credit)	$	39	$	45	$	(19)	$	(4)

7. BUSINESS SEGMENTS

Our reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

·	Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

·	Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.

·	OPCo purchases energy to serve standard service offer customers, and provides capacity for all connected load.

AEP Transmission Holdco

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

Generation & Marketing

·	Nonregulated generation in ERCOT and PJM.

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

AEP River Operations

·	Commercial barging operation that transports liquids, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.

The remainder of our activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. This segment also 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 months ended March 31, 2014 and 2013 and balance sheet information as of March 31, 2014 and December 31, 2013. These amounts include certain estimates and allocations where necessary.

					Transmission
		Vertically			and		AEP		Generation					Corporate
		Integrated			Distribution		Transmission		&			AEP River		and Other		Reconciling
		Utilities			Utilities		Holdco		Marketing			Operations		(a)		Adjustments			Consolidated
		(in millions)
Three Months Ended March 31, 2014
Revenues from:
	External Customers	$	2,549	(b)	$	1,161	$	12	$	821	(b)	$	146	$	10	$	(51)	(c)	$	4,648
	Other Operating Segments		37	(b)		54		16		430	(b)		19		16		(572)			-
Total Revenues		$	2,586		$	1,215	$	28	$	1,251		$	165	$	26	$	(623)		$	4,648

Net Income (Loss)		$	279		$	97	$	24	$	163		$	3	$	(5)	$	-		$	561

					Transmission
		Vertically			and		AEP		Generation					Corporate
		Integrated			Distribution		Transmission		&			AEP River		and Other		Reconciling
		Utilities			Utilities		Holdco		Marketing			Operations		(a)		Adjustments			Consolidated
		(in millions)
Three Months Ended March 31, 2013
Revenues from:
	External Customers	$	2,356		$	1,090	$	3	$	258		$	128	$	5	$	(14)	(c)	$	3,826
	Other Operating Segments		159			44		5		662			5		13		(888)			-
Total Revenues		$	2,515		$	1,134	$	8	$	920		$	133	$	18	$	(902)		$	3,826

Net Income (Loss)		$	181		$	87	$	12	$	85		$	(2)	$	1	$	-		$	364

					Transmission
		Vertically			and		AEP		Generation					Corporate		Reconciling
		Integrated			Distribution		Transmission		&			AEP River		and Other		Adjustments
		Utilities			Utilities		Holdco		Marketing			Operations		(a)		(d)			Consolidated
		(in millions)
March 31, 2014
Total Property, Plant and Equipment		$	37,923		$	12,339	$	1,842	$	8,302		$	639	$	321	$	(272)		$	61,094
Accumulated Depreciation and
	Amortization		12,424			3,382		13		3,460			197		176		(88)			19,564
Total Property, Plant and
	Equipment - Net	$	25,499		$	8,957	$	1,829	$	4,842		$	442	$	145	$	(184)		$	41,530

Total Assets		$	32,997		$	13,899	$	2,460	$	6,354		$	659	$	20,275	$	(19,606)	(e)	$	57,038

					Transmission
		Vertically			and		AEP		Generation					Corporate		Reconciling
		Integrated			Distribution		Transmission		&			AEP River		and Other		Adjustments
		Utilities			Utilities		Holdco		Marketing			Operations		(a)		(d)			Consolidated
		(in millions)
December 31, 2013
Total Property, Plant and Equipment		$	37,545		$	12,143	$	1,636	$	8,277		$	638	$	315	$	(269)		$	60,285
Accumulated Depreciation and
	Amortization		12,250			3,342		10		3,409			189		173		(85)			19,288
Total Property, Plant and
	Equipment - Net	$	25,295		$	8,801	$	1,626	$	4,868		$	449	$	142	$	(184)		$	40,997

Total Assets		$	32,791		$	14,165	$	2,245	$	6,426		$	673	$	19,645	$	(19,531)	(e)	$	56,414

(a)

Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

(b)	Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014.

(c)	Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation.

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

(e)	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, natural gas, 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 extent, heating oil, gasoline 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 March 31, 2014 and December 31, 2013:

Notional Volume of Derivative Instruments

		Volume
		March 31,		December 31,		Unit of
		2014		2013		Measure
Primary Risk Exposure		(in millions)
Commodity:
	Power		320		406	MWhs
	Coal		4		4	Tons
	Natural Gas		123		127	MMBtus
	Heating Oil and Gasoline		4		6	Gallons
	Interest Rate	$	192	$	191	USD

Interest Rate and Foreign Currency		$	819	$	820	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 and natural gas (“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. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014. During the three months ended March 31, 2013, we designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. 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 March 31, 2014 and December 31, 2013 condensed balance sheets, we netted $19 million and $4 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $17 million and $13 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 March 31, 2014 and December 31, 2013:

Fair Value of Derivative Instruments
March 31, 2014

									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		$	442	$	23	$	4	$	469	$	(344)	$	125
Long-term Risk Management Assets			342		5		-		347		(81)		266
Total Assets			784		28		4		816		(425)		391

Current Risk Management Liabilities			384		16		1		401		(341)		60
Long-term Risk Management Liabilities			205		4		13		222		(85)		137
Total Liabilities			589		20		14		623		(426)		197

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	195	$	8	$	(10)	$	193	$	1	$	194

Fair Value of Derivative Instruments
December 31, 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		$	347	$	12	$	4	$	363	$	(203)	$	160
Long-term Risk Management Assets			368		3		-		371		(74)		297
Total Assets			715		15		4		734		(277)		457

Current Risk Management Liabilities			292		11		1		304		(214)		90
Long-term Risk Management Liabilities			237		3		15		255		(78)		177
Total Liabilities			529		14		16		559		(292)		267

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	186	$	1	$	(12)	$	175	$	15	$	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 months ended March 31, 2014 and 2013:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended March 31, 2014 and 2013

Location of Gain (Loss)	2014			2013
	(in millions)
Vertically Integrated Utilities Revenues	$	18	$	6
Generation & Marketing Revenues		32		16
Regulatory Assets (a)		-		2
Regulatory Liabilities (a)		89		(6)
Total Gain on Risk Management Contracts	$	139	$	18

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

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

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

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

Accounting for Fair Value Hedging Strategies

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

We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our condensed statements of income. During the three months ended March 31, 2014, we recognized gains of $2 million on our hedging instruments and offsetting losses of $2 million on our long-term debt. During the three months ended March 31, 2013, we recognized losses of $1 million on our hedging instruments and offsetting gains of $1 million on our long-term debt. During the three months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, we designated power, coal and natural gas derivatives as cash flow hedges.

We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our condensed statements of income. During the three months ended March 31, 2013, we designated heating oil and gasoline derivatives as cash flow hedges. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Interest Expense on our condensed statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2014 and 2013, we designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Depreciation and Amortization expense on our condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 2014 and 2013, we did not designate any foreign currency derivatives as cash flow hedges.

During the three months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, see Note 3.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 2014 and December 31, 2013 were:

Impact of Cash Flow Hedges on the Condensed Balance Sheet
March 31, 2014

				Interest Rate
				and Foreign
		Commodity		Currency		Total
		(in millions)
Hedging Assets (a)		$	13	$	-	$	13
Hedging Liabilities (a)			5		2		7
AOCI Gain (Loss) Net of Tax			4		(22)		(18)
Portion Expected to be Reclassified to Net
	Income During the Next Twelve Months		3		(4)		(1)

Impact of Cash Flow Hedges on the Condensed Balance Sheet
December 31, 2013

				Interest Rate
				and Foreign
		Commodity		Currency		Total
		(in millions)
Hedging Assets (a)		$	7	$	-	$	7
Hedging Liabilities (a)			6		2		8
AOCI Gain (Loss) Net of Tax			-		(23)		(23)
Portion Expected to be Reclassified to Net
	Income During the Next Twelve Months		-		(4)		(4)

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

The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. As of March 31, 2014, 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 was 41 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), a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, and guaranties for contractual obligations, we are obligated to post an additional amount of collateral if our credit ratings decline below a specified rating threshold. 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 a specified rating threshold that would require the posting of additional collateral. 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 and guaranties for contractual obligations if our credit ratings had declined below a specified rating threshold and (c) how much was attributable to RTO and ISO activities as of March 31, 2014 and December 31, 2013:

		March 31,		December 31,
		2014		2013
		(in millions)
Liabilities for Derivative Contracts with Credit Downgrade Triggers		$	2	$	3
Amount of Collateral AEP Subsidiaries Would Have Been
	Required to Post		144		33
Amount Attributable to RTO and ISO Activities			38		28

In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts. The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of March 31, 2014 and December 31, 2013:

	March 31,		December 31,
	2014		2013
	(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual
Netting Arrangements	$	225	$	293
Amount of Cash Collateral Posted		-		1
Additional Settlement Liability if Cross Default Provision is Triggered		177		235

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 amount of risk taken is determined by the Commercial Operations, Energy Supply 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 (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to AEP Energy Supply’s President and Vice President.

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 March 31, 2014 and December 31, 2013 are summarized in the following table:

	March 31, 2014				December 31, 2013
	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
Long-term Debt	$	18,087	$	19,738	$	18,377	$	19,672

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:

			March 31, 2014
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
Other Temporary Investments			Cost		Gains		Losses		Value
			(in millions)
Restricted Cash (a)			$	206	$	-	$	-	$	206
Fixed Income Securities:
	Mutual Funds			80		-		-		80
Equity Securities - Mutual Funds				13		11		-		24
Total Other Temporary Investments			$	299	$	11	$	-	$	310

			December 31, 2013
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
Other Temporary Investments			Cost		Gains		Losses		Value
			(in millions)
Restricted Cash (a)			$	250	$	-	$	-	$	250
Fixed Income Securities:
	Mutual Funds			80		-		-		80
Equity Securities - Mutual Funds				12		11		-		23
Total Other Temporary Investments			$	342	$	11	$	-	$	353

(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 months ended March 31, 2014 and 2013:

	Three Months Ended March 31,
	2014		2013
	(in millions)
Proceeds from Investment Sales	$	-	$	-
Purchases of Investments		1		11
Gross Realized Gains on Investment Sales		-		-
Gross Realized Losses on Investment Sales		-		-

As of March 31, 2014 and December 31, 2013, we had no Other Temporary Investments with an unrealized loss position. As of March 31, 2014, fixed income securities were 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 months ended March 31, 2014 and 2013, see Note 3.

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 March 31, 2014 and December 31, 2013:

		March 31, 2014						December 31, 2013
		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		$	12	$	-	$	-	$	19	$	-	$	-
Fixed Income Securities:
	United States Government		606		31		(4)		609		26		(4)
	Corporate Debt		43		4		(1)		37		2		(1)
	State and Local Government		281		1		-		255		1		-
	Subtotal Fixed Income Securities		930		36		(5)		901		29		(5)
Equity Securities - Domestic			1,020		514		(80)		1,012		506		(82)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,962	$	550	$	(85)	$	1,932	$	535	$	(87)

The following table provides the securities activity within the decommissioning and SNF trusts for the three months ended March 31, 2014 and 2013:

	Three Months Ended March 31,
	2014		2013
	(in millions)
Proceeds from Investment Sales	$	148	$	168
Purchases of Investments		164		185
Gross Realized Gains on Investment Sales		8		3
Gross Realized Losses on Investment Sales		1		2

The adjusted cost of fixed income securities was $894 million and $872 million as of March 31, 2014 and December 31, 2013, respectively. The adjusted cost of equity securities was $506 million and $506 million as of March 31, 2014 and December 31, 2013, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2014 was as follows:

	Fair Value of
	Fixed Income
	Securities
	(in millions)
Within 1 year	$	82
1 year – 5 years		386
5 years – 10 years		193
After 10 years		269
Total	$	930

Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 and December 31, 2013. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in our valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2014

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

Cash and Cash Equivalents (a)			$	16	$	1	$	-	$	275	$	292

Other Temporary Investments
Restricted Cash (a)				187		7		-		12		206
Fixed Income Securities:
	Mutual Funds			80		-		-		-		80
Equity Securities - Mutual Funds (b)				24		-		-		-		24
Total Other Temporary Investments				291		7		-		12		310

Risk Management Assets
Risk Management Commodity Contracts (c) (d)				20		586		128		(364)		370
Cash Flow Hedges:
	Commodity Hedges (c)			-		21		2		(10)		13
Fair Value Hedges				-		2		-		2		4
De-designated Risk Management Contracts (e)				-		-		-		4		4
Total Risk Management Assets				20		609		130		(368)		391

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (f)				3		-		-		9		12
Fixed Income Securities:
	United States Government			-		606		-		-		606
	Corporate Debt			-		43		-		-		43
	State and Local Government			-		281		-		-		281
		Subtotal Fixed Income Securities		-		930		-		-		930
Equity Securities - Domestic (b)				1,020		-		-		-		1,020
Total Spent Nuclear Fuel and Decommissioning Trusts				1,023		930		-		9		1,962

Total Assets			$	1,350	$	1,547	$	130	$	(72)	$	2,955

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)			$	30	$	485	$	25	$	(362)	$	178
Cash Flow Hedges:
	Commodity Hedges (c)			-		15		-		(10)		5
	Interest Rate/Foreign Currency Hedges			-		2		-		-		2
Fair Value Hedges				-		10		-		2		12
Total Risk Management Liabilities			$	30	$	512	$	25	$	(370)	$	197

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013

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

Cash and Cash Equivalents (a)			$	16	$	1	$	-	$	101	$	118

Other Temporary Investments
Restricted Cash (a)				231		8		-		11		250
Fixed Income Securities:
	Mutual Funds			80		-		-		-		80
Equity Securities - Mutual Funds (b)				23		-		-		-		23
Total Other Temporary Investments				334		8		-		11		353

Risk Management Assets
Risk Management Commodity Contracts (c) (g)				22		549		142		(273)		440
Cash Flow Hedges:
	Commodity Hedges (c)			-		15		-		(8)		7
Fair Value Hedges				-		1		-		3		4
De-designated Risk Management Contracts (e)				-		-		-		6		6
Total Risk Management Assets				22		565		142		(272)		457

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (f)				8		-		-		11		19
Fixed Income Securities:
	United States Government			-		609		-		-		609
	Corporate Debt			-		37		-		-		37
	State and Local Government			-		255		-		-		255
		Subtotal Fixed Income Securities		-		901		-		-		901
Equity Securities - Domestic (b)				1,012		-		-		-		1,012
Total Spent Nuclear Fuel and Decommissioning Trusts				1,020		901		-		11		1,932

Total Assets			$	1,392	$	1,475	$	142	$	(149)	$	2,860

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)			$	30	$	475	$	22	$	(282)	$	245
Cash Flow Hedges:
	Commodity Hedges (c)			-		11		3		(8)		6
	Interest Rate/Foreign Currency Hedges			-		2		-		-		2
Fair Value Hedges				-		11		-		3		14
Total Risk Management Liabilities			$	30	$	499	$	25	$	(287)	$	267

(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 March 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $2 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $32 million in 2014, $56 million in periods 2015-2017, $8 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $15 million in 2014, $49 million in periods 2015-2017, $16 million in periods 2018-2019 and $23 million in periods 2020-2030. 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, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $4 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $25 million in 2014, $37 million in periods 2015-2017, $7 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $27 million in 2014, $60 million in periods 2015-2017, $14 million in periods 2018-2019 and $19 million in periods 2020-2030. Risk management commodity contracts are substantially comprised of power contracts.

There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 and 2013.

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

		Net Risk Management
Three Months Ended March 31, 2014		Assets (Liabilities)
		(in millions)
Balance as of December 31, 2013		$	117
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)			84
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		(10)
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			9
Purchases, Issuances and Settlements (c)			(100)
Transfers into Level 3 (d) (e)			(4)
Transfers out of Level 3 (e) (f)			(2)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			11
Balance as of March 31, 2014		$	105

		Net Risk Management
Three Months Ended March 31, 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)			(4)
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			1
Purchases, Issuances and Settlements (c)			(6)
Transfers into Level 3 (d) (e)			6
Transfers out of Level 3 (e) (f)			-
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			(2)
Balance as of March 31, 2013		$	76

(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 tables quantify the significant unobservable inputs used in developing the fair value of our Level 3 positions as of March 31, 2014 and December 31, 2013:

Significant Unobservable Inputs
March 31, 2014

	Fair Value				Valuation	Significant	Input/Range
	Assets		Liabilities		Technique	Unobservable Input	Low		High
	(in millions)
Energy Contracts	$	116	$	23	Discounted Cash Flow	Forward Market Price (a)	$	1.45	$	131.46
						Counterparty Credit Risk (b)	315
FTRs		14		2	Discounted Cash Flow	Forward Market Price (a)		(5.05)		9.17
Total	$	130	$	25

Significant Unobservable Inputs
December 31, 2013

	Fair Value				Valuation	Significant	Input/Range
	Assets		Liabilities		Technique	Unobservable Input	Low		High
	(in millions)
Energy Contracts	$	132	$	22	Discounted Cash Flow	Forward Market Price (a)	$	11.42	$	120.72
						Counterparty Credit Risk (b)	316
FTRs		10		3	Discounted Cash Flow	Forward Market Price (a)		(5.10)		10.44
Total	$	142	$	25

(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 IRS examination of years 2011 and 2012 started in April 2014. 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. We are currently under examination in several state and local jurisdictions. However, it is possible 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 that 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 2009.

11. FINANCING ACTIVITIES

Long-term Debt

The following table details long-term debt outstanding as of March 31, 2014 and December 31, 2013:

Type of Debt	March 31, 2014		December 31, 2013
	(in millions)
Senior Unsecured Notes	$	11,571	$	11,799
Pollution Control Bonds		1,932		1,932
Notes Payable		342		369
Securitization Bonds		2,574		2,686
Spent Nuclear Fuel Obligation (a)		265		265
Other Long-term Debt		1,434		1,360
Fair Value of Interest Rate Hedges		(7)		(9)
Unamortized Discount, Net		(24)		(25)
Total Long-term Debt Outstanding		18,087		18,377
Long-term Debt Due Within One Year		1,612		1,549
Long-term Debt	$	16,475	$	16,828

(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 $309 million and $309 million as of March 31, 2014 and December 31, 2013, 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 three months of 2014 are shown in the tables below:

				Principal			Interest
Company		Type of Debt		Amount			Rate	Due Date
Issuances:			(in millions)				(%)
PSO		Other Long-term Debt		$	50		Variable	2016

Non-Registrant:
Transource Missouri		Other Long-term Debt			27		Variable	2018
Total Issuances				$	77	(a)

				Principal			Interest
Company		Type of Debt		Amount Paid			Rate	Due Date
Retirements and			(in millions)				(%)
	Principal Payments:
I&M		Notes Payable		$	5		Variable	2016
I&M		Notes Payable			4		2.12	2016
I&M		Notes Payable			5		Variable	2016
I&M		Notes Payable			10		Variable	2017
I&M		Other Long-term Debt			2		Variable	2015
OPCo		Senior Unsecured Notes			225		4.85	2014
SWEPCo		Notes Payable			2		4.58	2032

Non-Registrant:
AEGCo		Senior Unsecured Notes			4		6.33	2037
AEP Subsidiaries		Notes Payable			1		Variable	2017
TCC		Securitization Bonds			72		5.09	2015
TCC		Securitization Bonds			40		6.25	2016
Total Retirements and
	Principal Payments			$	370

(a)	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.

In April 2014, I&M retired $13 million of Notes Payable related to DCC Fuel.

As of March 31, 2014, trustees held on our behalf, $500 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 primarily 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:

	March 31, 2014				December 31, 2013
	Outstanding		Interest		Outstanding		Interest
Type of Debt	Amount		Rate (a)		Amount		Rate (a)
	(in millions)				(in millions)
Securitized Debt for Receivables (b)	$	700	0.24	%	$	700	0.23	%
Commercial Paper		632	0.31	%		57	0.29	%
Total Short-term Debt	$	1,332			$	757

(a)	Weighted average rate.

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

Credit Facilities

For an additional discussion of credit facilities, see “Letters of Credit” section of Note 5.

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
	March 31,
	2014			2013
	(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable		0.24	%		0.23	%
Net Uncollectible Accounts Receivable Written Off	$	8		$	7

		March 31,		December 31,
		2014		2013
		(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
	Less Uncollectible Accounts	$	997	$	929
Total Principal Outstanding			700		700
Delinquent Securitized Accounts Receivable			55		45
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable			17		16
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable			278		331

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

Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended March 31, 2014 and 2013 were $39 million and $44 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 II 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 March 31, 2014 and 2013 were $25 million and $26 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. In October 2013, the lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC. 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 concluded that we are the primary beneficiary and are required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the condensed balance sheets. See “Securitized Accounts Receivables – 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 billion and $2 billion as of March 31, 2014 and December 31, 2013, respectively. Transition Funding has securitized transition assets of $1.8 billion and $1.9 billion as of March 31, 2014 and December 31, 2013, respectively. 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.

Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $267 million and $267 million as of March 31, 2014 and December 31, 2013, respectively. Ohio Phase-in-Recovery Funding has securitized assets of $127 million and $132 million as of March 31, 2014 and December 31, 2013, respectively. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding's assets and liabilities on the condensed balance sheets.

$380 million as of March 31, 2014 and December 31, 2013, respectively. Appalachian Consumer Rate Relief Funding has securitized assets of $365 million and $369 million as of March 31, 2014 and December 31, 2013, respectively. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding's assets and liabilities on the condensed balance sheets.

The securitized bonds of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in current and long-term debt on the condensed balance sheets. The securitized assets of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in securitized assets 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 EIS. Our insurance premium expense to the protected cell for the three months ended March 31, 2014 and 2013 was $16 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.

Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity. AEP's equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. In January 2014, Transource Missouri acquired transmission assets from the non-controlling owner and issued debt and received capital contributions to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, debt issuance and capital contribution. See the table below for the classification of Transource Energy’s assets and liabilities on the condensed balance sheets.

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

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
March 31, 2014
(in millions)

														APCo
											OPCo			Appalachian
											Ohio			Consumer
								TCC			Phase-in-			Rate			Protected
		SWEPCo		I&M		AEP		Transition			Recovery			Relief			Cell		Transource
		Sabine		DCC Fuel		Credit		Funding			Funding			Funding			of EIS		Energy
ASSETS
Current Assets		$	62	$	109	$	1,004	$	166		$	36		$	16		$	152	$	4
Net Property, Plant and
	Equipment		154		129		-		-			-			-			-		57
Other Noncurrent Assets			50		45		-		1,861	(a)		242	(b)		374	(c)		3		5
Total Assets		$	266	$	283	$	1,004	$	2,027		$	278		$	390		$	155	$	66

LIABILITIES AND EQUITY
Current Liabilities		$	29	$	100	$	894	$	304		$	60		$	28		$	48	$	18
Noncurrent Liabilities			236		183		1		1,705			217			360			67		28
Equity			1		-		109		18			1			2			40		20
Total Liabilities and Equity		$	266	$	283	$	1,004	$	2,027		$	278		$	390		$	155	$	66

(a)	Includes an intercompany item eliminated in consolidation of $81 million.

(b)	Includes an intercompany item eliminated in consolidation of $112 million.

(c)	Includes an intercompany item eliminated in consolidation of $4 million.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2013
(in millions)

													APCo
										OPCo			Appalachian
										Ohio			Consumer
							TCC			Phase-in-			Rate
	SWEPCo		I&M		AEP		Transition			Recovery			Relief			Protected Cell
	Sabine		DCC Fuel		Credit		Funding			Funding			Funding			of EIS
ASSETS
Current Assets	$	67	$	118	$	935	$	232		$	23		$	6		$	143
Net Property, Plant and Equipment		157		157		-		-			-			-			-
Other Noncurrent Assets		51		60		1		1,918	(a)		252	(b)		378	(c)		3
Total Assets	$	275	$	335	$	936	$	2,150		$	275		$	384		$	146

LIABILITIES AND EQUITY
Current Liabilities	$	33	$	108	$	827	$	312		$	37		$	14		$	39
Noncurrent Liabilities		242		227		1		1,820			237			368			66
Equity		-		-		108		18			1			2			41
Total Liabilities and Equity	$	275	$	335	$	936	$	2,150		$	275		$	384		$	146

(a)	Includes an intercompany item eliminated in consolidation of $82 million.
(b)	Includes an intercompany item eliminated in consolidation of $116 million.
(c)	Includes an intercompany item eliminated in consolidation of $4 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 March 31, 2014 and 2013 were $2 million and $18 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:

	March 31, 2014				December 31, 2013
	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		2		2		1		1
SWEPCo's Guarantee of Debt		-		85		-		61

Total Investment in DHLC	$	10	$	95	$	9	$	70

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 September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project’s abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case have been unable to reach a settlement agreement. In March 2014, the settlement judge recommended termination of the settlement proceedings and this case is expected to proceed to a hearing.

Our investment in PATH-WV was:

	March 31, 2014					December 31, 2013
	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		6			6		6		6

Total Investment in PATH-WV	$	25		$	25	$	25	$	25

As of March 31, 2014, our $25 million investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheet. If we cannot ultimately recover our investment related to PATH-WV, it could reduce future net income and cash flows.

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 Transfer

In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo. Management anticipates an order related to the proposed plant transfer will be issued in the fourth quarter of 2014. In April 2014, APCo and WPCo also filed a request with the FERC for approval to transfer AGR’s one-half interest in the Mitchell Plant to WPCo. Upon transfer of the Mitchell Plant to WPCo, WPCo will no longer purchase power from AGR.

WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting authority 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 merger. Also 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. In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo. In December 2013, the WVPSC issued an order that deferred ruling on the merger of WPCo into APCo. The feasibility of the merger remains under review. See the “WPCo Merger with APCo” section of APCo Rate Matters in Note 4.

2014 Virginia Biennial Base Rate Case

Litigation and Environmental Issues

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 132. 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 186 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWh Sales/Degree Days


Summary of KWh Energy Sales

		Three Months Ended March 31,
		2014		2013
		(in millions of KWhs)
Retail:
	Residential		4,362		4,001
	Commercial		1,780		1,742
	Industrial		2,492		2,588
	Miscellaneous		222		217
Total Retail			8,856		8,548

Wholesale			1,071		2,281

Total KWhs			9,927		10,829

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

Summary of Heating and Cooling Degree Days

		Three Months Ended March 31,
		2014		2013
		(in degree days)

Actual - Heating (a)			1,715		1,404
Normal - Heating (b)			1,311		1,312

Actual - Cooling (c)			-		-
Normal - Cooling (b)			7		7

(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.

First Quarter of 2014 Compared to First Quarter of 2013

Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income
(in millions)

First Quarter of 2013	$	71

Changes in Gross Margin:
Retail Margins		35
Off-system Sales		1
Transmission Revenues		4
Other Revenues		11
Total Change in Gross Margin		51

Changes in Expenses and Other:
Other Operation and Maintenance		25
Depreciation and Amortization		(17)
Taxes Other Than Income Taxes		(4)
Carrying Costs Income		(2)
Other Income		1
Interest Expense		(4)
Total Change in Expenses and Other		(1)

Income Tax Expense		(19)

First Quarter of 2014	$	102

·	Retail Margins increased $35 million primarily due to the following:
	·	A $27 million increase primarily due to a 22% increase in heating degree days.
	·	A $26 million increase primarily due to changes in rates in West Virginia. Of these increases, $10 million relate to riders/trackers which have corresponding increases in other expense items below.
	·	A $19 million decrease in capacity settlement due to the termination of the Interconnection Agreement.
	·	A $6 million decrease in other variable electric generation expenses.
	These increases were partially offset by:
	·	A $13 million increase in PJM expenses.
	·	A $10 million decrease due to increased sales of renewable energy credits in 2014. This decrease is offset in Other Revenues.
	·	A $7 million increase in expense due to the timing of fuel recovery.
	·	A $4 million decrease primarily due to lower industrial usage.
·	Transmission Revenues increased $4 million primarily due to increased investments in the PJM region. These increased revenues are offset in Other Operation and Maintenance expenses below.
·	Other Revenues increased $11 million primarily due to increased sales of renewable energy credits. This increase in revenues is mainly offset in Retail Margins in fuel recovery.

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

·	Other Operation and Maintenance expenses decreased $25 million primarily due to the following:
	·	A $30 million write-off in the first quarter of 2013 of previously deferred Virginia storm costs resulting from the 2013 enactment of a Virginia law.
	·	A $15 million decrease in distribution maintenance expense primarily due to the January 2013 snow storm.
	These decreases were partially offset by:
	·	A $6 million increase in transmission expenses due to increased investment in the PJM region. These expenses are partially offset in Transmission Revenues.
	·	A $5 million increase in steam operation and maintenance expenses.
	·	A $2 million increase in employee-related expenses.
·	Depreciation and Amortization expenses increased $17 million primarily due to:
	·	An $11 million increase primarily due to higher depreciable base.
	·	A $3 million increase due to over-recovery of revenues for securitization.
·	Taxes Other Than Income Taxes expenses increased $4 million primarily due to:
	·	A $2 million increase in state business occupation tax and state minimum tax accruals.
	·	A $1 million increase in real and personal property taxes amortization.
·	Interest Expense increased $4 million primarily due to the issuance of securitization bonds and the assumption of debt related to corporate separation.
·	Income Tax Expense increased $19 million primarily due to an increase in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2013 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 186 for a discussion of accounting pronouncements.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

	Three Months Ended March 31,
	2014		2013
REVENUES
Electric Generation, Transmission and Distribution	$	866,457	$	872,732
Sales to AEP Affiliates		44,914		76,860
Other Revenues		2,020		1,902
TOTAL REVENUES		913,391		951,494

EXPENSES
Fuel and Other Consumables Used for Electric Generation		230,737		204,939
Purchased Electricity for Resale		168,991		65,456
Purchased Electricity from AEP Affiliates		4,662		222,942
Other Operation		93,538		78,908
Maintenance		60,090		99,386
Depreciation and Amortization		104,586		87,903
Taxes Other Than Income Taxes		30,777		27,400
TOTAL EXPENSES		693,381		786,934

OPERATING INCOME		220,010		164,560

Other Income (Expense):
Interest Income		401		331
Carrying Costs Income (Expense)		(1,875)		103
Allowance for Equity Funds Used During Construction		1,235		770
Interest Expense		(51,672)		(48,204)

INCOME BEFORE INCOME TAX EXPENSE		168,099		117,560

Income Tax Expense		66,248		47,012

NET INCOME	$	101,851	$	70,548

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

		Three Months Ended March 31,
		2014		2013
Net Income		$	101,851	$	70,548

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $132 and $677 in 2014 and 2013, Respectively			246		1,258
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $179 and $193
	in 2014 and 2013, Respectively		(333)		358

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			(87)		1,616

TOTAL COMPREHENSIVE INCOME		$	101,764	$	72,164

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

								Accumulated
								Other
		Common		Paid-in		Retained		Comprehensive
		Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2012	$	260,458	$	1,573,752	$	1,248,250	$	(29,898)	$	3,052,562

Common Stock Dividends							(50,000)				(50,000)
Net Income							70,548				70,548
Other Comprehensive Income									1,616		1,616
TOTAL COMMON SHAREHOLDER'S
	EQUITY – MARCH 31, 2013	$	260,458	$	1,573,752	$	1,268,798	$	(28,282)	$	3,074,726

TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2013	$	260,458	$	1,809,562	$	1,156,461	$	2,951	$	3,229,432

Common Stock Dividends							(20,000)				(20,000)
Net Income							101,851				101,851
Other Comprehensive Loss									(87)		(87)
TOTAL COMMON SHAREHOLDER'S
	EQUITY – MARCH 31, 2014	$	260,458	$	1,809,562	$	1,238,312	$	2,864	$	3,311,196

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2014 and December 31, 2013
(in thousands)
(Unaudited)

			March 31,		December 31,
			2014		2013
CURRENT ASSETS
Cash and Cash Equivalents			$	4,758	$	2,745
Advances to Affiliates				245,516		92,485
Accounts Receivable:
	Customers			150,954		142,010
	Affiliated Companies			72,283		113,793
	Accrued Unbilled Revenues			46,631		55,930
	Miscellaneous			472		412
	Allowance for Uncollectible Accounts			(3,517)		(2,443)
		Total Accounts Receivable		266,823		309,702
Fuel				103,983		191,811
Materials and Supplies				128,614		128,843
Risk Management Assets				15,972		21,171
Regulatory Asset for Under-Recovered Fuel Costs				79,498		39,811
Prepayments and Other Current Assets				33,677		16,472
TOTAL CURRENT ASSETS				878,841		803,040

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			6,752,422		6,745,172
	Transmission			2,173,839		2,160,660
	Distribution			3,161,917		3,139,150
Other Property, Plant and Equipment				365,750		357,517
Construction Work in Progress				217,713		184,701
Total Property, Plant and Equipment				12,671,641		12,587,200
Accumulated Depreciation and Amortization				3,679,394		3,617,990
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				8,992,247		8,969,210

OTHER NONCURRENT ASSETS
Regulatory Assets				1,006,426		1,003,890
Securitized Assets				364,984		369,355
Long-term Risk Management Assets				14,013		16,948
Deferred Charges and Other Noncurrent Assets				157,592		148,205
TOTAL OTHER NONCURRENT ASSETS				1,543,015		1,538,398

TOTAL ASSETS			$	11,414,103	$	11,310,648

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
March 31, 2014 and December 31, 2013
(Unaudited)

		March 31,		December 31,
		2014		2013
			(in thousands)
CURRENT LIABILITIES
Accounts Payable:
	General	$	188,773	$	169,184
	Affiliated Companies		87,447		120,789
Long-term Debt Due Within One Year – Nonaffiliated			553,399		342,360
Risk Management Liabilities			4,636		8,892
Customer Deposits			69,180		66,040
Deferred Income Taxes			12,208		6,899
Accrued Taxes			115,557		114,699
Accrued Interest			62,397		51,899
Regulatory Liability for Over-Recovered Fuel Costs			45,144		107,048
Other Current Liabilities			76,445		97,566
TOTAL CURRENT LIABILITIES			1,215,186		1,085,376

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			3,555,117		3,765,997
Long-term Debt – Affiliated			86,000		86,000
Long-term Risk Management Liabilities			7,929		10,241
Deferred Income Taxes			2,297,662		2,232,441
Regulatory Liabilities and Deferred Investment Tax Credits			648,895		631,225
Employee Benefits and Pension Obligations			105,927		82,264
Deferred Credits and Other Noncurrent Liabilities			186,191		187,672
TOTAL NONCURRENT LIABILITIES			6,887,721		6,995,840

TOTAL LIABILITIES			8,102,907		8,081,216

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

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			1,809,562		1,809,562
Retained Earnings			1,238,312		1,156,461
Accumulated Other Comprehensive Income (Loss)			2,864		2,951
TOTAL COMMON SHAREHOLDER’S EQUITY			3,311,196		3,229,432

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	11,414,103	$	11,310,648

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

			Three Months Ended March 31,
			2014		2013
OPERATING ACTIVITIES
Net Income			$	101,851	$	70,548
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			104,586		87,903
	Deferred Income Taxes			65,690		17,185
	Carrying Costs Income			1,875		(103)
	Allowance for Equity Funds Used During Construction			(1,235)		(770)
	Mark-to-Market of Risk Management Contracts			1,625		9,404
	Fuel Over/Under-Recovery, Net			(102,051)		20,135
	Change in Other Noncurrent Assets			4,959		28,314
	Change in Other Noncurrent Liabilities			7,799		5,634
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		41,382		7,238
		Fuel, Materials and Supplies		88,057		(8,726)
		Accounts Payable		(4,314)		(20,597)
		Accrued Taxes, Net		929		30,197
		Other Current Assets		(7,276)		642
		Other Current Liabilities		(6,707)		(10,917)
Net Cash Flows from Operating Activities				297,170		236,087

INVESTING ACTIVITIES
Construction Expenditures				(112,824)		(110,552)
Change in Advances to Affiliates, Net				(153,031)		(179)
Other Investing Activities				(8,677)		(179)
Net Cash Flows Used for Investing Activities				(274,532)		(110,910)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated				(45)		(258)
Change in Advances from Affiliates, Net				-		(77,314)
Retirement of Long-term Debt – Nonaffiliated				(8)		(7)
Principal Payments for Capital Lease Obligations				(1,559)		(1,238)
Dividends Paid on Common Stock				(20,000)		(50,000)
Other Financing Activities				987		1,320
Net Cash Flows Used for Financing Activities				(20,625)		(127,497)

Net Increase (Decrease) in Cash and Cash Equivalents				2,013		(2,320)
Cash and Cash Equivalents at Beginning of Period				2,745		3,576
Cash and Cash Equivalents at End of Period			$	4,758	$	1,256

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	39,431	$	31,018
Net Cash Paid (Received) for Income Taxes				-		231
Noncash Acquisitions Under Capital Leases				2,657		1,548
Construction Expenditures Included in Current Liabilities as of March 31,				38,972		35,733

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

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	133
New Accounting Pronouncement	133
Comprehensive Income	134
Rate Matters	141
Commitments, Guarantees and Contingencies	149
Benefit Plans	152
Business Segments	153
Derivatives and Hedging	154
Fair Value Measurements	166
Income Taxes	177
Financing Activities	178
Variable Interest Entities	181

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

Cook Plant Life Cycle Management Project (LCM Project)

Litigation and Environmental Issues

In the ordinary course of business, I&M is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 132. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted the motion to transfer this case to the U.S. District Court for the Southern District of Ohio. AEGCo’s and I&M’s motion to dismiss the case, filed in October 2013, remains pending. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

RESULTS OF OPERATIONS

KWh Sales/Degree Days


Summary of KWh Energy Sales

		Three Months Ended March 31,
		2014		2013
		(in millions of KWhs)
Retail:
	Residential		1,905		1,726
	Commercial		1,221		1,188
	Industrial		1,805		1,813
	Miscellaneous		20		20
Total Retail			4,951		4,747

Wholesale			5,296		2,580

Total KWhs			10,247		7,327

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

Summary of Heating and Cooling Degree Days

		Three Months Ended March 31,
		2014		2013
		(in degree days)

Actual - Heating (a)			2,972		2,287
Normal - Heating (b)			2,149		2,155

Actual - Cooling (c)			-		-
Normal - Cooling (b)			2		2

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

First Quarter of 2014 Compared to First Quarter of 2013


Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income
(in millions)

First Quarter of 2013	$	43

Changes in Gross Margin:
Retail Margins		27
FERC Municipals and Cooperatives		10
Off-system Sales		47
Transmission Revenues		2
Other Revenues		(14)
Total Change in Gross Margin		72

Changes in Expenses and Other:
Other Operation and Maintenance		1
Depreciation and Amortization		(9)
Taxes Other Than Income Taxes		1
Other Income		(3)
Interest Expense		(1)
Total Change in Expenses and Other		(11)

Income Tax Expense		(17)

First Quarter of 2014	$	87

·	Retail Margins increased $27 million primarily due to the following:
	·	A $22 million increase primarily due to a rate increase in Indiana effective March 2013.
	·	A $13 million increase in weather-related usage primarily due to a 30% increase in heating degree days.
	These increases were partially offset by:
	·	An $8 million decrease for industrial customers primarily due to lower margins.
·	Margins from FERC Municipal and Cooperatives increased $10 million primarily due to higher formula rates effective June 2013.
·	Margins from Off-system Sales increased $47 million primarily due to higher market prices and increased sales volumes .
·	Other Revenues decreased $14 million primarily due to a decrease in barging. This decrease in barging is a result of the River Transportation Division (RTD) no longer serving Ohio plants transferred to AGR as a result of corporate separation. The decrease in RTD revenue was offset by a corresponding decrease in Other Operation and Maintenance expenses for barging as discussed below.

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

·	Other Operation and Maintenance expenses decreased $1 million primarily due to the following:
	·	A $13 million decrease in RTD expenses for barging activities. The decrease in RTD expenses was offset by a corresponding decrease in Other Revenues from barging activities discussed above.
	This decrease was partially offset by:
	●	A $9 million increase in nuclear expenses primarily due to a prior year deferral of expenses, as regulatory assets, for future recovery as approved by the IURC effective March 2013.
	●	A $2 million increase due to increased maintenance of overhead lines.
·	Depreciation and Amortization expenses increased $9 million primarily due to higher depreciable base.
·	Income Tax Expense increased $17 million primarily due to an increase in pretax book income .

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

	Three Months Ended March 31,
	2014		2013
REVENUES
Electric Generation, Transmission and Distribution	$	614,843	$	490,603
Sales to AEP Affiliates		2,284		54,977
Other Revenues - Affiliated		24,727		35,825
Other Revenues - Nonaffiliated		-		1,988
TOTAL REVENUES		641,854		583,393

EXPENSES
Fuel and Other Consumables Used for Electric Generation		156,643		104,865
Purchased Electricity for Resale		5,362		41,812
Purchased Electricity from AEP Affiliates		72,056		101,376
Other Operation		141,350		145,238
Maintenance		48,565		45,514
Depreciation and Amortization		50,031		40,902
Taxes Other Than Income Taxes		21,823		22,456
TOTAL EXPENSES		495,830		502,163

OPERATING INCOME		146,024		81,230

Other Income (Expense):
Interest Income		1,049		2,055
Allowance for Equity Funds Used During Construction		3,964		5,646
Interest Expense		(25,633)		(24,211)

INCOME BEFORE INCOME TAX EXPENSE		125,404		64,720

Income Tax Expense		38,315		21,263

NET INCOME	$	87,089	$	43,457

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

		Three Months Ended March 31,
		2014		2013
Net Income		$	87,089	$	43,457

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $229 and $1,682 in 2014 and 2013, Respectively			425		3,123
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $23 and $94
	in 2014 and 2013, Respectively		43		176

TOTAL OTHER COMPREHENSIVE INCOME			468		3,299

TOTAL COMPREHENSIVE INCOME		$	87,557	$	46,756

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

								Accumulated
								Other
		Common		Paid-in		Retained		Comprehensive
		Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2012	$	56,584	$	980,896	$	795,178	$	(28,883)	$	1,803,775

Common Stock Dividends							(12,500)				(12,500)
Net Income							43,457				43,457
Other Comprehensive Income									3,299		3,299
TOTAL COMMON SHAREHOLDER'S
	EQUITY – MARCH 31, 2013	$	56,584	$	980,896	$	826,135	$	(25,584)	$	1,838,031

TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2013	$	56,584	$	980,896	$	900,182	$	(15,509)	$	1,922,153

Common Stock Dividends							(25,000)				(25,000)
Net Income							87,089				87,089
Other Comprehensive Income									468		468
TOTAL COMMON SHAREHOLDER'S
	EQUITY – MARCH 31, 2014	$	56,584	$	980,896	$	962,271	$	(15,041)	$	1,984,710

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2014 and December 31, 2013
(in thousands)
(Unaudited)

			March 31,		December 31,
			2014		2013
CURRENT ASSETS
Cash and Cash Equivalents			$	2,288	$	1,317
Advances to Affiliates				59,162		55,863
Accounts Receivable:
	Customers			52,471		63,011
	Affiliated Companies			71,359		78,282
	Accrued Unbilled Revenues			13,999		17,293
	Miscellaneous			1,259		5,064
	Allowance for Uncollectible Accounts			(33)		(184)
		Total Accounts Receivable		139,055		163,466
Fuel				49,365		53,807
Materials and Supplies				206,820		209,718
Risk Management Assets				12,558		15,388
Accrued Tax Benefits				29,792		48,832
Prepayments and Other Current Assets				27,897		38,103
TOTAL CURRENT ASSETS				526,937		586,494

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			3,583,883		3,577,906
	Transmission			1,310,169		1,304,225
	Distribution			1,641,866		1,625,057
Other Property, Plant and Equipment (Including Plant to be Retired, Coal Mining
	and Nuclear Fuel)			1,440,408		1,421,361
Construction Work in Progress				476,734		427,164
Total Property, Plant and Equipment				8,453,060		8,355,713
Accumulated Depreciation, Depletion and Amortization				3,337,401		3,299,349
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				5,115,659		5,056,364

OTHER NONCURRENT ASSETS
Regulatory Assets				505,750		524,114
Spent Nuclear Fuel and Decommissioning Trusts				1,962,151		1,931,610
Long-term Risk Management Assets				9,505		11,495
Deferred Charges and Other Noncurrent Assets				140,198		143,657
TOTAL OTHER NONCURRENT ASSETS				2,617,604		2,610,876

TOTAL ASSETS			$	8,260,200	$	8,253,734

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
March 31, 2014 and December 31, 2013
(dollars in thousands)
(Unaudited)

		March 31,		December 31,
		2014		2013
CURRENT LIABILITIES
Accounts Payable:
	General	$	121,516	$	142,219
	Affiliated Companies		69,635		93,773
Long-term Debt Due Within One Year – Nonaffiliated
	(March 31, 2014 and December 31, 2013 Amounts Include $99,439 and
	$107,143, Respectively, Related to DCC Fuel)		287,598		294,845
Risk Management Liabilities			4,134		7,029
Customer Deposits			31,851		31,103
Accrued Taxes			83,314		73,292
Accrued Interest			15,182		27,686
Obligations Under Capital Leases			48,407		46,210
Other Current Liabilities			146,801		139,088
TOTAL CURRENT LIABILITIES			808,438		855,245

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			1,725,246		1,744,171
Long-term Risk Management Liabilities			5,378		6,946
Deferred Income Taxes			1,184,213		1,183,350
Regulatory Liabilities and Deferred Investment Tax Credits			1,122,812		1,112,645
Asset Retirement Obligations			1,269,671		1,255,184
Deferred Credits and Other Noncurrent Liabilities			159,732		174,040
TOTAL NONCURRENT LIABILITIES			5,467,052		5,476,336

TOTAL LIABILITIES			6,275,490		6,331,581

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

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			962,271		900,182
Accumulated Other Comprehensive Income (Loss)			(15,041)		(15,509)
TOTAL COMMON SHAREHOLDER’S EQUITY			1,984,710		1,922,153

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	8,260,200	$	8,253,734

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

			Three Months Ended March 31,
			2014		2013
OPERATING ACTIVITIES
Net Income			$	87,089	$	43,457
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			50,031		40,902
	Deferred Income Taxes			21,017		26,791
	Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net			14,821		(5,840)
	Allowance for Equity Funds Used During Construction			(3,964)		(5,646)
	Mark-to-Market of Risk Management Contracts			426		9,238
	Amortization of Nuclear Fuel			38,049		34,000
	Fuel Over/Under-Recovery, Net			11,683		417
	Change in Other Noncurrent Assets			(16,211)		(9,217)
	Change in Other Noncurrent Liabilities			11,505		8,577
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		24,411		22,531
		Fuel, Materials and Supplies		7,340		(6,868)
		Accounts Payable		(20,902)		(31,801)
		Accrued Taxes, Net		29,583		14,198
		Other Current Assets		5,933		8,487
		Other Current Liabilities		(18,862)		(13,443)
Net Cash Flows from Operating Activities				241,949		135,783

INVESTING ACTIVITIES
Construction Expenditures				(117,807)		(153,262)
Change in Advances to Affiliates, Net				(3,299)		(205,008)
Purchases of Investment Securities				(164,511)		(184,299)
Sales of Investment Securities				147,700		167,670
Acquisitions of Nuclear Fuel				(49,420)		(46,739)
Insurance Proceeds Related to Cook Plant Fire				-		72,000
Other Investing Activities				8,860		3,077
Net Cash Flows Used for Investing Activities				(178,477)		(346,561)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated				-		247,771
Retirement of Long-term Debt – Nonaffiliated				(26,337)		(24,864)
Principal Payments for Capital Lease Obligations				(11,569)		(1,265)
Dividends Paid on Common Stock				(25,000)		(12,500)
Other Financing Activities				405		646
Net Cash Flows from (Used for) Financing Activities				(62,501)		209,788

Net Increase (Decrease) in Cash and Cash Equivalents				971		(990)
Cash and Cash Equivalents at Beginning of Period				1,317		1,562
Cash and Cash Equivalents at End of Period			$	2,288	$	572

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	34,592	$	30,116
Net Cash Paid (Received) for Income Taxes				-		(8,007)
Noncash Acquisitions Under Capital Leases				2,406		1,355
Construction Expenditures Included in Current Liabilities as of March 31,				56,668		42,430
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31,				116		1,485
Expected Reimbursement for Capital Costs of Spent Nuclear Fuel Dry Cask Storage				854		-

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

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	133
New Accounting Pronouncement	133
Comprehensive Income	134
Rate Matters	141
Commitments, Guarantees and Contingencies	149
Benefit Plans	152
Business Segments	153
Derivatives and Hedging	154
Fair Value Measurements	166
Income Taxes	177
Financing Activities	178
Variable Interest Entities	181

OHIO POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

As a public utility, OPCo engages in the transmission and distribution of power to 1,464,000 retail customers in the northwestern, central, eastern and southern sections of Ohio. OPCo purchases energy and capacity to serve its remaining generation service customers. Prior to January 1, 2014, OPCo also engaged in the generation of electric power and the subsequent sale of that power to customers. On December 31, 2013, based on FERC and PUCO orders which approved corporate separation of generation assets and associated liabilities, OPCo transferred its generation assets and related generation liabilities at net book value to AGR. In accordance with the PUCO’s corporate separation order, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers. Effective January 1, 2014, OPCo purchases power from both affiliated and nonaffiliated entities, subject to auction requirements and PUCO approval, to meet the energy and capacity needs of customers.

Ormet

Ormet had a contract to purchase power from OPCo through 2018. In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down operations effective immediately. The loss of Ormet's load will not have a material impact on future gross margin.

Regulatory Activity

Ohio Electric Security Plan Filing

2009 – 2011 ESP

June 2012 – May 2015 Ohio ESP Including Capacity Charge

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. In February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 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. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012-2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC.

Proposed June 2015 – May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018. This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to market. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo. Additionally, the application identifies OPCo’s intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. Management intends to file this application in the second quarter of 2014. A hearing at the PUCO in the ESP case is scheduled for June 2014.

Litigation and Environmental Issues

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 132. 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 March 31,
		2014		2013
		(in millions of KWhs)
Retail:
	Residential		4,731		4,264
	Commercial		3,579		3,386
	Industrial		3,473		4,082
	Miscellaneous		34		35
Total Retail (a)			11,817		11,767

Wholesale			700		3,044

Total KWhs			12,517		14,811

(a) Represents energy delivered to distribution customers.

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.

Summary of Heating and Cooling Degree Days

		Three Months Ended March 31,
		2014		2013
		(in degree days)

Actual - Heating (a)			2,409		1,971
Normal - Heating (b)			1,880		1,885

Actual - Cooling (c)			-		-
Normal - Cooling (b)			3		3

(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.

100

First Quarter of 2014 Compared to First Quarter of 2013


Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income
(in millions)

First Quarter of 2013	$	130

Changes in Gross Margin:
Retail Margins		(219)
Off-system Sales		(27)
Transmission Revenues		15
Other Revenues		(14)
Total Change in Gross Margin		(245)

Changes in Expenses and Other:
Other Operation and Maintenance		72
Depreciation and Amortization		33
Taxes Other Than Income Taxes		10
Interest and Investment Income		4
Carrying Costs Income		4
Interest Expense		17
Total Change in Expenses and Other		140

Income Tax Expense		36

First Quarter of 2014	$	61

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, purchased electricity and amortization of generation deferrals were as follows:

·	Retail Margins decreased $219 million primarily due to the following:
	·	A $106 million decrease attributable to purchased power due to the AGR Power Supply Agreement related to the base generation SSO load.
	·	An $87 million decrease due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
	·	A $14 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.
	These decreases were partially offset by:
	·	A $15 million increase in revenues associated with the Distribution Investment Recovery Rider and Universal Service Fund (USF) surcharge. Of these increases, $10 million relate to riders/trackers which have corresponding increases in other expense items below.
·	Margins from Off-system Sales decreased $27 million due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
·	Transmission Revenues increased $15 million primarily due to increased transmission revenues from customers who have switched to alternative CRES providers and rate increases for customers in the PJM region. The increase in transmission revenues related to CRES providers offsets lost revenues included in Retail Margins above.
·	Other Revenues decreased $14 million due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013. This decrease in Other Revenues has a corresponding decrease in Other Operation and Maintenance expense below.

101

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

·	Other Operation and Maintenance expenses decreased $72 million primarily due to the following:
	·	A $114 million decrease due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
	This decrease was partially offset by:
	·	A $15 million increase in PJM expenses.
	·	An $8 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 $4 million increase in employee-related expenses.
	·	A $4 million increase in storm expense.
	·	A $3 million increase in expense related to the factoring of receivables.
·	Depreciation and Amortization expenses decreased $33 million primarily due to the following:
	·	A $49 million decrease due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
	This decrease was partially offset by:
	·	A $5 million increase in amortization of securitized regulatory assets and recognition of previously unrecognized equity being recovered through the Deferred Asset Phase-In Rider. This increase was offset by a corresponding increase in Retail Margins above.
	·	A $4 million increase due to carrying charge adjustments as a result of expensing certain gridSMART ® capital projects.
	·	A $3 million increase due to an increase in depreciable base of transmission and distribution assets.
·	Taxes Other Than Income Taxes decreased $10 million due to the following:
	·	An $18 million decrease due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
	This decrease was partially offset by:
	·	A $6 million increase in property taxes due to increased investment in transmission and distribution assets and increased tax rates.
	·	A $2 million increase in state excise taxes due to increased metered KWh sales.
·	Interest and Investment Income increased $4 million primarily due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
·	Carrying Costs Income increased $4 million primarily due to increased capacity deferral carrying charges.
·	Interest Expense decreased $17 million primarily due to corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013.
·	Income Tax Expense decreased $36 million primarily due to a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

102

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

	Three Months Ended March 31,
	2014		2013
REVENUES
Electric Generation, Transmission and Distribution	$	846,906	$	933,681
Sales to AEP Affiliates		31,978		285,642
Other Revenues – Affiliated		-		7,840
Other Revenues – Nonaffiliated		1,308		6,627
TOTAL REVENUES		880,192		1,233,790

EXPENSES
Fuel and Other Consumables Used for Electric Generation		-		409,584
Purchased Electricity for Resale		79,130		43,185
Purchased Electricity from AEP Affiliates		314,124		80,381
Amortization of Generation Deferrals		31,186		-
Other Operation		151,426		184,187
Maintenance		34,651		74,295
Depreciation and Amortization		58,699		92,324
Taxes Other Than Income Taxes		95,257		105,021
TOTAL EXPENSES		764,473		988,977

OPERATING INCOME		115,719		244,813

Other Income (Expense):
Interest Income		3,274		363
Carrying Costs Income		7,114		3,263
Allowance for Equity Funds Used During Construction		1,726		1,304
Interest Expense		(33,007)		(50,173)

INCOME BEFORE INCOME TAX EXPENSE		94,826		199,570

Income Tax Expense		34,052		69,796

NET INCOME	$	60,774	$	129,774

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

103

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

	Three Months Ended March 31,
	2014		2013
Net Income	$	60,774	$	129,774

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $241 and $574 in 2014 and 2013, Respectively		(448)		1,066
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,760 in 2013		-		3,269

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(448)		4,335

TOTAL COMPREHENSIVE INCOME	$	60,326	$	134,109

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

104

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

								Accumulated
								Other
		Common		Paid-in		Retained		Comprehensive
		Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2012	$	321,201	$	1,744,099	$	2,626,134	$	(165,725)	$	4,525,709

Common Stock Dividends							(75,000)				(75,000)
Net Income							129,774				129,774
Other Comprehensive Income									4,335		4,335
TOTAL COMMON SHAREHOLDER'S
	EQUITY – MARCH 31, 2013	$	321,201	$	1,744,099	$	2,680,908	$	(161,390)	$	4,584,818

TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2013	$	321,201	$	663,782	$	633,203	$	7,079	$	1,625,265

Common Stock Dividends							(25,000)				(25,000)
Net Income							60,774				60,774
Other Comprehensive Loss									(448)		(448)
TOTAL COMMON SHAREHOLDER'S
	EQUITY – MARCH 31, 2014	$	321,201	$	663,782	$	668,977	$	6,631	$	1,660,591

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

105

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2014 and December 31, 2013
(in thousands)
(Unaudited)

			March 31,		December 31,
			2014		2013
CURRENT ASSETS
Cash and Cash Equivalents			$	4,780	$	3,004
Restricted Cash for Securitized Funding				32,054		19,387
Advances to Affiliates				-		339,070
Accounts Receivable:
	Customers			96,218		67,054
	Affiliated Companies			72,311		74,771
	Accrued Unbilled Revenues			49,761		36,353
	Miscellaneous			747		1,559
	Allowance for Uncollectible Accounts			(39,602)		(34,984)
		Total Accounts Receivable		179,435		144,753
Notes Receivable Due Within One Year – Affiliated				178,580		178,580
Materials and Supplies				55,311		53,711
Risk Management Assets				3,980		3,082
Deferred Income Tax Benefits				33,642		36,105
Accrued Tax Benefits				487		7,109
Regulatory Asset for Under-Recovered Fuel Costs				26,153		15,829
Prepayments and Other Current Assets				7,085		6,483
TOTAL CURRENT ASSETS				521,507		807,113

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Transmission			2,030,881		2,011,289
	Distribution			3,907,852		3,877,532
Other Property, Plant and Equipment				379,780		364,573
Construction Work in Progress				188,636		185,428
Total Property, Plant and Equipment				6,507,149		6,438,822
Accumulated Depreciation and Amortization				1,986,318		1,973,042
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				4,520,831		4,465,780

OTHER NONCURRENT ASSETS
Notes Receivable – Affiliated				118,245		118,245
Regulatory Assets				1,398,055		1,378,697
Securitized Assets				126,597		131,582
Deferred Charges and Other Noncurrent Assets				211,819		260,141
TOTAL OTHER NONCURRENT ASSETS				1,854,716		1,888,665

TOTAL ASSETS			$	6,897,054	$	7,161,558

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

106


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
March 31, 2014 and December 31, 2013
(Unaudited)

		March 31,		December 31,
		2014		2013
			(in thousands)
CURRENT LIABILITIES
Advances from Affiliates		$	27,108	$	-
Accounts Payable:
	General		128,333		146,307
	Affiliated Companies		195,954		222,889
Long-term Debt Due Within One Year – Nonaffiliated
	(March 31, 2014 and December 31, 2013 Amounts Include $57,137 and
	$34,936, Respectively, Related to Ohio Phase-in-Recovery Funding)		235,785		438,595
Accrued Taxes			324,491		429,260
Accrued Interest			49,854		40,853
Other Current Liabilities			128,143		144,334
TOTAL CURRENT LIABILITIES			1,089,668		1,422,238

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated
	(March 31, 2014 and December 31, 2013 Amounts Include $210,266 and
	$232,466, Respectively, Related to Ohio Phase-in-Recovery Funding)		2,274,500		2,296,580
Deferred Income Taxes			1,352,301		1,330,711
Regulatory Liabilities and Deferred Investment Tax Credits			467,433		435,499
Employee Benefits and Pension Obligations			28,789		28,329
Deferred Credits and Other Noncurrent Liabilities			23,772		22,936
TOTAL NONCURRENT LIABILITIES			4,146,795		4,114,055

TOTAL LIABILITIES			5,236,463		5,536,293

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

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			663,782		663,782
Retained Earnings			668,977		633,203
Accumulated Other Comprehensive Income (Loss)			6,631		7,079
TOTAL COMMON SHAREHOLDER’S EQUITY			1,660,591		1,625,265

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	6,897,054	$	7,161,558

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

107

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

				Three Months Ended March 31,
				2014		2013
OPERATING ACTIVITIES
Net Income				$	60,774	$	129,774
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for)
	Operating Activities:
		Depreciation and Amortization			58,699		92,324
		Amortization of Generation Deferrals			31,186		-
		Deferred Income Taxes			24,917		55,328
		Carrying Costs Income			(7,114)		(3,263)
		Allowance for Equity Funds Used During Construction			(1,726)		(1,304)
		Mark-to-Market of Risk Management Contracts			(1,060)		12,901
		Property Taxes			48,743		55,246
		Fuel Over/Under-Recovery, Net			12,265		9,191
		Deferral of Ohio Capacity Costs, Net			(56,167)		(49,056)
		Change in Other Noncurrent Assets			(21,285)		14,092
		Change in Other Noncurrent Liabilities			29,277		1,730
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		(34,984)		58,235
			Fuel, Materials and Supplies		(1,600)		(1,388)
			Accounts Payable		(30,911)		(42,749)
			Accrued Taxes, Net		(98,147)		(91,308)
			Other Current Assets		(1,415)		(705)
			Other Current Liabilities		(13,633)		(21,374)
Net Cash Flows from (Used for) Operating Activities					(2,181)		217,674

INVESTING ACTIVITIES
Construction Expenditures					(100,220)		(131,590)
Change in Restricted Cash for Securitized Funding					(12,668)		-
Change in Advances to Affiliates, Net					339,070		106,080
Other Investing Activities					1,162		9,760
Net Cash Flows from (Used for) Investing Activities					227,344		(15,750)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Affiliated					-		200,000
Change in Advances from Affiliates, Net					27,108		172,211
Retirement of Long-term Debt – Nonaffiliated					(225,029)		(500,000)
Principal Payments for Capital Lease Obligations					(1,396)		(2,508)
Dividends Paid on Common Stock					(25,000)		(75,000)
Other Financing Activities					930		760
Net Cash Flows Used for Financing Activities					(223,387)		(204,537)

Net Increase (Decrease) in Cash and Cash Equivalents					1,776		(2,613)
Cash and Cash Equivalents at Beginning of Period					3,004		3,640
Cash and Cash Equivalents at End of Period				$	4,780	$	1,027

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	23,425	$	50,327
Net Cash Paid (Received) for Income Taxes					-		(2,390)
Noncash Acquisitions Under Capital Leases					3,324		1,811
Government Grants Included in Accounts Receivable as of March 31,					-		1,147
Construction Expenditures Included in Current Liabilities as of March 31,					46,910		69,152

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

108

OHIO POWER COMPANY AND SUBSIDIARIES

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	133
New Accounting Pronouncement	133
Comprehensive Income	134
Rate Matters	141
Commitments, Guarantees and Contingencies	149
Benefit Plans	152
Business Segments	153
Derivatives and Hedging	154
Fair Value Measurements	166
Income Taxes	177
Financing Activities	178
Variable Interest Entities	181

109

PUBLIC SERVICE COMPANY OF OKLAHOMA

110

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Regulatory Activity

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years. I n April 2014, the OCC Staff and intervenors filed testimony with various recommendations. A hearing at the OCC is scheduled for June 2014. See the "2014 Oklahoma Base Rate Case" section of Note 4.

Litigation and Environmental Issues

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 132. 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 March 31,
		2014		2013
		(in millions of KWhs)
Retail:
	Residential		1,634		1,436
	Commercial		1,139		1,079
	Industrial		1,193		1,194
	Miscellaneous		278		277
Total Retail			4,244		3,986

Wholesale			227		255

Total KWhs			4,471		4,241

111

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

Summary of Heating and Cooling Degree Days

		Three Months Ended March 31,
		2014		2013
		(in degree days)

Actual - Heating (a)			1,369		1,089
Normal - Heating (b)			1,045		1,045

Actual - Cooling (c)			3		5
Normal - Cooling (b)			15		15

(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.

112

First Quarter of 2014 Compared to First Quarter of 2013


Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income
(in millions)

First Quarter of 2013	$	14

Changes in Gross Margin:
Transmission Revenues		1
Total Change in Gross Margin		1

Changes in Expenses and Other:
Other Operation and Maintenance		(7)
Taxes Other Than Income Taxes		(2)
Other Income		(1)
Total Change in Expenses and Other		(10)

Income Tax Expense		3

First Quarter of 2014	$	8

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

·	Other Operation and Maintenance expenses increased $7 million primarily due to the following:
	·	A $6 million increase in transmission expenses primarily due to increased SPP transmission services.
	·	A $2 million increase in generation plant operation and maintenance expenses.
	These increases were partially offset by:
	·	A $3 million decrease in distribution expenses primarily related to the amortization of the 2007 and 2010 storm deferrals which were fully recovered in 2013.
·	Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

113

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

	Three Months Ended March 31,
	2014		2013
REVENUES
Electric Generation, Transmission and Distribution	$	296,710	$	259,903
Sales to AEP Affiliates		4,597		1,834
Other Revenues		78		552
TOTAL REVENUES		301,385		262,289

EXPENSES
Fuel and Other Consumables Used for Electric Generation		65,937		43,310
Purchased Electricity for Resale		79,691		64,655
Purchased Electricity from AEP Affiliates		11,024		10,216
Other Operation		58,711		47,807
Maintenance		24,745		28,572
Depreciation and Amortization		23,982		24,180
Taxes Other Than Income Taxes		11,969		9,997
TOTAL EXPENSES		276,059		228,737

OPERATING INCOME		25,326		33,552

Other Income (Expense):
Other Income		1,428		2,115
Interest Expense		(13,317)		(13,340)

INCOME BEFORE INCOME TAX EXPENSE		13,437		22,327

Income Tax Expense		4,989		8,634

NET INCOME	$	8,448	$	13,693

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

114

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

	Three Months Ended March 31,
	2014		2013
Net Income	$	8,448	$	13,693

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $132 and $90 in 2014 and 2013, Respectively		(246)		(167)

TOTAL COMPREHENSIVE INCOME	$	8,202	$	13,526

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

115

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

								Accumulated
								Other
		Common		Paid-in		Retained		Comprehensive
		Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2012	$	157,230	$	364,037	$	388,530	$	6,481	$	916,278

Common Stock Dividends							(13,750)				(13,750)
Net Income							13,693				13,693
Other Comprehensive Loss									(167)		(167)
TOTAL COMMON SHAREHOLDER'S
	EQUITY – MARCH 31, 2013	$	157,230	$	364,037	$	388,473	$	6,314	$	916,054

TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2013	$	157,230	$	364,037	$	415,076	$	5,758	$	942,101

Net Income							8,448				8,448
Other Comprehensive Loss									(246)		(246)
TOTAL COMMON SHAREHOLDER'S
	EQUITY – MARCH 31, 2014	$	157,230	$	364,037	$	423,524	$	5,512	$	950,303

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

116

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
March 31, 2014 and December 31, 2013
(in thousands)
(Unaudited)

			March 31,		December 31,
			2014		2013
CURRENT ASSETS
Cash and Cash Equivalents			$	1,756	$	1,277
Accounts Receivable:
	Customers			29,384		32,314
	Affiliated Companies			18,634		30,392
	Miscellaneous			3,460		3,102
	Allowance for Uncollectible Accounts			(325)		(462)
		Total Accounts Receivable		51,153		65,346
Fuel				15,054		15,191
Materials and Supplies				52,695		52,707
Risk Management Assets				1,349		1,167
Deferred Income Tax Benefits				-		7,333
Accrued Tax Benefits				35,708		21,665
Regulatory Asset for Under-Recovered Fuel Costs				26,692		3,298
Prepayments and Other Current Assets				5,994		6,194
TOTAL CURRENT ASSETS				190,401		174,178

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			1,236,105		1,203,221
	Transmission			727,512		731,312
	Distribution			2,001,049		1,986,032
Other Property, Plant and Equipment (Including Plant to be Retired)				411,700		393,026
Construction Work in Progress				172,949		175,890
Total Property, Plant and Equipment				4,549,315		4,489,481
Accumulated Depreciation and Amortization				1,334,507		1,323,522
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				3,214,808		3,165,959

OTHER NONCURRENT ASSETS
Regulatory Assets				164,929		156,690
Employee Benefits and Pension Assets				23,162		22,629
Deferred Charges and Other Noncurrent Assets				38,197		7,238
TOTAL OTHER NONCURRENT ASSETS				226,288		186,557

TOTAL ASSETS			$	3,631,497	$	3,526,694

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

117

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
March 31, 2014 and December 31, 2013
(Unaudited)

		March 31,		December 31,
		2014		2013
			(in thousands)
CURRENT LIABILITIES
Advances from Affiliates		$	70,119	$	36,772
Accounts Payable:
	General		106,312		150,184
	Affiliated Companies		45,468		45,427
Long-term Debt Due Within One Year – Nonaffiliated			34,118		34,115
Risk Management Liabilities			83		85
Customer Deposits			45,676		45,379
Accrued Taxes			44,847		23,442
Accrued Interest			15,040		12,646
Other Current Liabilities			80,931		58,992
TOTAL CURRENT LIABILITIES			442,594		407,042

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			1,015,675		965,695
Deferred Income Taxes			848,101		836,556
Regulatory Liabilities and Deferred Investment Tax Credits			328,224		327,673
Employee Benefits and Pension Obligations			9,966		10,561
Deferred Credits and Other Noncurrent Liabilities			36,634		37,066
TOTAL NONCURRENT LIABILITIES			2,238,600		2,177,551

TOTAL LIABILITIES			2,681,194		2,584,593


Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

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			423,524		415,076
Accumulated Other Comprehensive Income (Loss)			5,512		5,758
TOTAL COMMON SHAREHOLDER’S EQUITY			950,303		942,101

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	3,631,497	$	3,526,694

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

118

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

				Three Months Ended March 31,
				2014		2013
OPERATING ACTIVITIES
Net Income				$	8,448	$	13,693
Adjustments to Reconcile Net Income to Net Cash Flows from Operating
	Activities:
		Depreciation and Amortization			23,982		24,180
		Deferred Income Taxes			19,178		20,242
		Allowance for Equity Funds Used During Construction			(1,431)		(980)
		Mark-to-Market of Risk Management Contracts			(267)		(3,013)
		Property Taxes			(31,260)		(28,730)
		Fuel Over/Under-Recovery, Net			(23,394)		(17,812)
		Change in Regulatory Assets			(8,468)		4,165
		Change in Other Noncurrent Assets			(1,045)		(3,780)
		Change in Other Noncurrent Liabilities			(2,204)		4,620
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		14,193		1,665
			Fuel, Materials and Supplies		149		1,344
			Accounts Payable		(16,891)		(5,827)
			Accrued Taxes, Net		7,362		6,106
			Other Current Assets		(395)		1,181
			Other Current Liabilities		22,401		10,663
Net Cash Flows from Operating Activities					10,358		27,717

INVESTING ACTIVITIES
Construction Expenditures					(93,500)		(54,298)
Change in Advances to Affiliates, Net					-		10,558
Other Investing Activities					776		5,196
Net Cash Flows Used for Investing Activities					(92,724)		(38,544)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated					49,975		-
Change in Advances from Affiliates, Net					33,347		24,004
Retirement of Long-term Debt – Nonaffiliated					(102)		(99)
Principal Payments for Capital Lease Obligations					(941)		(754)
Dividends Paid on Common Stock					-		(13,750)
Other Financing Activities					566		533
Net Cash Flows from Financing Activities					82,845		9,934

Net Increase (Decrease) in Cash and Cash Equivalents					479		(893)
Cash and Cash Equivalents at Beginning of Period					1,277		1,367
Cash and Cash Equivalents at End of Period				$	1,756	$	474

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	10,487	$	10,519
Net Cash Paid for Income Taxes					67		284
Noncash Acquisitions Under Capital Leases					904		1,015
Construction Expenditures Included in Current Liabilities as of March 31,					34,199		19,868

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

119

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	133
New Accounting Pronouncement	133
Comprehensive Income	134
Rate Matters	141
Commitments, Guarantees and Contingencies	149
Benefit Plans	152
Business Segments	153
Derivatives and Hedging	154
Fair Value Measurements	166
Income Taxes	177
Financing Activities	178
Variable Interest Entities	181

120

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

121

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Regulatory Activity

2012 Louisiana Formula Rate Filing

2014 Louisiana Formula Rate Filing

In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase to be effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchase power agreement attributable to Louisiana customers. These increases are subject to LPSC staff review. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant, Units 1 and 3 - Environmental Projects

Litigation and Environmental Issues

In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2013 Annual Report. Also, see Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 132. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

122

RESULTS OF OPERATIONS

KWh Sales/Degree Days


Summary of KWh Energy Sales

		Three Months Ended March 31,
		2014		2013
		(in millions of KWhs)
Retail:
	Residential		1,747		1,494
	Commercial		1,393		1,279
	Industrial		1,377		1,259
	Miscellaneous		20		19
Total Retail			4,537		4,051

Wholesale			2,279		2,443

Total KWhs			6,816		6,494

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

Summary of Heating and Cooling Degree Days

		Three Months Ended March 31,
		2014		2013
		(in degree days)

Actual - Heating (a)			994		732
Normal - Heating (b)			721		728

Actual - Cooling (c)			10		16
Normal - Cooling (b)			33		33

(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.

123

First Quarter of 2014 Compared to First Quarter of 2013


Reconciliation of First Quarter of 2013 to First Quarter of 2014
Net Income
(in millions)

First Quarter of 2013		$	12

Changes in Gross Margin:
Retail Margins (a)			24
Off-system Sales			2
Transmission Revenues			2
Total Change in Gross Margin			28

Changes in Expenses and Other:
Other Operation and Maintenance			(12)
Depreciation and Amortization			(1)
Taxes Other Than Income Taxes			(1)
Other Income			1
Interest Expense			2
Total Change in Expenses and Other			(11)

Income Tax Expense			(6)

First Quarter of 2014		$	23

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

·	Retail Margins increased $24 million primarily due to the following:
	·	A $24 million increase primarily due to the Louisiana and Texas rate orders related to the Turk Plant.
	·	A $6 million increase in weather-related usage primarily due to a 36% increase in heating degree days.
	These increases were partially offset by:
	·	A $4 million decrease primarily due to 2013 fuel recovery adjustments.

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

·	Other Operation and Maintenance expenses increased $12 million primarily due to the following:
	·	A $6 million increase in transmission expenses primarily due to increased SPP transmission services.
	·	A $4 million increase in generation plant operation and maintenance expenses.
·	Income Tax Expense increased $6 million primarily due to an increase in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

124

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

	Three Months Ended March 31,
	2014		2013
REVENUES
Electric Generation, Transmission and Distribution	$	426,627	$	381,277
Sales to AEP Affiliates		13,598		12,709
Other Revenues		365		331
TOTAL REVENUES		440,590		394,317

EXPENSES
Fuel and Other Consumables Used for Electric Generation		145,587		151,358
Purchased Electricity for Resale		61,165		39,760
Purchased Electricity from AEP Affiliates		3,766		1,017
Other Operation		68,537		59,448
Maintenance		30,411		27,791
Depreciation and Amortization		45,661		44,882
Taxes Other Than Income Taxes		20,737		19,422
TOTAL EXPENSES		375,864		343,678

OPERATING INCOME		64,726		50,639

Other Income (Expense):
Other Income		1,967		1,054
Interest Expense		(31,876)		(33,990)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		34,817		17,703

Income Tax Expense		12,165		6,796
Equity Earnings of Unconsolidated Subsidiary		310		641

NET INCOME		22,962		11,548

Net Income Attributable to Noncontrolling Interest		1,102		1,090

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	21,860	$	10,458

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

125

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

		Three Months Ended March 31,
		2014		2013
Net Income		$	22,962	$	11,548

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $270 and $321 in 2014 and 2013, Respectively			502		596
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $126 and $34 in
	2014 and 2013, Respectively		(234)		(63)

TOTAL OTHER COMPREHENSIVE INCOME			268		533

TOTAL COMPREHENSIVE INCOME			23,230		12,081

Total Comprehensive Income Attributable to Noncontrolling Interest			1,102		1,090

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo
	COMMON SHAREHOLDER	$	22,128	$	10,991

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

126

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Three Months Ended March 31, 2014 and 2013
(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, 2012	$	135,660	$	674,606	$	1,228,806	$	(17,860)	$	261	$	2,021,473

Common Stock Dividends						(31,250)						(31,250)
Common Stock Dividends – Nonaffiliated										(964)		(964)
Net Income						10,458				1,090		11,548
Other Comprehensive Income								533				533
TOTAL EQUITY – MARCH 31, 2013	$	135,660	$	674,606	$	1,208,014	$	(17,327)	$	387	$	2,001,340

TOTAL EQUITY – DECEMBER 31, 2013	$	135,660	$	674,606	$	1,253,617	$	(8,444)	$	478	$	2,055,917

Common Stock Dividends						(25,000)						(25,000)
Common Stock Dividends – Nonaffiliated										(1,236)		(1,236)
Net Income						21,860				1,102		22,962
Other Comprehensive Income								268				268
TOTAL EQUITY – MARCH 31, 2014	$	135,660	$	674,606	$	1,250,477	$	(8,176)	$	344	$	2,052,911

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

127

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2014 and December 31, 2013
(in thousands)
(Unaudited)

			March 31,		December 31,
			2014		2013
CURRENT ASSETS
Cash and Cash Equivalents			$	17,995	$	17,241
		(March 31, 2014 and December 31, 2013 Amounts Include $15,539 and
		$15,827, Respectively, Related to Sabine)
Accounts Receivable:
	Customers			76,416		86,263
	Affiliated Companies			21,341		22,389
	Miscellaneous			24,380		27,175
	Allowance for Uncollectible Accounts			(1,342)		(1,418)
		Total Accounts Receivable		120,795		134,409
Fuel
	(March 31, 2014 and December 31, 2013 Amounts Include $36,143 and
	$37,518, Respectively, Related to Sabine)			116,294		122,026
Materials and Supplies				75,492		74,862
Risk Management Assets				1,907		1,179
Deferred Income Tax Benefits				170,410		177,297
Regulatory Asset for Under-Recovered Fuel Costs				32,325		17,949
Prepayments and Other Current Assets				24,786		21,089
TOTAL CURRENT ASSETS				560,004		566,052

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			3,790,809		3,764,429
	Transmission			1,190,356		1,165,167
	Distribution			1,850,573		1,843,912
Other Property, Plant and Equipment (Including Plant to be Retired)
	(March 31, 2014 and December 31, 2013 Amounts Include $291,571 and
	$291,556, Respectively, Related to Sabine)			873,458		869,230
Construction Work in Progress				309,200		281,849
Total Property, Plant and Equipment				8,014,396		7,924,587
Accumulated Depreciation and Amortization
	(March 31, 2014 and December 31, 2013 Amounts Include $138,789 and
	$134,282, Respectively, Related to Sabine)			2,424,701		2,391,652
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				5,589,695		5,532,935

OTHER NONCURRENT ASSETS
Regulatory Assets				367,406		369,905
Deferred Charges and Other Noncurrent Assets				133,123		92,890
TOTAL OTHER NONCURRENT ASSETS				500,529		462,795

TOTAL ASSETS			$	6,650,228	$	6,561,782

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

128

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 2014 and December 31, 2013
(Unaudited)

		March 31,		December 31,
		2014		2013
			(in thousands)
CURRENT LIABILITIES
Advances from Affiliates		$	117,342	$	9,180
Accounts Payable:
	General		138,177		152,653
	Affiliated Companies		53,742		56,923
Long-term Debt Due Within One Year – Nonaffiliated			56,750		3,250
Customer Deposits			57,065		56,375
Accrued Taxes			83,946		41,508
Accrued Interest			18,565		43,996
Obligations Under Capital Leases			18,220		17,899
Regulatory Liability for Over-Recovered Fuel Costs			-		7,275
Other Current Liabilities			61,448		79,622
TOTAL CURRENT LIABILITIES			605,255		468,681

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			1,985,046		2,040,082
Deferred Income Taxes			1,277,745		1,271,478
Regulatory Liabilities and Deferred Investment Tax Credits			477,469		472,128
Asset Retirement Obligations			88,866		87,630
Employee Benefits and Pension Obligations			13,914		14,602
Obligations Under Capital Leases			102,984		105,086
Deferred Credits and Other Noncurrent Liabilities			46,038		46,178
TOTAL NONCURRENT LIABILITIES			3,992,062		4,037,184

TOTAL LIABILITIES			4,597,317		4,505,865

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

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			1,250,477		1,253,617
Accumulated Other Comprehensive Income (Loss)			(8,176)		(8,444)
TOTAL COMMON SHAREHOLDER’S EQUITY			2,052,567		2,055,439

Noncontrolling Interest			344		478

TOTAL EQUITY			2,052,911		2,055,917

TOTAL LIABILITIES AND EQUITY		$	6,650,228	$	6,561,782

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

129

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2014 and 2013
(in thousands)
(Unaudited)

				Three Months Ended March 31,
				2014		2013
OPERATING ACTIVITIES
Net Income				$	22,962	$	11,548
Adjustments to Reconcile Net Income to Net Cash Flows from
	Operating Activities:
		Depreciation and Amortization			45,661		44,882
		Deferred Income Taxes			11,351		25,583
		Allowance for Equity Funds Used During Construction			(2,081)		(1,024)
		Mark-to-Market of Risk Management Contracts			(825)		(293)
		Property Taxes			(37,511)		(36,161)
		Fuel Over/Under-Recovery, Net			(21,651)		(7,496)
		Change in Other Noncurrent Assets			3,963		(1,245)
		Change in Other Noncurrent Liabilities			2,914		4,953
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		13,614		11,654
			Fuel, Materials and Supplies		5,102		3,303
			Accounts Payable		(9,410)		(12,658)
			Customer Deposits		690		(14,202)
			Accrued Taxes, Net		42,596		27,994
			Accrued Interest		(25,431)		(25,447)
			Other Current Assets		(4,663)		(638)
			Other Current Liabilities		(18,813)		(13,551)
Net Cash Flows from Operating Activities					28,468		17,202

INVESTING ACTIVITIES
Construction Expenditures					(105,165)		(97,786)
Change in Advances to Affiliates, Net					-		126,944
Other Investing Activities					1,046		(1,108)
Net Cash Flows from (Used for) Investing Activities					(104,119)		28,050

FINANCING ACTIVITIES
Credit Facility Borrowings					-		17,091
Change in Advances from Affiliates, Net					108,162		-
Retirement of Long-term Debt – Nonaffiliated					(1,625)		(1,625)
Credit Facility Repayments					-		(19,694)
Principal Payments for Capital Lease Obligations					(4,470)		(4,225)
Dividends Paid on Common Stock					(25,000)		(31,250)
Dividends Paid on Common Stock – Nonaffiliated					(1,236)		(964)
Other Financing Activities					574		522
Net Cash Flows from (Used for) Financing Activities					76,405		(40,145)

Net Increase in Cash and Cash Equivalents					754		5,107
Cash and Cash Equivalents at Beginning of Period					17,241		2,036
Cash and Cash Equivalents at End of Period				$	17,995	$	7,143

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	55,123	$	55,626
Net Cash Paid (Received) for Income Taxes					734		(8,387)
Noncash Acquisitions Under Capital Leases					2,824		2,454
Construction Expenditures Included in Current Liabilities as of March 31,					53,628		40,990

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 132.

130

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	133
New Accounting Pronouncement	133
Comprehensive Income	134
Rate Matters	141
Commitments, Guarantees and Contingencies	149
Benefit Plans	152
Business Segments	153
Derivatives and Hedging	154
Fair Value Measurements	166
Income Taxes	177
Financing Activities	178
Variable Interest Entities	181

131

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	133
New Accounting Pronouncement	APCo, I&M, OPCo, PSO, SWEPCo	133
Comprehensive Income	APCo, I&M, OPCo, PSO, SWEPCo	134
Rate Matters	APCo, I&M, OPCo, PSO, SWEPCo	141
Commitments, Guarantees and Contingencies	APCo, I&M, OPCo, PSO, SWEPCo	149
Benefit Plans	APCo, I&M, OPCo, PSO, SWEPCo	152
Business Segments	APCo, I&M, OPCo, PSO, SWEPCo	153
Derivatives and Hedging	APCo, I&M, OPCo, PSO, SWEPCo	154
Fair Value Measurements	APCo, I&M, OPCo, PSO, SWEPCo	166
Income Taxes	APCo, I&M, OPCo, PSO, SWEPCo	177
Financing Activities	APCo, I&M, OPCo, PSO, SWEPCo	178
Variable Interest Entities	APCo, I&M, OPCo, PSO, SWEPCo	181

132

1. SIGNIFICANT ACCOUNTING MATTERS

General

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

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014.

Revenue Recognition

Electricity Supply and Delivery Activities – Transactions with PJM

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrant Subsidiaries recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.

APCo and I&M sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary’s retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenue on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices.

2. NEW ACCOUNTING PRONOUNCEMENT

Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following summary of a final pronouncement will impact the financial statements.

ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08)

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management plans to adopt ASU 2014-08 effective January 1, 2015.

133

3. COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 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 March 31, 2014

			Cash Flow Hedges
					Interest Rate and		Pension
			Commodity		Foreign Currency		and OPEB		Total
			(in thousands)
	Balance in AOCI as of December 31, 2013		$	94	$	3,090	$	(233)	$	2,951
	Change in Fair Value Recognized in AOCI			1,583		-		-		1,583
	Amounts Reclassified from AOCI			(1,590)		253		(333)		(1,670)
	Net Current Period Other
		Comprehensive Income		(7)		253		(333)		(87)
	Balance in AOCI as of March 31, 2014		$	87	$	3,343	$	(566)	$	2,864

APCo
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended March 31, 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			794		(1)		-		793
	Amounts Reclassified from AOCI			211		254		358		823
	Net Current Period Other
		Comprehensive Income		1,005		253		358		1,616
	Balance in AOCI as of March 31, 2013		$	361	$	2,330	$	(30,973)	$	(28,282)

134

I&M
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended March 31, 2014

			Cash Flow Hedges
					Interest Rate and		Pension
			Commodity		Foreign Currency		and OPEB		Total
			(in thousands)
	Balance in AOCI as of December 31, 2013		$	46	$	(15,976)	$	421	$	(15,509)
	Change in Fair Value Recognized in AOCI			1,062		-		-		1,062
	Amounts Reclassified from AOCI			(1,047)		410		43		(594)
	Net Current Period Other
		Comprehensive Income		15		410		43		468
	Balance in AOCI as of March 31, 2014		$	61	$	(15,566)	$	464	$	(15,041)

I&M
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended March 31, 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			532		2,249		-		2,781
	Amounts Reclassified from AOCI			150		192		176		518
	Net Current Period Other
		Comprehensive Income		682		2,441		176		3,299
	Balance in AOCI as of March 31, 2013		$	236	$	(17,206)	$	(8,614)	$	(25,584)

OPCo
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended March 31, 2014

			Cash Flow Hedges
					Interest Rate and		Pension
			Commodity		Foreign Currency		and OPEB		Total
			(in thousands)
	Balance in AOCI as of December 31, 2013		$	105	$	6,974	$	-	$	7,079
	Change in Fair Value Recognized in AOCI			-		-		-		-
	Amounts Reclassified from AOCI			(105)		(343)		-		(448)
	Net Current Period Other
		Comprehensive Income		(105)		(343)		-		(448)
	Balance in AOCI as of March 31, 2014		$	-	$	6,631	$	-	$	6,631

OPCo
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended March 31, 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			1,102		-		-		1,102
	Amounts Reclassified from AOCI			304		(340)		3,269		3,233
	Net Current Period Other
		Comprehensive Income		1,406		(340)		3,269		4,335
	Balance in AOCI as of March 31, 2013		$	494	$	7,755	$	(169,639)	$	(161,390)

135

PSO
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended March 31, 2014

			Cash Flow Hedges
					Interest Rate and
			Commodity		Foreign Currency		Total

			(in thousands)
	Balance in AOCI as of December 31, 2013		$	57	$	5,701	$	5,758
	Change in Fair Value Recognized in AOCI			-		-		-
	Amounts Reclassified from AOCI			(57)		(189)		(246)
	Net Current Period Other
		Comprehensive Income		(57)		(189)		(246)
	Balance in AOCI as of March 31, 2014		$	-	$	5,512	$	5,512

PSO
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended March 31, 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			36		-		36
	Amounts Reclassified from AOCI			(13)		(190)		(203)
	Net Current Period Other
		Comprehensive Income		23		(190)		(167)
	Balance in AOCI as of March 31, 2013		$	44	$	6,270	$	6,314

SWEPCo
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended March 31, 2014

			Cash Flow Hedges
					Interest Rate and		Pension
			Commodity		Foreign Currency		and OPEB		Total
			(in thousands)
	Balance in AOCI as of December 31, 2013		$	66	$	(13,304)	$	4,794	$	(8,444)
	Change in Fair Value Recognized in AOCI			-		-		-		-
	Amounts Reclassified from AOCI			(66)		568		(234)		268
	Net Current Period Other
		Comprehensive Income		(66)		568		(234)		268
	Balance in AOCI as of March 31, 2014		$	-	$	(12,736)	$	4,560	$	(8,176)

SWEPCo
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended March 31, 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			44		-		-		44
	Amounts Reclassified from AOCI			(15)		567		(63)		489
	Net Current Period Other
		Comprehensive Income		29		567		(63)		533
	Balance in AOCI as of March 31, 2013		$	51	$	(15,004)	$	(2,374)	$	(17,327)

136

Reclassifications from Accumulated Other Comprehensive Income

The following tables provide details of reclassifications from AOCI for the three months ended March 31, 2014 and 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.

APCo
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Three Months Ended March 31, 2014 and 2013

			Amount of (Gain) Loss
			Reclassified from AOCI

			Three Months Ended March 31,
			2014		2013
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Electric Generation, Transmission and Distribution Revenues	$	-	$	20
		Purchased Electricity for Resale		(462)		57
		Other Operation Expense		(10)		(11)
		Maintenance Expense		(20)		(16)
		Property, Plant and Equipment		(17)		(14)
		Regulatory Assets/(Liabilities), Net (a)		(1,937)		289
	Subtotal - Commodity			(2,446)		325

	Interest Rate and Foreign Currency:
		Interest Expense		390		390
	Subtotal - Interest Rate and Foreign Currency			390		390

	Reclassifications from AOCI, before Income Tax (Expense) Credit			(2,056)		715
	Income Tax (Expense) Credit			(719)		250
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			(1,337)		465

	Pension and OPEB
	Amortization of Prior Service Cost (Credit)			(1,282)		(1,282)
	Amortization of Actuarial (Gains)/Losses			770		1,833
	Reclassifications from AOCI, before Income Tax (Expense) Credit			(512)		551
	Income Tax (Expense) Credit			(179)		193
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			(333)		358

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	(1,670)	$	823

137

I&M
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Three Months Ended March 31, 2014 and 2013

			Amount of (Gain) Loss
			Reclassified from AOCI

			Three Months Ended March 31,
			2014		2013
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Electric Generation, Transmission and Distribution Revenues	$	-	$	52
		Purchased Electricity for Resale		(717)		149
		Other Operation Expense		(7)		(7)
		Maintenance Expense		(7)		(7)
		Property, Plant and Equipment		(10)		(7)
		Regulatory Assets/(Liabilities), Net (a)		(870)		50
	Subtotal - Commodity			(1,611)		230

	Interest Rate and Foreign Currency:
		Interest Expense		631		296
	Subtotal - Interest Rate and Foreign Currency			631		296

	Reclassifications from AOCI, before Income Tax (Expense) Credit			(980)		526
	Income Tax (Expense) Credit			(343)		184
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			(637)		342

	Pension and OPEB
	Amortization of Prior Service Cost (Credit)			(199)		(199)
	Amortization of Actuarial (Gains)/Losses			265		469
	Reclassifications from AOCI, before Income Tax (Expense) Credit			66		270
	Income Tax (Expense) Credit			23		94
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			43		176

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	(594)	$	518

138

OPCo
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Three Months Ended March 31, 2014 and 2013

			Amount of (Gain) Loss
			Reclassified from AOCI

			Three Months Ended March 31,
			2014		2013
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Electric Generation, Transmission and Distribution Revenues	$	-	$	134
		Purchased Electricity for Resale		-		382
		Other Operation Expense		(11)		(18)
		Maintenance Expense		(11)		(12)
		Property, Plant and Equipment		(18)		(19)
		Regulatory Assets/(Liabilities), Net (a)		(122)		-
	Subtotal - Commodity			(162)		467

	Interest Rate and Foreign Currency:
		Depreciation and Amortization Expense		(3)		2
		Interest Expense		(524)		(524)
	Subtotal - Interest Rate and Foreign Currency			(527)		(522)

	Reclassifications from AOCI, before Income Tax (Expense) Credit			(689)		(55)
	Income Tax (Expense) Credit			(241)		(19)
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			(448)		(36)

	Pension and OPEB
	Amortization of Prior Service Cost (Credit)			-		(1,468)
	Amortization of Actuarial (Gains)/Losses			-		6,497
	Reclassifications from AOCI, before Income Tax (Expense) Credit			-		5,029
	Income Tax (Expense) Credit			-		1,760
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			-		3,269

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	(448)	$	3,233

PSO
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Three Months Ended March 31, 2014 and 2013

			Amount of (Gain) Loss
			Reclassified from AOCI

			Three Months Ended March 31,
			2014		2013
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Other Operation Expense	$	(8)	$	(9)
		Maintenance Expense		(9)		(4)
		Property, Plant and Equipment		(13)		(7)
		Regulatory Assets/(Liabilities), Net (a)		(58)		-
	Subtotal - Commodity			(88)		(20)

	Interest Rate and Foreign Currency:
		Interest Expense		(292)		(292)
	Subtotal - Interest Rate and Foreign Currency			(292)		(292)

	Reclassifications from AOCI, before Income Tax (Expense) Credit			(380)		(312)
	Income Tax (Expense) Credit			(134)		(109)
	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	(246)	$	(203)

139

SWEPCo
	Reclassifications from Accumulated Other Comprehensive Income (Loss)
	For the Three Months Ended March 31, 2014 and 2013

			Amount of (Gain) Loss
			Reclassified from AOCI

			Three Months Ended March 31,
			2014		2013
	Gains and Losses on Cash Flow Hedges		(in thousands)
	Commodity:
		Other Operation Expense	$	(13)	$	(10)
		Maintenance Expense		(10)		(6)
		Property, Plant and Equipment		(11)		(7)
		Regulatory Assets/(Liabilities), Net (a)		(67)		-
	Subtotal - Commodity			(101)		(23)

	Interest Rate and Foreign Currency:
		Interest Expense		872		872
	Subtotal - Interest Rate and Foreign Currency			872		872

	Reclassifications from AOCI, before Income Tax (Expense) Credit			771		849
	Income Tax (Expense) Credit			269		297
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			502		552

	Pension and OPEB
	Amortization of Prior Service Cost (Credit)			(478)		(445)
	Amortization of Actuarial (Gains)/Losses			118		348
	Reclassifications from AOCI, before Income Tax (Expense) Credit			(360)		(97)
	Income Tax (Expense) Credit			(126)		(34)
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit			(234)		(63)

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit		$	268	$	489

(a)

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

140

4. RATE MATTERS

As discussed in the 2013 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 2013 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 2014 and updates the 2013 Annual Report.

Regulatory Assets Not Yet Being Recovered

			APCo
			March 31,		December 31,
			2014		2013
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	$	65,206
	IGCC Pre-Construction Costs			20,528		-
	Expanded Net Energy Charge - Coal Inventory			18,818		20,528
	Mountaineer Carbon Capture and Storage
		Product Validation Facility		13,264		13,264
	Virginia Demand Response Program Costs			5,897		5,012
	Transmission Agreement Phase-In			3,450		3,313
	Virginia Environmental Rate Adjustment Clause			1,941		2,440
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility		1,287		1,287
	Other Regulatory Assets Not Yet Being Recovered			513		168
Total Regulatory Assets Not Yet Being Recovered			$	130,904	$	111,218

		I&M
		March 31,		December 31,
		2014		2013
Noncurrent Regulatory Assets		(in thousands)
Regulatory assets not yet being recovered pending future proceedings:

Regulatory Assets Currently Not Earning a Return
	Indiana Under-Recovered Capacity Costs	$	28,149	$	21,945
	Cook Plant Turbine		4,238		3,452
	Stranded Costs on Abandoned Plants		3,897		3,896
	Storm Related Costs		751		1,836
	Indiana Deferred Cook Plant Life Cycle Management Project Costs		-		4,093
	Other Regulatory Assets Not Yet Being Recovered		694		164
Total Regulatory Assets Not Yet Being Recovered		$	37,729	$	35,386

		OPCo
		March 31,		December 31,
		2014		2013
Noncurrent Regulatory Assets		(in thousands)
Regulatory assets not yet being recovered pending future proceedings:

Regulatory Assets Currently Earning a Return
	Economic Development Rider	$	-	$	13,854
Regulatory Assets Currently Not Earning a Return
	Ormet Special Rate Recovery Mechanism		10,483		35,631
	Storm Related Costs		1,635		57,589
Total Regulatory Assets Not Yet Being Recovered		$	12,118	$	107,074

141

		PSO
		March 31,		December 31,
		2014		2013
Noncurrent Regulatory Assets		(in thousands)
Regulatory assets not yet being recovered pending future proceedings:

Regulatory Assets Currently Not Earning a Return
	Storm Related Costs	$	19,093	$	18,743
	Other Regulatory Assets Not Yet Being Recovered		1,079		845
Total Regulatory Assets Not Yet Being Recovered		$	20,172	$	19,588

			SWEPCo
			March 31,		December 31,
			2014		2013
Noncurrent Regulatory Assets			(in thousands)
Regulatory assets not yet being recovered pending future proceedings:

Regulatory Assets Currently Not Earning a Return
	Rate Case Expenses		$	7,930	$	7,934
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility		1,143		1,143
	Other Regulatory Assets Not Yet Being Recovered			2,025		1,951
Total Regulatory Assets Not Yet Being Recovered			$	11,098	$	11,028

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 Filings

2009 – 2011 ESP

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net deferred fuel balance up to the total balance. These intervenors’ appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of March 31, 2014, could reduce carrying costs by $30 million including $16 million of unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending.

June 2012 – May 2015 ESP Including Capacity Charge

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. As of March 31, 2014, OPCo’s incurred deferred capacity costs balance of $348 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

Proposed June 2015 – May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider, effective June 2015 through May 2018. This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to market. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation

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Significantly Excessive Earnings Test (SEET) Filings

Corporate Separation

Storm Damage Recovery Rider (SDRR)

2009 Fuel Adjustment Clause Audit

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2010 and 2011 Fuel Adjustment Clause Audits

2012 – 2013 Fuel Adjustment Clause Audits

Ormet

To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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Ohio IGCC Plant

SWEPCo Rate Matters

2012 Texas Base Rate Case

2013 Texas Transmission Cost Recovery Factor Filing

2012 Louisiana Formula Rate Filing

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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.

2014 Louisiana Formula Rate Filing

APCo Rate Matters

Plant Transfer

APCo IGCC Plant

2013 Virginia Transmission Rate Adjustment Clause (transmission RAC)

2014 Virginia Biennial Base Rate Case

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WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting authority 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 merger. Also 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. In June 2013, the WVPSC issued an order consolidating the merger case with APCo’s plant asset transfer case. In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo. In December 2013, the WVPSC issued an order that deferred ruling on the merger of WPCo into APCo. The order also directed APCo and WPCo to submit a plan with the WVPSC identifying a course of action to serve the load of WPCo. See the “Plant Transfer” section of APCo Rate Matters. The feasibility of the merger remains under review.

PSO Rate Matters

2014 Oklahoma Base Rate Case

In April 2014, OCC Staff and intervenors filed testimony with recommendations that included adjustments to annual base rates ranging from an increase of $ 16 million to a reduction of $ 22 million, primarily based upon the determination of depreciation rates and a return on common equity between 9.18% and 9.5%. Additionally, the recommendations did not support the advanced metering rider or the expansion of the transmission rider. A hearing at the OCC is scheduled for June 2014. If the OCC were to disallow any portion of this base rate request, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

2011 Indiana Base Rate Case

Cook Plant Life Cycle Management Project (LCM Project)

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certain projects effective January 2012 to the extent such costs are not reflected in rates. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC.

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.

Tanners Creek Plant, Units 1 - 4

5. 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 2013 Annual Report should be read in conjunction with this report.

GUARANTEES

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

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

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

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AEP has two revolving credit facilities totaling $3.5 billion, under which up to $1.2 billion may be issued as letters of credit. As of March 31, 2014, the maximum future payments for letters of credit issued under the revolving credit facilities were as follows:

Company	Amount		Maturity
	(in thousands)
I&M	$	150	March 2015
OPCo		3,081	June 2014

The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 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 2016 to March 2017
I&M		77,000		77,886	March 2015

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 March 31, 2014, SWEPCo has collected approximately $62 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $46 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 March 31, 2014, 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.

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

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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 March 31, 2014, 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	$	3,772
I&M		2,580
OPCo		4,384
PSO		1,347
SWEPCo		2,486

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 March 31, 2014.

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

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 generation 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 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 $8 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

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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.

OPERATIONAL CONTINGENCIES

Rockport Plant Litigation – Affecting I&M

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. The motion to dismiss, filed in October 2013, is pending. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Wage and Hours Lawsuit – Affecting PSO

In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Management will continue to defend the case. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

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 months ended March 31, 2014 and 2013:

APCo
					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended March 31,				Three Months Ended March 31,
	2014		2013		2014		2013
	(in thousands)
Service Cost	$	1,759	$	1,543	$	362	$	641
Interest Cost		7,406		6,916		3,197		3,363
Expected Return on Plan Assets		(8,482)		(9,260)		(4,633)		(4,536)
Amortization of Prior Service Cost (Credit)		50		49		(2,513)		(2,512)
Amortization of Net Actuarial Loss		4,148		6,256		1,146		3,062
Net Periodic Benefit Cost (Credit)	$	4,881	$	5,504	$	(2,441)	$	18

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I&M
					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended March 31,				Three Months Ended March 31,
	2014		2013		2014		2013
	(in thousands)
Service Cost	$	2,517	$	2,184	$	487	$	805
Interest Cost		6,573		6,025		1,909		2,055
Expected Return on Plan Assets		(7,748)		(8,207)		(3,364)		(3,296)
Amortization of Prior Service Cost (Credit)		49		49		(2,355)		(2,355)
Amortization of Net Actuarial Loss		3,646		5,422		592		1,882
Net Periodic Benefit Cost (Credit)	$	5,037	$	5,473	$	(2,731)	$	(909)

OPCo
					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended March 31,				Three Months Ended March 31,
	2014		2013		2014		2013
	(in thousands)
Service Cost	$	1,285	$	2,372	$	256	$	1,300
Interest Cost		5,526		10,292		1,901		4,447
Expected Return on Plan Assets		(6,607)		(15,141)		(3,380)		(6,238)
Amortization of Prior Service Cost (Credit)		39		71		(1,731)		(3,231)
Amortization of Net Actuarial Loss		3,106		9,309		595		4,041
Net Periodic Benefit Cost (Credit)	$	3,349	$	6,903	$	(2,359)	$	319

PSO
					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended March 31,				Three Months Ended March 31,
	2014		2013		2014		2013
	(in thousands)
Service Cost	$	1,302	$	1,391	$	210	$	343
Interest Cost		3,014		2,748		893		948
Expected Return on Plan Assets		(3,651)		(3,918)		(1,575)		(1,522)
Amortization of Prior Service Cost (Credit)		74		74		(1,072)		(1,072)
Amortization of Net Actuarial Loss		1,688		2,461		277		869
Net Periodic Benefit Cost (Credit)	$	2,427	$	2,756	$	(1,267)	$	(434)

SWEPCo
					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended March 31,				Three Months Ended March 31,
	2014		2013		2014		2013
	(in thousands)
Service Cost	$	1,655	$	1,753	$	253	$	423
Interest Cost		3,163		2,864		998		1,075
Expected Return on Plan Assets		(3,857)		(4,127)		(1,754)		(1,720)
Amortization of Prior Service Cost (Credit)		87		87		(1,289)		(1,288)
Amortization of Net Actuarial Loss		1,761		2,553		309		982
Net Periodic Benefit Cost (Credit)	$	2,809	$	3,130	$	(1,483)	$	(528)

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

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The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of March 31, 2014 and December 31, 2013:

Notional Volume of Derivative Instruments
March 31, 2014

Primary Risk			Unit of
Exposure			Measure	APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Commodity:
	Power		MWhs		29,680		19,636		12,108		9,251		11,716
	Coal		Tons		186		2,666		-		750		1,292
	Natural Gas		MMBtus		1,934		1,312		-		-		-
	Heating Oil and
		Gasoline	Gallons		792		379		806		446		508
	Interest Rate		USD	$	10,877	$	7,378	$	-	$	-	$	-

Interest Rate and
	Foreign Currency		USD	$	-	$	-	$	-	$	-	$	-

Notional Volume of Derivative Instruments
December 31, 2013

Primary Risk			Unit of
Exposure			Measure	APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Commodity:
	Power		MWhs		48,995		33,231		34,843		13,469		17,057
	Coal		Tons		31		3,389		-		1,013		1,692
	Natural Gas		MMBtus		2,477		1,680		-		-		-
	Heating Oil and
		Gasoline	Gallons		1,089		521		1,108		614		699
	Interest Rate		USD	$	12,720	$	8,627	$	-	$	-	$	-

Interest Rate and
	Foreign Currency		USD	$	-	$	-	$	-	$	-	$	-

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 and natural gas (“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. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.

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

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

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

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

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

According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the March 31, 2014 and December 31, 2013 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:

	March 31, 2014				December 31, 2013
	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	$	32	$	1,362	$	-	$	2,993
I&M		21		924		-		2,030
OPCo		3		-		-		-
PSO		1		-		-		1
SWEPCo		2		-		-		3

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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 March 31, 2014 and December 31, 2013:

APCo
Fair Value of Derivative Instruments
March 31, 2014

		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		$	34,483	$	224	$	-	$	34,707	$	(18,735)	$	15,972
Long-term Risk Management Assets			17,304		-		-		17,304		(3,291)		14,013
Total Assets			51,787		224		-		52,011		(22,026)		29,985

Current Risk Management Liabilities			24,273		90		-		24,363		(19,727)		4,636
Long-term Risk Management Liabilities			11,558		-		-		11,558		(3,629)		7,929
Total Liabilities			35,831		90		-		35,921		(23,356)		12,565

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	15,956	$	134	$	-	$	16,090	$	1,330	$	17,420

APCo
Fair Value of Derivative Instruments
December 31, 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		$	46,431	$	389	$	-	$	46,820	$	(25,649)	$	21,171
Long-term Risk Management Assets			20,948		-		-		20,948		(4,000)		16,948
Total Assets			67,379		389		-		67,768		(29,649)		38,119

Current Risk Management Liabilities			37,010		313		-		37,323		(28,431)		8,892
Long-term Risk Management Liabilities			14,452		-		-		14,452		(4,211)		10,241
Total Liabilities			51,462		313		-		51,775		(32,642)		19,133

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	15,917	$	76	$	-	$	15,993	$	2,993	$	18,986

157

I&M
Fair Value of Derivative Instruments
March 31, 2014

		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		$	26,273	$	152	$	-	$	26,425	$	(13,867)	$	12,558
Long-term Risk Management Assets			11,737		-		-		11,737		(2,232)		9,505
Total Assets			38,010		152		-		38,162		(16,099)		22,063

Current Risk Management Liabilities			18,614		61		-		18,675		(14,541)		4,134
Long-term Risk Management Liabilities			7,839		-		-		7,839		(2,461)		5,378
Total Liabilities			26,453		61		-		26,514		(17,002)		9,512

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	11,557	$	91	$	-	$	11,648	$	903	$	12,551

I&M
Fair Value of Derivative Instruments
December 31, 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		$	33,229	$	234	$	-	$	33,463	$	(18,075)	$	15,388
Long-term Risk Management Assets			14,208		-		-		14,208		(2,713)		11,495
Total Assets			47,437		234		-		47,671		(20,788)		26,883

Current Risk Management Liabilities			26,779		212		-		26,991		(19,962)		7,029
Long-term Risk Management Liabilities			9,802		-		-		9,802		(2,856)		6,946
Total Liabilities			36,581		212		-		36,793		(22,818)		13,975

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	10,856	$	22	$	-	$	10,878	$	2,030	$	12,908

158

OPCo
Fair Value of Derivative Instruments
March 31, 2014

		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		$	4,066	$	-	$	-	$	4,066	$	(86)	$	3,980
Long-term Risk Management Assets			-		-		-		-		-		-
Total Assets			4,066		-		-		4,066		(86)		3,980

Current Risk Management Liabilities			83		-		-		83		(83)		-
Long-term Risk Management Liabilities			-		-		-		-		-		-
Total Liabilities			83		-		-		83		(83)		-

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	3,983	$	-	$	-	$	3,983	$	(3)	$	3,980

OPCo
Fair Value of Derivative Instruments
December 31, 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		$	3,269	$	162	$	-	$	3,431	$	(349)	$	3,082
Long-term Risk Management Assets			-		-		-		-		-		-
Total Assets			3,269		162		-		3,431		(349)		3,082

Current Risk Management Liabilities			349		-		-		349		(349)		-
Long-term Risk Management Liabilities			-		-		-		-		-		-
Total Liabilities			349		-		-		349		(349)		-

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	2,920	$	162	$	-	$	3,082	$	-	$	3,082

159

PSO
Fair Value of Derivative Instruments
March 31, 2014

		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		$	1,403	$	-	$	-	$	1,403	$	(54)	$	1,349
Long-term Risk Management Assets			-		-		-		-		-		-
Total Assets			1,403		-		-		1,403		(54)		1,349

Current Risk Management Liabilities			136		-		-		136		(53)		83
Long-term Risk Management Liabilities			-		-		-		-		-		-
Total Liabilities			136		-		-		136		(53)		83

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	1,267	$	-	$	-	$	1,267	$	(1)	$	1,266

PSO
Fair Value of Derivative Instruments
December 31, 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		$	1,078	$	84	$	-	$	1,162	$	5	$	1,167
Long-term Risk Management Assets			-		-		-		-		-		-
Total Assets			1,078		84		-		1,162		5		1,167

Current Risk Management Liabilities			81		-		-		81		4		85
Long-term Risk Management Liabilities			-		-		-		-		-		-
Total Liabilities			81		-		-		81		4		85

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	997	$	84	$	-	$	1,081	$	1	$	1,082

160

SWEPCo
Fair Value of Derivative Instruments
March 31, 2014

		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		$	2,080	$	-	$	-	$	2,080	$	(173)	$	1,907
Long-term Risk Management Assets			-		-		-		-		-		-
Total Assets			2,080		-		-		2,080		(173)		1,907

Current Risk Management Liabilities			171		-		-		171		(171)		-
Long-term Risk Management Liabilities			-		-		-		-		-		-
Total Liabilities			171		-		-		171		(171)		-

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	1,909	$	-	$	-	$	1,909	$	(2)	$	1,907

SWEPCo
Fair Value of Derivative Instruments
December 31, 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		$	1,233	$	97	$	-	$	1,330	$	(151)	$	1,179
Long-term Risk Management Assets			-		-		-		-		-		-
Total Assets			1,233		97		-		1,330		(151)		1,179

Current Risk Management Liabilities			154		-		-		154		(154)		-
Long-term Risk Management Liabilities			-		-		-		-		-		-
Total Liabilities			154		-		-		154		(154)		-

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	1,079	$	97	$	-	$	1,176	$	3	$	1,179

(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.

161

The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three months ended March 31, 2014 and 2013:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended March 31, 2014

Location of Gain (Loss)		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	4,847	$	6,156	$	-	$	64	$	23
Sales to AEP Affiliates			-		(221)		-		221		-
Regulatory Assets (a)			4		-		-		2		3
Regulatory Liabilities (a)			32,332		18,317		35,099		480		1,330
Total Gain on Risk Management
	Contracts	$	37,183	$	24,252	$	35,099	$	767	$	1,356

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended March 31, 2013

Location of Gain (Loss)		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	679	$	4,947	$	1,714	$	47	$	28
Regulatory Assets (a)			-		486		(1,205)		2,010		271
Regulatory Liabilities (a)			(466)		(5,182)		-		1		96
Total Gain on Risk Management
	Contracts	$	213	$	251	$	509	$	2,058	$	395

(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.

Accounting for Fair Value Hedging Strategies

162

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. During the three months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. During the three months ended March 31, 2013, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2014 and 2013, I&M 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 months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges.

During the three months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, see Note 3.

163

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 2014 and December 31, 2013 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
March 31, 2014

	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	$	209	$	-	$	75	$	-	$	87	$	3,343
I&M		142		-		51		-		61		(15,566)
OPCo		-		-		-		-		-		6,631
PSO		-		-		-		-		-		5,512
SWEPCo		-		-		-		-		-		(12,736)

	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	$	87	$	(682)		2
I&M		61		(1,426)		2
OPCo		-		1,372		-
PSO		-		759		-
SWEPCo		-		(2,267)		-

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 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	$	363	$	-	$	287	$	-	$	94	$	3,090
I&M		216		-		194		-		46		(15,976)
OPCo		162		-		-		-		105		6,974
PSO		84		-		-		-		57		5,701
SWEPCo		97		-		-		-		66		(13,304)

	Expected to be Reclassified to
	Net Income During the Next
	Twelve Months
			Interest Rate
			and Foreign
Company	Commodity		Currency
	(in thousands)
APCo	$	94	$	(806)
I&M		46		(1,568)
OPCo		105		1,363
PSO		57		759
SWEPCo		66		(2,267)

(a)

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

164

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 March 31, 2014 and December 31, 2013:

	March 31, 2014
	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	$	285	$	5,254	$	4,774
I&M		190		3,560		3,238
OPCo		78		-		-
PSO		132		4,156		-
SWEPCo		167		145		-

	December 31, 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	$	575	$	2,747	$	2,539
I&M		390		1,863		1,722
OPCo		349		-		-
PSO		-		2,930		410
SWEPCo		-		713		519

165

In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of March 31, 2014 and December 31, 2013:

	March 31, 2014
	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	$	16,375	$	-	$	12,865
I&M		11,107		-		8,726
OPCo		-		-		-
PSO		-		-		-
SWEPCo		-		-		-

	December 31, 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	$	19,648	$	-	$	18,568
I&M		13,326		-		12,594
OPCo		-		-		-
PSO		3		-		3
SWEPCo		3		-		3

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 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. The AEP System’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.

166

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, Restricted Cash for Securitized Funding 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 March 31, 2014 and December 31, 2013 are summarized in the following table:

	March 31, 2014				December 31, 2013
Company	Book Value		Fair Value		Book Value		Fair Value
	(in thousands)
APCo	$	4,194,516	$	4,730,819	$	4,194,357	$	4,587,079
I&M		2,012,844		2,203,640		2,039,016		2,174,891
OPCo		2,510,285		2,869,364		2,735,175		3,007,191
PSO		1,049,793		1,200,741		999,810		1,111,149
SWEPCo		2,041,796		2,277,262		2,043,332		2,214,730

167

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 March 31, 2014 and December 31, 2013:

		March 31, 2014						December 31, 2013
		Estimated		Gross		Other-Than-		Estimated		Gross		Other-Than-
		Fair		Unrealized		Temporary		Fair		Unrealized		Temporary
		Value		Gains		Impairments		Value		Gains		Impairments
		(in thousands)
Cash and Cash Equivalents		$	12,439	$	-	$	-	$	18,804	$	-	$	-
Fixed Income Securities:
	United States Government		606,228		31,666		(3,621)		608,875		26,114		(3,824)
	Corporate Debt		42,727		3,223		(1,097)		36,782		2,450		(1,123)
	State and Local Government		280,612		972		(345)		254,638		748		(370)
	Subtotal Fixed Income Securities		929,567		35,861		(5,063)		900,295		29,312		(5,317)
Equity Securities - Domestic			1,020,145		513,803		(79,563)		1,012,511		505,538		(81,677)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,962,151	$	549,664	$	(84,626)	$	1,931,610	$	534,850	$	(86,994)

The following table provides the securities activity within the decommissioning and SNF trusts for the three months ended March 31, 2014 and 2013:

	Three Months Ended March 31,
	2014		2013
	(in thousands)
Proceeds from Investment Sales	$	147,700	$	167,670
Purchases of Investments		164,511		184,299
Gross Realized Gains on Investment Sales		8,141		3,323
Gross Realized Losses on Investment Sales		874		2,315

168

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2014 was as follows:

	Fair Value of
	Fixed Income
	Securities
	(in thousands)
Within 1 year	$	82,190
1 year – 5 years		386,173
5 years – 10 years		193,018
After 10 years		268,186
Total	$	929,567

169

Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 and December 31, 2013. 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
March 31, 2014

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

Restricted Cash for Securitized Funding (a)		$	13,536	$	-	$	-	$	36	$	13,572

Risk Management Assets
Risk Management Commodity Contracts (b) (c)			393		37,854		10,508		(18,979)		29,776
Cash Flow Hedges:
	Commodity Hedges (b)		-		224		-		(15)		209
Total Risk Management Assets			393		38,078		10,508		(18,994)		29,985

Total Assets:		$	13,929	$	38,078	$	10,508	$	(18,958)	$	43,557

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)		$	306	$	29,386	$	3,107	$	(20,309)	$	12,490
Cash Flow Hedges:
	Commodity Hedges (b)		-		90		-		(15)		75
Total Risk Management Liabilities		$	306	$	29,476	$	3,107	$	(20,324)	$	12,565

APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013

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

Restricted Cash for Securitized Funding (a)		$	2,714	$	-	$	-	$	36	$	2,750

Risk Management Assets
Risk Management Commodity Contracts (b) (c)			827		54,448		12,097		(29,616)		37,756
Cash Flow Hedges:
	Commodity Hedges (b)		-		389		-		(26)		363
Total Risk Management Assets			827		54,837		12,097		(29,642)		38,119

Total Assets		$	3,541	$	54,837	$	12,097	$	(29,606)	$	40,869

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)		$	700	$	49,220	$	1,535	$	(32,609)	$	18,846
Cash Flow Hedges:
	Commodity Hedges (b)		-		313		-		(26)		287
Total Risk Management Liabilities		$	700	$	49,533	$	1,535	$	(32,635)	$	19,133

170

I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2014

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

Risk Management Assets
Risk Management Commodity Contracts (b) (c)			$	267	$	28,746	$	6,945	$	(14,037)	$	21,921
Cash Flow Hedges:
	Commodity Hedges (b)			-		152		-		(10)		142
Total Risk Management Assets				267		28,898		6,945		(14,047)		22,063

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (d)				3,576		-		-		8,863		12,439
Fixed Income Securities:
	United States Government			-		606,228		-		-		606,228
	Corporate Debt			-		42,727		-		-		42,727
	State and Local Government			-		280,612		-		-		280,612
		Subtotal Fixed Income Securities		-		929,567		-		-		929,567
Equity Securities - Domestic (e)				1,020,145		-		-		-		1,020,145
Total Spent Nuclear Fuel and Decommissioning Trusts				1,023,721		929,567		-		8,863		1,962,151

Total Assets			$	1,023,988	$	958,465	$	6,945	$	(5,184)	$	1,984,214

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)			$	208	$	22,089	$	2,104	$	(14,940)	$	9,461
Cash Flow Hedges:
	Commodity Hedges (b)			-		61		-		(10)		51
Total Risk Management Liabilities			$	208	$	22,150	$	2,104	$	(14,950)	$	9,512

I&M
		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		December 31, 2013

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

Risk Management Assets
Risk Management Commodity Contracts (b) (c)			$	561	$	38,667	$	8,205	$	(20,766)	$	26,667
Cash Flow Hedges:
	Commodity Hedges (b)			-		234		-		(18)		216
Total Risk Management Assets				561		38,901		8,205		(20,784)		26,883

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (d)				8,082		-		-		10,722		18,804
Fixed Income Securities:
	United States Government			-		608,875		-		-		608,875
	Corporate Debt			-		36,782		-		-		36,782
	State and Local Government			-		254,638		-		-		254,638
		Subtotal Fixed Income Securities		-		900,295		-		-		900,295
Equity Securities - Domestic (e)				1,012,511		-		-		-		1,012,511
Total Spent Nuclear Fuel and Decommissioning Trusts				1,020,593		900,295		-		10,722		1,931,610

Total Assets			$	1,021,154	$	939,196	$	8,205	$	(10,062)	$	1,958,493

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)			$	475	$	35,061	$	1,041	$	(22,796)	$	13,781
Cash Flow Hedges:
	Commodity Hedges (b)			-		212		-		(18)		194
Total Risk Management Liabilities			$	475	$	35,273	$	1,041	$	(22,814)	$	13,975

171

OPCo
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	March 31, 2014

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

Restricted Cash for Securitized Funding (a)		$	32,054	$	-	$	-	$	12	$	32,066

Risk Management Assets
Risk Management Commodity Contracts (b) (c)			-		76		3,990		(86)		3,980

Total Assets		$	32,054	$	76	$	3,990	$	(74)	$	36,046

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)		$	-	$	5	$	78	$	(83)	$	-

OPCo
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2013

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

Restricted Cash for Securitized Funding (a)		$	19,387	$	-	$	-	$	12	$	19,399

Risk Management Assets
Risk Management Commodity Contracts (b) (c)			-		-		3,269		(349)		2,920
Cash Flow Hedges:
	Commodity Hedges (b)		-		162		-		-		162
Total Risk Management Assets			-		162		3,269		(349)		3,082

Total Assets		$	19,387	$	162	$	3,269	$	(337)	$	22,481

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)		$	-	$	-	$	349	$	(349)	$	-

172

PSO
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	March 31, 2014

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

Risk Management Assets
Risk Management Commodity Contracts (b) (c)		$	-	$	922	$	481	$	(54)	$	1,349

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)		$	-	$	4	$	132	$	(53)	$	83

PSO
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2013

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

Risk Management Assets
Risk Management Commodity Contracts (b) (c)		$	-	$	1,078	$	-	$	5	$	1,083
Cash Flow Hedges:
	Commodity Hedges (b)		-		84		-		-		84
Total Risk Management Assets		$	-	$	1,162	$	-	$	5	$	1,167

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)		$	-	$	81	$	-	$	4	$	85

173

SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2014

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

Cash and Cash Equivalents (a)	$	15,537	$	-	$	-	$	2,458	$	17,995

Risk Management Assets
Risk Management Commodity Contracts (b) (c)		-		1,471		609		(173)		1,907

Total Assets	$	15,537	$	1,471	$	609	$	2,285	$	19,902

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)	$	-	$	4	$	167	$	(171)	$	-

SWEPCo
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2013

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

Cash and Cash Equivalents (a)		$	15,871	$	-	$	-	$	1,370	$	17,241

Risk Management Assets
Risk Management Commodity Contracts (b) (c)			-		1,233		-		(151)		1,082
Cash Flow Hedges:
	Commodity Hedges (b)		-		97		-		-		97
Total Risk Management Assets			-		1,330		-		(151)		1,179

Total Assets		$	15,871	$	1,330	$	-	$	1,219	$	18,420

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)		$	-	$	154	$	-	$	(154)	$	-

(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 investment in money market funds.

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

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

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

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

There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 and 2013.

174

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

Three Months Ended March 31, 2014		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of December 31, 2013		$	10,562	$	7,164	$	2,920	$	-	$	-
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		29,162		18,219		30,963		-		-
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		-		-		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-
Purchases, Issuances and Settlements (c)			(31,781)		(19,995)		(34,036)		-		-
Transfers into Level 3 (d) (e)			(3,825)		(2,594)		-		-		-
Transfers out of Level 3 (e) (f)			(6)		(4)		-		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		3,289		2,052		4,065		349		442
Balance as of March 31, 2014		$	7,401	$	4,842	$	3,912	$	349	$	442

Three Months Ended March 31, 2013		APCo		I&M		OPCo		PSO		SWEPCo
		(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)		(1,456)		(1,005)		(2,055)		-		-
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		-		(1,988)		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-
Purchases, Issuances and Settlements (c)			257		179		366		-		-
Transfers into Level 3 (d) (e)			632		434		888		-		-
Transfers out of Level 3 (e) (f)			(533)		(366)		(749)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		(1,123)		(732)		490		-		-
Balance as of March 31, 2013		$	8,756	$	6,051	$	12,381	$	-	$	-

(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.

175

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of March 31, 2014 and December 31, 2013:

Significant Unobservable Inputs
March 31, 2014
APCo
	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	6,454	$	2,822	Discounted Cash Flow	Forward Market Price	$	13.34	$	59.60
FTRs		4,054		285	Discounted Cash Flow	Forward Market Price		(5.05)		9.17
Total	$	10,508	$	3,107

Significant Unobservable Inputs
December 31, 2013
APCo
	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	9,359	$	960	Discounted Cash Flow	Forward Market Price	$	13.04	$	80.50
FTRs		2,738		575	Discounted Cash Flow	Forward Market Price		(5.10)		10.44
Total	$	12,097	$	1,535

Significant Unobservable Inputs
March 31, 2014
I&M
	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	4,378	$	1,914	Discounted Cash Flow	Forward Market Price	$	13.34	$	59.60
FTRs		2,567		190	Discounted Cash Flow	Forward Market Price		(5.05)		9.17
Total	$	6,945	$	2,104

Significant Unobservable Inputs
December 31, 2013
I&M
	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	6,348	$	651	Discounted Cash Flow	Forward Market Price	$	13.04	$	80.50
FTRs		1,857		390	Discounted Cash Flow	Forward Market Price		(5.10)		10.44
Total	$	8,205	$	1,041

176

Significant Unobservable Inputs
March 31, 2014
OPCo
	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	-	$	-	Discounted Cash Flow	Forward Market Price	$	-	$	-
FTRs		3,990		78	Discounted Cash Flow	Forward Market Price		(5.05)		9.17
Total	$	3,990	$	78

Significant Unobservable Inputs
December 31, 2013
OPCo
	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	-	$	-	Discounted Cash Flow	Forward Market Price	$	-	$	-
FTRs		3,269		349	Discounted Cash Flow	Forward Market Price		(5.10)		10.44
Total	$	3,269	$	349

Significant Unobservable Inputs
March 31, 2014
PSO
	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	-	$	-	Discounted Cash Flow	Forward Market Price	$	-	$	-
FTRs		481		132	Discounted Cash Flow	Forward Market Price		(5.05)		9.17
Total	$	481	$	132

Significant Unobservable Inputs
March 31, 2014
SWEPCo
	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	-	$	-	Discounted Cash Flow	Forward Market Price	$	-	$	-
FTRs		609		167	Discounted Cash Flow	Forward Market Price		(5.05)		9.17
Total	$	609	$	167

(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.

177

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 IRS examination of years 2011 and 2012 started in April 2014. 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. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and 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 2009.

11. FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first three months of 2014 are shown in the tables below:

		Principal		Interest
Company	Type of Debt	Amount (a)		Rate	Due Date
Issuances:		(in thousands)		(%)
PSO	Other Long-term Debt	$	50,000	Variable	2016

			Principal		Interest
Company		Type of Debt	Amount Paid		Rate	Due Date
Retirements and			(in thousands)		(%)
	Principal Payments:
APCo		Land Note	$	8	13.718	2026
I&M		Notes Payable		9,866	Variable	2017
I&M		Notes Payable		5,324	Variable	2016
I&M		Notes Payable		5,214	Variable	2016
I&M		Notes Payable		3,611	2.12	2016
I&M		Other Long-term Debt		2,063	Variable	2015
I&M		Other Long-term Debt		259	6.00	2025
OPCo		Other Long-term Debt		29	1.149	2028
OPCo		Senior Unsecured Notes		225,000	4.85	2014
PSO		Other Long-term Debt		102	3.00	2027
SWEPCo		Notes Payable		1,625	4.58	2032

(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.

In April 2014, I&M retired $13 million of Notes Payable related to DCC Fuel.

As of March 31, 2014, trustees held on behalf of I&M and OPCo, $40 million and $460 million, respectively, of their reacquired Pollution Control Bonds.

178

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 generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M.

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 PSO 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 a majority of AEP’s 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 March 31, 2014 and December 31, 2013 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 three months ended March 31, 2014 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		March 31, 2014		Limit
	(in thousands)
APCo	$	-	$	249,630	$	-	$	164,681	$	245,516	$	600,000
I&M		-		158,857		-		92,303		59,162		500,000
OPCo		55,640		405,350		25,930		135,747		(27,108)		600,000
PSO		121,100		-		58,500		-		(70,119)		300,000
SWEPCo		130,258		-		61,132		-		(117,342)		350,000

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

	Three Months Ended March 31,
	2014		2013
Maximum Interest Rate	0.33	%	0.43	%
Minimum Interest Rate	0.28	%	0.35	%

179

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 2014 and 2013 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
	Three Months Ended March 31,				Three Months Ended March 31,
Company	2014		2013		2014		2013
APCo	-	%	0.38	%	0.31	%	0.37	%
I&M	-	%	0.36	%	0.31	%	0.37	%
OPCo	0.31	%	0.36	%	0.29	%	0.37	%
PSO	0.31	%	0.36	%	-	%	0.38	%
SWEPCo	0.31	%	-	%	-	%	0.38	%

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 5.

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.

AEP Credit's receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2014. The remaining commitment of $315 million expires in June 2015. AEP Credit intends to extend or replace the agreement expiring in June 2014 on or before its maturity.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of March 31, 2014 and December 31, 2013 was as follows:

	March 31,		December 31,
Company	2014		2013
	(in thousands)
APCo	$	175,738	$	156,599
I&M		154,510		139,257
OPCo		350,735		324,287
PSO		111,522		115,260
SWEPCo		145,648		149,337

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

	Three Months Ended March 31,
Company	2014		2013
	(in thousands)
APCo	$	2,423	$	1,556
I&M		2,040		1,452
OPCo		7,498		4,669
PSO		1,323		1,414
SWEPCo		1,566		1,380

180

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

	Three Months Ended March 31,
Company	2014		2013
	(in thousands)
APCo	$	437,196	$	398,193
I&M		407,150		351,830
OPCo		686,627		696,958
PSO		290,217		240,275
SWEPCo		390,588		331,936

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. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding. 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.

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

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
March 31, 2014 and December 31, 2013
(in thousands)
	Sabine
ASSETS	2014		2013
Current Assets	$	61,675	$	66,478
Net Property, Plant and Equipment		153,928		157,274
Other Noncurrent Assets		50,140		51,211
Total Assets	$	265,743	$	274,963

LIABILITIES AND EQUITY
Current Liabilities	$	29,257	$	32,812
Noncurrent Liabilities		236,142		241,673
Equity		344		478
Total Liabilities and Equity	$	265,743	$	274,963

181

I&M has nuclear fuel lease agreements with DCC Fuel II 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 March 31, 2014 and 2013 were $25 million and $26 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 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. In October 2013, the lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s condensed balance sheets.

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

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
March 31, 2014 and December 31, 2013
(in thousands)
	DCC Fuel
ASSETS	2014		2013
Current Assets	$	109,374	$	117,762
Net Property, Plant and Equipment		129,013		156,820
Other Noncurrent Assets		44,853		60,450
Total Assets	$	283,240	$	335,032

LIABILITIES AND EQUITY
Current Liabilities	$	100,141	$	107,815
Noncurrent Liabilities		183,099		227,217
Total Liabilities and Equity	$	283,240	$	335,032

Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $267 million and $267 million as of March 31, 2014 and December 31, 2013, respectively, and are included in current and long-term debt on the condensed balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $127 million and $132 million as of March 31, 2014 and December 31, 2013, respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs.

182

The balances below represent the assets and liabilities of Ohio Phase-in-Recovery Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.

OHIO POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
March 31, 2014 and December 31, 2013
(in thousands)
	Ohio Phase-in-
	Recovery Funding
ASSETS	2014		2013
Current Assets	$	35,958	$	23,198
Other Noncurrent Assets (a)		241,814		251,409
Total Assets	$	277,772	$	274,607

LIABILITIES AND EQUITY
Current Liabilities	$	59,590	$	36,470
Noncurrent Liabilities		216,845		236,800
Equity		1,337		1,337
Total Liabilities and Equity	$	277,772	$	274,607

(a)

Includes an intercompany item eliminated in consolidation as of March 31, 2014 and December 31, 2013 of $112 million and $116 million, respectively.

Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $380 million and $380 million as of March 31, 2014 and December 31, 2013, respectively, and are included in current and long-term debt on the condensed balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $365 million and $369 as of March 31, 2014 and December 31, 2013, respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect WV deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs.

The balances below represent the assets and liabilities of Appalachian Consumer Rate Relief Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
March 31, 2014 and December 31, 2013
(in thousands)
	Appalachian Consumer
	Rate Relief Funding
ASSETS	2014		2013
Current Assets	$	15,981	$	5,891
Other Noncurrent Assets (a)		373,521		378,029
Total Assets	$	389,502	$	383,920

LIABILITIES AND EQUITY
Current Liabilities	$	27,682	$	14,000
Noncurrent Liabilities		359,919		368,018
Equity		1,901		1,902
Total Liabilities and Equity	$	389,502	$	383,920

(a)

Includes an intercompany item eliminated in consolidation as of March 31, 2014 of and December 31, 2013 of $4 million and $4 million, respectively.

183

DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended March 31, 2014 and 2013 were $2 million and $18 million, respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheets.

SWEPCo’s investment in DHLC was:

	March 31, 2014				December 31, 2013
	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		1,910		1,910		1,600		1,600
SWEPCo's Guarantee of Debt		-		85,190		-		61,348

Total Investment in DHLC	$	9,553	$	94,743	$	9,243	$	70,591

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

Total AEPSC billings to the Registrant Subsidiaries were as follows:

	Three Months Ended March 31,
Company	2014		2013
	(in thousands)
APCo	$	50,136	$	39,040
I&M		31,969		27,498
OPCo		39,049		54,069
PSO		24,439		18,161
SWEPCo		33,023		27,480

184

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

	March 31, 2014				December 31, 2013
	As Reported on the		Maximum		As Reported on the		Maximum
Company	Balance Sheet		Exposure		Balance Sheet		Exposure
	(in thousands)
APCo	$	19,304	$	19,304	$	20,191	$	20,191
I&M		12,040		12,040		12,864		12,864
OPCo		14,046		14,046		31,425		31,425
PSO		9,330		9,330		10,596		10,596
SWEPCo		12,833		12,833		13,520		13,520

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 has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 12 in the 2013 Annual Report.

Total billings from AEGCo were as follows:

	Three Months Ended March 31,
Company	2014		2013
	(in thousands)
I&M	$	70,422	$	58,535
OPCo		-		38,711

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

	March 31, 2014				December 31, 2013
	As Reported on		Maximum		As Reported on		Maximum
Company	the Balance Sheet		Exposure		the Balance Sheet		Exposure
	(in thousands)
I&M	$	24,364	$	24,364	$	23,916	$	23,916
OPCo		-		-		12,810		12,810

185

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 2013 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

Customer Demand

In comparison to 2013, heating degree days in 2014 were up 40% in AEP’s western region and 24% in AEP’s eastern region. Weather-normalized retail sales volumes for the first quarter of 2014 increased by 1.5% from their levels for the first quarter of 2013. First quarter 2014 weather-adjusted residential and commercial customer sales were up 4.4% and 2.9%, respectively, from their levels for the first quarter of 2013. Residential and commercial customer counts grew 0.4% and 0.8% in the first quarter of 2014, respectively, from the first quarter of 2013.

AEP’s industrial sales volumes in the first quarter of 2014 decreased 2.9% from the first quarter of 2013 due mainly to the closure of Ormet, a large aluminum company. Ormet had a contract to purchase power from OPCo through 2018. In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down its operations effective immediately. Excluding Ormet, total AEP first quarter 2014 industrial sales volumes increased 2.2% over the first quarter of 2013. The loss of Ormet's load will not have a material impact on future gross margin because power previously sold to Ormet will be available for sale into generally higher priced wholesale markets.

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 2013 Annual Report. Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. 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.

186

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of March 31, 2014, 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	$	310	$	360
I&M		410		470
PSO		280		320
SWEPCo		910		1,060

For APCo, the projected environmental investment above includes the conversion of 470 MWs of coal generation to natural gas capacity. If natural gas conversion is not completed, the units could be closed 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 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 than the proposed rules, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.

Subject to the factors listed above and based upon continuing evaluation, management has given notice to the applicable RTO’s of intent to retire the following plants or units of plants before or during 2016:

		Generating
Company	Plant Name and Unit	Capacity
		(in MWs)
APCo	Clinch River Plant, Unit 3		235
APCo	Glen Lyn Plant		335
APCo	Kanawha River Plant		400
APCo/AGR	Sporn Plant, Units 1-4		600
I&M	Tanners Creek Plant, Units 1-4		995
PSO	Northeastern Station, Unit 4		470
SWEPCo	Welsh Plant, Unit 2		528

As of March 31, 2014, the net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the plants in the table above was $727 million.

PSO received Federal EPA approval of the Oklahoma SIP, in February 2014, related to the environmental compliance plan for Northeastern Station, Unit 3.

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.

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Clean Air Act Requirements

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)

188

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.

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

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis. In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. The effective date of the final rule was April 16, 2012 and compliance is required within three years. The 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. The Federal EPA issued revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions in March 2013. The Federal EPA is still considering 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 participated in petitions for review filed in the U.S. Court of Appeals for the District of Columbia Circuit by several organizations of 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. In April 2014, the appellate court issued a decision denying all of the petitions for review of the April 2012 final rule.

189

CO 2 Regulation

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. The President directed the Federal EPA, in developing this proposal, 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 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

190

In February 2014, the Federal EPA completed a risk evaluation of the beneficial uses of coal fly ash in concrete and flue gas desulfurization gypsum in wallboard and concluded that the Federal EPA supports these beneficial uses. Currently, approximately 40% of the coal ash and other residual products from the AEP System’s generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses. Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes. In addition, surface impoundments and landfills to manage these materials are currently used at the generating facilities. The Registrant Subsidiaries will incur significant costs to upgrade or close and replace their existing facilities under the proposed solid waste management alternative. Regulation of these materials as hazardous wastes would significantly increase these costs. As the rule is not final, management is unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

Clean Water Act Regulations

In 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 expected in 2014. 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 September 2015. 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 continues to 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 submitted detailed comments to the Federal EPA in September 2013 and participated in comments filed by various organizations of which the AEP System companies are members.

In March 2014, the Federal EPA and the U.S. Army Corps of Engineers jointly announced that they will be issuing a proposed rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases and released a pre-publication version of the proposed rule. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This proposed jurisdictional definition will apply to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are: permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. Management agrees that clarity and efficiency in the permitting process is needed. Management is concerned that the proposed rule introduces new concepts and could subject more of the Registrant Subsidiaries’ operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. Management will continue to evaluate the rule and its financial impact on the AEP System. Management plans to submit comments and also participate in the preparation of comments to be filed by various organizations of which the AEP System companies are members.

191

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 actively participating 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.

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 2013 Form 10-K under the headings entitled “Environmental and Other Matters” and “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries.”

ACCOUNTING PRONOUNCEMENTS

Pronouncements Effective in the Future

The FASB issued ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. Management plans to adopt ASU 2014-08 effective January 1, 2015.

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.

CONTROLS AND PROCEDURES

During the first quarter of 2014, 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

192

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 March 31, 2014, 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.

Effective March 1, 2014, the SPP transitioned from an Energy Imbalance Service Market to a fully integrated market that consists of both a Day-Ahead and Real Time Balancing Market. In connection with SPP’s transition to a fully integrated market, PSO and SWEPCo implemented or modified a number of business processes and controls to facilitate participation and settlement in the SPP integrated market. Apart from this, there have been no material changes (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter of 2014 that have materially affected, or are reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 5 incorporated herein by reference.

Item 1A. Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2013 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 2013 Annual Report on Form 10-K.

GENERAL RISKS OF OUR REGULATED OPERATIONS

Ohio may require us to refund revenue that we have collected. – Affecting AEP and OPCo

Ohio law requires that the PUCO determine on an annual basis if rate adjustments included in prior orders resulted in significantly excessive earnings. If the PUCO determines there were significantly excessive earnings, the excess amount could be returned to customers. In November 2013, OPCo filed its 2012 significantly excessive earnings filing with the PUCO. OPCo plans to file its 2013 SEET filing in May 2014. If the PUCO determines that OPCo’s earnings were significantly excessive, and requires OPCo to return a portion of its revenues to customers, it could reduce future net income and cash flows and impact financial condition.

Request for rate recovery in Louisiana may not be approved in its entirety. – Affecting AEP and SWEPCo

In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase to be effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. These increases are subject to LPSC review. If SWEPCo cannot ultimately recover its costs that are the subject of this request, it could reduce future net income and cash flows.

193

Request for rate and other recovery in Virginia for generation and distribution service may not be approved in its entirety. – Affecting AEP and APCo

In March 2014, APCo filed a generation and distribution base rate biennial review with the Virginia SCC. APCo did not request an increase in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to the changes in the expected service life of certain plants. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to certain deferred costs. If the Virginia SCC denies all or part of the requested rate and other recovery, it could reduce future net income and cash flows.

Ohio may require a reduction in our 2012 and 2013 fuel deferrals. – Affecting AEP and OPCo

In April 2014, the PUCO-selected outside consultant provided its preliminary draft report related to their 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. If the PUCO does not permit full recovery of OPCo’s FAC deferral, 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

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 AGR and KPCo, through their use of the Conner Run fly ash impoundment, are subject to the provisions of the Mine Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act and its related regulations require companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 contains the notices of violation and proposed assessments received by DHLC and Conner Run under the Mine Act for the quarter ended March 31, 2014.

Item 5. Other Information

None

Item 6. Exhibits

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

194

SIGNATURE



Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.


AMERICAN ELECTRIC POWER COMPANY, INC.



	By: /s/ Joseph M. Buonaiuto
	Joseph M. Buonaiuto
	Controller and Chief Accounting Officer




APPALACHIAN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY




	By: /s/ Joseph M. Buonaiuto
	Joseph M. Buonaiuto
	Controller and Chief Accounting Officer



Date: April 25, 2014

195

TABLE OF CONTENTS

Part I. Financial Informationprint Part II. Other Informationprint Item 1. Legal Proceedings 193print Item 1A. Risk Factors 193print Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds 194print Item 4. Mine Safety Disclosures 194print Item 5. Other Information 194print Item 6. Exhibits: 194print Item 1. Legal Proceedingsprint Item 1A. Risk Factorsprint Item 2. Unregistered Sales Of Equity Securities and Use Of Proceedsprint Item 4. Mine Safety Disclosuresprint Item 5. Other Informationprint Item 6. Exhibitsprint

DIRECTORS	AGE	BIO	OTHER DIRECTOR MEMBERSHIPS
Reginald H Gilyard	61		CBRE GROUP, INC.
Parker S Kennedy	62	Mr. Kennedy is our chairman emeritus and lead independent director. He served as chairman of our Board from 2010 to 2022. Mr. Kennedy served as executive chairman of the Company from 2010 to 2012. From 2003 to 2010, he served as chairman and chief executive officer of The First American Corporation, the Company’s prior parent company, and as its president from 1993 to 2004. He served as a director of The First American Corporation and, as renamed in 2010, CoreLogic, Inc., from 1987 to 2011, and was CoreLogic, Inc.’s executive chairman from 2010 to 2011. He is a director of the Automobile Club of Southern California. We believe that Mr. Kennedy, who has worked with us in various capacities for over 40 years, has unparalleled executive experience in our industry. He also brings to the Company an incomparable understanding of our history and culture.
Michael D McKee	79	Mr. McKee has served as a principal of The Contrarian Group, a private equity firm, since 2018. He is the chairman of Realty Income Corporation (NYSE: O), a real estate investment trust, and the Tiger Woods Foundation. He served as a director of HCP, Inc. (NYSE: HCP), a publicly traded real estate investment trust, from 1989 to 2018, as executive chairman of HCP from 2016 to 2018 and, during 2016, he also served as interim chief executive officer and president of HCP. From 2010 to 2016, Mr. McKee was chief executive officer of Bentall Kennedy (U.S.), a registered real estate investment advisor. He also served as the chief executive officer and vice chairman of the board of directors of The Irvine Company, a privately-held real estate development and investment company, and as a partner with the law firm of Latham & Watkins LLP. Mr. McKee brings to the Board significant operating and executive management experience. This experience, combined with Mr. McKee’s extensive background in the real estate industry, facilitates the Board’s oversight of the Company’s operations and enhances its ability to assess strategic opportunities.
Martha B Wyrsch	67	Ms. Wyrsch retired in 2019 as executive vice president and general counsel for Sempra, a leading energy services company, where she oversaw the company’s legal affairs and compliance initiatives. Prior to joining Sempra in 2013, Ms. Wyrsch served as the president of Vestas American Wind Technology from 2009 to 2012, where she had direct responsibility for all North American sales, construction, service and maintenance. In addition to her former executive leadership roles, she served as a member of the board of directors of Spectra Energy Corporation and SPX Corporation. She currently serves on the board of directors of Quanta Services, Inc. (NYSE: PWR), a specialized contracting services company, and National Grid plc (FTSE: NG; NYSE: NGG), an investor-owned utility managing electric and natural gas assets in the United Kingdom and the United States. From 2012 to 2021 she also served as a director of Spectris plc, a publicly traded company listed on the London Stock Exchange, and from 2019 to 2020 as a director of Noble Energy, Inc. (NYSE: NBL), an energy exploration and production company. As an accomplished director for publicly-traded companies, and with deep experience leading intricate businesses, Ms. Wyrsch provides valuable insight into how we can enhance our operations and effectively serve our customers.	QUANTA SERVICES, INC.
Marsha A Spence	73	Ms. Spence served as the chairman of Mother Lode Holding Co. (“MLHC”), a subsidiary of our Company that was acquired on May 2, 2022, until her retirement in 2023. Ms. Spence was the beneficiary of a legacy Supplemental Executive Retirement Plan (“MLHC SERP”) and Deferred Compensation Plan (“MLHC DCP”) that MLHC offered prior to the acquisition by our Company. Although those plans were frozen at the time of the acquisition, our Company assumed the obligations under those plans that were then in place, including the obligations under Ms. Spence’s MLHC SERP contract and with respect to her DCP contributions. MLHC was also a lessee under five lease agreements with respect to properties beneficially owned by a trust to which Ms. Spence and her husband are beneficiaries. One of those lease arrangements terminated during 2024, with four remaining in place as of December 31, 2024. Our Company paid approximately $674,050 in rent payments under the leases during 2024. These leases were included in the acquisition and were determined by our Company’s corporate real estate team at the time to be at fair market value rates.
Mark C Oman	62	Mr. Oman retired from Wells Fargo & Company in 2011, after serving it or its predecessors since 1979. He held numerous positions at Wells Fargo, including senior executive vice president (home and consumer finance) from 2005 until his retirement and group executive vice president (home and consumer finance) from 2002 to 2005. Mr. Oman also served as a director and the chief executive officer of Wachovia Preferred Funding Corp. from 2009 to 2011. He is currently involved with several private ventures and serves on a variety of private-company and non-profit boards. Mr. Oman brings to the Board important insights into the mortgage market and working with large mortgage lenders.
Margaret M McCarthy	71	Ms. McCarthy retired in 2019 as executive vice president of CVS Health Corporation, a health innovation company (NYSE: CVS), supporting the technology integration following the completion of CVS Health’s acquisition of Aetna, Inc. in 2018. She served as executive vice president of operations and technology for Aetna, Inc., a diversified healthcare benefits company, from 2010 until 2018, where she was responsible for innovation, technology, data security, procurement, real estate and service operations. Prior to joining Aetna in 2003, she served in various information technology-related roles, including at CIGNA Healthcare, Catholic Health Initiatives and Andersen Consulting (now Accenture), as well as a consulting partner at Ernst & Young. She is a director of Marriott International, Inc. (Nasdaq: MAR), an operator, franchisor, and licensor of hotel, residential, and timeshare properties worldwide; American Electric Power (Nasdaq: AEP), an electrical energy company; and Alignment Healthcare, Inc. (Nasdaq GS: ALHC), a tech-enabled Medicare Advantage company. She served as a director of Brighthouse Financial, Inc. (Nasdaq GS: BHF), a life and annuity insurance company from 2018 to 2021. Given her extensive experience managing large groups of employees, complex processes and enterprise-critical technology, Ms. McCarthy brings to the Board valuable insights into areas of critical import to the operations of the Company, including privacy and cybersecurity.	MARRIOTT INTERNATIONAL INC /MD/
Kenneth D DeGiorgio	76	Mr. DeGiorgio has served as our chief executive officer since February 2022. From 2021 to 2022 he was our president with oversight responsibility for the Company’s operating groups, including its title insurance, specialty insurance and data and analytics businesses. He served as executive vice president from 2010 to 2021, overseeing the Company's international division, trust company and various corporate functions. He serves as a director of Offerpad Solutions Inc. (NYSE:OPAD), a leading tech-enabled real estate company, and Lev Inc., a privately held technology company focused on digitizing commercial real estate financing. With over 25 years of service to our Company in various operational and corporate roles, Mr. DeGiorgio provides our Board with an in-depth understanding of the Company’s businesses, risk profile and competitive landscape.
James L Doti	78	Dr. Doti has been a professor of economics at Chapman University since 1974 and served as Chapman University’s president from 1991 to 2016. He previously served on the boards of The First American Corporation, the Company’s prior parent company, Standard Pacific Corp. and Fleetwood Enterprises, Inc. Given his experience as president of Chapman University and his doctorate in economics from the University of Chicago, Dr. Doti gives our Company insight into the organizational challenges that large companies face and the impact of the economic environment on the Company.
Dennis J Gilmore	66	Mr. Gilmore has served as chairman of the Board since February 2022 and as a director since 2010. He served as our chief executive officer from 2010 to 2022. From 1993 to 2010, he served in various managerial roles with The First American Corporation, including as the chief executive officer of its financial services group and as its chief operating officer. He currently serves as a director of the Automobile Club of Southern California. As the Company’s former chief executive officer, Mr. Gilmore brings to our Board significant operational and executive management experience specific to our Company’s businesses and our industry.
Deborah L Wahl	62	Ms. Wahl was appointed a director in September 2024. Ms. Wahl retired in 2023 as senior vice president and global chief marketing officer (CMO) of General Motors Company (NYSE: GM), a leading automotive manufacturing company, where she oversaw the company’s global marketing strategy since 2019. Ms. Wahl has also served as an executive leader and CMO for several other premier consumer product companies, including Cadillac (a brand of General Motors Company) from 2018 to 2019, McDonald’s Corporation (NYSE: MCD), a leading global foodservice retailer, from 2014 to 2017 and PulteGroup, Inc., one of the largest homebuilding companies in the United States, from 2009 to 2014. Ms. Wahl is a director of Mediaocean, LLC, a global advertising software solutions and consumer measurement data company. She previously served as a director of Groupon, Inc. (Nasdaq: GRPN) from 2017 to 2023, ActionIQ, Inc. from 2023 to 2024, Beyond Ordinary Events, Inc. from 2023 to 2024, and OnStar Insurance Services Inc. from 2021 to 2023, as well as in several board-level roles with the Association of National Advertisers, the Mobile Marketing Association, and the Interactive Advertising Bureau. With her extensive experience leading global marketing strategy and helping drive growth for influential brands in a variety of industries, Ms. Wahl brings to the Board a valuable perspective on how the Company can capitalize on its leadership of the digital transformation of the title and settlement industry.

Name and Principal Position	Year		Salary ($)			Bonus ($)			Stock Awards ($)			Non-Equity Incentive Plan Compensation ($)			Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)			All Other Compensation ($)			Total ($)
Kenneth D. DeGiorgio		2024		$	832,500		$	—		$	4,450,093		$	2,460,500		$	28,017		$	13,830		$	7,784,940
Chief Executive Officer		2023		$	832,500		$	—		$	4,841,829		$	1,050,000		$	332,267		$	12,761		$	7,069,357
		2022		$	865,673		$	—		$	3,792,696		$	1,347,500		$	—		$	20,730		$	6,026,599
Mark E. Seaton		2024		$	630,000		$	—		$	2,162,011		$	964,250		$	—		$	10,900		$	3,767,161
EVP, Chief Financial Officer		2023		$	630,000		$	—		$	2,289,842		$	435,000		$	—		$	10,151		$	3,364,993
		2022		$	665,000		$	—		$	2,641,705		$	558,250		$	—		$	18,400		$	3,883,355
Lisa W. Cornehl		2024		$	445,385		$	—		$	706,995		$	395,010		$	—		$	10,740		$	1,558,130
SVP, Chief Legal Officer		2023		$	407,162		$	—		$	570,154		$	138,600		$	—		$	9,910		$	1,125,826
		2022		$	390,000		$	—		$	319,849		$	140,140		$	—		$	18,200		$	868,189
Matthew F. Wajner		2024		$	350,000		$	—		$	296,591		$	203,158		$	—		$	10,600		$	860,349
VP, Treasurer		2023		$	350,000		$	—		$	335,419		$	109,980		$	—		$	9,849		$	805,248
		2022		$	346,923		$	—		$	333,357		$	117,618		$	—		$	18,050		$	815,948
Steven A. Adams		2024		$	358,462		$	—		$	237,204		$	203,158		$	—		$	10,600		$	809,424
VP, Chief Accounting Officer		2023		$	350,000		$	—		$	267,313		$	109,980		$	—		$	9,850		$	737,143
		2022		$	350,000		$	—		$	290,079		$	117,618		$	—		$	18,100		$	775,797

Customer name	Ticker
Consolidated Edison, Inc.	ED
FirstEnergy Corp.	FE
First Trust New Opportunities MLP & Energy Fund	FPL
NiSource Inc.	NI
PG&E Corporation	PCG
Pinnacle West Capital Corporation	PNW
PPL Corporation	PPL
Sempra Energy	SRE
The Williams Companies, Inc.	WMB
Xcel Energy Inc.	XEL

Supplier name	Ticker
Duke Energy Corporation	DUK
General Electric Company	GE
The Southern Company	SO
Waste Management, Inc.	WM
Eaton Corporation plc	ETN
Honeywell International Inc.	HON
Union Pacific Corporation	UNP
CSX Corporation	CSX

Owner	Position	Direct Shares	Indirect Shares
First American Financial Corp	-	76,779,700	0
GILMORE DENNIS J	-	494,574	2,343
DEGIORGIO KENNETH D	-	311,762	128
KENNEDY PARKER S	-	189,081	2,165,550
Seaton Mark Edward	-	188,151	0
DOTI JAMES L	-	73,987	0
Cornehl Lisa W	-	23,825	0
Adams Steven a	-	9,252	0
Adams Steven a	-	7,411	0
Spence Marsha A	-	1,747	0
Wahl Deborah	-	696	0

AEP 10-Q Quarter ended March 31, 2014