Appendix A to the

Proxy Statement

American Electric Power

2015 Annual Report

Audited Consolidated Financial Statements and

Management’s Discussion and Analysis of Financial Condition and Results of Operations

CONTENTS	AMERICAN ELECTRIC POWER 1 Riverside Plaza Columbus, Ohio 43215-2373
Glossary of Terms		i
Forward-Looking Information		v
AEP Common Stock and Dividend Information		vii
Selected Consolidated Financial Data		1
Management’s Discussion and Analysis of Financial Condition and Results of Operations		2
Reports of Independent Registered Public Accounting Firm		57
Management’s Report on Internal Control Over Financial Reporting		59
Consolidated Statements of Income		60
Consolidated Statements of Comprehensive Income (Loss)		61
Consolidated Statements of Changes in Equity		62
Consolidated Balance Sheets		63
Consolidated Statements of Cash Flows		65
Index of Notes to Financial Statements of Registrants		66
Corporate and Shareholder Information		242
Executive Leadership Team		243

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	American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and 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.
AEP System	American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP Transmission Holdco	AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEPEP	AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, asset management and commercial and industrial sales in the deregulated Texas market.
AEPES	AEP Energy Services, Inc., a subsidiary of AEP Resources, Inc.
AEPRO	AEP River Operations, LLC.
AEPSC	American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC	Allowance for Funds Used During Construction.
AGR	AEP Generation Resources Inc., a nonregulated AEP subsidiary in the Generation & Marketing segment.
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.
APSC	Arkansas Public Service Commission.
ASU	Accounting Standards Update.
CAA	Clean Air Act.
CLECO	Central Louisiana Electric Company, a nonaffiliated utility company.
CO2	Carbon dioxide and other greenhouse gases.
Cook Plant	Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CRES provider	Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service.
CWIP	Construction Work in Progress.
DCC Fuel	DCC Fuel IV LLC, DCC Fuel VI LLC, DCC Fuel VII LLC and DCC Fuel VIII 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.
Energy Supply	AEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.

i

Term	Meaning
ERCOT	Electric Reliability Council of Texas regional transmission organization.
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 Parent and Berkshire Hathaway Energy Company 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.
IMT	International Marine Terminals, an equity method investment of AEPRO.
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.
kV	Kilovolt.
KWh	Kilowatthour.
LPSC	Louisiana Public Service Commission.
MISO	Midwest Independent Transmission System Operator.
MLR	Member load ratio, the method used to allocate transactions among members of the Interconnection Agreement.
MMBtu	Million British Thermal Units.
MPSC	Michigan Public Service Commission.
MTM	Mark-to-Market.
MW	Megawatt.
MWh	Megawatthour.
NOx	Nitrogen oxide.
Nonutility Money Pool	Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NSR	New Source Review.
OATT	Open Access Transmission Tariff.
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.
Operating Agreement	Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third party sales.  AEPSC acts as the agent.

ii

Term	Meaning
OTC	Over the counter.
OVEC	Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
Parent	American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PCA	Power Coordination Agreement among APCo, I&M, KPCo and WPCo.
PIRR	Phase-In Recovery Rider.
PJM	Pennsylvania – New Jersey – Maryland regional transmission organization.
PM	Particulate Matter.
PSO	Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO	Public Utilities Commission of Ohio.
PUCT	Public Utility Commission of Texas.
Registrant Subsidiaries	AEP subsidiaries which are SEC registrants: APCo, I&M, OPCo, PSO and SWEPCo.
Registrants	SEC registrants: AEP, 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, as amended, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF	Spent Nuclear Fuel.
SO2	Sulfur dioxide.
SPP	Southwest Power Pool regional transmission organization.
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.
TRA	Tennessee Regulatory Authority.
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.

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Term	Meaning
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.

iv

FORWARD-LOOKING INFORMATION

This report made by the Registrants 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,” 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, management undertakes 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:

Ÿ	The economic climate, growth or contraction within and changes in market demand and demographic patterns in AEP service territories.
Ÿ	Inflationary or deflationary interest rate trends.
Ÿ	Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
Ÿ	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.
Ÿ	Electric load, customer growth and the impact of competition, including competition for retail customers.
Ÿ	Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.
Ÿ	The cost of fuel and its transportation and the creditworthiness and performance of fuel suppliers and transporters.
Ÿ	Availability of necessary generation capacity and the performance of generation plants.
Ÿ	The ability to recover fuel and other energy costs through regulated or competitive electric rates.
Ÿ	The ability to build transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs.
Ÿ	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 generation plants and related assets.
Ÿ	Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
Ÿ	A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
Ÿ	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.
Ÿ	Resolution of litigation.
Ÿ	The ability to constrain operation and maintenance costs.
Ÿ	The ability to develop and execute a strategy based on a view regarding prices of electricity and other energy-related commodities.
Ÿ	Prices and demand for power generated and sold at wholesale.
Ÿ	Changes in technology, particularly with respect to new, developing, alternative or distributed sources of generation.
Ÿ	The 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.
Ÿ	Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas and capacity auction returns.
Ÿ	Changes in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP.
Ÿ	The market for generation in Ohio and PJM and the ability to recover investments in Ohio generation assets.
Ÿ	The ability to successfully and profitably manage competitive generation assets, including the evaluation of strategic alternatives for these assets as some of the alternatives could result in a loss.

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Ÿ	Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
Ÿ	Actions of rating agencies, including changes in the ratings of debt.
Ÿ	The impact of volatility in the capital markets on the value of the investments held by the pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.
Ÿ	Accounting pronouncements periodically issued by accounting standard-setting bodies.
Ÿ	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 the Registrants speak only as of the date of this report or as of the date they are made.  The Registrants 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 this report.

Investors should note that the Registrants announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, the Registrants may use the Investors section of AEP’s website (www.aep.com) to communicate with investors about the Registrants. It is possible that the financial and other information posted there could be deemed to be material information. The information on AEP’s website is not part of this report.

vi

AEP COMMON STOCK AND DIVIDEND INFORMATION

The AEP common stock quarterly high and low sales prices, quarter-end closing price and the cash dividends paid per share are shown in the following table:

Quarter Ended	High		Low		Quarter-End Closing Price		Dividend
December 31, 2015	$	59.52	$	53.30	$	58.27	$	0.56
September 30, 2015	59.18		52.29		56.86		0.53
June 30, 2015	58.35		52.32		52.97		0.53
March 31, 2015	65.38		54.66		56.25		0.53
December 31, 2014	$	63.22	$	51.97	$	60.72	$	0.53
September 30, 2014	55.91		49.06		52.21		0.50
June 30, 2014	55.94		49.99		55.77		0.50
March 31, 2014	50.95		45.80		50.66		0.50

AEP common stock is traded principally on the New York Stock Exchange.  As of December 31, 2015, AEP had approximately 70,000 registered shareholders.

vii

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
	2015			2014			2013			2012			2011
	(dollars in millions, except per share amounts)
STATEMENTS OF INCOME DATA (a)
Total Revenues	$	16,453.2		$	16,378.6		$	14,813.5		$	14,298.4		$	14,419.4
Operating Income	$	3,333.5		$	3,127.4		$	2,822.5		$	2,620.7		$	2,697.4
Income from Continuing Operations	$	1,768.6		$	1,590.5		$	1,473.9		$	1,247.7		$	1,531.2
Income From Discontinued Operations, Net of Tax	283.7			47.5			10.3			14.5			44.9
Income Before Extraordinary Items	$	2,052.3		$	1,638.0		$	1,484.2		$	1,262.2		$	1,576.1
Extraordinary Items, Net of Tax	—			—			—			—			373.1
Net Income	2,052.3			1,638.0			1,484.2			1,262.2			1,949.2
Net Income Attributable to Noncontrolling Interests	5.2			4.2			3.7			3.4			3.4
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS	2,047.1			1,633.8			1,480.5			1,258.8			1,945.8
Preferred Stock Dividend Requirements of Subsidiaries Including Capital Stock Expense	—			—			—			—			5.3
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	2,047.1		$	1,633.8		$	1,480.5		$	1,258.8		$	1,940.5
BALANCE SHEETS DATA (a)
Total Property, Plant and Equipment	$	65,481.4		$	63,605.9		$	59,646.7		$	56,817.4		$	55,062.1
Accumulated Depreciation and Amortization	19,348.2			19,970.8			19,098.6			18,529.6			18,563.0
Total Property, Plant and Equipment – Net	$	46,133.2		$	43,635.1		$	40,548.1		$	38,287.8		$	36,499.1
Total Assets	$	61,683.1		$	59,544.6		$	56,321.0		$	54,272.1		$	52,119.3
Total AEP Common Shareholders’ Equity	$	17,891.7		$	16,820.2		$	16,085.0		$	15,237.2		$	14,664.2
Noncontrolling Interests	$	13.2		$	4.3		$	0.8		$	0.4		$	0.7
Long-term Debt (b)(c)	$	19,572.7		$	18,512.4		$	18,198.2		$	17,574.4		$	16,322.0
Obligations Under Capital Leases (b)	$	343.5		$	362.8		$	403.3		$	306.3		$	314.4
AEP COMMON STOCK DATA
Basic Earnings per Share Attributable to AEP Common Shareholders:
From Continuing Operations	$	3.59		$	3.24		$	3.02		$	2.57		$	3.16
From Discontinued Operations	0.58			0.10			0.02			0.03			0.09
Income Before Extraordinary Items	$	4.17		$	3.34		$	3.04		$	2.60		$	3.25
From Extraordinary Items, Net of Tax	—			—			—			—			0.77
Total Basic Earnings per Share Attributable to AEP Common Shareholders	$	4.17		$	3.34		$	3.04		$	2.60		$	4.02
Weighted Average Number of Basic Shares Outstanding (in millions)	490.3			488.6			486.6			484.7			482.2
Market Price Range:
High	$	65.38		$	63.22		$	51.60		$	45.41		$	41.71
Low	$	52.29		$	45.80		$	41.83		$	36.97		$	33.09
Year-end Market Price	$	58.27		$	60.72		$	46.74		$	42.68		$	41.31
Cash Dividends Declared per AEP Common Share	$	2.15		$	2.03		$	1.95		$	1.88		$	1.85
Dividend Payout Ratio	51.56		%	60.78		%	64.14		%	72.31		%	46.02		%
Book Value per AEP Common Share	$	36.44		$	34.37		$	32.98		$	31.35		$	30.36

(a) Amounts reflect reclassifications due to the impact of discontinued operations (see Note 7 to the Financial Statements).

(b) Includes portion due within one year.

(c) Amounts reflect the adoption of ASU 2015-3 “Simplifying the Presentation of Debt Issuance Costs” (see Note 2 to the Financial Statements).

1

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

AEP is one of the largest investor-owned electric public utility holding companies in the United States.  AEP’s electric utility operating companies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia.

AEP’s subsidiaries operate an extensive portfolio of assets including:

• Approximately 224,000miles of distribution lines that deliver electricity to 5.4 million customers.

• Approximately 40,000 miles of transmission lines, including 2,114miles of 765 kV lines, the backbone of the electric interconnection grid in the Eastern United States.

• AEP Transmission Holdco has approximately $2.9 billion of transmission assets in-service.

• Approximately 32,000 megawatts of generating capacity in 3 RTOs, one of the largest complements of generation in the United States.

• Substantial commodity transportation assets (4,838railcars, 498 barges, 12 towboats, 8 harbor boats and a coal handling terminal with approximately 18 million tons of annual capacity).  

Customer Demand

In comparison to 2014, AEP’s weather-normalized retail sales decreased 0.8% for the year ended December 31, 2015. AEP’s industrial sales volumes decreased by 0.2% compared to 2014. 2015 weather-normalized residential and commercial sales decreased 1.8% and 0.2%, respectively, compared to 2014.

In 2016, AEP anticipates weather-normalized retail sales will increase by 0.9%. The industrial class is expected to grow by 1.1% in 2016, primarily related to a number of new oil and natural gas expansions, especially around the major shale gas areas within AEP’s footprint. Weather-normalized residential sales are projected to increase by 0.5%, primarily related to projected customer growth. Weather-normalized commercial class energy sales are projected to increase by 0.9%.

Merchant Fleet Alternatives

AEP is evaluating strategic alternatives for its merchant generation fleet, included in the Generation & Marketing segment, which primarily includes AGR’s generation fleet and AEGCo’s Lawrenceburg Plant, both of which operate in PJM as well as a purchased power agreement related to a 54.7% interest in the Oklaunion Plant which operates in ERCOT.  Potential alternatives may include, but are not limited to, continued ownership of the merchant generation fleet, executing a purchased power agreement with OPCo for certain merchant generation units in Ohio under the filed settlement agreement currently pending with the PUCO or a sale of the merchant generation fleet.  Management has not made a decision regarding the potential alternatives, nor have they set a specific time frame for a decision.  Certain of these alternatives could result in a loss which could reduce future net income and cash flows and impact financial condition.

Disposition of AEP River Operations

In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party.  The sale closed in November 2015. AEP received net proceeds of $491 million, which resulted in a net gain of $253 million that was recorded in Income from Discontinued Operations, Net of Tax, on the statement of income. The nonaffiliated party acquired AEPRO by purchasing all of the common stock of AEP Resources, Inc., the parent company of AEPRO. The nonaffiliated party assumed certain assets and liabilities of AEPRO, excluding

2

the investment in IMT, pension and benefit assets and liabilities and debt obligations. Prior to the closing of the sale, AEP retired the debt obligations of AEPRO. AEP retained ownership of its captive barge fleet for the company’s regulated coal-fueled power plant units owned or leased by AEGCo, APCo, I&M, KPCo and WPCo. AEP signed a contract with the nonaffiliated party to dispatch and schedule its captive barge fleet for the company’s regulated coal-fueled power plant units. AEP also has a separate contract with the nonaffiliated party to barge coal for AGR. Both agreements extend through the end of 2016.

AEPRO’s assets and liabilities have been recorded as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on the balance sheet as of December 31, 2014. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.

Merchant Portion of Turk Plant

SWEPCo constructed the Turk Plant, a base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012 and is included in the Vertically Integrated Utilities segment. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This share of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under cost-based rate recovery in Texas, Louisiana, and through SWEPCo’s wholesale customers under FERC-based rates.

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

Ohio Electric Security Plan Filings

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. In June 2015, the Supreme Court of Ohio issued a decision that reversed, as requested by OPCo, the PUCO order on the carrying cost rate issue and dismissed an appeal filed by the IEU. In September 2015, the Supreme Court of Ohio denied a request for reconsideration filed by the IEU and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. A decision from the PUCO is pending.

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 established 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 collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and $150/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. Oral arguments at the Supreme Court of Ohio were held in December 2015. A decision from the Supreme Court of Ohio is pending.

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As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50/MWh through May 2014 and 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. In April 2015, the PUCO issued an order that approved, with modifications, OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. In May 2015, the PUCO granted intervenors requests for rehearing. As of December 31, 2015, OPCo’s net deferred capacity costs balance was $359 million, including debt carrying costs. Through December 31, 2015, OPCo has collected $222 million in deferred capacity costs, and related carrying charges.

In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. 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 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015.

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. 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.

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. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo’s $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.

June 2015 - May 2018 ESP Including PPA Application

In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA.

In February 2015, the PUCO issued an order approving OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the Distribution Investment Rider (DIR) with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo’s and various intervenors’ requests for rehearing related to the May 2015 order.

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In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider and an amended application was filed in May 2015. In December 2015, a non-unanimous stipulation agreement related to the PPA application was filed with the PUCO. The stipulation agreement is based upon a 10.38% return on common equity with the PPA Rider term extending through May 2024. The stipulation agreement included (a) a revised affiliate PPA between OPCo and AGR to be included in the PPA Rider, (b) OPCo’s OVEC contractual entitlement, (c) a potential additional customer credit to be included in the PPA Rider, (d) annual compliance reviews before the PUCO and (e) an agreement to retire, refuel or repower, to 100% natural gas, Conesville Plant, Units 5 and 6 and Cardinal Plant, Unit 1 by 2029 and 2030, respectively. Additionally, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. OPCo would own up to 50% of these solar and wind projects and would include cost recovery in the proposed PPA rider, subject to PUCO review and approval. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions. Hearings related to this proposed stipulation agreement were held in January 2016. Management anticipates receiving an order from the PUCO in the first quarter of 2016. In January 2016, intervenors filed a complaint at the FERC related to the affiliate PPA. The complaint asserts that the proposed affiliate PPA between AGR and OPCo is reviewable by the FERC under its standards for affiliate transactions.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filings” section of Note 4.

2012 Texas Base Rate Case

Upon rehearing in 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 was approximately $52 million.  In May 2014, intervenors filed appeals of the order with the Texas District Court.  If certain parts of the PUCT order are overturned it could reduce future net income and cash flows and impact financial condition. See the “2012 Texas Base Rate Case” section of Note 4.

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 SWEPCo’s 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 December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million, primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, 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 - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost approximately $900 million, excluding AFUDC. As part of this investment, 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 $400 million, excluding AFUDC. As of December 31, 2015, SWEPCo had incurred costs of $343 million, including AFUDC, and had remaining contractual construction obligations of $40 million related to these projects.  SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. See “Mercury and Other Hazardous Air Pollutants (HAPs)

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Regulation” and “Climate Change, CO₂ Regulation and Energy Policy” sections of “Environmental Issues” below.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of December 31, 2015, the net book value of Welsh Plant, Units 1 and 3 was $578 million, before cost of removal, including materials and supplies inventory and CWIP.  Welsh Plant, Unit 2 is scheduled for retirement during 2016 and is probable of abandonment. As of December 31, 2015, the net book value of Welsh Plant, Unit 2 was $82 million, before cost of removal, including materials and supplies inventory and CWIP.

If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

2015 Oklahoma Base Rate Case

In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million, which includes $48 million in increased depreciation expense, (b) a rider or base rate increase of $44 million to recover costs for environmental controls and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service.

In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million, will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC.

In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million, based upon returns on common equity ranging from 8.75% to 9.3%, and increases to depreciation expense ranging from $23 million to $46 million. Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, some intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC were held in December 2015. In January 2016, PSO implemented an interim annual base rate increase of $75 million, subject to refund pending a final order from the OCC. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2015 Oklahoma Base Rate Case” section of Note 4.

ETT Interim Transmission Rates

Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of December 31, 2015, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $433 million based upon interim rate increases received from 2009 through 2015. In November 2015, the PUCT ordered ETT to file a base rate case by February 2017. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses that are reasonably possible of occurring. A refund of interim transmission rates could reduce future net income and cash flows and impact financial condition.

Kingsport Base Rate Case

In January 2016, KGPCo refiled its request with the TRA to increase base rates by $12 million annually based upon a proposed return on common equity of 10.66%. New rates are expected to be implemented in the third quarter of 2016. See the “Kingsport Base Rate Case” section of Note 4.

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Virginia Legislation Affecting Biennial Reviews

In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA.

In February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning March 2016. In February 2016, APCo filed a motion to stay the Virginia SCC’s consideration of the petition due to a pending appeal at the Supreme Court of Virginia by industrial customers of a non-related utility regarding the constitutionality of the 2015 amendments. Oral arguments at the Virginia SCC are scheduled for March 2016. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition.

PJM Capacity Market

AGR is required to offer all of its available generation capacity in the PJM Reliability Pricing Model (RPM) auction, which is conducted three years in advance of the delivery year.

Through May 2015, AGR provided generation capacity to OPCo for both switched and non-switched OPCo generation customers.  For switched customers, OPCo paid AGR $188.88/MW day for capacity.  For non-switched OPCo generation customers, OPCo paid AGR its blended tariff rate for capacity consisting of $188.88/MW day for auctioned load and the non-fuel generation portion of its base rate for non-auctioned load.  As of June 2015, AGR’s generation resources are compensated through the PJM capacity auction.  Shown below are the RPM results through the June 2017 through May 2018 period:

	PJM
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
June 2017 through May 2018	120.00

In June 2015, FERC approved PJM’s proposal to create a new Capacity Performance (CP) product, intended to improve generator performance and reliability during emergency events by allowing higher offers into the RPM auction and imposing greater charges for non-performance during emergency events. PJM will procure approximately 80% CP and 20% Base Capacity for the June 2018 through May 2019 and June 2019 through May 2020 periods, while transitioning to 100% CP with the June 2020 through May 2021 period. FERC also approved transition incremental auctions to procure CP for the June 2016 through May 2017 and June 2017 through May 2018 periods.

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In the third quarter of 2015, PJM conducted the two transition auctions. The transition auctions allowed generators, including AGR, to re-offer cleared capacity that qualifies as CP. Shown below are the results of the two transition auctions:

	Capacity Performance
	Transition Incremental
PJM Auction Period	Auction Price
	(per MW day)
June 2016 through May 2017	$	134.00
June 2017 through May 2018	151.50

AGR cleared 7,169MW at $134/MW-day for the June 2016 through May 2017 period, replacing the original auction clearing price of $59.37/MW-day. AGR cleared 6,495MW for the June 2017 through May 2018 period at $151.50/MW-day, replacing the original auction clearing price of $120/MW-day.

In August 2015, PJM held its first base residual auction implementing CP rules for the June 2018 through May 2019 period. PJM cleared approximately 81% of the capacity for the June 2018 through May 2019 period as CP and 19% as Base Capacity. AGR cleared 7,209 MW at the CP auction price of $164.77/MW-day. Shown below are the results for the June 2018 through May 2019 period:

	Capacity Performance		Base Capacity
PJM Auction Period	Auction Price		Auction Price
	(per MW day)		(per MW day)
June 2018 through May 2019	$	164.77	$	150.00

The FERC order exempted Fixed Resource Requirement entities, including APCo, I&M, KPCo and WPCo, from the CP rules through the delivery period ending May 2019. In July 2015, AEP filed a request seeking rehearing of the FERC order approving CP. AEP is awaiting an order on its request for rehearing and will continue to advocate for further improvements to the CP rules and the capacity market as a whole through the PJM stakeholder process.

LITIGATION

In the ordinary course of business, AEP 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 that have a probable likelihood of loss if the loss can be estimated.  For details on the regulatory proceedings and pending litigation see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies. 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 a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.  In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiff’s claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing.  In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the

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breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiff subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiff’s motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. Management will continue to defend against the remaining claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

ENVIRONMENTAL ISSUES

AEP is implementing a substantial capital investment program and incurring additional operational costs to comply with environmental control requirements.  Additional investments and operational changes will need to be made in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO₂, NO_x, PM, CO₂ and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, rules governing the beneficial use and disposal of coal combustion products, clean water rules and renewal permits for certain water discharges.

AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units.  AEP, along with various industry groups, affected states and other parties 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 state plans to reduce CO₂ 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.

AEP 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 AEP is 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.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of December 31, 2015, the AEP System had a total generating capacity of approximately 32,000 MWs, of which approximately 18,000 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 fossil generating facilities.  Based upon management estimates, AEP’s investment to meet these proposed requirements ranges from approximately $3.2 billion to $3.8 billion through 2025.  These amounts include investments to convert some of the coal generation to natural gas.  

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 (SIPs) or federal implementation plans (FIPs) that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.  In addition, management is continuing to evaluate the economic feasibility of environmental investments on both regulated and nonregulated plants.

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In May 2015, AEP retired the following plants or units of plants:

Company	Plant Name and Unit	Generating Capacity
		(in MWs)
AGR	Kammer Plant	630
AGR	Muskingum River Plant	1,440
AGR	Picway Plant	100
APCo	Clinch River Plant, Unit 3	235
APCo	Glen Lyn Plant	335
APCo	Kanawha River Plant	400
APCo/AGR	Sporn Plant	600
I&M	Tanners Creek Plant	995
KPCo	Big Sandy Plant, Unit 2	800
Total		5,535

As of December 31, 2015, the net book value of the AGR units listed above was zero.  The net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of the regulated plants in the table above was approved for recovery, except for $148 million which is pending regulatory approval.

Subject to the factors listed above and based upon continuing evaluation, management intends to retire the following units of plants during 2016:

Company	Plant Name and Unit	Generating Capacity
		(in MWs)
PSO	Northeastern Station, Unit 4	470
SWEPCo	Welsh Plant, Unit 2	528
Total		998

As of December 31, 2015, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of the PSO and SWEPCo units listed above was $176 million. For Northeastern Station, Unit 4, management is seeking regulatory recovery of remaining net book values. For Welsh Plant, Unit 2, management will seek regulatory recovery of remaining net book values.

In October 2015, management obtained permits following the KPSC’s approval for the conversion of KPCo’s 278 MW Big Sandy Plant, Unit 1 to natural gas. Management expects to begin operations as a natural gas unit in the second quarter of 2016. As of December 31, 2015, the net book value, before cost of removal, including related materials and supplies inventory and CWIP balances of Big Sandy Plant, Unit 1 was $91 million.

Management is in the process of obtaining permits following the Virginia SCC’s and WVPSC’s approval for the conversion of APCo’s 470 MW Clinch River Plant, Units 1 and 2 to natural gas. In the third and fourth quarters of 2015, APCo retired the coal-related assets of Clinch River Plant, Units 1 and 2. For Clinch River Plant, Unit 3, which was retired in 2015, $23 million is pending regulatory approval. Management expects to begin operations as a natural gas unit in the first quarter of 2016 for Clinch River Plant, Unit 1 and the second quarter of 2016 for Clinch River Plant, Unit 2. As of December 31, 2015, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of Clinch River Plant, Units 1 and 2 was $143 million.

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 and impact financial condition.

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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 SO₂ and NO_x emissions from power plants.  The Federal EPA issued the Cross-State Air Pollution Rule (CSAPR) in August 2011 to replace CAIR.  The CSAPR was challenged in the courts.  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 was appealed to the U.S. Supreme Court, which reversed the decision and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit.  The U.S. Court of Appeals for the District of Columbia Circuit ordered CSAPR to take effect on January 1, 2015 while the remand proceeding was still pending. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit remanded the rule to the Federal EPA. All of the states in which AEP’s power plants are located are covered by CSAPR. See “Cross-State Air Pollution Rule (CSAPR)” section below.

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) will 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 SIPs or, if SIPs are not adequate or are not developed on schedule, through FIPs.  The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas.  In March 2012, the Federal EPA disapproved certain portions of the Arkansas regional haze SIP. In April 2015, the Federal EPA published a proposed FIP to replace the disapproved portions, including revised BART determinations for the Flint Creek Plant that are consistent with the environmental controls currently under construction. 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 SO₂ 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. In July 2015, management submitted comments to the proposed Arkansas FIP and participated in comments filed by industry associations of which AEP is a member. Management supports compliance with CSAPR programs as satisfaction of the BART requirements.

The Federal EPA issued rules for CO₂ emissions that apply to new and existing electric utility units. See “Climate Change, CO₂ Regulation and Energy Policy” section below.

The Federal EPA also issued new, more stringent national ambient air quality standards (NAAQS) for PM, SO₂ and ozone. In October 2015, the Federal EPA announced a lower final NAAQS for ozone of 70 parts per billion. 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 AEP’s operations are discussed in the following sections.

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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 SO₂ 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 SO₂ and NO_x in addition to the seasonal NO_x program.  The annual SO₂ 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.  In 2012, the court issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing 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. A petition for review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013. In April 2014, the U.S. Supreme Court issued a decision reversing in part the decision of the U.S. Court of Appeals for the District of Columbia Circuit and remanding the case for further proceedings consistent with the opinion. The Federal EPA filed a motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. The court granted the Federal EPA’s motion. The parties filed briefs and presented oral arguments. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit found that the Federal EPA over-controlled the SO₂ and/or NO_x budgets of 14 states. The U.S. Court of Appeals for the District of Columbia Circuit remanded the rule to the Federal EPA to timely revise the rule consistent with the court’s opinion while CSAPR remains in place.

In December 2015, the Federal EPA issued a proposal to revise the ozone season NO_x budgets in 23 states beginning in 2017 to address transport issues associated with the 2008 ozone standard and the budget errors identified in the U.S. Court of Appeals for the District of Columbia Circuit’s July 2015 decision. The proposal was open for public comment through February 1, 2016. Management believes that the Federal EPA mistakenly relied on future projected retirements and failed to take into account actual operating experience when establishing the 2017 budgets. Management also believes there is insufficient time to implement the required reductions.

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 units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of nonmercury metals) and hydrogen chloride (as a surrogate for acid gases).  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 was required within three years. Management obtained a one-year administrative extension at several units to facilitate 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.

In April 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the April 2012 final rule. Industry trade groups and several states filed petitions for further review in the U.S. Supreme Court and the court granted those petitions in November 2014.

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In June 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit remanded the MATS rule for further proceedings consistent with the U.S. Supreme Court’s decision that the Federal EPA was unreasonable in refusing to consider costs in its determination whether to regulate emissions of HAPs from power plants. The Federal EPA issued notice of a supplemental finding concluding that it is appropriate and necessary to regulate HAP emissions from coal-fired and oil-fired units. Management submitted comments on the proposal and will continue to monitor future regulatory developments. The rule remains in effect.

Climate Change, CO₂ Regulation and Energy Policy

The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions.  Management is taking steps to comply with these requirements, including increasing wind power purchases and broadening the AEP System’s portfolio of energy efficiency programs.

In October 2015, the Federal EPA published the final standards for new, modified and reconstructed fossil fired steam generating units and combustion turbines, and final guidelines for the development of state plans to regulate CO₂ emissions from existing sources. The final standard for new combustion turbines is 1,000 pounds of CO₂ per MWh and the final standard for new fossil steam units is 1,400 pounds of CO₂ per MWh. Reconstructed turbines are subject to the same standard as new units and no standard for modified combustion turbines was issued. Reconstructed fossil steam units are subject to a standard of 1,800 pounds of CO₂ per MWh for larger units and 2,000 pounds of CO₂ per MWh for smaller units. Modified fossil steam units will be subject to a site specific standard no lower than the standards that would be applied if the units were reconstructed.

The final emissions guidelines for existing sources, known as the Clean Power Plan, are based on a series of declining emission rates that are implemented beginning in 2022 through 2029. The final emission rate is 771 pounds of CO₂ per MWh for existing natural gas combined cycle units and 1,305 pounds of CO₂ per MWh for existing fossil steam units in 2030 and thereafter. The Federal EPA also developed a set of rate-based and mass-based state goals.

The Federal EPA also published proposed “model” rules that can be adopted by the states that would allow sources within “trading ready” state programs to trade, bank or sell allowances or credits issued by the states. These rules would also be the basis for any federal plan issued by the Federal EPA in a state that fails to submit or receive approval for a state plan. The Federal EPA intends to finalize either a rate-based or mass-based trading program that can be enforced in states that fail to submit approved plans by the deadlines established in the final guidelines. States are required to submit final plans or an extension request by September 2016 to the Federal EPA. States receiving an extension request must submit final plans by September 2018. Management is reviewing the final rules and evaluating the rule’s impacts as well as the anticipated actions by states where assets are located. The final rules are being challenged in the courts. In February 2016, the U.S. Supreme Court issued a stay on the final Clean Power Plan, including all of the deadlines for submission of initial or final state plans. The stay will remain in effect until a final decision is issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review. The Federal EPA established a 90-day public comment period on the proposed rules and management submitted comments.

Federal and state legislation or regulations that mandate limits on the emission of CO₂ could 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 AEP to close some coal-fired facilities and could lead to possible impairment of assets.

Coal Combustion Residual Rule

In April 2015, the Federal EPA published a final rule to regulate the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants.  

13

The final rule became effective in October 2015. The Federal EPA will regulate CCR as a non-hazardous solid waste and issued new minimum federal solid waste management standards. The rule applies to new and existing active CCR landfills and CCR surface impoundments at operating electric utility or independent power production facilities. The rule imposes new and additional construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements. The rule does not apply to inactive CCR landfills and inactive surface impoundments at retired generating stations or the beneficial use of CCR. The rule is self-implementing so state action is not required. Because of this self-implementing feature, the rule contains extensive record keeping, notice and internet posting requirements. The CCR rule requirements contain a compliance schedule spanning an approximate four year implementation period. If CCR units do not meet these standards within the timeframes provided, they will be required to close. Extensions of time for closure are available provided there is no alternative disposal capacity or the owner can certify cessation of a boiler by a certain date. Challenges to the rule by industry associations of which AEP is a member are proceeding.

Because AEP currently uses surface impoundments and landfills to manage CCR materials at generating facilities, significant costs will be incurred to upgrade or close and replace these existing facilities at some point in the future as the new rule is implemented. Management recorded a $95 million increase in asset retirement obligations in the second quarter of 2015 primarily due to the publication of the final rule. Management will continue to evaluate the rule’s impact on operations.

In February 2014, the Federal EPA completed a risk evaluation of the beneficial uses of coal fly ash in concrete and FGD 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 AEP’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.  Encapsulated beneficial uses are not materially impacted by the new rule but additional demonstrations may be required to continue land applications in significant amounts except in road construction projects.

Clean Water Act (CWA) Regulations

In 2014, the Federal EPA issued a final rule setting forth standards for existing power plants that is intended to 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 final rule affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to comply with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures at facilities withdrawing more than 125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, are not expected to require any technology changes. Facilities subject to both the impingement standard and site-specific entrainment studies will typically be given at least three years to conduct and submit the results of those studies to the permit agency. Compliance timeframes will then be established by the permit agency through each facility’s National Pollutant Discharge Elimination System (NPDES) permit for installation of any required technology changes, as those permits are renewed over the next five to eight years. Petitions for review of the final rule were filed by industry and environmental groups and are currently pending in the U.S. Court of Appeals for the Second Circuit.

In addition, the Federal EPA developed revised effluent limitation guidelines for electricity generating facilities.  A final rule was issued in November 2015. In addition to other requirements, the final rule establishes limits on flue gas desulfurization wastewater, zero discharge for fly ash and bottom ash transport water and flue gas mercury control wastewater. The applicability of these requirements is as soon as possible after November 2018 and no later than December 2023. These new requirements will be implemented through each facility’s wastewater discharge permit. Management will continue to review the final rule in detail to evaluate whether the plants are currently meeting the proposed limitations, what technologies are incorporated into AEP’s long-range plans and what additional costs might be incurred. Management is assessing technology additions and retrofits.

14

In June 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This jurisdictional definition applies 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. The final definition continues to recognize traditional navigable waters of the U.S. as jurisdictional as well as certain exclusions. The rule also contains a number of new specific definitions and criteria for determining whether certain other waters are jurisdictional because of a “significant nexus.” Management believes that clarity and efficiency in the permitting process is needed. Management remains concerned that the rule introduces new concepts and could subject more of AEP’s operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. The final rule is being challenged in both courts of appeal and district courts. Challengers include industry associations of which AEP is a member. The U.S. Court of Appeal for the Sixth Circuit granted a nationwide stay of the rule pending jurisdictional determinations.

RESULTS OF OPERATIONS

SEGMENTS

AEP’s primary business is the generation, transmission and distribution of electricity.  Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its 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.

AEP’s 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 and capacity to serve SSO customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

• Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission 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, SPP and MISO.

The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.

15

The table below presents Earnings Attributable to AEP Common Shareholders by segment for the years ended December 31, 2015, 2014 and 2013.

	Years Ended December 31,
	2015		2014		2013
	(in millions)
Vertically Integrated Utilities	$	896.5	$	707.6	$	677.7
Transmission and Distribution Utilities	351.7		354.6		357.8
AEP Transmission Holdco	191.2		150.8		79.7
Generation & Marketing	366.0		367.4		227.9
Corporate and Other	241.7		53.4		137.4
Earnings Attributable to AEP Common Shareholders	$	2,047.1	$	1,633.8	$	1,480.5

AEP CONSOLIDATED

2015 Compared to 2014

Earnings Attributable to AEP Common Shareholders increased from $1.6 billion in 2014 to $2 billion in 2015 primarily due to:

• Successful rate proceedings during 2015 in AEP’s various jurisdictions.

• The gain on the sale of commercial barge operations.

• An increase in transmission investment which resulted in higher revenues and income.

• A decrease in expenses due to a settlement and revision of certain asset retirement obligations.

• Favorable retail, trading and marketing activity.

These increases were partially offset by:

• A decrease in generation revenues due to lower capacity revenue.

• A decrease in off-system sales margins due to lower market prices and reduced sales volumes.

• An increase in depreciation and amortization expenses primarily due to higher depreciable base.

2014 Compared to 2013

Earnings Attributable to AEP Common Shareholders increased from $1.5 billion in 2013 to $1.6 billion in 2014 primarily due to:

• Impairments during 2013 for the following:

• Muskingum River Plant, Unit 5.

• A decision from the KPSC disallowing scrubber costs on KPCo’s Big Sandy Plant.

• A net increase in weather-related usage.

• Higher market prices and increased sales volumes.

• An increase in transmission investment which resulted in higher revenues and income.

• Successful rate proceedings during 2014 in AEP’s various jurisdictions.

These increases were partially offset by:

• A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in 2013.

• An increase in depreciation expense due to increased investments.

• An increase in negative regulatory provisions in 2014.

• An increase in fuel expense due to the termination of a long-term coal contract.

• An increase in plant maintenance.

• An increase in vegetation management expenses.

AEP’s results of operations by operating segment are discussed below.

16

VERTICALLY INTEGRATED UTILITIES

	Years Ended December 31,
Vertically Integrated Utilities	2015			2014			2013
	(in millions)
Revenues	$	9,172.2		$	9,484.4		$	9,992.5
Fuel and Purchased Electricity	3,413.6			3,953.4			4,770.4
Gross Margin	5,758.6			5,531.0			5,222.1
Other Operation and Maintenance	2,529.5			2,515.0			2,275.6
Asset Impairments and Other Related Charges	—			—			72.1
Depreciation and Amortization	1,062.6			1,033.0			941.5
Taxes Other Than Income Taxes	383.1			370.8			371.6
Operating Income	1,783.4			1,612.2			1,561.3
Interest and Investment Income	4.6			3.4			7.2
Carrying Costs Income	11.8			6.7			13.8
Allowance for Equity Funds Used During Construction	63.2			46.3			35.3
Interest Expense	(517.4		)	(525.5		)	(540.1		)
Income Before Income Tax Expense and Equity Earnings	1,345.6			1,143.1			1,077.5
Income Tax Expense	449.3			433.5			398.1
Equity Earnings of Unconsolidated Subsidiaries	3.9			2.2			2.3
Net Income	900.2			711.8			681.7
Net Income Attributable to Noncontrolling Interests	3.7			4.2			4.0
Earnings Attributable to AEP Common Shareholders	$	896.5		$	707.6		$	677.7

Summary of KWh Energy Sales for Vertically Integrated Utilities
	Years Ended December 31,
	2015	2014	2013
	(in millions of KWhs)
Retail:
Residential	32,720	34,073	33,851
Commercial	25,006	25,048	25,037
Industrial	34,638	35,281	34,216
Miscellaneous	2,279	2,311	2,284
Total Retail	94,643	96,713	95,388
Wholesale (a)	25,353	34,241	NM	(b)
Total KWhs	119,996	130,954	95,388

(a) Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers.

(b) 2013 is not comparable to 2015 or 2014 due to the 2013 asset transfers related to corporate separation in Ohio on December 31, 2013 and the termination of the Interconnection Agreement effective January 1, 2014.

NM    Not meaningful.

17

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.  In general, degree day changes in the eastern region have a larger effect on revenues than changes in the 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
	Years Ended December 31,
	2015	2014	2013
	(in degree days)
Eastern Region
Actual – Heating (a)	2,710	3,313	2,949
Normal – Heating (b)	2,755	2,740	2,734
Actual – Cooling (c)	1,113	932	1,040
Normal – Cooling (b)	1,075	1,080	1,080
Western Region
Actual – Heating (a)	1,379	1,840	1,772
Normal – Heating (b)	1,491	1,510	1,501
Actual – Cooling (c)	2,315	2,049	2,163
Normal – Cooling (b)	2,210	2,203	2,202

(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) Cooling degree days are calculated on a 65 degree temperature base.

18

2015 Compared to 2014

Reconciliation of Year Ended December 31, 2014 to Year Ended December 31, 2015

Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities

(in millions)

Year Ended December 31, 2014	$	707.6
Changes in Gross Margin:
Retail Margins	377.6
Off-system Sales	(124.9		)
Transmission Revenues	(26.4		)
Other Revenues	1.3
Total Change in Gross Margin	227.6
Changes in Expenses and Other:
Other Operation and Maintenance	(14.5		)
Depreciation and Amortization	(29.6		)
Taxes Other Than Income Taxes	(12.3		)
Interest and Investment Income	1.2
Carrying Costs Income	5.1
Allowance for Equity Funds Used During Construction	16.9
Interest Expense	8.1
Total Change in Expenses and Other	(25.1		)
Income Tax Expense	(15.8		)
Equity Earnings	1.7
Net Income Attributable to Noncontrolling Interests	0.5
Year Ended December 31, 2015	$	896.5

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 $378 million primarily due to the following:

• The effect of successful rate proceedings in AEP’s service territories which included:

• A $158 million increase primarily due to increases in rates in West Virginia, as well as an adjustment due to the amended Virginia law impacting biennial reviews.

• An $88 million increase for I&M primarily due to rate increases from Indiana rate riders and annual FERC formula rate adjustments.

• A $79 million increase for SWEPCo due to revenue increases from rate riders in Louisiana and Texas and increases in municipal and cooperative revenues due to annual FERC formula rate adjustments.

• A $25 million increase for PSO primarily due to revenue increases from rate riders.

For the increases described above, $70 million relate to riders/trackers which have corresponding increases in expense items below.

• A $72 million decrease in Fuel and Purchased Electricity primarily due to the transfer of a one-half interest in the Mitchell Plant from AGR to WPCo in January 2015. This decrease was partially offset by increases in other expense items below.

• A $32 million decrease in PJM charges not currently included in rate recovery riders/trackers.

These increases were partially offset by:

• A $70 million decrease in weather-normalized load primarily due to lower residential and industrial sales.

• A $32 million decrease in weather-related usage primarily in the eastern region.

• Margins from Off-system Sales decreased $125 million primarily due to lower market prices and decreased sales volumes.

• Transmission Revenues decreased $26 million primarily due to decreased PJM revenues, partially offset by an increase in SPP margins.

19

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

• Other Operation and Maintenance expenses increased $15 million primarily due to the following:

• A $56 million increase in recoverable expenses, primarily PJM expenses and vegetation management expenses currently fully recovered in rate recovery riders/trackers, partially offset by lower River Transportation Division (RTD) barging costs.

• A $23 million increase in plant-related expenses primarily due to the transfer of a one-half interest in the Mitchell Plant from AGR to WPCo in January 2015.  This increase was offset by an increase in Retail Margins above.

• A $10 million increase in SPP and PJM transmission services.

• A $4 million increase in regulatory commission expenses.

These increases were partially offset by:

• A $41 million decrease in employee-related expenses.

• A $25 million decrease in vegetation management expenses not included in riders/trackers.

• A $14 million decrease in environmental liabilities at I&M.

• Depreciation and Amortization expenses increased $30 million primarily due to overall higher depreciable base as well as amortization related to an advanced metering rider implemented in November 2014 in Oklahoma.

• Taxes Other Than Income Taxes increased $12 million primarily due to an increase in property taxes.

• Allowance for Equity Funds Used During Construction increased $17 million primarily due to increases in environmental and transmission projects.

• Interest Expense decreased $8 million primarily due to lower interest rates on APCo long-term debt.

• Income Tax Expense increased $16 million primarily due to an increase in pretax book income, partially offset by the recording of state and federal income tax adjustments and other book/tax differences which are accounted for on a flow-through basis.

20

2014 Compared to 2013

Reconciliation of Year Ended December 31, 2013 to Year Ended December 31, 2014

Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities

(in millions)

Year Ended December 31, 2013	$	677.7
Changes in Gross Margin:
Retail Margins	212.1
Off-system Sales	122.4
Transmission Revenues	21.8
Other Revenues	(47.4		)
Total Change in Gross Margin	308.9
Changes in Expenses and Other:
Other Operation and Maintenance	(239.4		)
Asset Impairments and Other Related Charges	72.1
Depreciation and Amortization	(91.5		)
Taxes Other Than Income Taxes	0.8
Interest and Investment Income	(3.8		)
Carrying Costs Income	(7.1		)
Allowance for Equity Funds Used During Construction	11.0
Interest Expense	14.6
Total Change in Expenses and Other	(243.3		)
Income Tax Expense	(35.4		)
Equity Earnings	(0.1		)
Net Income Attributable to Noncontrolling Interests	(0.2		)
Year Ended December 31, 2014	$	707.6

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 $212 million primarily due to the following:

• The effect of successful rate proceedings in AEP service territories, which included:

• A $129 million rate increase for APCo.

• A $55 million rate increase for KPCo.

• A $45 million rate increase for I&M.

• A $22 million rate increase for SWEPCo.

• A $12 million rate increase for PSO.

• A $9 million rate increase for WPCo.

For the rate increases described above, $153 million relates to riders/trackers which have corresponding increases in other expense items below.

• A $14 million increase due to favorable weather conditions.

These increases were partially offset by:

• A $43 million increase in PJM expenses net of recovery or offsets.

• A $36 million decrease due to a fuel proceeding disallowance.

• Margins from Off-system Sales increased $122 million primarily due to higher market prices and changes in margin sharing.

• Transmission Revenues increased $22 million primarily due to increased investment in the PJM region.

• Other Revenues decreased $47 million primarily due to a decrease in barging because RTD is no longer serving plants transferred from OPCo to AGR as of December 31, 2013 as a result of corporate separation in Ohio. This decrease in RTD revenue has a corresponding decrease in Other Operation and Maintenance expenses for barging as discussed below.

21

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

• Other Operation and Maintenance expenses increased $239 million primarily due to the following:

• A $56 million increase in recoverable expenses, primarily including PJM expenses, currently fully recovered in rate recovery riders/trackers, partially offset by RTD expenses for barging activities.

• A $46 million increase in employee-related expenses.

• A $45 million increase in transmission services related to PJM and SPP services.

• A $43 million increase in plant outage and maintenance expense primarily due to higher planned and advanced spending.

• A $26 million increase in distribution and transmission vegetation management expenses primarily due to higher advanced spending.

• A $25 million increase due to a favorable settlement of an insurance claim in the first quarter of 2013.

• A $10 million increase due to the 2014 write-off of IGCC costs in Virginia.

• An $8 million increase due to an increase in environmental remediation expense.

These increases were partially offset by:

• A $30 million write-off in the first quarter of 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.

• A $23 million decrease in storm expense primarily in the APCo service territory.

• Asset Impairments and Other Related Charges decreased $72 million due to the following:

• A $39 million decrease due to APCo’s 2013 write-off from a regulatory disallowance of a portion of Amos Plant, Unit 3 pursuant to a Virginia SCC order approving the transfer of Amos Plant, Unit 3.

• A $33 million decrease due to KPCo’s 2013 write-off of scrubber costs on the Big Sandy Plant and other generation costs in accordance with the KPSC’s October 2013 order.

• Depreciation and Amortization expenses increased $92 million primarily due to higher depreciable base.

• Carrying Cost Income decreased $7 million primarily due to the November 2013 securitization of the West Virginia ENEC deferral balance.

• Allowance for Equity Funds Used During Construction increased $11 million primarily due to increases in environmental and transmission projects.

• Interest Expense decreased $15 million primarily due to the following:

• A $6 million decrease due to the retirement of KPCo Senior Unsecured Notes in the third quarter of 2013.

• A $4 million decrease due to the redemption of I&M Senior Unsecured Notes in the fourth quarter of 2013.

• A $4 million decrease due to rate approvals in Louisiana and Texas as well as an increase in the debt component of AFUDC due to increased transmission and environmental projects.

• Income Tax Expense increased $35 million primarily due to an increase in pretax book income, the recording of state income tax adjustments and other book/tax differences which are accounted for on a flow-through basis, partially offset by the recording of federal income tax adjustments.

22

TRANSMISSION AND DISTRIBUTION UTILITIES

	Years Ended December 31,
Transmission and Distribution Utilities	2015			2014			2013
	(in millions)
Revenues	$	4,556.6		$	4,813.6		$	4,478.4
Purchased Electricity	1,113.5			1,519.7			1,626.5
Amortization of Generation Deferrals	169.1			110.9			—
Gross Margin	3,274.0			3,183.0			2,851.9
Other Operation and Maintenance	1,329.9			1,275.8			1,003.6
Depreciation and Amortization	686.2			657.8			591.3
Taxes Other Than Income Taxes	478.3			453.4			435.6
Operating Income	779.6			796.0			821.4
Interest and Investment Income	6.1			11.4			1.6
Carrying Costs Income	11.8			26.5			16.3
Allowance for Equity Funds Used During Construction	15.5			11.7			7.8
Interest Expense	(275.8		)	(279.9		)	(291.0		)
Income Before Income Tax Expense	537.2			565.7			556.1
Income Tax Expense	185.5			211.1			198.3
Net Income	351.7			354.6			357.8
Net Income Attributable to Noncontrolling Interests	—			—			—
Earnings Attributable to AEP Common Shareholders	$	351.7		$	354.6		$	357.8

Summary of KWh Energy Sales for Transmission and Distribution Utilities
	Years Ended December 31,
	2015		2014		2013
	(in millions of KWhs)
Retail:
Residential	25,735		26,209		25,531
Commercial	25,268		25,307		24,631
Industrial	22,353		21,830		22,668
Miscellaneous	702		713		710
Total Retail (a)	74,058		74,059		73,540
Wholesale	1,701	(b)	2,198	(b)	NM	(c)
Total KWhs	75,759		76,257		73,540

(a) Represents energy delivered to distribution customers.

(b) Primarily Ohio’s contractually obligated purchases of OVEC power sold into PJM.

(c) 2013 is not comparable to 2015 or 2014 due to the 2013 asset transfers related to corporate separation in Ohio on December 31, 2013, and the termination of the Interconnection Agreement effective January 1, 2014.

NM    Not meaningful.

23

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.  In general, degree day changes in the eastern region have a larger effect on revenues than changes in the 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 Transmission and Distribution Utilities
	Years Ended December 31,
	2015	2014	2013
	(in degree days)
Eastern Region
Actual – Heating (a)	3,235	3,734	3,383
Normal – Heating (b)	3,226	3,230	3,229
Actual – Cooling (c)	975	949	1,029
Normal – Cooling (b)	970	960	954
Western Region
Actual – Heating (a)	390	428	368
Normal – Heating (b)	325	337	337
Actual – Cooling (d)	2,718	2,553	2,737
Normal – Cooling (b)	2,642	2,618	2,608

(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.

24

2015 Compared to 2014

Reconciliation of Year Ended December 31, 2014 to Year Ended December 31, 2015

Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities

(in millions)

Year Ended December 31, 2014	$	354.6
Changes in Gross Margin:
Retail Margins	199.3
Off-System Sales	(28.5		)
Transmission Revenues	(83.7		)
Other Revenues	3.9
Total Change in Gross Margin	91.0
Changes in Expenses and Other:
Other Operation and Maintenance	(54.1		)
Depreciation and Amortization	(28.4		)
Taxes Other Than Income Taxes	(24.9		)
Interest and Investment Income	(5.3		)
Carrying Costs Income	(14.7		)
Allowance for Equity Funds Used During Construction	3.8
Interest Expense	4.1
Total Change in Expenses and Other	(119.5		)
Income Tax Expense	25.6
Year Ended December 31, 2015	$	351.7

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 $199 million primarily due to the following:

• A $131 million increase in Ohio transmission and PJM revenues primarily due to energy supplied as result of the Ohio auction and a regulatory change which resulted in revenues collected through a non-bypassable transmission rider, partially offset by a corresponding decrease in Transmission Revenues below.

• A $50 million increase in Ohio rider revenues associated with the Distribution Investment Rider (DIR), the gridSMART^® Rider, the Enhanced Service Reliability (ESR) Rider and the Retail Stability Rider (RSR). These increases in rider revenues are partially offset by net increases in other expense items below.

• A $33 million negative Ohio regulatory provision recorded in 2014.

• A $26 million increase in TCC and TNC revenues primarily due to the recovery of ERCOT transmission expenses, offset in Other Operation and Maintenance expenses below.

These increases were partially offset by:

• A $25 million decrease in revenues associated with the recovery of 2012 storm costs under the Ohio Storm Damage Recovery Rider which ended in April 2015. This decrease in Retail Margins is offset by a decrease in Other Operation and Maintenance expenses below.

• A $17 million decrease in Ohio Energy Efficiency/Peak Demand Reduction (EE/PDR) Rider revenues. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.

• An $11 million decrease in revenues associated with the Universal Service Fund (USF) surcharge. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.

• Margins from Off-system Sales decreased $29 million primarily due to losses from a legacy OPCo power contract.

25

• Transmission Revenues decreased $84 million primarily due to the following:

• An $80 million decrease in PJM Network Integrated Transmission Service (NITS) revenue primarily due to OPCo assuming the responsibility for items determined to be cost-based transmission-related charges that were the responsibility of the CRES providers prior to June 2015, partially offset by a corresponding increase in Retail Margins above.

• A $12 million decrease in Ohio revenues related to a lower annual transmission formula rate true-up.

• A $9 million OPCo transmission regulatory settlement in 2015.

These decreases were partially offset by:

• A $25 million increase primarily due to increased transmission investment in ERCOT.

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

• Other Operation and Maintenance expenses increased $54 million primarily due to the following:

• A $72 million increase in recoverable PJM, ERCOT and gridSMART^® expenses. These increases were offset by increases in Retail Margins above.

• A $19 million increase in distribution expenses including system improvements and storm expenses.

• A $12 million increase related to a regulatory settlement in Ohio.

• A $6 million increase due to PUCO ordered contributions to the Ohio Growth Fund.

These increases were partially offset by:

• A $26 million decrease due to the completion of the amortization of 2012 deferred storm expenses in April 2015. This decrease was offset by a corresponding decrease in Retail Margins above.

• A $17 million decrease in EE/PDR costs and associated deferrals. This decrease was offset by a corresponding decrease in Retail Margins above.

• An $11 million decrease in remitted Universal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset by a corresponding decrease in Retail Margins above.

• Depreciation and Amortization expenses increased $28 millionprimarily due to the following:

• A $29 million increase due to an increase in the depreciable base of transmission and distribution assets.

• An $8 million increase in amortization of TCC’s securitization transition asset, partially offset in Other Revenues.

• An $8 million increase in amortization expenses for the collection of carrying costs on deferred capacity charges beginning June 2015. This increase was offset by a corresponding increase in Retail Margins above.

These increases were partially offset by:

• A $9 million decrease in recoverable DIR depreciation expense. This decrease was offset by a decrease in Retail Margins above.

• An $8 million decrease in recoverable gridSMART^® depreciation expense. This decrease was offset by a decrease in Retail Margins above.

• Taxes Other Than Income Taxes increased $25 million primarily due to increased property taxes.

• Interest and Investment Income decreased $5 million primarily due to a decrease in affiliated notes payable for OPCo. This decrease was offset by a decrease in Interest Expense.

• Carrying Costs Income decreased $15 million primarily due to the collection ofcarrying costs on deferred capacity charges beginning June 2015.

• Income Tax Expense decreased $26 million primarily due to a decrease in pretax book income and by the recording of state income tax adjustments.

26

2014 Compared to 2013

Reconciliation of Year Ended December 31, 2013 to Year Ended December 31, 2014

Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities

(in millions)

Year Ended December 31, 2013	$	357.8
Changes in Gross Margin:
Retail Margins	235.4
Off-System Sales	3.4
Transmission Revenues	71.1
Other Revenues	21.2
Total Change in Gross Margin	331.1
Changes in Expenses and Other:
Other Operation and Maintenance	(272.2		)
Depreciation and Amortization	(66.5		)
Taxes Other Than Income Taxes	(17.8		)
Interest and Investment Income	9.8
Carrying Costs Income	10.2
Allowance for Equity Funds Used During Construction	3.9
Interest Expense	11.1
Total Change in Expenses and Other	(321.5		)
Income Tax Expense	(12.8		)
Year Ended December 31, 2014	$	354.6

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 $235 million primarily due to the following:

• A $106 million increase in revenues primarily associated with Ohio rate riders/trackers and PJM revenues, partially offset by regulatory provisions.  These increases have corresponding increases in expense items discussed below.

• A $96 million increase in TCC and TNC revenues primarily due to the recovery of ERCOT transmission expenses which is offset in Other Operation and Maintenance below.

• Transmission Revenues increased $71 million primarily due to:

• A $58 million increase due to increased transmission revenues from customers who have switched to alternative CRES providers, rate increases for customers in the PJM region and increased transmission investment. This increase in transmission revenues related to CRES providers primarily offsets lost revenues included in Retail Margins above.

• A $14 million increase due to increased transmission investment in ERCOT.

• Other Revenues increased $21 million primarily due to an increase in Texas securitization revenues which is offset in Depreciation and Amortization and Interest Expense below.

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

• Other Operation and Maintenance expenses increased $272 million primarily due to the following:

• A $213 million increase in recoverable expenses, including PJM expenses, ERCOT expenses and the Ohio storm amortization, currently fully recovered in rate recovery riders/trackers.

• A $19 million increase in expenses related to various distribution services as a result of advanced spending.

• An $18 million increase in remitted Universal Service Fund (USF) surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase is offset by an increase in Retail Margins above.

• A $9 million increase in vegetation management expenses primarily due to advanced spending.

• Depreciation and Amortization expenses increased $67 million primarily due to the following:

• A $39 million increase in amortization related to OPCo and TCC securitizations, which are partially offset in Retail Margins and Other Revenues above.

• A $28 million increase due to an increase in the depreciable base of transmission and distribution assets.

• Taxes Other Than Income Taxes increased $18 million primarily due to increased property taxes.

• Interest and Investment Income increased $10 million primarily due to interest on affiliated notes resulting from corporate separation.

• Carrying Costs Income increased $10 million primarily due to increased capacity deferral carrying charges.

• Interest Expense decreased $11 million primarily due to reduced TCC securitization long-term debt outstanding, which is partially offset in Other Revenues above.

• Income Tax Expense increased $13 million primarily due to an increase in pretax book income and by the recording of federal and state income tax adjustments.

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AEP TRANSMISSION HOLDCO

	Years Ended December 31,
AEP Transmission Holdco	2015			2014			2013
	(in millions)
Transmission Revenues	$	329.2		$	191.9		$	77.7
Other Operation and Maintenance	38.4			28.7			11.7
Depreciation and Amortization	43.0			23.7			10.1
Taxes Other Than Income Taxes	66.0			31.8			20.0
Operating Income	181.8			107.7			35.9
Interest and Investment Income	0.2			—			—
Carrying Costs Income (Expense)	(0.2		)	—			0.1
Allowance for Equity Funds Used During Construction	53.0			44.8			29.5
Interest Expense	(37.2		)	(23.5		)	(10.0		)
Income Before Income Tax Expense and Equity Earnings	197.6			129.0			55.5
Income Tax Expense	91.3			62.9			29.0
Equity Earnings of Unconsolidated Subsidiaries	86.4			84.7			52.9
Net Income	192.7			150.8			79.4
Net Income Attributable to Noncontrolling Interests	1.5			—			(0.3		)
Earnings Attributable to AEP Common Shareholders	$	191.2		$	150.8		$	79.7

Summary of Net Plant In Service and CWIP for AEP Transmission Holdco

	December 31,
	2015		2014		2013
	(in millions)
Net Plant In Service	$	2,832.7	$	1,800.8	$	981.5
CWIP	1,092.6		888.9		645.0

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2015 Compared to 2014

Reconciliation of Year Ended December 31, 2014 to Year Ended December 31, 2015

Earnings Attributable to AEP Common Shareholders from Transmission Holdco

(in millions)

Year Ended December 31, 2014	$	150.8
Changes in Transmission Revenues:
Transmission Revenues	137.3
Total Change in Transmission Revenues	137.3
Changes in Expenses and Other:
Other Operation and Maintenance	(9.7		)
Depreciation and Amortization	(19.3		)
Taxes Other Than Income Taxes	(34.2		)
Interest and Investment Income	0.2
Carrying Costs Income	(0.2		)
Allowance for Equity Funds Used During Construction	8.2
Interest Expense	(13.7		)
Total Change in Expenses and Other	(68.7		)
Income Tax Expense	(28.4		)
Equity Earnings	1.7
Net Income Attributable to Noncontrolling Interests	(1.5		)
Year Ended December 31, 2015	$	191.2

The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and non-affiliates were as follows:

• Transmission Revenues increased $137 million primarily due to an increase in projects placed in-service by AEP’s wholly-owned transmission subsidiaries.

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

• Other Operation and Maintenance expenses increased $10 million primarily due to increased transmission investment.

• Depreciation and Amortization expenses increased $19 million primarily due to higher depreciable base.

• Taxes Other Than Income Taxes increased $34 million primarily due to increased property taxes.

• Allowance for Equity Funds Used During Construction increased $8 million primarily due to increased transmission investment.

• Interest Expense increased $14 million primarily due to higher outstanding long-term debt balances.

• Income Tax Expense increased $28 million primarily due to an increase in pretax book income.

30

2014 Compared to 2013

Reconciliation of Year Ended December 31, 2013 to Year Ended December 31, 2014

Earnings Attributable to AEP Common Shareholders from Transmission Holdco

(in millions)

Year Ended December 31, 2013	$	79.4
Changes in Transmission Revenues:
Transmission Revenues	114.2
Total Change in Transmission Revenues	114.2
Changes in Expenses and Other:
Other Operation and Maintenance	(17.0		)
Depreciation and Amortization	(13.6		)
Taxes Other Than Income Taxes	(11.8		)
Carrying Costs Income	(0.1		)
Allowance for Equity Funds Used During Construction	15.3
Interest Expense	(13.5		)
Total Change in Expenses and Other	(40.7		)
Income Tax Expense	(33.9		)
Equity Earnings	31.8
Year Ended December 31, 2014	$	150.8

The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and non-affiliates were as follows:

• Transmission Revenues increased $114 million primarily due to an increase in projects placed in-service by AEP’s wholly-owned transmission subsidiaries.

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

• Other Operation and Maintenance expenses increased $17 million primarily due to increased transmission investment.

• Depreciation and Amortization expenses increased $14 million primarily due to higher depreciable base.

• Taxes Other Than Income Taxes increased $12 million primarily due to increased property taxes.

• Allowance for Equity Funds Used During Construction increased $15 million primarily due to increased transmission investment.

• Interest Expense increased $14 million primarily due to higher outstanding long-term debt balances.

• Income Tax Expense increased $34 million primarily due to an increase in pretax book income.

• Equity Earnings increased $32 million primarily due to an increase in transmission investment by ETT.

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GENERATION & MARKETING

	Years Ended December 31,
Generation & Marketing	2015			2014			2013
	(in millions)
Revenues	$	3,412.7		$	3,849.6		$	3,665.2
Fuel, Purchased Electricity and Other	2,164.6			2,436.3			2,305.1
Gross Margin	1,248.1			1,413.3			1,360.1
Other Operation and Maintenance	408.4			549.7			522.5
Asset Impairments and Other Related Charges	—			—			154.3
Depreciation and Amortization	201.4			226.8			236.1
Taxes Other Than Income Taxes	40.7			49.6			53.8
Operating Income	597.6			587.2			393.4
Interest and Investment Income	2.8			4.7			2.1
Allowance for Equity Funds Used During Construction	0.2			0.1			0.1
Interest Expense	(40.0		)	(45.3		)	(55.5		)
Income Before Income Tax Expense	560.6			546.7			340.1
Income Tax Expense	194.6			179.3			112.2
Net Income	366.0			367.4			227.9
Net Income Attributable to Noncontrolling Interests	—			—			—
Earnings Attributable to AEP Common Shareholders	$	366.0		$	367.4		$	227.9

Summary of MWhs Generated for Generation & Marketing
	Years Ended December 31,
	2015	2014	2013
	(in millions of MWhs)
Fuel Type:
Coal	27	38	38
Natural Gas	13	7	6
Wind	1	1	1
Total MWhs	41	46	45

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2015 Compared to 2014

Reconciliation of Year Ended December 31, 2014 to Year Ended December 31, 2015

Earnings Attributable to AEP Common Shareholders from Generation & Marketing

(in millions)

Year Ended December 31, 2014	$	367.4
Changes in Gross Margin:
Generation	(203.9		)
Retail, Trading and Marketing	43.2
Other	(4.5		)
Total Change in Gross Margin	(165.2		)
Changes in Expenses and Other:
Other Operation and Maintenance	141.3
Depreciation and Amortization	25.4
Taxes Other Than Income Taxes	8.9
Interest and Investment Income	(1.9		)
Allowance for Equity Funds Used During Construction	0.1
Interest Expense	5.3
Total Change in Expenses and Other	179.1
Income Tax Expense	(15.3		)
Year Ended December 31, 2015	$	366.0

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 certain cost of service for retail operations were as follows:

• Generation decreased $204 million primarily due to lower capacity revenue due to the termination of the Power Supply Agreement between AGR and OPCo in May 2015.

• Retail, Trading and Marketing increased $43 million primarily due to favorable wholesale trading and marketing performance as well as an increase in retail volumes.

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

• Other Operation and Maintenance expenses decreased $141 million primarily due to a settlement and revision of certain asset retirement obligations and decreased plant outage and maintenance costs.

• Depreciation and Amortization expenses decreased $25 million primarily due to reduced plant in-service.

• Taxes Other Than Income Taxes decreased $9 million primarily due to a decrease in property taxes.

• Interest Expense decreased $5 million primarily due to lower outstanding debt balances and lower long-term interest rates.

• Income Tax Expense increased $15 million primarily due to an increase in pretax book income and by the recording of federal and state income tax adjustments.

33

2014 Compared to 2013

Reconciliation of Year Ended December 31, 2013 to Year Ended December 31, 2014

Earnings Attributable to AEP Common Shareholders from Generation & Marketing

(in millions)

Year Ended December 31, 2013	$	227.9
Changes in Gross Margin:
Generation	56.5
Retail, Trading and Marketing	(3.8		)
Other	0.5
Total Change in Gross Margin	53.2
Changes in Expenses and Other:
Other Operation and Maintenance	(27.2		)
Asset Impairments and Other Related Charges	154.3
Depreciation and Amortization	9.3
Taxes Other Than Income Taxes	4.2
Interest and Investment Income	2.6
Interest Expense	10.2
Total Change in Expenses and Other	153.4
Income Tax Expense	(67.1		)
Year Ended December 31, 2014	$	367.4

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 certain cost of service for retail operations were as follows:

• Generation increased $57 million primarily due to $111 million of increased demand and market prices driven by cold temperatures in the first quarter of 2014, partially offset by $54 million due to the termination of a long-term coal contract.

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

• Other Operation and Maintenance expenses increased $27 million primarily due to increased asset retirement obligation costs related to planned retirements.

• Asset Impairments and Other Related Charges decreased $154 million due to the 2013 impairment of Muskingum River Plant, Unit 5.

• Depreciation and Amortization expenses decreased $9 million primarily due to the 2013 impairment of Muskingum River Plant, Unit 5.

• Interest Expense decreased $10 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.

• Income Tax Expense increased $67 million primarily due to an increase in pretax book income.

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CORPORATE AND OTHER

2015 Compared to 2014

Earnings attributable to AEP Common Shareholders from Corporate and Other increased from $53 million in 2014 to $242 million in 2015 primarily due to the gain on the sale of AEP River Operations that was recorded in Income from Discontinued Operations, Net of Tax, on the statement of income.

2014 Compared to 2013

Earnings attributable to AEP Common Shareholders from Corporate and Other decreased from $137 million in 2013 to $53 million in 2014 primarily due to a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in 2013. This decrease was partially offset by an increase in AEP River Operations due to a 28% increase in barge freight revenue for 2014 compared to 2013. The increase in 2014 freight revenue over 2013 was driven by strong barge freight demand particularly for export grain, strong northbound imports of fertilizer, salt and steel and increased shipments of domestic coal.

AEP SYSTEM INCOME TAXES

2015 Compared to 2014

Income Tax Expense increased $17 million primarily due to an increase in pretax book income, partially offset by the recording of state income tax adjustments and other book/tax differences which are accounted for on a flow-through basis.

2014 Compared to 2013

Income Tax Expense increased $258 million primarily due to an increase in pretax book income and the recording of state income tax adjustments and by a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in 2013.

FINANCIAL CONDITION

AEP measures financial condition by the strength of its balance sheet and the liquidity provided by its cash flows.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

	December 31,
	2015				2014
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	19,572.7	51.1	%	$	18,512.4	(a)	50.5	%
Short-term Debt	800.0		2.1		1,346.0			3.7
Total Debt	20,372.7		53.2		19,858.4		(a)	54.2
AEP Common Equity	17,891.7		46.8		16,820.2			45.8
Noncontrolling Interests	13.2		—		4.3			—
Total Debt and Equity Capitalization	$	38,277.6	100.0	%	$	36,682.9		100.0	%

(a) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.

AEP’s ratio of debt-to-total capital improved from 54.2% as of December 31, 2014 to 53.2% as of December 31, 2015 primarily due to an increase in common equity from earnings.

35

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability.  Management believes AEP has adequate liquidity under its existing credit facilities.  As of December 31, 2015, AEP had $3.5 billion in aggregate credit facility commitments to support its operations.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  Management is committed to maintaining adequate liquidity.  AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, sale-leaseback or leasing agreements or common stock.

Commercial Paper Credit Facilities

AEP manages liquidity by maintaining adequate external financing commitments.  As of December 31, 2015, available liquidity was approximately $3.5 billion as illustrated in the table below:

	Amount		Maturity
	(in millions)
Commercial Paper Backup:
Revolving Credit Facility	$	1,750.0	June 2017
Revolving Credit Facility	1,750.0		July 2018
Total	3,500.0
Cash and Cash Equivalents	176.4
Total Liquidity Sources	3,676.4
Less: AEP Commercial Paper Outstanding	125.0
Letters of Credit Issued	22.7
Net Available Liquidity	$	3,528.7

AEP has credit facilities totaling $3.5 billion to support its commercial paper program.  The credit facilities allow management to issue letters of credit in an amount up to $1.2 billion.

AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain 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 2015 was $788 million.  The weighted-average interest rate for AEP’s commercial paper during 2015 was 0.46%.

Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit under three uncommitted facilities totaling $225 million.  As of December 31, 2015, the maximum future payments for letters of credit issued under the uncommitted facilities was $125 million with maturities ranging from June 2016 to December 2016.

Financing Plan

As of December 31, 2015, AEP has $1.8 billion of long-term debt due within one year which includes $607 million of Pollution Control Bonds with mandatory tender dates and credit support for variable interest rates that requires the debt be classified as current.  Also included in AEP’s long-term debt due within one year is $407 million of securitization bonds and DCC Fuel notes which will be repaid.  Management plans to refinance the majority of the other maturities due within one year.

36

Securitized Accounts Receivables

AEP’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables.  The agreement expires in June 2017.  

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a 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 AEP’s credit agreements.  Debt as defined in the revolving credit agreements excludes securitization bonds and debt of AEP Credit.  As of December 31, 2015, this contractually-defined percentage was 50.2%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  As of December 31, 2015, AEP complied with all of the covenants contained in these credit agreements.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s 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 AEP’s non-exchange traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable.  However, a default under AEP’s non-exchange traded commodity contracts would not cause an event of default under its 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 and AEP manages its borrowings to stay within those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.56 per share in January 2016.  Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time.  Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries.  Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends.  

Management does not believe these restrictions related to AEP’s various financing arrangements and regulatory requirements will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock.

Credit Ratings

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

37

CASH FLOW

AEP relies primarily on cash flows from operations, debt issuances and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders.

	Years Ended December 31,
	2015			2014			2013
	(in millions)
Cash and Cash Equivalents at Beginning of Period	$	162.5		$	117.5		$	278.7
Net Cash Flows from Continuing Operating Activities	4,748.7			4,602.4			4,096.2
Net Cash Flows Used for Continuing Investing Activities	(4,564.0		)	(4,405.9		)	(3,817.8		)
Net Cash Flows Used for Continuing Financing Activities	(661.7		)	(150.9		)	(438.7		)
Net Cash Flows from (Used for) Discontinued Operations	490.9			(0.6		)	(0.9		)
Net Increase (Decrease) in Cash and Cash Equivalents	13.9			45.0			(161.2		)
Cash and Cash Equivalents at End of Period	$	176.4		$	162.5		$	117.5

AEP uses short-term debt, including commercial paper, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.

Operating Activities

	Years Ended December 31,
	2015		2014		2013
	(in millions)
Income from Continuing Operations	$	1,768.6	$	1,590.5	$	1,473.9
Depreciation and Amortization	2,009.7		1,897.6		1,712.5
Other	970.4		1,114.3		909.8
Net Cash Flows from Continuing Operating Activities	$	4,748.7	$	4,602.4	$	4,096.2

Net Cash Flows from Continuing Operating Activities were $4.7 billion in 2015 consisting primarily of Income from Continuing Operations of $1.8 billion and $2 billion 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.Deferred Income Taxes increased primarily due to provisions in the Protecting Americans from Tax Hikes Act of 2015 and an increase in tax versus book temporary differences from operations.  

Net Cash Flows from Continuing Operating Activities were $4.6 billion in 2014 consisting primarily of Income from Continuing Operations of $1.6 billion and $1.9 billion 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.  Deferred Income Taxes increased primarily due to provisions in the Tax Increase Prevention Act of 2014 and an increase in tax versus book temporary differences from operations.  The reduction in Fuel, Material and Supplies balance reflects a decrease in fuel inventory due to cold winter weather and increased generation.

Net Cash Flows from Continuing Operating Activities were $4.1 billion in 2013 consisting primarily of Income from Continuing Operations of $1.5 billion, $1.7 billion of noncash Depreciation and Amortization and $226 million of Asset Impairments related to Muskingum River Plant, Unit 5, Big Sandy and Amos Plants, partially offset by $214 million of Ohio capacity deferrals as a result of a 2012 PUCO order.  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 versus book temporary differences from operations.  Significant changes in other items include the favorable impact of a decrease in fuel inventory and net cash flows for Accrued Taxes as a result of the recognition of the tax benefit related to the U.K. Windfall Tax.

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Investing Activities

	Years Ended December 31,
	2015			2014			2013
	(in millions)
Construction Expenditures	$	(4,508.0	)	$	(4,130.0	)	$	(3,616.4	)
Acquisitions of Nuclear Fuel	(92.0		)	(116.2		)	(153.7		)
Acquisitions of Assets/Businesses	(5.3		)	(64.8		)	(32.0		)
Other	41.3			(94.9		)	(15.7		)
Net Cash Flows Used for Continuing Investing Activities	$	(4,564.0	)	$	(4,405.9	)	$	(3,817.8	)

Net Cash Flows Used for Continuing Investing Activities were $4.6 billion in 2015 primarily due to Construction Expenditures for generation, distribution and transmission investments.

Net Cash Flows Used for Continuing Investing Activities were $4.4 billion in 2014 primarily due to Construction Expenditures for generation, distribution and transmission investments. AEP also purchased transmission assets for $38 million.

Net Cash Flows Used for Continuing Investing Activities were $3.8 billion in 2013 primarily due to Construction Expenditures for generation, distribution and transmission investments.

Financing Activities

	Years Ended December 31,
	2015			2014			2013
	(in millions)
Issuance of Common Stock, Net	$	81.6		$	73.6		$	83.2
Issuance/Retirement of Debt, Net	492.7			878.6			390.2
Proceeds from Nuclear Fuel Sale/Leaseback	—			—			110.2
Dividends Paid on Common Stock	(1,059.0		)	(997.6		)	(954.3		)
Other	(177.0		)	(105.5		)	(68.0		)
Net Cash Flows Used for Continuing Financing Activities	$	(661.7	)	$	(150.9	)	$	(438.7	)

Net Cash Flows Used for Continuing Financing Activities in 2015 were $662 million.  AEP’s net debt issuances were $493 million.  The net issuances included issuances of $2.1 billion of senior unsecured notes, $140 million of pollution control bonds and $1.2 billion of other debt notes offset by retirements of $1 billion of senior unsecured notes, $342 million of securitization bonds, $308 of pollution control bonds and $716 million of other debt notes and a decrease in short term borrowing of $546 million.  AEP paid common stock dividends of $1.1 billion.  See Note 14 – Financing Activities.

Net Cash Flows Used for Continuing Financing Activities in 2014 were $151 million.  AEP’s net debt issuances were $879 million.  The net issuances included issuances of $1.6 billion of senior unsecured notes and other debt notes, $444 million of pollution control bonds and an increase in short-term borrowing of $589 million offset by retirements of $1.1 billion of notes, $412 million of pollution control bonds and $306 million of securitization bonds.  AEP paid common stock dividends of $998 million.  See Note 14 – Financing Activities.

Net Cash Flows Used for Continuing Financing Activities in 2013 were $439 million.  AEP’s net debt issuances were $388 million.  The net issuances included issuances of $745 million of senior unsecured notes, $1 billion draws on a $1 billion term credit facility, $647 million of securitization bonds, $328 million of notes payable and other debt and $305 million of pollution control bonds offset by retirements of $1.8 billion of senior unsecured and other debt notes, $331 million of pollution control bonds, $243 million of securitization bonds and a decrease in short-term borrowing of $224 million.  AEP paid common stock dividends of $954 million.

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Cash Flow Activity from Discontinued Operations

In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015 and resulted in net cash proceeds from the sale of $491 million, which were immediately available for use in AEP’s continuing operations. The cash proceeds of $539 million were recorded in Discontinued Investing Activities. These proceeds were reduced by a make whole payment on the extinguishment of AEPRO long-term debt of $32 million, which was recorded in Discontinued Financing Activities, and transaction costs of $16 million, which were recorded in Discontinued Operating Activities. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.

The following financing activities occurred during 2015:

AEP Common Stock:

• During 2015, AEP issued 1.7 million shares of common stock under the incentive compensation, employee saving and dividend reinvestment plans and received net proceeds of $82 million.

Debt:

• During 2015, AEP issued approximately $3.5 billion of long-term debt, including $2.1 billion of senior notes at interest rates ranging from 3.17% to 4.71%, $140 million of pollution control revenue bonds at interest rates ranging from 1.6% to 1.9%, and $1.2 billion of other debt at variable interest rates.  The proceeds from these issuances were used to fund long-term debt maturities and construction programs.

• During 2015, AEP did not enter into any interest rate derivatives and settled $5 million of such transactions. The settlements resulted in net cash received of $3 million. As of December 31, 2015, AEP had in place $810 million of notional interest rate derivatives designated as cash flow and fair value hedges.

In 2016:

• In January 2016 and February 2016, I&M retired $14 million and $8 million, respectively, of Notes Payable related to DCC Fuel.

• In January 2016, APCo retired $75 million of variable rate Pollution Control Bonds due in 2016 and issued $75 million of variable rate Pollution Control Bonds due in 2036.

• In January 2016, OPCo retired $23 million of Securitization Bonds.

• In January 2016, TCC retired $128 million of Securitization Bonds.

• In February 2016, APCo retired $11 million of Securitization Bonds.

• In February 2016, Transource Missouri drew $3 million on an existing $300 million variable rate credit facility due in 2018.

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BUDGETED CONSTRUCTION EXPENDITURES

Management forecasts approximately $5 billion of construction expenditures in 2016.  For both 2017 and 2018, management forecasts construction expenditures of $5 billion. The expenditures are generally for transmission, generation, distribution and required environmental investment to comply with the Federal EPA rules.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  Management expects to fund these construction expenditures through cash flows from operations and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. The 2016 estimated construction expenditures include generation, transmission and distribution related investments, as well as expenditures for compliance with environmental regulations as follows:

	2016 Budgeted Construction Expenditures
Segment	Environmental		Generation		Transmission		Distribution		Other		Total
	(in millions)
Vertically Integrated Utilities	$	311.0	$	527.1	$	551.5	$	730.8	$	137.7	$	2,258.1
Transmission and Distribution Utilities	1.0		6.8		528.0		603.3		71.9		1,211.0
AEP Transmission Holdco	—		—		1,224.0		—		21.2		1,245.2
Generation & Marketing	41.2		162.1		—		—		14.1		217.4
Corporate and Other	—		—		—		—		68.3		68.3
Total	$	353.2	$	696.0	$	2,303.5	$	1,334.1	$	313.2	$	5,000.0

The 2016 estimated construction expenditures by Registrant Subsidiary include distribution, transmission and generation related investments, as well as expenditures for compliance with environmental regulations as follows:

	2016 Budgeted Construction Expenditures
Company	Environmental		Generation		Transmission		Distribution		Other		Total
	(in millions)
APCo	$	58.3	$	91.2	$	255.5	$	221.5	$	42.3	$	668.8
I&M	60.8		254.2		90.0		153.1		27.7		585.8
OPCo	—		—		123.2		353.5		45.9		522.6
PSO	29.4		92.2		62.0		197.9		25.6		407.1
SWEPCo	86.3		61.3		121.1		96.7		28.9		394.3

OFF-BALANCE SHEET ARRANGEMENTS

AEP’s current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that AEP enters in the normal course of business.  The following identifies significant off-balance sheet arrangements.

Rockport Plant, Unit 2

AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated unconsolidated trustee for Rockport Plant, Unit 2 (the Plant).  The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and certain institutional investors.  The future minimum lease payments for AEGCo and I&M are $517 million each as of December 31, 2015.

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022.  The Owner Trustee owns the Plant and leases it to AEGCo and I&M.  AEP’s subsidiaries account for the lease as an operating lease with the future payment obligations included in Note 13.  The lease term is for 33 years with potential renewal options.  At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant.  AEP, as well as AEP’s subsidiaries, have no ownership interest in the Owner Trustee and do not guarantee its debt.

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Railcars

In June 2003, AEP entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  AEP intends to maintain the lease for the full lease term of twenty years via the renewal options.  The lease is accounted for as an operating lease.  The future minimum lease obligation is $21 million for the remaining railcars as of December 31, 2015.  Under a return-and-sale option, the lessor is guaranteed that the sale proceeds will equal at least a specified lessee obligation amount which declines with each five-year renewal.  As of December 31, 2015, the maximum potential loss was approximately $19 million 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.  AEP has other railcar lease arrangements that do not utilize this type of financing structure.

CONTRACTUAL OBLIGATION INFORMATION

AEP’s contractual cash obligations include amounts reported on the balance sheets and other obligations disclosed in the footnotes.  The following table summarizes AEP’s contractual cash obligations as of December 31, 2015:

Payments Due by Period
Contractual Cash Obligations	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Short-term Debt (a)	$	800.0	$	—	$	—	$	—	$	800.0
Interest on Fixed Rate Portion of Long-term Debt (b)	840.1		1,538.2		1,284.8		7,715.7		11,378.8
Fixed Rate Portion of Long-term Debt (c)	906.1		3,158.0		2,174.0		11,262.4		17,500.5
Variable Rate Portion of Long-term Debt (d)	925.7		1,258.5		7.4		—		2,191.6
Capital Lease Obligations (e)	112.9		131.1		66.4		110.7		421.1
Noncancelable Operating Leases (e)	239.1		448.6		414.0		452.3		1,554.0
Fuel Purchase Contracts (f)	1,963.0		2,515.7		1,866.2		1,359.5		7,704.4
Energy and Capacity Purchase Contracts	203.0		431.5		437.1		1,961.7		3,033.3
Construction Contracts for Capital Assets (g)	1,471.5		1,515.5		767.7		1,174.7		4,929.4
Total	$	7,461.4	$	10,997.1	$	7,017.6	$	24,037.0	$	49,513.1

(a) Represents principal only, excluding interest.

(b) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2015 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(c) See “Long-term Debt” section of Note 14.  Represents principal only, excluding interest.

(d) See “Long-term Debt” section of Note 14.  Represents principal only, excluding interest.  Variable rate debt had interest rates that ranged between 0.01% and 2.19% as of December 31, 2015.

(e) See Note 13.

(f) Represents contractual obligations to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.

(g) Represents only capital assets for which there are signed contracts.  Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs.

AEP’s $95 million liability related to uncertain tax positions is not included above because management cannot reasonably estimate the cash flows by period.

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AEP’s pension funding requirements are not included in the above table.  As of December 31, 2015, AEP expects to make contributions to the pension plans totaling $94 million in 2016.  Estimated contributions of $89 million in 2017 and $90 million in 2018 may vary significantly based on market returns, changes in actuarial assumptions and other factors.  Based upon the projected benefit obligation and fair value of assets available to pay pension benefits, the pension plans were 95.5% funded as of December 31, 2015.

In addition to the amounts disclosed in the contractual cash obligations table above, additional commitments are made in the normal course of business.  These commitments include standby letters of credit, guarantees for the payment of obligation performance bonds and other commitments.  As of December 31, 2015, the commitments outstanding under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period
Other Commercial Commitments	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Standby Letters of Credit (a)	$	147.3	$	—	$	—	$	—	$	147.3
Guarantees of the Performance of Outside Parties (b)	—		—		—		115.0		115.0
Guarantees of Performance (c)	1,073.8		10.2		—		11.1		1,095.1
Total Commercial Commitments	$	1,221.1	$	10.2	$	—	$	126.1	$	1,357.4

(a) Standby letters of credit (LOCs) are entered into with third parties.  These LOCs are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.  There is no collateral held in relation to any guarantees in excess of the ownership percentages.  In the event any LOC is drawn, there is no recourse to third parties.  See “Letters of Credit” section of Note 6.

(b) See “Guarantees of Third-Party Obligations” section of Note 6.

(c) Performance guarantees and indemnifications issued for energy trading and various sale agreements.

SIGNIFICANT TAX LEGISLATION

The American Taxpayer Relief Act of 2012 provided for the extension of several business and energy industry tax deductions and credits, including the one-year extension of the 50% bonus depreciation to 2013.  The Tax Increase Prevention Act of 2014 also included a one-year extension of the 50% bonus depreciation and provided for the extension of research and development, employment and several energy tax credits for 2014.

The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit.

These enacted provisions had no material impact on net income or financial condition but did have a favorable impact on cash flows in 2013, 2014 and 2015 and are expected to have a favorable impact on future cash flows.

CYBER SECURITY

Cyber security presents a growing risk for electric utility systems because a cyber-attack could affect critical energy infrastructure.  Breaches to the cyber security of the grid or to the AEP System are potentially disruptive to people, property and commerce and create risk for business, investors and customers.  In February 2013, President Obama signed an executive order that addresses how government agencies will operate and support their functions in cyber security as well as redefines how the government interfaces with critical infrastructure, such as the electric grid.  The

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AEP System already operates under regulatory cyber security standards to protect critical infrastructure.  The cyber security framework that was being developed through this executive order was reviewed by FERC and the U.S. Department of Energy (DOE).  In 2014, the DOE published an Energy Sector Cyber Security Framework Implementation Guide for utilities to use in adopting and implementing the National Institute of Standards and Technology framework. AEP continues to be actively engaged in the framework adoption process.

The electric utility industry is one of the few critical infrastructure functions with mandatory cyber security requirements under the authority of FERC. The Energy Policy Act of 2005 gave FERC the authority to oversee reliability of the bulk power system, including the authority to implement mandatory cyber security reliability standards. The North American Electric Reliability Corporation (NERC), which FERC certified as the nation’s Electric Reliability Organization, developed mandatory critical infrastructure protection cyber security reliability standards. AEP participated in the NERC GridEx II exercises in 2013 and GridEx III exercises in 2015.  These efforts, led by NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.

Critical cyber assets, such as data centers, power plants, transmission operations centers and business networks are protected using multiple layers of cyber security and authentication.  The AEP System is constantly scanned for risks or threats. Cyber hackers have been able to breach a number of very secure facilities, from federal agencies, banks and retailers to social media sites.  As these events become known and develop, AEP continually assesses its cyber security tools and processes to determine where to strengthen its defenses. Management continually reviews its business continuity plan to develop an effective recovery effort that decreases response times, limits financial impacts and maintains customer confidence following any business interruption. Management works closely with a broad range of departments, including Legal, Regulatory, Corporate Communications, Audit Services, Information Technology and Security, to ensure the corporate response to consequences of any breach or potential breach is appropriate both for internal and external audiences based on the specific circumstances surrounding the event.

Management continues to take steps to enhance the AEP System’s capabilities for identifying risks or threats and has shared that knowledge of threats with utility peers, industry and federal agencies.  AEP operates a Cyber Security Intelligence and Response Center responsible for monitoring the AEP System for cyber threats as well as collaborating with internal and external threat sharing partners from both industry and government. AEP is a member of an industry specific threat and information sharing community. Funding for this community was initially provided by a grant from the American Recovery and Reinvestment Act – U.S. Department of Energy Smart Grid Demonstration Program but is now fully funded by community membership.

AEP has partnered with a major defense contractor who has significant cyber security experience and technical capabilities developed through their work with the U.S. Department of Defense.  AEP works with a consortium of other utilities across the country, learning how best to share information about potential threats and collaborating with each other.  AEP continues to work with a nonaffiliated entity to conduct several seminars each year about recognizing and investigating cyber vulnerabilities.  Through these types of efforts, AEP is working to protect itself while helping its industry advance its cyber security capabilities.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies.  Management considers an accounting estimate to be critical if:

• It requires assumptions to be made that were uncertain at the time the estimate was made; and

• Changes in the estimate or different estimates that could have been selected could have a material effect on net income or financial condition.

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Management discusses the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the disclosures relating to them.

Management believes that the current assumptions and other considerations used to estimate amounts reflected in the financial statements are appropriate.  However, actual results can differ significantly from those estimates.

The sections that follow present information about AEP’s critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate.

Regulatory Accounting

Nature of Estimates Required

The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.

The Registrants recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation.  Specifically, the timing of expense and income recognition is matched with regulated revenues.  Liabilities are also recorded for refunds, or probable refunds, to customers that have not been made.

Assumptions and Approach Used

When incurred costs are probable of recovery through regulated rates, regulatory assets are recorded on the balance sheet.  Management reviews the probability of recovery at each balance sheet date and whenever new events occur.  Similarly, regulatory liabilities are recorded when a determination is made that a refund is probable or when ordered by a commission.  Examples of new events that affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation.  The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs as well as the return of revenues, rate of return earned on invested capital and timing and amount of assets to be recovered through regulated rates.  If recovery of a regulatory asset is no longer probable, that regulatory asset is written-off as a charge against earnings.  A write-off of regulatory assets or establishment of a regulatory liability may also reduce future cash flows since there will be no recovery through regulated rates.

Effect if Different Assumptions Used

A change in the above assumptions may result in a material impact on net income.  Refer to Note 5 for further detail related to regulatory assets and regulatory liabilities.

Revenue Recognition – Unbilled Revenues

Nature of Estimates Required

AEP records revenues when energy is delivered to the customer.  The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded.  This estimate is reversed in the following month and actual revenue is recorded based on meter readings.  PSO and SWEPCo do not record the fuel portion of unbilled revenue in accordance with the applicable state commission regulatory treatment in Arkansas, Louisiana, Oklahoma and Texas.

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The changes in unbilled electric utility revenues for AEP’s Vertically Integrated Utilities segment were $(63) million, $(29) million and $(9) million for the years ended December 31, 2015, 2014 and 2013, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather and rates.  Accrued unbilled revenues for the Vertically Integrated Utilities segment were $191 million and $254 million as of December 31, 2015 and 2014, respectively.

The changes in unbilled electric utility revenues for AEP’s Transmission and Distribution Utilities segment were $(30) million, $16 million and $(22) million for the years ended December 31, 2015, 2014 and 2013, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather and rates.  Accrued unbilled revenues for the Transmission and Distribution Utilities segment were $151 million and $181 million as of December 31, 2015 and 2014, respectively.

The changes in unbilled electric utility revenues for AEP’s Generation & Marketing segment were $(3) million, $9 million and $10 million for the years ended December 31, 2015, 2014 and 2013, respectively.  Accrued unbilled revenues for the Generation & Marketing segment were $47 million and $50 million as of December 31, 2015 and 2014, respectively.

Assumptions and Approach Used

For each Registrant, the monthly estimate for unbilled revenues is based upon a primary computation of net generation (generation plus purchases less sales) less the current month’s billed KWh and estimated line losses, plus the prior month’s unbilled KWh.  However, due to meter reading issues, meter drift and other anomalies, a secondary computation is made, based upon an allocation of billed KWh to the current month and previous month, on a billing cycle-by-cycle basis, and by dividing the current month aggregated result by the billed KWh.  The two methodologies are evaluated to confirm that they are not statistically different.

For AEP’s Generation & Marketing segment, management calculates unbilled revenues by contract using the most recent historic daily activity adjusted for significant known changes in usage.

Effect if Different Assumptions Used

If the two methodologies used to estimate unbilled revenue are statistically different, a limiter adjustment is made to bring the primary computation within one standard deviation of the secondary computation. Additionally, significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the estimate of unbilled revenue.  

Accounting for Derivative Instruments

Nature of Estimates Required

Management considers fair value techniques, valuation adjustments related to credit and liquidity and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates.  These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors.

Assumptions and Approach Used

The Registrants measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based primarily on exchange prices and broker quotes.  If a quoted market price is not available, the fair value is estimated based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and other assumptions.  Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment.  These uncertainties include projections of macroeconomic trends and future commodity prices, including supply and demand levels and future price volatility.

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The Registrants reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality.  Liquidity adjustments are calculated by utilizing bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time.  Credit adjustments on risk management contracts are calculated using estimated default probabilities and recovery rates relative to the counterparties or counterparties with similar credit profiles and contractual netting agreements.

With respect to hedge accounting, management assesses hedge effectiveness and evaluates a forecasted transaction’s probability of occurrence within the specified time period as provided in the original hedge documentation.

Effect if Different Assumptions Used

There is inherent risk in valuation modeling given the complexity and volatility of energy markets.  Therefore, it is possible that results in future periods may be materially different as contracts settle.

The probability that hedged forecasted transactions will not occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified into operating income.

For additional information regarding derivatives, hedging and fair value measurements, see Notes 10 and 11.  See “Fair Value Measurements of Assets and Liabilities” section of Note 1 for fair value calculation policy.

Long-Lived Assets

Nature of Estimates Required

In accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the Registrants evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable including planned abandonments and a probable disallowance for rate-making on a plant under construction or the assets meet the held-for-sale criteria.  The Registrants utilize a group composite method of depreciation to estimate the useful lives of long-lived assets.  The evaluations of long-lived, held and used assets may result from abandonments, significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operations analyses.  If the carrying amount is not recoverable, the Registrants record an impairment to the extent that the fair value of the asset is less than its book value.  Performing an impairment evaluation involves a significant degree of estimation and judgment in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets and developing the undiscounted and discounted future cash flows (used to estimate fair value in the absence of market-based value, in some instances) associated with the asset.  For assets held for sale, an impairment is recognized if the expected net sales price is less than its book value.  For regulated assets, the earnings impact of an impairment charge could be offset by the establishment of a regulatory asset, if rate recovery is probable. For nonregulated assets, any impairment charge is recorded against earnings.

Assumptions and Approach Used

The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, the Registrants estimate fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals.  Cash flow estimates are based on relevant information available at the time the estimates are made.  Estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.  Also, when measuring fair value, management evaluates the characteristics of the asset or liability to determine if market participants would take those characteristics into account when pricing the asset or liability at the

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measurement date.  Such characteristics include, for example, the condition and location of the asset or restrictions of the use of the asset.  The Registrants perform depreciation studies that include a review of any external factors that may affect the useful life to determine composite depreciation rates and related lives which are subject to periodic review by state regulatory commissions for cost-based regulated assets.  The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

Effect if Different Assumptions Used

In connection with the evaluation of long-lived assets in accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the fair value of the asset can vary if different estimates and assumptions would have been used in the applied valuation techniques.  The estimate for depreciation rates takes into account the history of interim capital replacements and the amount of salvage expected.  In cases of impairment, the best estimate of fair value was made using valuation methods based on the most current information at that time.  Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including, but not limited to, differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions and management’s analysis of the benefits of the transaction.

Pension and Other Postretirement Benefits

AEP maintains a qualified, defined benefit pension plan (Qualified Plan), which covers substantially all nonunion and certain union employees, and unfunded, nonqualified supplemental plans (Nonqualified Plans) to provide benefits in excess of amounts permitted under the provisions of the tax law for participants in the Qualified Plan (collectively the Pension Plans).  Additionally, AEP entered into individual employment contracts with certain current and retired executives that provide additional retirement benefits as a part of the Nonqualified Plans.  AEP also sponsors other postretirement benefit plans to provide health and life insurance benefits for retired employees (Postretirement Plans).  The Pension Plans and Postretirement Plans are collectively referred to as the Plans.

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1.  See Note 8 for information regarding costs and assumptions for employee retirement and postretirement benefits.

The following table shows the net periodic cost (credit) of the Plans:

	Years Ended December 31,
Net Periodic Cost (Credit)	2015			2014			2013
	(in millions)
Pension Plans	$	133.3		$	157.8		$	180.1
Postretirement Plans	(92.3		)	(76.8		)	(17.2		)

The net periodic benefit cost is calculated based upon a number of actuarial assumptions, including expected long-term rates of return on the Plans’ assets.  In developing the expected long-term rate of return assumption for 2016, management evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions.  Management also considered historical returns of the investment markets and changes in tax rates which affect a portion of the Postretirement Plans’ assets.  Management anticipates that the investment managers employed for the Plans will invest the assets to generate future returns averaging 6% for the Qualified Plan and 7% for the Postretirement Plans.

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The expected long-term rate of return on the Plans’ assets is based on management’s targeted asset allocation and expected investment returns for each investment category.  Assumptions for the Plans are summarized in the following table:

	Pension Plans				Other Postretirement Benefit Plans
			Assumed/				Assumed/
	2016		Expected		2016		Expected
	Target		Long-Term		Target		Long-Term
	Asset		Rate of		Asset		Rate of
	Allocation		Return		Allocation		Return
Equity	25	%	8.75	%	65	%	8.59	%
Fixed Income	59	%	4.37	%	33	%	4.19	%
Other Investments	15	%	7.67	%	—	%	—	%
Cash and Cash Equivalents	1	%	2.25	%	2	%	2.25	%
Total	100	%			100	%

Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation.  Management believes that 6% for the Qualified Plan and 7% for the Postretirement Plans are reasonable estimates of the long-term rate of return on the Plans’ assets.  The Pension Plans’ assets had an actual gain of 0.8% and 10.6% for the years ended December 31, 2015 and 2014, respectively.  The Postretirement Plans’ assets had an actual loss of 0.9% for the year ended December 31, 2015 and an actual gain of 7.2% for the year ended December 31, 2014.  Management will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary.

AEP bases the determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets.  Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.  As of December 31, 2015, AEP had cumulative losses of approximately $23 million that remain to be recognized in the calculation of the market-related value of assets.  These unrecognized net actuarial losses may result in increases in the future pension costs depending on several factors, including whether such losses at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance.

The method used to determine the discount rate that AEP utilizes for determining future obligations is a duration-based method in which a hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.  The discount rate as of December 31, 2015 under this method was 4.3% for the Qualified Plan, 4.05% for the Nonqualified Plans and 4.3% for the Postretirement Plans.  Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on the Pension Plans’ assets of 6%, discount rates of 4.3% and 4.05% and various other assumptions, management estimates that the pension costs for the Pension Plans will approximate $105 million, $78 million and $67 million in 2016, 2017 and 2018, respectively.  Based on an expected rate of return on the Postretirement Plans’ assets of 7%, a discount rate of 4.3% and various other assumptions, management estimates Postretirement Plan credits will approximate $74 million, $77 million and $79 million in 2016, 2017 and 2018, respectively. Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans.  The actuarial assumptions used may differ materially from actual results.  The effects of a 50 basis point change to selective actuarial assumptions are included in the “Effect if Different Assumptions Used” section below.

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The value of AEP’s Pension Plans’ assets decreased to $4.8 billion as of December 31, 2015 from $5 billion as of December 31, 2014 primarily due to benefit payments in excess of investment returns and company contributions from AEP System companies.  During 2015, the Qualified Plan paid $325 million and the Nonqualified Plans paid $5 million in benefits to plan participants.  The value of AEP’s Postretirement Plans’ assets decreased to $1.6 billion as of December 31, 2015 from $1.7 billion as of December 31, 2014 primarily due to benefit payments and investment losses in excess of contributions from AEP System companies and the participants.  The Postretirement Plans paid $129 million in benefits to plan participants during 2015.

Nature of Estimates Required

AEP sponsors pension and other retirement and postretirement benefit plans in various forms covering all employees who meet eligibility requirements.  These benefits are accounted for under “Compensation” and “Plan Accounting” accounting guidance.  The measurement of pension and postretirement benefit obligations, costs and liabilities is dependent on a variety of assumptions.

Assumptions and Approach Used

The critical assumptions used in developing the required estimates include the following key factors:

• Discount rate

• Compensation increase rate

• Cash balance crediting rate

• Health care cost trend rate

• Expected return on plan assets

Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.

Effect if Different Assumptions Used

The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants.  These differences may result in a significant impact to the amount of pension and postretirement benefit expense recorded.  If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:

							Other Postretirement
	Pension Plans						Benefit Plans
	+0.5%			-0.5%			+0.5%			-0.5%
	(in millions)
Effect on December 31, 2015 Benefit Obligations
Discount Rate	$	(257.4	)	$	282.9		$	(74.6	)	$	82.0
Compensation Increase Rate	19.5			(17.8		)	NA			NA
Cash Balance Crediting Rate	67.0			(60.7		)	NA			NA
Health Care Cost Trend Rate	NA			NA			31.6			(28.5		)
Effect on 2015 Periodic Cost
Discount Rate	(14.1		)	15.3			(2.7		)	2.9
Compensation Increase Rate	5.3			(4.8		)	NA			NA
Cash Balance Crediting Rate	14.9			(13.9		)	NA			NA
Health Care Cost Trend Rate	NA			NA			3.6			(3.2		)
Expected Return on Plan Assets	(22.9		)	22.9			(8.2		)	8.2

NA Not applicable.

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ACCOUNTING PRONOUNCEMENTS

New Accounting Pronouncements Adopted During 2015

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. Management adopted ASU 2014-08 effective January 1, 2015.

The FASB issued ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” to simplify the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-03 in October 2015 and applied the new standard retrospectively for all periods presented. Prior to adoption, AEP included debt issuance costs in Deferred Charges and Other Noncurrent Assets on the balance sheets.

The FASB issued ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. Management has analyzed the impact of this new standard and determined that it had no impact on the accounting of the Registrants’ contracts. Additionally, adoption had no impact on net income. Management adopted ASU 2015-13 upon its issuance date.

The FASB issued ASU 2015-17 “Balance Sheet Classification of Deferred Taxes” simplifying the presentation of deferred income taxes on the balance sheets. Under the new standard, deferred tax assets and liabilities are classified as noncurrent on the balance sheets. The new accounting guidance is effective for annual periods beginning after December 15, 2016 with early adoption permitted. Management adopted ASU 2015-17 upon its issuance date and applied the new standard prospectively.

Pronouncements Effective in the Future

The FASB issued ASU 2014-09 “Revenue from Contracts with Customers” clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted for annual periods beginning after December 15, 2016. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018.

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The FASB issued ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. As applicable, this standard may change the presentation of amounts in the income statements. Management adopted ASU 2015-01 effective January 1, 2016.

The FASB issued ASU 2015-05 “Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement” providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-05 prospectively, effective January 1, 2016, with no impact on results of operations, financial position or cash flows.

The FASB issued ASU 2015-11 “Simplifying the Measurement of Inventory” to simplify the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management does not expect the new standard to impact its results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017.

The FASB issued ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments should be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018.

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 operations and financial position that may result from any such future changes.  The FASB is currently working on several projects including financial instruments, leases, insurance, hedge accounting, consolidation policy and pension and postretirement benefits.  The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

The Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through transactions in power, coal, natural gas and marketing contracts.  These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk.  In addition, this segment is exposed to foreign currency exchange risk from occasionally procuring various services and materials used in its energy business from foreign suppliers.  These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates.

The Transmission and Distribution Utilities segment was exposed to FTR price risk as it related to RTO congestion during the June 2012 – May 2015 Ohio ESP period.  Additional risks include energy procurement risk and interest rate risk.

The Generation & Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO.  This segment is exposed to certain market risks as a marketer of wholesale and retail electricity.  These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk.  These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates.  In addition, the Generation & Marketing segment is also exposed to certain market risks as a major power producer and through transactions in wholesale electricity and natural gas and marketing contracts.

Management employs risk management contracts including physical forward purchase-and-sale contracts and financial forward purchase-and-sale contracts.  Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business.  As a result, AEP is subject to price risk.  The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.  AEPSC’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) and the Energy Supply Risk Committee (Competitive Risk Committee) various 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 Energy Supply’s President and Vice President.  When commercial activities exceed predetermined limits, positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee.

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The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2014:

MTM Risk Management Contract Net Assets (Liabilities)
Year Ended December 31, 2015
	Vertically Integrated Utilities			Transmission and Distribution Utilities			Generation & Marketing			Total
	(in millions)
Total MTM Risk Management Contract Net Assets as of December 31, 2014	$	36.3		$	46.1		$	140.3		$	222.7
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period	(30.9		)	(3.9		)	(29.5		)	(64.3		)
Fair Value of New Contracts at Inception When Entered During the Period (a)	—			—			58.8			58.8
Changes in Fair Value Due to Market Fluctuations During the Period (b)	—			—			(26.4		)	(26.4		)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	3.2			(27.8		)	—			(24.6		)
Total MTM Risk Management Contract Net Assets as of December 31, 2015	$	8.6		$	14.4		$	143.2		166.2
Commodity Cash Flow Hedge Contracts										(8.5		)
Interest Rate and Foreign Currency Cash Flow Hedge Contracts										(0.4		)
Fair Value Hedge Contracts										(3.0		)
Collateral Deposits										38.6
Elimination of Affiliated MTM Risk Management Contracts										(2.9		)
Total MTM Derivative Contract Net Assets as of December 31, 2015										$	190.0

(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 statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets.

See Note 10 – Derivatives and Hedging and Note 11 – Fair Value Measurements for additional information related to risk management contracts.  The following tables and discussion provide information on credit risk and market volatility risk.

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Credit Risk

Credit risk is limited in 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.  Management uses 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.

AEP has risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily.  As of December 31, 2015, credit exposure net of collateral to sub investment grade counterparties was approximately 7.1%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).  As of December 31, 2015, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

Counterparty Credit Quality	Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number of Counterparties >10% of Net Exposure	Net Exposure of Counterparties >10%
	(in millions, except number of counterparties)
Investment Grade	$	748.9	$	2.7	$	746.2	2	$	304.4
Split Rating	28.6		—		28.6		1	28.0
Noninvestment Grade	1.6		1.3		0.3		2	0.3
No External Ratings:
Internal Investment Grade	109.6		—		109.6		3	64.1
Internal Noninvestment Grade	84.9		17.9		67.0		3	40.3
Total as of December 31, 2015	$	973.6	$	21.9	$	951.7	11	$	437.1
Total as of December 31, 2014	$	816.7	$	20.5	$	796.2	11	$	346.9

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

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Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates VaR, to measure AEP’s 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 December 31, 2015, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

Management calculates the VaR for both a trading and non-trading portfolio. The trading portfolio consists primarily of contracts related to energy trading and marketing activities. The non-trading portfolio consists primarily of economic hedges of generation and retail supply activities. The following tables show the end, high, average and low market risk as measured by VaR for the periods indicated:

VaR Model

Trading Portfolio

Twelve Months Ended								Twelve Months Ended
December 31, 2015								December 31, 2014
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	0.2	$	0.9	$	0.2	$	0.1	$	0.2	$	2.6	$	0.6	$	0.1

VaR Model

Non-Trading Portfolio

Twelve Months Ended								Twelve Months Ended
December 31, 2015								December 31, 2014
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	1.1	$	2.4	$	0.9	$	0.4	$	1.8	$	3.3	$	0.8	$	0.1

Management back-tests 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 the VaR calculation captures recent price movements, management also performs regular stress testing of the trading portfolio to understand AEP’s exposure to extreme price movements.  A historical-based method is employed whereby the current trading 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.  Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee, Regulated Risk Committee, or Competitive Risk Committee as appropriate.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which 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 December 31, 2015 and 2014, the estimated EaR on AEP’s debt portfolio for the following twelve months was $25 million and $33 million, respectively.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

American Electric Power Company, Inc.:

We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and subsidiary companies (the "Company") as of December 31, 2015 and 2014, and the related consolidated statements of income, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and subsidiary companies as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2016 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 23, 2016

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

American Electric Power Company, Inc.:

We have audited the internal control over financial reporting of American Electric Power Company, Inc. and subsidiary companies (the "Company") as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2015 of the Company and our report dated February 23, 2016 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 23, 2016

58

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of American Electric Power Company, Inc. and subsidiary companies (AEP) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  AEP’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of AEP’s internal control over financial reporting as of December 31, 2015.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 2013) in Internal Control – Integrated Framework.  Based on management’s assessment, AEP’s internal control over financial reporting was effective as of December 31, 2015.

AEP’s independent registered public accounting firm has issued an attestation report on AEP’s internal control over financial reporting.  The Report of Independent Registered Public Accounting Firm appears on the previous page.

59

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2015, 2014 and 2013

 (in millions, except per-share and share amounts)

	Years Ended December 31,
	2015			2014			2013
REVENUES
Vertically Integrated Utilities	$	9,069.9		$	9,396.8		$	9,346.6
Transmission and Distribution Utilities	4,392.0			4,552.6			4,279.1
Generation & Marketing	2,866.7			2,384.3			1,208.0
Other Revenues	124.6			44.9			(20.2		)
TOTAL REVENUES	16,453.2			16,378.6			14,813.5
EXPENSES
Fuel and Other Consumables Used for Electric Generation	3,348.1			4,271.8			4,068.3
Purchased Electricity for Resale	2,760.1			2,085.9			1,490.8
Other Operation	2,703.9			2,766.6			2,448.4
Maintenance	1,325.3			1,328.0			1,163.2
Asset Impairments and Other Related Charges	—			—			226.4
Depreciation and Amortization	2,009.7			1,897.6			1,712.5
Taxes Other Than Income Taxes	972.6			901.3			881.4
TOTAL EXPENSES	13,119.7			13,251.2			11,991.0
OPERATING INCOME	3,333.5			3,127.4			2,822.5
Other Income (Expense):
Interest and Investment Income	7.9			7.4			57.9
Carrying Costs Income	23.5			33.2			30.2
Allowance for Equity Funds Used During Construction	131.9			102.9			72.7
Interest Expense	(873.9		)	(868.0		)	(890.0		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	2,622.9			2,402.9			2,093.3
Income Tax Expense	919.6			902.6			677.7
Equity Earnings of Unconsolidated Subsidiaries	65.3			90.2			58.3
INCOME FROM CONTINUING OPERATIONS	1,768.6			1,590.5			1,473.9
INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX	283.7			47.5			10.3
NET INCOME	2,052.3			1,638.0			1,484.2
Net Income Attributable to Noncontrolling Interests	5.2			4.2			3.7
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	2,047.1		$	1,633.8		$	1,480.5
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	490,340,522			488,592,997			486,619,555
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS	$	3.59		$	3.24		$	3.02
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS	0.58			0.10			0.02
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	4.17		$	3.34		$	3.04
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	490,574,568			488,899,840			487,040,956
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS	$	3.59		$	3.24		$	3.02
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS	0.58			0.10			0.02
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	4.17		$	3.34		$	3.04

See Notes to Financial Statements of Registrants beginning on page 66.

60

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2015, 2014 and 2013

(in millions)

	Years Ended December 31,
	2015			2014		2013
Net Income	$	2,052.3		$	1,638.0	$	1,484.2
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $(2.6), $2.9 and $8.3 in 2015, 2014 and 2013, Respectively	(4.9		)	5.3		15.5
Securities Available for Sale, Net of Tax of $(0.3), $0.4 and $1.4 in 2015, 2014 and 2013, Respectively	(0.6		)	0.9		2.6
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0.6, $2.6 and $11.8 in 2015, 2014 and 2013, Respectively	1.2			4.8		21.9
Pension and OPEB Funded Status, Net of Tax of $(13.9), $0.6 and $95.1 in 2015, 2014 and 2013, Respectively	(25.7		)	1.1		176.6
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(30.0		)	12.1		216.6
TOTAL COMPREHENSIVE INCOME	2,022.3			1,650.1		1,700.8
Total Comprehensive Income Attributable to Noncontrolling Interests	5.2			4.2		3.7
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	2,017.1		$	1,645.9	$	1,697.1

See Notes to Financial Statements of Registrants beginning on page 66.

61

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Years Ended December 31, 2015, 2014 and 2013

(in millions)

	AEP Common Shareholders
	Common Stock
	Shares	Amount		Paid-in Capital		Retained Earnings				Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
TOTAL EQUITY – DECEMBER 31, 2012	506.0	$	3,289.0	$	6,049.0	$	6,236.1			$	(337.0	)	$	0.4		$	15,237.5
Issuance of Common Stock	2.1	13.7		69.5												83.2
Common Stock Dividends						(950.5		)	(a)				(3.8		)	(954.3		)
Other Changes in Equity				12.7									0.5			13.2
Net Income						1,480.5							3.7			1,484.2
Other Comprehensive Income										216.6						216.6
Pension and OPEB Adjustment Related to Mitchell Plant										5.2						5.2
TOTAL EQUITY – DECEMBER 31, 2013	508.1	3,302.7		6,131.2		6,766.1				(115.2		)	0.8			16,085.6
Issuance of Common Stock	1.6	10.6		63.0												73.6
Common Stock Dividends						(993.3		)	(a)				(4.3		)	(997.6		)
Other Changes in Equity				9.2									3.6			12.8
Net Income						1,633.8							4.2			1,638.0
Other Comprehensive Income										12.1						12.1
TOTAL EQUITY – DECEMBER 31, 2014	509.7	3,313.3		6,203.4		7,406.6				(103.1		)	4.3			16,824.5
Issuance of Common Stock	1.7	10.7		70.9												81.6
Common Stock Dividends						(1,055.4		)	(a)				(3.6		)	(1,059.0		)
Other Changes in Equity				22.2									7.3			29.5
Net Income						2,047.1							5.2			2,052.3
Other Comprehensive Loss										(30.0		)				(30.0		)
Pension and OPEB Adjustment Related to Mitchell Plant										6.0						6.0
TOTAL EQUITY – DECEMBER 31, 2015	511.4	$	3,324.0	$	6,296.5	$	8,398.3			$	(127.1	)	$	13.2		$	17,904.9

(a) Cash dividends declared per AEP common share were $2.15, $2.03 and $1.95 as of December 31, 2015, 2014 and 2013, respectively.

See Notes to Financial Statements of Registrants beginning on page 66.

62

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2015 and 2014

(in millions)

	December 31,
	2015			2014
CURRENT ASSETS
Cash and Cash Equivalents	$	176.4		$	162.5
Other Temporary Investments     (December 31, 2015 and 2014 Amounts Include $376.6 and $371, Respectively, Related to Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and EIS)	386.8			385.6
Accounts Receivable:
Customers	615.9			637.2
Accrued Unbilled Revenues	31.2			146.1
Pledged Accounts Receivable – AEP Credit	940.3			987.4
Miscellaneous	82.1			85.3
Allowance for Uncollectible Accounts	(29.0		)	(20.8		)
Total Accounts Receivable	1,640.5			1,835.2
Fuel	600.8			580.8
Materials and Supplies	738.6			735.8
Risk Management Assets	134.4			177.9
Regulatory Asset for Under-Recovered Fuel Costs	115.2			126.6
Margin Deposits	107.3			95.2
Assets from Discontinued Operations	—			103.3
Prepayments and Other Current Assets	172.4			275.2
TOTAL CURRENT ASSETS	4,072.4			4,478.1
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	25,559.8			25,727.5
Transmission	14,247.9			12,433.4
Distribution	18,046.9			17,156.6
Other Property, Plant and Equipment (December 31, 2015 and 2014 Amounts Include Plant to be Retired, Coal Mining and Nuclear Fuel, December 31, 2014 Amount Includes 2015 Plant Retirement)	3,722.9			5,073.1
Construction Work in Progress	3,903.9			3,215.3
Total Property, Plant and Equipment	65,481.4			63,605.9
Accumulated Depreciation and Amortization	19,348.2			19,970.8
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	46,133.2			43,635.1
OTHER NONCURRENT ASSETS
Regulatory Assets	5,140.3			4,263.7
Securitized Assets	1,749.9			2,072.4
Spent Nuclear Fuel and Decommissioning Trusts	2,106.4			2,095.7
Goodwill	52.5			52.5
Long-term Risk Management Assets	321.8			294.2
Assets from Discontinued Operations	—			521.6
Deferred Charges and Other Noncurrent Assets	2,106.6			2,131.3
TOTAL OTHER NONCURRENT ASSETS	11,477.5			11,431.4
TOTAL ASSETS	$	61,683.1		$	59,544.6

See Notes to Financial Statements of Registrants beginning on page 66.

63

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

December 31, 2015 and 2014

(dollars in millions)

			December 31,
			2015			2014
CURRENT LIABILITIES
Accounts Payable			$	1,418.0		$	1,258.2
Short-term Debt:
Securitized Debt for Receivables – AEP Credit			675.0			744.0
Other Short-term Debt			125.0			602.0
Total Short-term Debt			800.0			1,346.0
Long-term Debt Due Within One Year (December 31, 2015 and 2014 Amounts Include $410.4 and $430.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine)			1,831.8			2,500.4
Risk Management Liabilities			87.1			91.6
Customer Deposits			346.6			323.9
Accrued Taxes			979.1			863.5
Accrued Interest			226.9			238.3
Regulatory Liability for Over-Recovered Fuel Costs			113.9			55.2
Liabilities from Discontinued Operations			—			84.8
Other Current Liabilities			1,305.1			1,204.7
TOTAL CURRENT LIABILITIES			7,108.5			7,966.6
NONCURRENT LIABILITIES
Long-term Debt (December 31, 2015 and 2014 Amounts Include $1,971.4 and $2,241.1, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy and Sabine)			17,740.9			16,012.0
Long-term Risk Management Liabilities			179.1			130.9
Deferred Income Taxes			11,733.2			10,892.2
Regulatory Liabilities and Deferred Investment Tax Credits			3,736.1			3,892.4
Asset Retirement Obligations			1,806.5			1,950.7
Employee Benefits and Pension Obligations			583.3			629.5
Liabilities from Discontinued Operations			—			350.0
Deferred Credits and Other Noncurrent Liabilities			890.6			895.8
TOTAL NONCURRENT LIABILITIES			36,669.7			34,753.5
TOTAL LIABILITIES			43,778.2			42,720.1
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2015	2014
Shares Authorized	600,000,000	600,000,000
Shares Issued	511,389,173	509,739,159
(20,336,592 Shares were Held in Treasury as of December 31, 2015 and 2014)			3,324.0			3,313.3
Paid-in Capital			6,296.5			6,203.4
Retained Earnings			8,398.3			7,406.6
Accumulated Other Comprehensive Income (Loss)			(127.1		)	(103.1		)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			17,891.7			16,820.2
Noncontrolling Interests			13.2			4.3
TOTAL EQUITY			17,904.9			16,824.5
TOTAL LIABILITIES AND EQUITY			$	61,683.1		$	59,544.6

See Notes to Financial Statements of Registrants beginning on page 66.

64

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2015, 2014 and 2013

	Years Ended December 31,
	2015			2014			2013
OPERATING ACTIVITIES	(in millions)
Net Income	$	2,052.3		$	1,638.0		$	1,484.2
Income from Discontinued Operations	283.7			47.5			10.3
Income from Continuing Operations	1,768.6			1,590.5			1,473.9
Adjustments to Reconcile Income from Continuing Operations to Net Cash Flows from Continuing
Operating Activities:
Depreciation and Amortization	2,009.7			1,897.6			1,712.5
Deferred Income Taxes	808.2			868.8			711.2
Asset Impairments and Other Related Charges	—			—			226.4
Carrying Costs Income	(23.5		)	(33.2		)	(30.2		)
Allowance for Equity Funds Used During Construction	(131.9		)	(102.9		)	(72.7		)
Mark-to-Market of Risk Management Contracts	52.5			(53.1		)	38.5
Amortization of Nuclear Fuel	145.0			144.2			130.6
Pension and Postemployment Benefit Reserves	33.2			77.2			167.7
Pension Contributions to Qualified Plan Trust	(91.8		)	(70.3		)	—
Property Taxes	(52.4		)	(41.8		)	(35.4		)
Fuel Over/Under-Recovery, Net	137.8			(35.5		)	62.0
Recovery (Deferral) of Ohio Capacity Costs, Net	65.5			(113.5		)	(214.4		)
Change in Other Noncurrent Assets	(105.7		)	35.6			(196.8		)
Change in Other Noncurrent Liabilities	(89.0		)	256.1			(152.3		)
Changes in Certain Components of Continuing Working Capital:
Accounts Receivable, Net	200.2			(60.3		)	22.9
Fuel, Materials and Supplies	(38.6		)	100.8			119.2
Accounts Payable	16.5			(74.9		)	94.1
Accrued Taxes, Net	120.2			0.4			86.2
Other Current Assets	(26.7		)	(20.6		)	15.4
Other Current Liabilities	(49.1		)	237.3			(62.6		)
Net Cash Flows from Continuing Operating Activities	4,748.7			4,602.4			4,096.2
INVESTING ACTIVITIES
Construction Expenditures	(4,508.0		)	(4,130.0		)	(3,616.4		)
Change in Other Temporary Investments, Net	9.6			(31.1		)	(11.2		)
Purchases of Investment Securities	(2,282.7		)	(1,088.0		)	(927.4		)
Sales of Investment Securities	2,218.4			1,031.8			858.4
Acquisitions of Nuclear Fuel	(92.0		)	(116.2		)	(153.7		)
Acquisitions of Assets/Businesses	(5.3		)	(64.8		)	(32.0		)
Insurance Proceeds Related to Cook Plant Fire	—			—			72.0
Other Investing Activities	96.0			(7.6		)	(7.5		)
Net Cash Flows Used for Continuing Investing Activities	(4,564.0		)	(4,405.9		)	(3,817.8		)
FINANCING ACTIVITIES
Issuance of Common Stock, Net	81.6			73.6			83.2
Issuance of Long-term Debt	3,436.6			2,067.0			3,206.6
Change in Short-term Debt, Net	(546.0		)	589.0			(221.0		)
Retirement of Long-term Debt	(2,397.9		)	(1,777.4		)	(2,595.4		)
Make Whole Premium on Extinguishment of Long-term Debt	(92.7		)	—			—
Proceeds from Nuclear Fuel Sale/Leaseback	—			—			110.2
Principal Payments for Capital Lease Obligations	(99.0		)	(111.2		)	(73.2		)
Dividends Paid on Common Stock	(1,059.0		)	(997.6		)	(954.3		)
Other Financing Activities	14.7			5.7			5.2
Net Cash Flows Used for Continuing Financing Activities	(661.7		)	(150.9		)	(438.7		)
Net Cash Flows from Discontinued Operating Activities	69.8			11.1			9.5
Net Cash Flows from (Used for) Discontinued Investing Activities	548.8			(0.1		)	(0.4		)
Net Cash Flows Used for Discontinued Financing Activities	(127.7		)	(11.6		)	(10.0		)
Net Increase (Decrease) in Cash and Cash Equivalents	13.9			45.0			(161.2		)
Cash and Cash Equivalents at Beginning of Period	162.5			117.5			278.7
Cash and Cash Equivalents at End of Period	$	176.4		$	162.5		$	117.5

See Notes to Financial Statements of Registrants beginning on page 66.

65

INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANTS

The notes to financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise.

Note	Registrant	Page Number
Organization and Summary of Significant Accounting Policies	AEP, APCo, I&M, OPCo, PSO, SWEPCo	67
New Accounting Pronouncements	AEP, APCo, I&M, OPCo, PSO, SWEPCo	85
Comprehensive Income	AEP, APCo, I&M, OPCo, PSO, SWEPCo	88
Rate Matters	AEP, APCo, I&M, OPCo, PSO, SWEPCo	99
Effects of Regulation	AEP, APCo, I&M, OPCo, PSO, SWEPCo	108
Commitments, Guarantees and Contingencies	AEP, APCo, I&M, OPCo, PSO, SWEPCo	121
Dispositions and Impairments	AEP, APCo, OPCo	129
Benefit Plans	AEP, APCo, I&M, OPCo, PSO, SWEPCo	132
Business Segments	AEP, APCo, I&M, OPCo, PSO, SWEPCo	151
Derivatives and Hedging	AEP, APCo, I&M, OPCo, PSO, SWEPCo	155
Fair Value Measurements	AEP, APCo, I&M, OPCo, PSO, SWEPCo	170
Income Taxes	AEP, APCo, I&M, OPCo, PSO, SWEPCo	186
Leases	AEP, APCo, I&M, OPCo, PSO, SWEPCo	197
Financing Activities	AEP, APCo, I&M, OPCo, PSO, SWEPCo	202
Stock-based Compensation	AEP	210
Related Party Transactions	APCo, I&M, OPCo, PSO, SWEPCo	215
Variable Interest Entities	AEP, APCo, I&M, OPCo, PSO, SWEPCo	224
Property, Plant and Equipment	AEP, APCo, I&M, OPCo, PSO, SWEPCo	230
Cost Reduction Programs	AEP, APCo, I&M, OPCo, PSO, SWEPCo	236
Unaudited Quarterly Financial Information	AEP, APCo, I&M, OPCo, PSO, SWEPCo	238
Goodwill and Other Intangible Assets	AEP	241

66

1.  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The disclosures in this note apply to all Registrants unless indicated otherwise.

ORGANIZATION

The Registrants engage in the generation, transmission and distribution of electric power.  The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines.  Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.

AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier.

The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services.  In addition, operations include barging operations and nonregulated wind farms. I&M provides barging services to both affiliated and nonaffiliated companies.  SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.

Corporate Separation (Applies to AEP, APCo, I&M and OPCo)

On December 31, 2013, as approved by the FERC and the PUCO, OPCo transferred its generation assets and related generation liabilities at net book value to AGR.  In accordance with Ohio law, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers.  Effective January 1, 2014, OPCo began purchasing power from both affiliated and nonaffiliated entities, subject to PUCO approval, to meet the energy and capacity needs of customers. In 2013, in connection with corporate separation of OPCo’s generation assets and liabilities, OPCo transferred its ownership of Cook Coal Terminal to AEGCo and sold the majority of its assets related to its wholly-owned subsidiary, Conesville Coal Preparation Company (CCPC). On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value its ownership (867 MW) in Amos Plant, Unit 3 to APCo and one-half of its interest (780 MW) in the Mitchell Plant to KPCo.  

APCo’s acquisition of the two-thirds ownership in Amos Plant, Unit 3 qualifies as an acquisition of a business under common control, which is typically accounted for as if the transfer had occurred at the beginning of the earliest period presented, pursuant to accounting guidance for “Business Combinations.”  However, management determined the retrospective application of this transfer to be quantitatively and qualitatively immaterial when taken as a whole in relation to APCo’s financial statements.  As a result, APCo’s financial statements were not retrospectively adjusted to reflect the transfer.

Other Impacts of Corporate Separation

The Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO₂ emission allowances associated with transactions under the Interconnection agreement was also terminated.

Effective January 1, 2014, the FERC approved:

• A PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  Under the PCA, APCo, I&M and KPCo are individually responsible for planning their respective capacity obligations and there are no capacity equalization charges/credits under the PCA on deficit/surplus companies.   Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.

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• A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent.  The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies would fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year.  Under the Bridge Agreement, AGR is committed to use its capacity to help meet the PJM capacity obligations of member companies.

• A Power Supply Agreement (PSA) between AGR and OPCo that provided for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014.

Disposition of AEP River Operations

In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated third party. The sale closed in November 2015. AEPRO’s assets and liabilities have been recorded as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on the balance sheet as of December 31, 2014. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income for the current period and prior periods presented. The transaction was accounted for in accordance with the accounting guidance for “Presentation of Financial Statements and Property, Plant and Equipment.” Material disclosures within the notes to the financial statements exclude amounts related to Discontinued Operations for all periods presented as well as amounts related to Assets from Discontinued Operations and Liabilities from Discontinued Operations as of December 31, 2014. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate.  The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act.  The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company.  For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate.  The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes.  Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system.

The FERC regulates wholesale power markets and wholesale power transactions.  The Registrants’ wholesale power transactions are generally market-based.  Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs.  Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts.  These contracts are generally formula rate mechanisms, which are trued up to actual costs annually.  

The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis.  The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas.  For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates.  In addition, all OPCo distribution customers pay for certaindeferred generation-relatedcosts through non-bypassable charges.  In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-

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term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT.

The FERC also regulates the Registrants’ wholesale transmission operations and rates.  Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring.  OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based.  Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based.

In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis.

In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement.  In accordance with management’s 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO₂ emission allowances associated with transactions under the Interconnection Agreement was also terminated.  In December 2013, the FERC issued orders approving the creation of a PCA and a PSA, effective January 1, 2014.  The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. Effective June 1, 2014, the FERC approved the cancellation of the System Transmission Integration Agreement.

Principles of Consolidation

AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE).  The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs).  The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE).  The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE).  Intercompany items are eliminated in consolidation.  The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest.  Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income.  Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned.  The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets.  See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment.

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Accounting for the Effects of Cost-Based Regulation

The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated.  In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.

Use of Estimates

The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes.  These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits.  The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements.  Actual results could ultimately differ from those estimates.

Cash and Cash Equivalents

Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.

Other Temporary Investments (Applies to AEP)

Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by its protected cell of EIS.

Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance.  AEP does not have any investments classified as trading.

Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI.  Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost.  The cost of securities sold is based on the specific identification or weighted average cost method.

In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions.  See “Fair Value Measurements of Other Temporary Investments” in Note 11.

Restricted Cash for Securitized Funding (Applies to APCo and OPCo)

Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds.

Inventory

Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market.  Materials and supplies inventories are carried at average cost.

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Accounts Receivable

Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities.

Revenue is recognized from electric power sales when power is delivered to customers.  To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo.  Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit.  AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information.

Allowance for Uncollectible Accounts

Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable.  For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis.  For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified.  Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.

Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries)

The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues as of December 31, 2015.

The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk.  The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs.  Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.

Emission Allowances

In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO₂ and NO_x emission allowance entitlements received at no cost from the Federal EPA.  For AEP’s nonregulated business, management records allowances at the lower of cost or market. Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market.  The Registrants follow the inventory model for these allowances.  Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets.  Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically

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Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations.  The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.

Property, Plant and Equipment

Regulated

Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts.  Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation.  The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss.  The equipment in each primary electric plant account is identified as a separate group.  The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received.  These rates and the related lives are subject to periodic review.  Removal costs are charged to regulatory liabilities.  The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses.

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.”  When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense.

The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Nonregulated

Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions.  Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals.  Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation.  A gain or loss would be recorded if the retirement is not considered an interim routine replacement.  Removal costs are charged to expense.

Allowance for Funds Used During Construction and Interest Capitalization

For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant.  The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense.  For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”

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Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments.  The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value.

Fair Value Measurements of Assets and Liabilities

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 established risk management policies as approved by the Finance Committee of AEP’s Board of Directors.  AEPSC’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) and the Energy Supply Risk Committee (Competitive Risk Committee) various 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 Energy Supply’s President and Vice President.

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 contracts being classified as Level 3 is the inability to substantiate energy price curves in the market.  A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and 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.

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Assets in the benefits and nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding 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 equivalent funds.  Fixed income securities generally do not trade on exchanges 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.  Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate or private equity investment.

Deferred Fuel Costs

The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized.  The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method.  In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets.  Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended.  These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval.  The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions.  On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals.  FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable.

Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia (upon securitization in November 2013) for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC.  Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo and in West Virginia for APCo (prior to securitization in November 2013) are reflected in rates through FAC phase-in plans.  The FAC generally includes some sharing of off-system sales margins.  In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC.  Prior to corporate separation, none of the margins from off-system sales were given to customers through the FAC in Ohio for OPCo.  A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M.  Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.

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Revenue Recognition

Regulatory Accounting

The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.  Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.

When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets.  Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur.  Examples of new events include the issuance of a regulatory commission order or passage of new legislation.  If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income.

Electricity Supply and Delivery Activities

The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services.  The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.  In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates.

Most of the power produced at the generation plants is sold to PJM or SPP.  The Registrants also purchase power from PJM and SPP to supply power to customers.  Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income.  However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales.

Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income.  Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances.  Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income.  All other non-trading derivative purchases are recorded net in revenues.

In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated.  In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Energy Marketing and Risk Management Activities

The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and adjacent markets.  These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices.  These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options.  Certain energy marketing and risk management transactions are with RTOs.

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The Registrants recognize revenues and expenses from marketing and risk management transactions that are not derivatives upon delivery of the commodity.  The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election.  The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances.  In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).  Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate.

Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge).  The Registrants initially record the effective portion of the cash flow hedge’s gain or loss as a component of AOCI.  When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income.  In regulated jurisdictions, the ineffective portion is deferred as regulatory assets (for losses) and regulatory liabilities (for gains).  See “Accounting for Cash Flow Hedging Strategies” section of Note 10.

Barging Activities (Applies to AEP)

AEP River Operations’ revenue, which is presented in Discontinued Operations, was recognized based on percentage of voyage completion.  The proportion of freight transportation revenue to be recognized was determined by applying a percentage to the contractual charges for such services.  The percentage was determined by dividing the number of miles from the loading point to the position of the barge as of the end of the accounting period by the total miles to the destination specified in the customer’s freight contract.  The position of the barge at accounting period end was determined by AEP’s computerized barge tracking system. See the “AEPRO (Corporate and Other)” section of Note 7.

SPP Integrated Power Market (Applies to AEP, PSO and SWEPCo)

In March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In the past, PSO and SWEPCo would satisfy their load requirements with their own generation resources or through the Operating Agreement. In the new integrated power market, PSO and SWEPCo operate as standalone entities by offering their respective generation into the SPP power market, which then economically dispatches the resources. This change further enables retail customers to obtain power through either internal generation or power purchases from the SPP market. The new integrated power market now operates in a similar manner as the PJM power market for the AEP East Companies. The change in the SPP integrated power market did not have a significant effect on the results of operations or cash flows.

Levelization of Nuclear Refueling Outage Costs (Applies to AEP and I&M)

In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over the period beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins.  I&M adjusts the amortization amount as necessary to ensure full amortization of all deferred costs by the end of the refueling cycle.

Maintenance

The Registrants expense maintenance costs as incurred.  If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues.  In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.

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Income Taxes and Investment Tax Credits

The Registrants use the liability method of accounting for income taxes.  Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence.

When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.

Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis.  Investment tax credits that have been deferred are amortized over the life of the plant investment.

The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.”  The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense.

Excise Taxes

As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers.  The Registrants do not record these taxes as revenue or expense.

Debt

Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced.  If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates.  Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition.

Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt.  The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations.  The net amortization expense is included in Interest Expense on the statements of income.

Goodwill and Intangible Assets (Applies to AEP)

When AEP acquires businesses, management records the fair value of all assets and liabilities, including intangible assets.  To the extent that consideration exceeds the fair value of identified assets, goodwill is recorded.  Goodwill and intangible assets with indefinite lives are not amortized.  Management tests acquired goodwill and other intangible assets with indefinite lives for impairment at least annually at their estimated fair value.  Management tests goodwill at the reporting unit level and other intangibles at the asset level.  Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, management estimates fair value using various internal and external valuation methods.  AEP amortizes intangible assets with finite lives over their respective estimated lives to their estimated residual values.  AEP also reviews the lives of the amortizable intangibles with finite lives on an annual basis.

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Investments Held in Trust for Future Liabilities

AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal.  All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations.  The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities.  To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers.  Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate.  Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities.  The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance.

Benefit Plans

All benefit plan assets are invested in accordance with each plan’s investment policy.  The investment policy outlines the investment objectives, strategies and target asset allocations by plan.

The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns.  Strategies used include:

• Maintaining a long-term investment horizon.

• Diversifying assets to help control volatility of returns at acceptable levels.

• Managing fees, transaction costs and tax liabilities to maximize investment earnings.

• Using active management of investments where appropriate risk/return opportunities exist.

• Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks.

• Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.

The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities.  The current target asset allocations are as follows:

Pension Plan Assets	Target
Equity	25	%
Fixed Income	59	%
Other Investments	15	%
Cash and Cash Equivalents	1	%
OPEB Plans Assets	Target
Equity	65	%
Fixed Income	33	%
Cash and Cash Equivalents	2	%

The investment policy for each benefit plan contains various investment limitations.  The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies).  However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law.

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For equity investments, the concentration limits are as follows:

• No security in excess of 5% of all equities.

• Cash equivalents must be less than 10% of an investment manager’s equity portfolio.

• No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio.

• No investment in excess of 5% of an outstanding class of any company.

• No securities may be bought or sold on margin or other use of leverage.

For fixed income investments, the concentration limits must not exceed:

• 3% in any single issuer.

• 5% for private placements.

• 5% for convertible securities.

• 60% for bonds rated AA+ or lower.

• 50% for bonds rated A+ or lower.

• 10% for bonds rated BBB- or lower.

For obligations of non-government issuers within the fixed income portfolio, the following limitations apply:

• AAA rated debt: a single issuer should account for no more than 5% of the portfolio.

• AA+, AA, AA- rated debt: a single issuer should account for no more than 3% of the portfolio.

• Debt rated A+ or lower:  a single issuer should account for no more than 2% of the portfolio.

• No more than 10% of the portfolio may be invested in high yield and emerging market debt combined at any time.

Each investment manager’s portfolio is compared to a diversified benchmark index.

A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation.  Real estate properties are illiquid, difficult to value and not actively traded.  The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties.  To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification.  Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities.

A portion of the pension assets is invested in private equity.  Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance.  Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded.  The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum.   The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise.  The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments.  Commingled private equity funds are used to enhance the holdings’ diversity.

AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses.  AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral.  All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested.  The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security.  The securities lending program’s objective is providing modest incremental income with a limited increase in risk.

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Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts.  The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust.  Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid.  Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities.  With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds.  A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges.  The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities.

Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal.  The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities.  The cash funds are valued each business day and provide daily liquidity.

Nuclear Trust Funds (Applies to AEP and I&M)

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, I&M or their affiliates.

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

I&M maintains trust funds for each regulatory jurisdiction.  Regulatory approval is required to withdraw decommissioning funds.  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 these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets.  I&M records these securities at fair value.  I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose.  Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.  See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters.  See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.

Comprehensive Income(Loss)

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources.  It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners.  Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).

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Stock-Based Compensation Plans (Applies to AEP)

As of December 31, 2015, AEP had performance units and restricted stock units outstanding under the American Electric Power System Long-Term Incentive Plan (LTIP).  Upon vesting, performance units are paid in cash and restricted stock units are settled in AEP common shares, except for restricted stock units granted after January 1, 2013 and vesting to executive officers, which are paid in cash. The impact of AEP’s stock-based compensation plans are insignificant to the financial statements of the Registrant Subsidiaries.

AEP maintains a variety of tax qualified and nonqualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock.  This includes AEP career shares maintained under the American Electric Power System Stock Ownership Requirement Plan, which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors.  AEP career shares are derived from vested performance units granted to employees under the LTIP.  AEP career shares are equal in value to shares of AEP common stock and become payable to executives in cash after their service ends.  AEP career shares accrue additional dividend shares in an amount equal to dividends paid on AEP common shares, and are reinvested in such shares at the closing market price on the dividend payments date.

AEP compensates their non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors.  These stock units become payable in cash to directors after their service ends.

Management measures and recognizes compensation expense for all share-based payment awards to employees and directors based on estimated fair values. For share-based payment awards with service only vesting conditions, management recognizes compensation expense using the straight-line single-option method.  Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2015, 2014 and 2013 is based on awards ultimately expected to vest.  Therefore, stock-based compensation expense has been reduced to reflect estimated forfeitures.  Accounting guidance for “Compensation - Stock Compensation” requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates.

For the years ended December 31, 2015, 2014 and 2013, compensation expense is included in Net Income for the performance units, career shares, restricted stock units and the non-employee director’s stock units. See Note 15 for additional discussion.

Earnings Per Share (EPS) (Applies to AEP)

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

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The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:

	Years Ended December 31,
	2015				2014				2013
	(in millions, except per share data)
			$/share				$/share				$/share
Income from Continuing Operations	$	1,768.6			$	1,590.5			$	1,473.9
Less: Net Income Attributable to Noncontrolling Interests	5.2				4.2				3.7
Earnings Attributable to AEP Common Shareholders from Continuing Operations	$	1,763.4			$	1,586.3			$	1,470.2
Weighted Average Number of Basic Shares Outstanding	490.3		$	3.59	488.6		$	3.24	486.6		$	3.02
Weighted Average Dilutive Effect of Restricted Stock Units	0.3		—		0.3		—		0.4		—
Weighted Average Number of Diluted Shares Outstanding	490.6		$	3.59	488.9		$	3.24	487.0		$	3.02

There were no antidilutive shares outstanding as of December 31, 2015, 2014 and 2013.

OPCo Revised Depreciation Rates (Applies to AEP and OPCo)

In the second quarter of 2013, OPCo impaired Muskingum River Plant, Unit 5 (MR5).  As a result of the impairment of the full book value of this generating unit, OPCo ceased depreciation on MR5 effective July 1, 2013.

Supplementary Related Party Information (Applies to AEP)

AEP and several nonaffiliated utility companies jointly own OVEC.  As of December 31, 2015, AEP’s ownership and investment in OVEC were 43.47% and $4.4 million, respectively.

OVEC’s owners are members to an intercompany power agreement.  Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios.  The aggregate power participation ratio of certain AEP utility subsidiaries is 43.47%.  The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and provide a return on capital.  The intercompany power agreement ends in June 2040.

AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures totaling $1.3 billion in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants.  These environmental projects were funded through debt issuances.  As of December 31, 2015, both generation plants were operating with environmental controls.

The following details related party transactions for the years ended December 31, 2015, 2014 and 2013:

	Years Ended December 31,
Related Party Transactions	2015		2014		2013
	(in millions)
AEP Revenues – Other Revenues:
OVEC – Barging and Other Transportation Services (a)	$	0.1	$	24.0	$	20.9
AEP Expenses – Purchased Electricity for Resale:
OVEC	241.7		268.5		289.2

(a) AEP did not ship coal to OVEC in 2015.

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Supplementary Income Statement Information

The following tables provide the components of Depreciation and Amortization for the years ended December 31, 2015, 2014 and 2013:

2015
Depreciation and Amortization	AEP		APCo		I&M		OPCo			PSO		SWEPCo
	(in millions)
Depreciation and Amortization of Property, Plant and Equipment	$	1,674.3	$	385.6	$	193.5	$	184.4		$	108.6	$	190.7
Amortization of Certain Securitized Assets	318.9		—		—		43.3			—		—
Amortization of Regulatory Assets and Liabilities	16.5		3.2		4.9		(10.2		)	8.9		1.3
Total Depreciation and Amortization	$	2,009.7	$	388.8	$	198.4	$	217.5		$	117.5	$	192.0

2014
Depreciation and Amortization	AEP		APCo		I&M		OPCo			PSO		SWEPCo
	(in millions)
Depreciation and Amortization of Property, Plant and Equipment	$	1,573.7	$	383.3	$	199.3	$	188.3		$	99.7	$	183.2
Amortization of Certain Securitized Assets	310.4		—		—		43.5			—		—
Amortization of Regulatory Assets and Liabilities	13.5		17.6		0.9		(18.1		)	1.3		1.9
Total Depreciation and Amortization	$	1,897.6	$	400.9	$	200.2	$	213.7		$	101.0	$	185.1

2013
Depreciation and Amortization	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Depreciation and Amortization of Property, Plant and Equipment	$	1,441.4	$	334.2	$	175.8	$	358.0	$	94.6	$	177.3
Amortization of Certain Securitized Assets	248.2		—		—		20.0		—		—
Amortization of Regulatory Assets and Liabilities	22.9		8.4		1.9		4.6		1.1		1.9
Total Depreciation and Amortization	$	1,712.5	$	342.6	$	177.7	$	382.6	$	95.7	$	179.2

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Supplementary Cash Flow Information (Applies to AEP)

	Years Ended December 31,
Cash Flow Information	2015		2014		2013
	(in millions)
Cash Paid (Received) for:
Interest, Net of Capitalized Amounts	$	857.2	$	838.5	$	882.1
Income Taxes	120.2		117.3		(54.8		)
Noncash Investing and Financing Activities:
Acquisitions Under Capital Leases	150.2		135.1		181.6
Construction Expenditures Included in Current Liabilities as of December 31,	741.4		559.3		492.4
Construction Expenditures Included in Noncurrent Liabilities as of December 31,	51.6		—		—
Construction Expenditures Included in Noncurrent Assets as of December 31,	10.5		—		—
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	37.9		44.5		—
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	2.2		3.4		4.4

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2. NEW ACCOUNTING PRONOUNCEMENTS

The disclosures in this note apply to all Registrants unless indicated otherwise.

Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the 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.

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 adopted ASU 2014-08 effective January 1, 2015.

ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09)

In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts.

The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018.

ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01)

In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. As applicable, this standard may change the presentation of amounts in the income statements. Management adopted ASU 2015-01 effective January 1, 2016.

ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03)

In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts.

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The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-03 in October 2015 and applied the new standard retrospectively for all periods presented. Prior to adoption, the Registrants included debt issuance costs in Deferred Charges and Other Noncurrent Assets on the balance sheets. The effect of the reclassification between assets and liabilities for each Registrant as of December 31, 2014 is disclosed in the table below.

Company	December 31, 2014
	(in millions)
AEP	$	88.5
APCo	21.6
I&M	7.8
OPCo	10.3
PSO	4.3
SWEPCo	8.1

ASU 2015-05 “Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05)

In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-05 prospectively, effective January 1, 2016, with no impact on results of operations, financial position or cash flows.

ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11)

In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management does not expect the new standard to impact its results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017.

ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13)

In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator.  Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception.  As a result, an entity may elect to designate that contract as a normal purchase or normal sale.

The new accounting guidance is effective upon issuance and applied prospectively.  Management has analyzed the impact of this new standard and determined that it had no impact on the accounting of the Registrants’ contracts.  Additionally, adoption had no impact on net income.  Management adopted ASU 2015-13 upon its issuance date.

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ASU 2015-17 “Balance Sheet Classification of Deferred Taxes” (ASU 2015-17)

In November 2015, the FASB issued ASU 2015-17 simplifying the presentation of deferred income taxes on the balance sheets. Under the new standard, deferred tax assets and liabilities are classified as noncurrent on the balance sheets. The new accounting guidance is effective for annual periods beginning after December 15, 2016 with early adoption permitted. Management adopted ASU 2015-17 upon its issuance date and applied the new standard prospectively. As a result, the new standard impacted the December 31, 2015 presentation of deferred tax assets and liabilities on the balance sheet.

ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01)

In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for sale securities in combination with the entity’s other deferred tax assets.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments should be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018.

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3.  COMPREHENSIVE INCOME

The disclosures in this note apply to all Registrants unless indicated otherwise.

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI for the years ended December 31, 2015, 2014 and 2013.  All amounts in the following tables are presented net of related income taxes.

AEP
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2015
	Cash Flow Hedges									Pension and OPEB
	Commodity			Interest Rate and Foreign Currency			Securities Available for Sale			Amortization of Deferred Costs		Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2014	$	1.6		$	(19.1	)	$	7.7		$	138.7	$	(232.0	)	$	(103.1	)
Change in Fair Value Recognized in AOCI	5.6			—			(0.6		)	—		(25.7		)	(20.7		)
Amounts Reclassified from AOCI	(12.4		)	1.9			—			1.2		—			(9.3		)
Net Current Period Other Comprehensive Income (Loss)	(6.8		)	1.9			(0.6		)	1.2		(25.7		)	(30.0		)
Pension and OPEB Adjustment Related to Mitchell Plant	—			—			—			—		6.0			6.0
Balance in AOCI as of December 31, 2015	$	(5.2	)	$	(17.2	)	$	7.1		$	139.9	$	(251.7	)	$	(127.1	)

AEP
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2014
	Cash Flow Hedges								Pension and OPEB
	Commodity			Interest Rate and Foreign Currency			Securities Available for Sale		Amortization of Deferred Costs		Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2013	$	0.2		$	(23.0	)	$	6.8	$	133.9	$	(233.1	)	$	(115.2	)
Change in Fair Value Recognized in AOCI	(9.8		)	—			0.9		—		1.1			(7.8		)
Amounts Reclassified from AOCI	11.2			3.9			—		4.8		—			19.9
Net Current Period Other Comprehensive Income	1.4			3.9			0.9		4.8		1.1			12.1
Balance in AOCI as of December 31, 2014	$	1.6		$	(19.1	)	$	7.7	$	138.7	$	(232.0	)	$	(103.1	)

AEP
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2013
	Cash Flow Hedges								Pension and OPEB
	Commodity			Interest Rate and Foreign Currency			Securities Available for Sale		Amortization of Deferred Costs		Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2012	$	(8.1	)	$	(30.2	)	$	4.2	$	112.0	$	(414.9	)	$	(337.0	)
Change in Fair Value Recognized in AOCI	10.4			2.6			2.6		—		176.6			192.2
Amounts Reclassified from AOCI	(2.1		)	4.6			—		21.9		—			24.4
Net Current Period Other Comprehensive Income	8.3			7.2			2.6		21.9		176.6			216.6
Pension and OPEB Adjustment Related to Mitchell Plant	—			—			—		—		5.2			5.2
Balance in AOCI as of December 31, 2013	$	0.2		$	(23.0	)	$	6.8	$	133.9	$	(233.1	)	$	(115.2	)

88

APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2015
	Cash Flow Hedges					Pension and OPEB
	Commodity		Interest Rate and Foreign Currency			Amortization of Deferred Costs			Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2014	$	—	$	3.9		$	19.2		$	(18.1	)	$	5.0
Change in Fair Value Recognized in AOCI	—		—			—			(5.7		)	(5.7		)
Amounts Reclassified from AOCI	—		(0.3		)	(1.8		)	—			(2.1		)
Net Current Period Other Comprehensive Loss	—		(0.3		)	(1.8		)	(5.7		)	(7.8		)
Balance in AOCI as of December 31, 2015	$	—	$	3.6		$	17.4		$	(23.8	)	$	(2.8	)

APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2014
	Cash Flow Hedges					Pension and OPEB
	Commodity			Interest Rate and Foreign Currency		Amortization of Deferred Costs			Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2013	$	0.1		$	3.1	$	20.5		$	(20.8	)	$	2.9
Change in Fair Value Recognized in AOCI	1.7			—		—			2.7			4.4
Amounts Reclassified from AOCI	(1.8		)	0.8		(1.3		)	—			(2.3		)
Net Current Period Other Comprehensive Income (Loss)	(0.1		)	0.8		(1.3		)	2.7			2.1
Balance in AOCI as of December 31, 2014	$	—		$	3.9	$	19.2		$	(18.1	)	$	5.0

APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2013
	Cash Flow Hedges					Pension and OPEB
	Commodity			Interest Rate and Foreign Currency		Amortization of Deferred Costs		Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2012	$	(0.6	)	$	2.1	$	19.1	$	(50.5	)	$	(29.9	)
Change in Fair Value Recognized in AOCI	0.7			—		—		29.7			30.4
Amounts Reclassified from AOCI	—			1.0		1.4		—			2.4
Net Current Period Other Comprehensive Income	0.7			1.0		1.4		29.7			32.8
Balance in AOCI as of December 31, 2013	$	0.1		$	3.1	$	20.5	$	(20.8	)	$	2.9

89

I&M
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2015
	Cash Flow Hedges					Pension and OPEB
	Commodity		Interest Rate and Foreign Currency			Amortization of Deferred Costs		Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2014	$	—	$	(14.4	)	$	5.1	$	(5.0	)	$	(14.3	)
Change in Fair Value Recognized in AOCI	—		—			—		(3.5		)	(3.5		)
Amounts Reclassified from AOCI	—		1.1			—		—			1.1
Net Current Period Other Comprehensive Income (Loss)	—		1.1			—		(3.5		)	(2.4		)
Balance in AOCI as of December 31, 2015	$	—	$	(13.3	)	$	5.1	$	(8.5	)	$	(16.7	)

I&M
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2014
	Cash Flow Hedges						Pension and OPEB
	Commodity			Interest Rate and Foreign Currency			Amortization of Deferred Costs		Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2013	$	0.1		$	(16.0	)	$	4.9	$	(4.5	)	$	(15.5	)
Change in Fair Value Recognized in AOCI	1.1			—			—		(0.5		)	0.6
Amounts Reclassified from AOCI	(1.2		)	1.6			0.2		—			0.6
Net Current Period Other Comprehensive Income (Loss)	(0.1		)	1.6			0.2		(0.5		)	1.2
Balance in AOCI as of December 31, 2014	$	—		$	(14.4	)	$	5.1	$	(5.0	)	$	(14.3	)

I&M
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2013
	Cash Flow Hedges						Pension and OPEB
	Commodity			Interest Rate and Foreign Currency			Amortization of Deferred Costs		Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2012	$	(0.4	)	$	(19.7	)	$	4.2	$	(13.0	)	$	(28.9	)
Change in Fair Value Recognized in AOCI	0.5			2.3			—		8.5			11.3
Amounts Reclassified from AOCI	—			1.4			0.7		—			2.1
Net Current Period Other Comprehensive Income	0.5			3.7			0.7		8.5			13.4
Balance in AOCI as of December 31, 2013	$	0.1		$	(16.0	)	$	4.9	$	(4.5	)	$	(15.5	)

90

OPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2015
	Cash Flow Hedges					Pension and OPEB
	Commodity		Interest Rate and Foreign Currency			Amortization of Deferred Costs		Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2014	$	—	$	5.6		$	58.4	$	(58.4	)	$	5.6
Change in Fair Value Recognized in AOCI	—		—			—		—			—
Amounts Reclassified from AOCI	—		(1.3		)	—		—			(1.3		)
Net Current Period Other Comprehensive Loss	—		(1.3		)	—		—			(1.3		)
Balance in AOCI as of December 31, 2015	$	—	$	4.3		$	58.4	$	(58.4	)	$	4.3

OPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2014
	Cash Flow Hedges						Pension and OPEB
	Commodity			Interest Rate and Foreign Currency			Amortization of Deferred Costs		Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2013	$	0.1		$	7.0		$	58.4	$	(58.4	)	$	7.1
Change in Fair Value Recognized in AOCI	—			—			—		—			—
Amounts Reclassified from AOCI	(0.1		)	(1.4		)	—		—			(1.5		)
Net Current Period Other Comprehensive Loss	(0.1		)	(1.4		)	—		—			(1.5		)
Balance in AOCI as of December 31, 2014	$	—		$	5.6		$	58.4	$	(58.4	)	$	5.6

OPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2013
	Cash Flow Hedges						Pension and OPEB
	Commodity			Interest Rate and Foreign Currency			Amortization of Deferred Costs		Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2012	$	(0.9	)	$	8.1		$	45.9	$	(218.8	)	$	(165.7	)
Change in Fair Value Recognized in AOCI	1.0			—			—		65.4			66.4
Amounts Reclassified from AOCI	—			(1.3		)	12.5		—			11.2
Net Current Period Other Comprehensive Income (Loss)	1.0			(1.3		)	12.5		65.4			77.6
Distribution of Cook Coal Terminal to Parent	—			—			—		19.6			19.6
Distribution of OPCo Generation to Parent	—			0.2			—		75.4			75.6
Balance in AOCI as of December 31, 2013	$	0.1		$	7.0		$	58.4	$	(58.4	)	$	7.1

91

PSO
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2015
	Cash Flow Hedges
	Commodity		Interest Rate and Foreign Currency			Total
	(in millions)
Balance in AOCI as of December 31, 2014	$	—	$	5.0		$	5.0
Change in Fair Value Recognized in AOCI	—		—			—
Amounts Reclassified from AOCI	—		(0.8		)	(0.8		)
Net Current Period Other Comprehensive Loss	—		(0.8		)	(0.8		)
Balance in AOCI as of December 31, 2015	$	—	$	4.2		$	4.2

PSO
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2014
	Cash Flow Hedges
	Commodity			Interest Rate and Foreign Currency			Total
	(in millions)
Balance in AOCI as of December 31, 2013	$	0.1		$	5.7		$	5.8
Change in Fair Value Recognized in AOCI	—			—			—
Amounts Reclassified from AOCI	(0.1		)	(0.7		)	(0.8		)
Net Current Period Other Comprehensive Loss	(0.1		)	(0.7		)	(0.8		)
Balance in AOCI as of December 31, 2014	$	—		$	5.0		$	5.0

PSO
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2013
	Cash Flow Hedges
	Commodity		Interest Rate and Foreign Currency			Total
	(in millions)
Balance in AOCI as of December 31, 2012	$	—	$	6.5		$	6.5
Change in Fair Value Recognized in AOCI	0.1		—			0.1
Amounts Reclassified from AOCI	—		(0.8		)	(0.8		)
Net Current Period Other Comprehensive Income (Loss)	0.1		(0.8		)	(0.7		)
Balance in AOCI as of December 31, 2013	$	0.1	$	5.7		$	5.8

92

SWEPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2015
	Cash Flow Hedges					Pension and OPEB
	Commodity		Interest Rate and Foreign Currency			Amortization of Deferred Costs			Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2014	$	—	$	(11.1	)	$	3.6		$	—		$	(7.5	)
Change in Fair Value Recognized in AOCI	—		—			—			(2.9		)	(2.9		)
Amounts Reclassified from AOCI	—		2.0			(1.0		)	—			1.0
Net Current Period Other Comprehensive Income (Loss)	—		2.0			(1.0		)	(2.9		)	(1.9		)
Balance in AOCI as of December 31, 2015	$	—	$	(9.1	)	$	2.6		$	(2.9	)	$	(9.4	)

SWEPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2014
	Cash Flow Hedges					Pension and OPEB
	Commodity		Interest Rate and Foreign Currency			Amortization of Deferred Costs			Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2013	$	—	$	(13.3	)	$	4.5		$	0.3		$	(8.5	)
Change in Fair Value Recognized in AOCI	—		—			—			(0.3		)	(0.3		)
Amounts Reclassified from AOCI	—		2.2			(0.9		)	—			1.3
Net Current Period Other Comprehensive Income (Loss)	—		2.2			(0.9		)	(0.3		)	1.0
Balance in AOCI as of December 31, 2014	$	—	$	(11.1	)	$	3.6		$	—		$	(7.5	)

SWEPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2013
	Cash Flow Hedges						Pension and OPEB
	Commodity			Interest Rate and Foreign Currency			Amortization of Deferred Costs			Changes in Funded Status			Total
	(in millions)
Balance in AOCI as of December 31, 2012	$	—		$	(15.6	)	$	4.8		$	(7.1	)	$	(17.9	)
Change in Fair Value Recognized in AOCI	0.1			—			—			7.4			7.5
Amounts Reclassified from AOCI	(0.1		)	2.3			(0.3		)	—			1.9
Net Current Period Other Comprehensive Income (Loss)	—			2.3			(0.3		)	7.4			9.4
Balance in AOCI as of December 31, 2013	$	—		$	(13.3	)	$	4.5		$	0.3		$	(8.5	)

93

Reclassifications from Accumulated Other Comprehensive Income

The following tables provide details of reclassifications from AOCI for the years ended December 31, 2015, 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 8 for additional details.

AEP
Reclassifications from Accumulated Other Comprehensive Income (Loss)
	Amount of (Gain) Loss Reclassified from AOCI
	Years Ended December 31,
	2015			2014			2013
Gains and Losses on Cash Flow Hedges	(in millions)
Commodity:
Vertically Integrated Utilities Revenues	$	—		$	—		$	(1.1	)
Generation & Marketing Revenues	(48.1		)	59.1			(9.7		)
Purchased Electricity for Resale	29.1			(39.1		)	7.6
Regulatory Assets/(Liabilities), Net (a)	—			(2.8		)	—
Subtotal – Commodity	(19.0		)	17.2			(3.2		)
Interest Rate and Foreign Currency:
Interest Expense	2.9			6.1			7.1
Subtotal – Interest Rate and Foreign Currency	2.9			6.1			7.1
Reclassifications from AOCI, before Income Tax (Expense) Credit	(16.1		)	23.3			3.9
Income Tax (Expense) Credit	(5.6		)	8.2			1.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(10.5		)	15.1			2.5
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(19.5		)	(20.6		)	(21.0		)
Amortization of Actuarial (Gains)/Losses	21.3			28.0			54.7
Reclassifications from AOCI, before Income Tax (Expense) Credit	1.8			7.4			33.7
Income Tax (Expense) Credit	0.6			2.6			11.8
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.2			4.8			21.9
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit	$	(9.3	)	$	19.9		$	24.4

94

APCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
	Amount of (Gain) Loss Reclassified from AOCI
	Years Ended December 31,
	2015			2014			2013
Gains and Losses on Cash Flow Hedges	(in millions)
Commodity:
Electric Generation, Transmission and Distribution Revenues	$	—		$	—		$	(0.1	)
Purchased Electricity for Resale	—			(0.5		)	0.1
Regulatory Assets/(Liabilities), Net (a)	—			(2.2		)	—
Subtotal – Commodity	—			(2.7		)	—
Interest Rate and Foreign Currency:
Interest Expense	(0.4		)	1.2			1.5
Subtotal – Interest Rate and Foreign Currency	(0.4		)	1.2			1.5
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.4		)	(1.5		)	1.5
Income Tax (Expense) Credit	(0.1		)	(0.5		)	0.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.3		)	(1.0		)	1.0
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(5.1		)	(5.1		)	(5.1		)
Amortization of Actuarial (Gains)/Losses	2.3			3.1			7.3
Reclassifications from AOCI, before Income Tax (Expense) Credit	(2.8		)	(2.0		)	2.2
Income Tax (Expense) Credit	(1.0		)	(0.7		)	0.8
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.8		)	(1.3		)	1.4
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit	$	(2.1	)	$	(2.3	)	$	2.4

95

I&M
Reclassifications from Accumulated Other Comprehensive Income (Loss)
	Amount of (Gain) Loss Reclassified from AOCI
	Years Ended December 31,
	2015			2014			2013
Gains and Losses on Cash Flow Hedges	(in millions)
Commodity:
Electric Generation, Transmission and Distribution Revenues	$	—		$	—		$	(0.2	)
Purchased Electricity for Resale	—			(0.8		)	0.2
Regulatory Assets/(Liabilities), Net (a)	—			(1.0		)	—
Subtotal – Commodity	—			(1.8		)	—
Interest Rate and Foreign Currency:
Interest Expense	1.7			2.4			2.2
Subtotal – Interest Rate and Foreign Currency	1.7			2.4			2.2
Reclassifications from AOCI, before Income Tax (Expense) Credit	1.7			0.6			2.2
Income Tax (Expense) Credit	0.6			0.2			0.8
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.1			0.4			1.4
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(0.9		)	(0.8		)	(0.8		)
Amortization of Actuarial (Gains)/Losses	0.9			1.1			1.9
Reclassifications from AOCI, before Income Tax (Expense) Credit	—			0.3			1.1
Income Tax (Expense) Credit	—			0.1			0.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	—			0.2			0.7
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit	$	1.1		$	0.6		$	2.1

96

OPCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
	Amount of (Gain) Loss Reclassified from AOCI
	Years Ended December 31,
	2015			2014			2013
Gains and Losses on Cash Flow Hedges	(in millions)
Commodity:
Electric Generation, Transmission and Distribution Revenues	$	—		$	—		$	(0.4	)
Purchased Electricity for Resale	—			—			0.6
Other Operation Expense	—			—			(0.1		)
Regulatory Assets/(Liabilities), Net (a)	—			(0.2		)	—
Subtotal – Commodity	—			(0.2		)	0.1
Interest Rate and Foreign Currency:
Interest Expense	(2.0		)	(2.1		)	(2.1		)
Subtotal – Interest Rate and Foreign Currency	(2.0		)	(2.1		)	(2.1		)
Reclassifications from AOCI, before Income Tax (Expense) Credit	(2.0		)	(2.3		)	(2.0		)
Income Tax (Expense) Credit	(0.7		)	(0.8		)	(0.7		)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.3		)	(1.5		)	(1.3		)
Pension and OPEB
Amortization of Prior Service Cost (Credit)	—			—			(5.8		)
Amortization of Actuarial (Gains)/Losses	—			—			25.0
Reclassifications from AOCI, before Income Tax (Expense) Credit	—			—			19.2
Income Tax (Expense) Credit	—			—			6.7
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	—			—			12.5
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit	$	(1.3	)	$	(1.5	)	$	11.2

PSO
Reclassifications from Accumulated Other Comprehensive Income (Loss)
	Amount of (Gain) Loss Reclassified from AOCI
	Years Ended December 31,
	2015			2014			2013
Gains and Losses on Cash Flow Hedges	(in millions)
Commodity:
Regulatory Assets/(Liabilities), Net (a)	$	—		$	(0.1	)	$	—
Subtotal – Commodity	—			(0.1		)	—
Interest Rate and Foreign Currency:
Interest Expense	(1.2		)	(1.1		)	(1.2		)
Subtotal – Interest Rate and Foreign Currency	(1.2		)	(1.1		)	(1.2		)
Reclassifications from AOCI, before Income Tax (Expense) Credit	(1.2		)	(1.2		)	(1.2		)
Income Tax (Expense) Credit	(0.4		)	(0.4		)	(0.4		)
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit	$	(0.8	)	$	(0.8	)	$	(0.8	)

97

SWEPCo
Reclassifications from Accumulated Other Comprehensive Income (Loss)
	Amount of (Gain) Loss Reclassified from AOCI
	Years Ended December 31,
	2015			2014			2013
Gains and Losses on Cash Flow Hedges	(in millions)
Commodity:
Other Operation Expense	$	—		$	—		$	(0.1	)
Regulatory Assets/(Liabilities), Net (a)	—			(0.1		)	—
Subtotal – Commodity	—			(0.1		)	(0.1		)
Interest Rate and Foreign Currency:
Interest Expense	3.1			3.5			3.5
Subtotal – Interest Rate and Foreign Currency	3.1			3.5			3.5
Reclassifications from AOCI, before Income Tax (Expense) Credit	3.1			3.4			3.4
Income Tax (Expense) Credit	1.1			1.2			1.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	2.0			2.2			2.2
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(1.9		)	(1.9		)	(1.8		)
Amortization of Actuarial (Gains)/Losses	0.4			0.5			1.4
Reclassifications from AOCI, before Income Tax (Expense) Credit	(1.5		)	(1.4		)	(0.4		)
Income Tax (Expense) Credit	(0.5		)	(0.5		)	(0.1		)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.0		)	(0.9		)	(0.3		)
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit	$	1.0		$	1.3		$	1.9

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

98

4.  RATE MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions.  Rate matters can have a material impact on net income, cash flows and possibly financial condition.  The Registrants’ recent significant rate orders and pending rate filings are addressed in this note.

APCo and WPCo Rate Matters (Applies to AEP and APCo)

2014 West Virginia Base Rate Case

In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total combined revenue, annual base rates were authorized to be increased by $99 million ($85 million related to APCo) based upon a 9.75% return on common equity. The order included a delayed billing of $25 million ($22 million related to APCo) of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a weighted average cost of capital (WACC) rate for the $25 million annual delayed billing through June 2016, and stated recovery would be addressed concurrent with the next ENEC change in rates. Additionally, the order included approval of (a) an initial vegetation management rider of $45 million ($38 million related to APCo) annually, (b) revised deprecation rates, including recovery of plants to be retired in the second quarter of 2015 and (c) the recovery of $89 million ($77 million related to APCo) in previously recorded regulatory assets, which will predominantly be recovered over five years. In February 2016, APCo and WPCo filed a petition with the WVPSC to implement recovery of the delayed billing totaling $29 million ($26 million related to APCo), which includes carrying charges through June 2016. Recovery of the $29 million was requested over two years, beginning July 2016, with the unpaid principal subject to carrying charges.

2015 Virginia Regulatory Asset Proceeding

In 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets and briefs related to this proceeding were filed by various parties. The Virginia SCC has no statutory deadline to issue its decision in this proceeding. As of December 31, 2015, APCo’s authorized regulatory assets under review in this proceeding were $10 million. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Virginia Legislation Affecting Biennial Reviews

In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA.

In February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning March 2016. In February 2016, APCo filed a motion to stay the Virginia SCC’s consideration of the petition due to a pending appeal at the Supreme Court of Virginia by industrial customers of a non-related utility regarding the constitutionality of the 2015 amendments. Oral arguments at the Virginia SCC are scheduled for March 2016. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition.

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ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of December 31, 2015, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $433 million based upon interim rate increases received from 2009 through 2015. In November 2015, the PUCT ordered ETT to file a base rate case by February 2017. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses that are reasonably possible of occurring. A refund of interim transmission rates could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters (Applies to AEP and I&M)

Tanners Creek Plant

In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M’s Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M’s request for revised depreciation rates. Revised depreciation rates were previously approved by the MPSC in 2014, along with a credit rider to reduce customer rates upon retirement of Tanners Creek Plant.

In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval.

Transmission, Distribution and Storage System Improvement Charge (TDSIC)

In 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million. In 2015, the IURC granted I&M’s motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals.

KPCo Rate Matters (Applies to AEP)

Plant Transfer

Consistent with KPCo’s December 2012 plant transfer filing that was approved by the KPSC, Big Sandy Plant, Unit 2 was retired in May 2015. Upon retirement, $194 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Big Sandy Plant, Unit 2 and the related asset retirement obligations, costs of removal and materials and supplies. These regulatory assets will be amortized over 25 years, effective July 2015.

In October 2013, the KPSC issued an order that approved a modified settlement agreement which included the approval to transfer to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed. In April 2015, the Franklin County Circuit Court issued an order that affirmed the KPSC’s October 2013 order. In May 2015, the Attorney General filed an appeal with the Kentucky Court of Appeals of the April 2015 order. In December 2015, KPCo, the Attorney General and the KPSC filed a joint motion to dismiss the appeals filed with the Kentucky Court of Appeals and in February 2016, the joint motion to dismiss was granted.

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Kentucky Fuel Adjustment Clause Review

In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owned and operated both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court. In September 2015, the Franklin County Circuit Court issued an order that dismissed all appeals filed related to this FAC review, as agreed to by the parties to the stipulation agreement in the “2014 Kentucky Base Rate Case” discussed below.

2014 Kentucky Base Rate Case

In December 2014, KPCo filed a request with the KPSC for a net increase in rates of $70 million. In April 2015, a stipulation agreement between KPCo and certain intervenors was filed with the KPSC that recommended a net revenue increase of $45 million, which consisted of a $68 million increase in rider rates, offset by a $23 million decrease in annual base rates, to be effective July 2015. The proposed net increase reflected KPCo’s ownership interest in the Mitchell Plant, riders to recover the Big Sandy Plant retirement and operational costs and the inclusion of an environmental compliance plan.  The proposed net increase of $45 million also included (a) recovery of $12 million of deferred storm costs, (b) any difference between the actual off-system sales margins and the $15 million included in the proposed annual base rates to be shared with 75% to the customer and 25% to KPCo and (c) dismissal of the KPCo and the Kentucky Industrial Utility Customers appeals of the KPSC order in the KPCo fuel adjustment clause review. See “Kentucky Fuel Adjustment Clause Review” discussed above.

In June 2015, the KPSC issued an order that approved a modified stipulation agreement. The order approved a net revenue increase of $45 million, as proposed in the stipulation agreement, and contained modifications that included (a) approval to recover $2 million of IGCC and certain carbon capture study costs, both over 25 years, (b) no deferral of certain PJM costs and (c) denial of the recovery of certain potential purchased power costs through a rider.

KGPCo Rate Matters (Applies to AEP)

Kingsport Base Rate Case

In September 2015, KGPCo filed a request with the TRA to increase base rates by $12 million annually based upon a proposed return on common equity of 10.66%. In December 2015, KGPCo withdrew its base rate case filing for administrative purposes and refiled its request with the TRA in January 2016. If KGPCo does not recover its costs, it could reduce future net income and cash flows and impact financial condition.

OPCo Rate Matters (Applies to AEP and OPCo)

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. 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.

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 appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a WACC rate. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed an appeal filed by the IEU. In September 2015, the Supreme Court of Ohio denied a request for reconsideration filed by the IEU and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. A decision from the PUCO is pending.

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June 2012 – May 2015 ESP Including Capacity Charge

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

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the 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 collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and $150/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. Oral arguments at the Supreme Court of Ohio were held in December 2015. A decision from the Supreme Court of Ohio is pending.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR was collected from customers at $3.50/MWh through May 2014 and 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 2015, the PUCO issued an order that approved, with modifications, OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00/MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million. In May 2015, the PUCO granted intervenors requests for rehearing. As of December 31, 2015, OPCo’s net deferred capacity costs balance of $359 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. Through December 31, 2015, OPCo has collected $222 million in deferred capacity costs, and related carrying charges.

In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. 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 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015.

In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. 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.

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. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo’s $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.

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June 2015 - May 2018 ESP Including PPA Application

In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets.

In February 2015, the PUCO issued an order approving OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo’s and various intervenors’ requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider. In October 2015, the Supreme Court of Ohio granted the PUCO’s motion to dismiss these intervenor appeals, without prejudice, since rehearing related to the PPA issues was still pending.

In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo’s OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. Hearings at the PUCO related to the PPA were concluded in November 2015.

In December 2015, a non-unanimous stipulation agreement related to the PPA application was filed with the PUCO. The stipulation agreement is based upon a 10.38% return on common equity with the PPA Rider term extending through May 2024. The stipulation agreement included (a) a revised affiliate PPA between OPCo and AGR to be included in the PPA Rider, (b) OPCo’s OVEC contractual entitlement, (c) a potential additional customer credit to be included in the PPA Rider, (d) annual compliance reviews before the PUCO and (e) an agreement to retire, refuel or repower, to 100% natural gas, Conesville Plant, Units 5 and 6 and Cardinal Plant, Unit 1 by 2029 and 2030, respectively. Additionally, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. OPCo would own up to 50% of these solar and wind projects and would include cost recovery in the proposed PPA rider, subject to PUCO review and approval. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions. Hearings related to this proposed stipulation agreement were held in January 2016. Management anticipates receiving an order from the PUCO in the first quarter of 2016. In January 2016, intervenors filed a complaint at the FERC related to the affiliate PPA. The complaint asserts that the proposed affiliate PPA between AGR and OPCo is reviewable by the FERC under its standards for affiliate transactions.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.

Significantly Excessive Earnings Test 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.

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In June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements.

Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation and 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. In December 2013, corporate separation of OPCo’s generation assets was completed. In December 2015, the IEU withdrew its appeal.

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.

In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. 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.

2012 and 2013 Fuel Adjustment Clause Audits

In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the “June 2012 - May 2015 ESP Including Capacity Charge” section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, 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 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (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 November 2015, the PUCO issued an order approving the stipulation agreement and OPCo’s request to recover its remaining $10 million of Ormet deferrals through the EDR.

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.

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PSO Rate Matters (Applies to AEP and PSO)

2015 Oklahoma Base Rate Case

In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million, which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million, excluding AFUDC. As of December 31, 2015, PSO had incurred costs of $190 million related to these projects, including AFUDC.

In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million, will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of December 31, 2015, the net book value of Northeastern Plant, Unit 4 was $93 million, before cost of removal, including materials and supplies inventory and CWIP.

In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million, based upon returns on common equity ranging from 8.75% to 9.3%, and increases to depreciation expense ranging from $23 million to $46 million. Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, some intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC were held in December 2015. In January 2016, PSO implemented an interim annual base rate increase of $75 million. These interim rates are subject to refund pending a final order from the OCC related to the initial $137 million request. An order from the OCC is anticipated in the second quarter of 2016.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2014 Oklahoma Base Rate Case

In April 2015, the OCC issued an order that approved a stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014.

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SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 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.

Upon rehearing in 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 was approximately $52 million. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses.

If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo’s 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 prudency review of the Turk Plant. The settlement also provided that the LPSC review base rates in 2014 and 2015 and that SWEPCo 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 December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million, primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition.

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, which was 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 purchased power agreement attributable to Louisiana customers.  In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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2015 Louisiana Formula Rate Filing

In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC.  The filing included a $14 million annual increase, which was effective August 2015.  This increase is subject to LPSC staff review and is subject to refund.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost approximately $900 million, excluding AFUDC. As part of this investment, 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 $400 million, excluding AFUDC.  As of December 31, 2015, SWEPCo had incurred costs of $343 million, including AFUDC, and had remaining contractual construction obligations of $40 million related to these projects.  SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of December 31, 2015, the net book value of Welsh Plant, Units 1 and 3 was $578 million, before cost of removal, including materials and supplies inventory and CWIP.  Welsh Plant, Unit 2 is scheduled for retirement during 2016 and is probable of abandonment. As of December 31, 2015, the net book value of Welsh Plant, Unit 2 was $82 million, before cost of removal, including materials and supplies inventory and CWIP.

If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

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5.  EFFECTS OF REGULATION

The disclosures in this note apply to all Registrants unless indicated otherwise.

Regulated Generating Units Expected to be Retired During 2016 (Applies to AEP, PSO and SWEPCo)

The following regulated generating units are probable of abandonment.  Accordingly, CWIP and Plant in Service has been reclassified as Other Property, Plant and Equipment on the balance sheets as of December 31, 2015 and 2014.  The following table summarizes the plant investment and cost of removal, currently being recovered, for each generating unit as of December 31, 2015.

Plant Name and Unit	Company	Gross Investment		Accumulated Depreciation		Net Investment		Materials and Supplies		Cost of Removal Regulatory Liability		Expected Retirement Date	Remaining Recovery Period
(in millions)
Northeastern Station, Unit 4	PSO	$	182.5	$	93.1	$	89.4	$	4.0	$	11.3	2016	25 years
Welsh Plant, Unit 2	SWEPCo	176.1		98.6		77.5		4.6		19.9		2016	25 years
Total		$	358.6	$	191.7	$	166.9	$	8.6	$	31.2

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Regulatory Assets and Liabilities

Regulatory assets and liabilities are comprised of the following items:

	AEP
	December 31,				Remaining Recovery Period
	2015		2014
Current Regulatory Assets	(in millions)
Under-recovered Fuel Costs - earns a return	$	38.9	$	121.2	1 year
Under-recovered Fuel Costs - does not earn a return	76.3		5.4		1 year
Total Current Regulatory Assets	$	115.2	$	126.6
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
Storm Related Costs	$	24.2	$	20.2
Plant Retirement Costs - Materials and Supplies	20.9		—
West Virginia Vegetation Management Program	—		20.4
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs	59.8		—
Storm Related Costs	18.2		100.4
Peak Demand Reduction/Energy Efficiency	13.1		9.0
Carbon Capture and Storage Product Validation Facility	—		13.3
IGCC Pre-Construction Costs	—		10.8
Ormet Special Rate Recovery Mechanism	—		10.5
Other Regulatory Assets Pending Final Regulatory Approval	31.7		42.7
Total Regulatory Assets Pending Final Regulatory Approval	167.9		227.3
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant	577.4		—		29 years
Ohio Capacity Deferral	358.7		422.1		3 years
Ohio Phase-In Recovery Rider	304.5		377.5		3 years
Meter Replacement Costs	90.4		59.2		12 years
Ohio Distribution Decoupling	37.5		35.1		2 years
Mitchell Plant Transfer	19.3		—		25 years
Ohio Transmission Cost Recovery Rider	12.3		27.9		1 year
Red Rock Generating Facility	9.3		9.5		41 years
Storm Related Costs	8.8		13.0		3 years
Other Regulatory Assets Approved for Recovery	36.7		29.1		various
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	1,410.5		1,273.1		12 years
Income Taxes, Net	1,385.3		1,268.3		52 years
Unamortized Loss on Reacquired Debt	148.7		65.7		30 years
Storm Related Costs	94.6		26.0		5 years
Virginia Transmission Rate Adjustment Clause	74.6		53.2		2 years
Plant Retirement Costs - Asset Retirement Obligation Costs	58.0		—		25 years
Postemployment Benefits	42.6		39.2		5 years
Medicare Subsidy	41.8		46.5		9 years
Vegetation Management	36.9		5.4		6 years
Peak Demand Reduction/Energy Efficiency	33.3		62.4		2 years
Cook Plant Nuclear Refueling Outage Levelization	26.8		38.0		3 years
United Mine Workers of America Pension Withdrawal	14.4		25.4		10 years
Distribution Investment Rider	12.3		9.9		2 years
Carbon Capture and Storage Product Validation Facility	11.7		—		5 years
IGCC Pre-Construction Costs	10.9		—		25 years
Unrealized Loss on Forward Commitments	10.7		9.7		2 years
Transmission Cost Recovery Factor	9.9		15.4		1 year
Deferred System Reliability Rider Expenses	9.9		8.3		1 year
Indiana Capacity Costs	7.5		25.1		1 year
gridSMART ® Costs	4.5		15.9		2 years
PJM Expense	4.1		21.9		2 years
Other Regulatory Assets Approved for Recovery	68.5		53.6		various
Total Regulatory Assets Approved for Recovery	4,972.4		4,036.4
Total Noncurrent Regulatory Assets	$	5,140.3	$	4,263.7

109

	AEP
	December 31,				Remaining
	2015		2014		Refund Period
Current Regulatory Liabilities	(in millions)
Over-recovered Fuel Costs - pays a return	$	84.8	$	—	1 year
Over-recovered Fuel Costs - does not pay a return	29.1		55.2		1 year
Total Current Regulatory Liabilities	$	113.9	$	55.2
Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Not Paying a Return
Provision for Regulatory Loss	$	40.6	$	35.2
Other Regulatory Liabilities Pending Final Regulatory Determination	0.2		16.8
Total Regulatory Liabilities Pending Final Regulatory Determination	40.8		52.0
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	2,656.5		2,660.3		(a)
Louisiana Refundable Construction Financing Costs	37.4		58.2		3 years
Advanced Metering Infrastructure Surcharge	21.2		43.7		5 years
Deferred Investment Tax Credits	14.7		25.8		43 years
Excess Earnings	10.6		11.1		38 years
Other Regulatory Liabilities Approved for Payment	20.5		3.8		various
Regulatory Liabilities Currently Not Paying a Return
Excess Asset Retirement Obligations for Nuclear
Decommissioning Liability	636.5		694.9		(b)
Deferred Investment Tax Credits	113.3		112.6		47 years
Transition Charges	46.5		46.8		12 years
Spent Nuclear Fuel Liability	43.4		43.5		(b)
Unrealized Gain on Forward Commitments	33.8		92.2		17 years
Deferred Wind Power Costs	11.8		—		2 years
Advanced Metering Costs	11.4		—		1 year
Indiana Off-system Sales Margin Sharing	—		19.4
Other Regulatory Liabilities Approved for Payment	37.7		28.1		various
Total Regulatory Liabilities Approved for Payment	3,695.3		3,840.4
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	3,736.1	$	3,892.4

(a) Relieved as removal costs are incurred.

(b) Relieved when plant is decommissioned.

110

	APCo
	December 31,				Remaining Recovery Period
Regulatory Assets:	2015		2014
	(in millions)
Current Regulatory Assets
Under-recovered Fuel Costs - earns a return	$	27.3	$	60.7	1 year
Under-recovered Fuel Costs - does not earn a return	59.6		5.4		1 year
Total Current Regulatory Assets	$	86.9	$	66.1
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Materials and Supplies	$	9.3	$	—
Vegetation Management Program - West Virginia	—		19.1
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs	32.7		—
Peak Demand Reduction/Energy Efficiency - Virginia	12.7		8.8
Amos Plant Transfer Costs - West Virginia	2.0		1.4
Storm Related Costs - West Virginia	—		65.2
Carbon Capture and Storage Product Validation Facility - West Virginia, FERC	—		13.3
IGCC Pre-Construction Costs - West Virginia, FERC	—		10.8
Expanded Net Energy Charge - Coal Inventory	—		3.4
Expanded Net Energy Charge - Construction Surcharge	—		2.3
Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC	—		1.3
Other Regulatory Assets Pending Final Regulatory Approval	0.6		0.1
Total Regulatory Assets Pending Final Regulatory Approval	57.3		125.7
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant	86.5		—		24 years
Storm Related Costs - Virginia	8.8		13.0		3 years
RTO Formation/Integration Costs	2.1		2.5		4 years
Regulatory Assets Currently Not Earning a Return
Income Taxes, Net	441.7		381.7		25 years
Pension and OPEB Funded Status	217.6		212.5		12 years
Unamortized Loss on Reacquired Debt	101.5		11.1		30 years
Virginia Transmission Rate Adjustment Clause	74.6		53.2		2 years
Storm Related Costs - West Virginia	63.5		8.5		5 years
Vegetation Management Program - West Virginia	31.2		—		6 years
Postemployment Benefits	19.6		17.8		5 years
Carbon Capture and Storage Product Validation Facility - West Virginia, FERC	11.7		—		5 years
IGCC Pre-Construction Costs - West Virginia, FERC	9.6		—		5 years
Medicare Subsidy - West Virginia, FERC	5.3		5.9		9 years
Virginia Generation Rate Adjustment Clause	5.2		3.8		3 years
Deferred Restructuring Costs - West Virginia	4.5		6.5		3 years
Peak Demand Reduction/Energy Efficiency - West Virginia	3.5		0.9		2 years
Uncollected Accounts - West Virginia	3.5		—		5 years
Asset Retirement Obligation	2.4		4.4		2 years
Transmission Agreement Phase-In - West Virginia	1.7		2.9		2 years
Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC	1.2		—		7 years
Unrealized Loss on Forward Commitments	0.6		4.1		2 years
Virginia Environmental Rate Adjustment Clause	—		3.3
Other Regulatory Assets Approved for Recovery	0.6		0.1		various
Total Regulatory Assets Approved for Recovery	1,096.9		732.2
Total Noncurrent Regulatory Assets	$	1,154.2	$	857.9

111

	APCo
	December 31,				Remaining Refund Period
Regulatory Liabilities:	2015		2014
	(in millions)
Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Not Paying a Return
Expanded Net Energy Charge - Construction Surcharge	$	—	$	5.4
Deferred Wind Power Costs - Virginia	—		4.5
Felman Special Rate Mechanism - West Virginia	—		2.1
Total Regulatory Liabilities Pending Final Regulatory Determination	—		12.0
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	612.9		617.3		(a)
Deferred Investment Tax Credits	1.0		1.3		43 years
Regulatory Liabilities Currently Not Paying a Return
Deferred Wind Power Costs - Virginia	11.8		—		2 years
Unrealized Gain on Forward Commitments	8.4		19.7		2 years
Consumer Rate Relief - West Virginia	2.9		2.6		1 year
Other Regulatory Liabilities Approved for Payment	0.1		—		various
Total Regulatory Liabilities Approved for Payment	637.1		640.9
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	637.1	$	652.9

(a) Relieved as removal costs are incurred.

112

	I&M
	December 31,				Remaining Recovery Period
Regulatory Assets:	2015		2014
	(in millions)
Current Regulatory Assets
Under-recovered Fuel Costs -earns a return	$	7.5	$	0.8	1 year
Under-recovered Fuel Costs -does not earn a return	4.1		—		1 year
Total Current Regulatory Assets	$	11.6	$	0.8
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Materials and Supplies	$	11.6	$	—
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana	27.1		—
Cook Plant Turbine	9.7		6.6
Deferred Cook Plant Life Cycle Management Project Costs - Michigan	4.2		1.2
Stranded Costs on Abandoned Plants	3.9		3.9
Rockport Plant Dry Sorbent Injection System - Indiana	2.8		0.1
Storm Related Costs - Indiana	—		1.1
Other Regulatory Assets Pending Final Regulatory Approval	—		0.7
Total Regulatory Assets Pending Final Regulatory Approval	59.3		13.6
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant	260.3		—		29 years
Cook Plant, Unit 2 Baffle Bolts - Indiana	6.6		6.9		23 years
RTO Formation/Integration Costs	1.5		1.8		4 years
Other Regulatory Assets Approved for Recovery	1.0		0.8		various
Regulatory Assets Currently Not Earning a Return
Income Taxes, Net	246.8		255.0		29 years
Pension and OPEB Funded Status	126.4		107.8		12 years
Cook Plant Nuclear Refueling Outage Levelization	26.8		38.0		3 years
Unamortized Loss on Reacquired Debt	12.0		13.3		17 years
Postemployment Benefits	10.7		10.0		5 years
Peak Demand Reduction/Energy Efficiency	10.6		16.6		2 years
Medicare Subsidy	9.2		10.2		9 years
Litigation Settlement - Indiana	8.6		9.5		10 years
Capacity Costs - Indiana	7.5		25.1		1 year
Off-system Sales Margin Sharing - Indiana	6.8		—		2 years
PJM Expense - Indiana	4.1		21.9		2 years
Unrealized Loss on Forward Commitments	3.2		0.5		2 years
Storm Related Costs - Indiana	1.8		—		1 year
Deferred Cook Plant Life Cycle Management Project Costs - Indiana	—		2.2
Deferred Restructuring Costs - Michigan	—		1.2
Other Regulatory Assets Approved for Recovery	1.1		1.8		various
Total Regulatory Assets Approved for Recovery	745.0		522.6
Total Noncurrent Regulatory Assets	$	804.3	$	536.2

113

	I&M
	December 31,				Remaining Refund Period
Regulatory Liabilities:	2015		2014
	(in millions)
Current Regulatory Liabilities
Over-recovered Fuel Costs - pays a return	$	0.3	$	—	1 year
Over-recovered Fuel Costs - does not pay a return	—		7.1
Total Current Regulatory Liabilities	$	0.3	$	7.1
Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Not Paying a Return
Other Regulatory Liabilities Pending Final Regulatory Determination	$	—	$	0.1
Total Regulatory Liabilities Pending Final Regulatory Determination	—		0.1
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	350.6		378.5		(a)
Regulatory Liabilities Currently Not Paying a Return
Excess Asset Retirement Obligations for Nuclear Decommissioning Liability	636.5		694.9		(b)
Spent Nuclear Fuel Liability	43.4		43.5		(b)
Deferred Investment Tax Credits	35.0		38.3		21 years
Unrealized Gain on Forward Commitments	7.1		19.6		2 years
River Transportation Division Expenses	1.9		5.3		1 year
Off-system Sales Margin Sharing - Indiana	—		19.4
Other Regulatory Liabilities Approved for Payment	1.7		0.1		various
Total Regulatory Liabilities Approved for Payment	1,076.2		1,199.6
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	1,076.2	$	1,199.7

(a) Relieved as removal costs are incurred.

(b) Relieved when plant is decommissioned.

114

	OPCo
	December 31,				Remaining Recovery Period
Regulatory Assets:	2015		2014
	(in millions)
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Not Earning a Return
Ormet Special Rate Recovery Mechanism	$	—	$	10.5
gridSMART ® Costs	1.3		—
Total Regulatory Assets Pending Final Regulatory Approval	1.3		10.5
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Capacity Deferral	358.7		422.1		3 years
Phase-In Recovery Rider	304.5		377.5		3 years
Distribution Decoupling	37.5		35.1		2 years
Transmission Cost Recovery Rider	12.3		27.9		1 year
RTO Formation/Integration Costs	3.1		3.7		4 years
Economic Development Rider	—		4.1
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	219.4		195.4		12 years
Income Taxes, Net	129.0		137.5		31 years
Distribution Investment Rider	12.3		9.9		2 years
Unamortized Loss on Reacquired Debt	10.4		11.7		23 years
Medicare Subsidy	9.3		10.3		9 years
Postemployment Benefits	7.3		6.1		5 years
gridSMART® Costs	4.5		15.9		2 years
Partnership with Ohio Contribution	2.4		0.4		3 years
Storm Related Costs	0.1		15.2		1 year
Peak Demand Reduction/Energy Efficiency	—		29.1
Enhanced Service Reliability Plan	—		6.5
Other Regulatory Assets Approved for Recovery	0.9		—		various
Total Regulatory Assets Approved for Recovery	1,111.7		1,308.4
Total Noncurrent Regulatory Assets	$	1,113.0	$	1,318.9

115

	OPCo
	December 31,				Remaining Refund Period
	2015		2014
Regulatory Liabilities:	(in millions)
Current Regulatory Liabilities
Over-recovered Fuel Costs - does not pay a return	$	27.6	$	46.3	1 year
Total Current Regulatory Liabilities	$	27.6	$	46.3
Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Not Paying a Return
Provision for Regulatory Loss	$	40.6	$	35.2
Other Regulatory Liabilities Pending Final Regulatory Determination	0.2		0.4
Total Regulatory Liabilities Pending Final Regulatory Determination	40.8		35.6
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	422.3		423.2		(a)
Economic Development Rider	5.0		—		2 years
Basic Transmission Cost Rider	4.9		—		2 years
Deferred Investment Tax Credits	—		0.1
Regulatory Liabilities Currently Not Paying a Return
Unrealized Gain on Forward Commitments	15.3		47.3		17 years
Regulatory Settlement	9.0		—		2 years
Enhanced Service Reliability Plan	8.0		—		2 years
Deferred Asset Phase-In Rider	5.1		7.1		5 years
Peak Demand Reduction/Energy Efficiency	1.5		—		2 years
Storm Related Costs	1.3		—		1 year
Low Income Customers/Economic Recovery	1.0		1.3		1 year
Other Regulatory Liabilities Approved for Payment	—		0.1
Total Regulatory Liabilities Approved for Payment	473.4		479.1
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	514.2	$	514.7

(a)    Relieved as removal costs are incurred.

116

	PSO
	December 31,				Remaining Recovery Period
	2015		2014
Regulatory Assets:	(in millions)
Current Regulatory Assets
Under-recovered Fuel Costs -earns a return	$	—	$	35.7
Total Current Regulatory Assets	$	—	$	35.7
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Not Earning a Return
Storm Related Costs	$	12.3	$	16.6
Other Regulatory Assets Pending Final Regulatory Approval	1.1		1.1
Total Regulatory Assets Pending Final Regulatory Approval	13.4		17.7
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Meter Replacement Costs	35.8		—		11 years
Red Rock Generating Facility	9.3		9.5		41 years
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	95.1		89.7		12 years
Storm Related Costs	15.4		—		4 years
Peak Demand Reduction/Energy Efficiency	11.8		9.2		2 years
Deferred System Reliability Rider Expenses	9.9		8.3		1 year
Unamortized Loss on Reacquired Debt	6.8		8.0		17 years
Income Taxes, Net	6.1		1.9		35 years
Vegetation Management	4.5		2.9		1 year
Medicare Subsidy	4.4		4.9		9 years
Rate Case Expenses	1.2		—		2 years
Deferral of Major Generation Overhauls	0.7		1.3		2 years
Other Regulatory Assets Approved for Recovery	0.4		0.9		various
Total Regulatory Assets Approved for Recovery	201.4		136.6
Total Noncurrent Regulatory Assets	$	214.8	$	154.3

117

	PSO
	December 31,				Remaining Refund Period
	2015		2014
Regulatory Liabilities:	(in millions)
Current Regulatory Liabilities
Over-recovered Fuel Costs - pays a return	$	76.1	$	—	1 year
Total Current Regulatory Liabilities	$	76.1	$	—
Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Not Paying a Return
Advanced Metering Costs	$	—	$	3.9
Other Regulatory Liabilities Pending Final Regulatory Determination	—		0.3
Total Regulatory Liabilities Pending Final Regulatory Determination	—		4.2
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	275.5		275.4		(a)
Regulatory Liabilities Currently Not Paying a Return
Deferred Investment Tax Credits	46.3		46.9		26 years
Advanced Metering Costs	11.4		—		1 year
Base Plan Funding Costs	1.3		1.4		2 years
Base Load Purchase Power Contract	—		6.1
Other Regulatory Liabilities Approved for Payment	0.6		0.5		various
Total Regulatory Liabilities Approved for Payment	335.1		330.3
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	335.1	$	334.5

(a) Relieved as removal costs are incurred.

118

	SWEPCo
	December 31,				Remaining Recovery Period
	2015		2014
Regulatory Assets:	(in millions)
Current Regulatory Assets
Under-recovered Fuel Costs - earns a return	$	4.1	$	24.0	1 year
Total Current Regulatory Assets	$	4.1	$	24.0
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Not Earning a Return
Shipe Road Transmission Project - FERC	$	3.1	$	2.3
Asset Retirement Obligation - Arkansas, Louisiana	1.7		1.1
Rate Case Expense - Texas	0.3		8.1
Other Regulatory Assets Pending Final Regulatory Approval	0.8		0.6
Total Regulatory Assets Pending Final Regulatory Approval	5.9		12.1
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Acquisition of Valley Electric Membership Corporation (VEMCO)	—		1.8
Other Regulatory Assets Approved for Recovery	0.2		0.1		various
Regulatory Assets Currently Not Earning a Return
Income Taxes, Net	271.9		254.9		31 years
Pension and OPEB Funded Status	108.9		99.9		12 years
Rate Case Expense - Texas	6.8		—		3 years
Unamortized Loss on Reacquired Debt	6.0		7.0		28 years
Unrealized Loss on Forward Commitments	5.5		1.1		2 years
Medicare Subsidy	4.8		5.3		9 years
Deferred Restructuring Costs - Louisiana	3.5		5.1		3 years
Peak Demand Reduction/Energy Efficiency	1.0		2.2		2 years
Vegetation Management Program - Louisiana	—		2.5
Other Regulatory Assets Approved for Recovery	1.3		1.6		various
Total Regulatory Assets Approved for Recovery	409.9		381.5
Total Noncurrent Regulatory Assets	$	415.8	$	393.6

119

	SWEPCo
	December 31,				Remaining Refund Period
	2015		2014
Regulatory Liabilities:	(in millions)
Current Regulatory Liabilities
Over-recovered Fuel Costs - pays a return	$	8.4	$	—	1 year
Total Current Regulatory Liabilities	$	8.4	$	—
Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	$	396.8	$	384.3	(a)
Refundable Construction Financing Costs - Louisiana	37.4		58.2		3 years
Excess Earnings - Texas	2.7		2.8		38 years
Generation Recovery Rider Costs - Arkansas	1.5		1.7		2 years
Regulatory Liabilities Currently Not Paying a Return
Deferred Investment Tax Credits	8.5		9.8		15 years
Other Regulatory Liabilities Approved for Payment	1.9		1.7		various
Total Regulatory Liabilities Approved for Payment	448.8		458.5
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	448.8	$	458.5

(a) Relieved as removal costs are incurred.

120

6.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are subject to certain claims and legal actions arising in the ordinary course of business.  In addition, the Registrants 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 the Registrants cannot be predicted.  Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.

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.

COMMITMENTS

Construction and Commitments

The AEP System has substantial construction commitments to support its operations and environmental investments.  In managing the overall construction program and in the normal course of business, AEP subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. Fuel, materials, supplies, services and property, plant and equipment are also purchased under contract as part of the normal course of business.  Certain supply contracts contain penalty provisions for early termination.

In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2015:

Contractual Commitments - AEP	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	2,038.0	$	2,442.7	$	1,723.6	$	1,072.6	$	7,276.9
Energy and Capacity Purchase Contracts	203.0		431.5		437.1		1,961.7		3,033.3
Construction Contracts for Capital Assets (b)	178.6		—		—		—		178.6
Total	$	2,419.6	$	2,874.2	$	2,160.7	$	3,034.3	$	10,488.8

Contractual Commitments - APCo	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	447.4	$	585.8	$	486.8	$	244.8	$	1,764.8
Energy and Capacity Purchase Contracts	33.0		67.3		69.8		473.5		643.6
Construction Contracts for Capital Assets (b)	19.5		—		—		—		19.5
Total	$	499.9	$	653.1	$	556.6	$	718.3	$	2,427.9

Contractual Commitments - I&M	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	394.2	$	349.9	$	252.2	$	286.4	$	1,282.7
Energy and Capacity Purchase Contracts	108.1		230.1		236.0		613.9		1,188.1
Construction Contracts for Capital Assets (b)	8.8		—		—		—		8.8
Total	$	511.1	$	580.0	$	488.2	$	900.3	$	2,479.6

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Contractual Commitments - OPCo	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Energy and Capacity Purchase Contracts	$	27.0	$	54.8	$	56.2	$	479.9	$	617.9
Construction Contracts for Capital Assets (b)	4.7		—		—		—		4.7
Total	$	31.7	$	54.8	$	56.2	$	479.9	$	622.6

Contractual Commitments - PSO	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	123.7	$	86.8	$	41.8	$	41.8	$	294.1
Energy and Capacity Purchase Contracts	83.6		182.2		181.9		369.7		817.4
Construction Contracts for Capital Assets (b)	1.8		—		—		—		1.8
Total	$	209.1	$	269.0	$	223.7	$	411.5	$	1,113.3

Contractual Commitments - SWEPCo	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	198.5	$	136.8	$	78.6	$	69.8	$	483.7
Energy and Capacity Purchase Contracts	27.3		66.0		67.7		204.6		365.6
Construction Contracts for Capital Assets (b)	4.8		—		—		—		4.8
Total	$	230.6	$	202.8	$	146.3	$	274.4	$	854.1

(a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.

(b) Represents only capital assets for which there are signed contracts.  Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs.

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 (Applies to AEP, APCo, I&M and OPCo)

Standby letters of credit are entered into with third parties.  These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

AEP has two revolving credit facilities totaling $3.5 billion, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries.  As of December 31, 2015, AEP’s maximum future payments for letters of credit issued under the revolving credit facilities were $23 million with maturities ranging from February 2016 to December 2016. In January 2016, the letter of credit maturing in February 2016 was replaced with a new letter of credit expiring in January 2017.

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An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under three uncommitted facilities totaling $225 million.  As of December 31, 2015, the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows:

Company	Amount		Maturity
	(in millions)
AEP	$	124.6	June 2016 to December 2016
OPCo	4.2		September 2016

The Registrants have $477 million of variable rate Pollution Control Bonds supported by $482 million of bilateral letters of credit as follows:

Company	Pollution Control Bonds		Bilateral Letters of Credit			Maturity of Bilateral Letters of Credit
	(in millions)
AEP	$	476.7	$	482.1	(a)	March 2016 to July 2017
APCo	229.7		232.3		(a)	March 2016 to March 2017
I&M	77.0		77.9			March 2017

(a) In January 2016, $76 million of bilateral letters of credit maturing in March 2016 were cancelled.

Guarantees of Third-Party Obligations (Applies to AEP and 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 December 31, 2015, SWEPCo has collected approximately $65 million through a rider for final mine closure and reclamation costs, of which $15 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $50 million is recorded in Asset Retirement Obligations on SWEPCo’s balance sheet.

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

The Registrants 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 December 31, 2015, 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 AEP companies related to power purchase and sale activity.  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.

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Lease Obligations

Certain Registrants lease certain equipment under master lease agreements.  See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for disclosure of lease residual value guarantees.

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, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials.  The Registrants currently incur costs to dispose of these substances safely.

Superfund addresses clean-up of hazardous substances that are released to the environment.  The Federal EPA administers the clean-up programs.  Several states enacted similar laws.  As of December 31, 2015, APCo and OPCo are named as a Potentially Responsible Party (PRP) for one site and three sites, respectively, by the Federal EPA for which alleged liability is unresolved.  There are nine additional sites for which APCo, I&M, OPCo, SWEPCo and other AEP subsidiaries received information requests which could lead to PRP designation.  I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph.  SWEPCo has also been named potentially liable at one site under state law.  In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories.  Liability has been resolved for a number of sites with no significant effect on net income.

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. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of December 31, 2015, I&M’s accrual for all of these sites is $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 sites or changes in the scope of remediation.  Management cannot predict the amount of additional cost, if any.

Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability.  Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous.  Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises.  At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M sites discussed above.

NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M)

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

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Decommissioning and Low Level Waste Accumulation Disposal

The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program.  Decommissioning costs are accrued over the service life of the Cook Plant.  The most recent decommissioning cost study was performed in 2015.  According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste is $1.6 billion in 2015 nondiscounted dollars, with additional ongoing costs of $5 million per year for post decommissioning storage of SNF and an eventual cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates.  The amounts recovered in rates were $9 million, $9 million and $10 million for the years ended December 31, 2015, 2014 and 2013, respectively.  Decommissioning costs recovered from customers are deposited in external trusts.

As of December 31, 2015 and 2014, the total decommissioning trust fund balance was $1.8 billion and $1.8 billion, respectively.  Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers.  The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability.

I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant.  However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.

SNF Disposal

The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal.  A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant is being collected from customers and remitted to the U.S. Treasury.  This fee was terminated in May 2014. As of December 31, 2015 and 2014, fees and related interest of $266 million and $266 million, respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $309 million and $309 million, respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts.  I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.

In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage.  Under the settlement agreement, I&M received $13 million, $22 million and $31 million in 2015, 2014 and 2013, respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016.  The proceeds reduced costs for dry cask storage.  As of December 31, 2015, I&M has deferred $6 million in Prepayments and Other Current Assets and $21 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement.

See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.

Nuclear Incident Liability

I&M carries insurance coverage for a nuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion.  Insurance coverage for a nonnuclear incident at the Cook Plant is $1.7 billion.  Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage.  I&M utilizes industry mutual insurers for the placement of this insurance coverage.  Participation in this mutual insurance requires a contingent financial obligation of up to $49 million for I&M which is assessable if the insurer’s financial resources would be inadequate to pay for losses.

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The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $13.5 billion and covers any incident at a licensed reactor in the U.S.  Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage.  In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $127 million on each licensed reactor in the U.S. payable in annual installments of $19 million.  As a result, I&M could be assessed $255 million per nuclear incident payable in annual installments of $38 million.  The number of incidents for which payments could be required is not limited.

In the event of an incident of a catastrophic nature, I&M is initially covered for the first $375 million through commercially available insurance.  The next level of liability coverage of up to $13.1 billion would be covered by claims made under the Price-Anderson Act.  If the liability were in excess of amounts recoverable from insurance and retrospective claim payments made under the Price-Anderson Act, I&M would seek to recover those amounts from customers through rate increases.  In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition.

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles.  The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions.  Covered property generally includes power plants, substations, facilities and inventories.  Excluded property generally includes transmission and distribution lines, poles and towers.  The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrants.  Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers.

See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance.

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant.  Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation (Applies to AEP and 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.  In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiff’s claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiff

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subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiff’s motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. Management will continue to defend against the remaining claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Natural Gas Markets Lawsuits (Applies to AEP)

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.  AEP settled, received summary judgment or was 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.  Defendants in these cases, including AEP, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue. AEP also subsequently filed a separate petition with the U.S. Supreme Court seeking review of the personal jurisdiction issue. In July 2014, the U.S. Supreme Court granted the defendants’ previously filed petition for further review with the U.S. Supreme Court on the preemption issue. Oral argument occurred in January 2015. In April 2015, the U.S. Supreme Court affirmed the judgment of the U.S. Court of Appeals for the Ninth Circuit on the preemption issue, holding that the plaintiffs’ state antitrust claims were not preempted by the Natural Gas Act. The U.S. Supreme Court denied AEP’s petition for review of the personal jurisdiction issue shortly thereafter. The cases were remanded to the district court for further proceedings. There are four pending cases, of which three are class actions and one is a single plaintiff case. A tentative settlement has been reached in the three class actions. This settlement, once finalized, will be subject to court approval. Management will continue to defend the remaining case. Management is unable to determine the amount of potential additional loss that is reasonably possible of occurring.

Wage and Hours Lawsuit (Applies to AEP and PSO)

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 were 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.  Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. In January 2016, the plaintiffs’ lead counsel filed a motion to withdraw from the case and the motion was denied by the court. Subsequently, a motion to dismiss without prejudice was filed on behalf of 35 named plaintiffs. In February 2016, PSO filed a motion for summary judgment. Management will continue to defend the case. Management does not believe a loss is probable. If there is an unfavorable outcome contrary to expectations, management estimates possible losses of up to $30 million.

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National Do Not Call Registry Lawsuit (Applies to AEP)

In May 2014, AEP Energy was served with a complaint filed in the U.S. District Court for the Northern District of Illinois, alleging violations of the Telephone Consumer Protection Act (TCPA). The plaintiff alleges that he received telemarketing calls on behalf of AEP Energy despite having registered his telephone number on the National Do Not Call Registry. Plaintiff seeks to represent a class of persons who allegedly received such calls. Plaintiff seeks statutory damages under the TCPA on behalf of himself and the alleged class as well as injunctive relief. As a result of a mediation held in October 2014, the parties reached an agreement in principle, subject to final documentation and preliminary and final court approval. The court granted final approval of the settlement in September 2015 and terminated the case in November 2015. The settlement had an immaterial impact to AEP’s financial statements.

Gavin Landfill Litigation (Applies to AEP and OPCo)

In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill.  The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors.  Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims.  The plaintiffs seek compensatory and punitive damages, as well as medical monitoring.  In September 2014, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Management appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel rather than back to the Mason County, West Virginia Circuit Court. Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

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7.  DISPOSITIONS AND IMPAIRMENTS

The disclosures in this note apply to all Registrants unless indicated otherwise.

DISPOSITIONS

2015

AEPRO (Corporate and Other) (Applies to AEP)

In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015 and resulted in a net gain of $253 million that was recorded in Income from Discontinued Operations, Net of Tax, on the statement of income. AEP received net cash proceeds from the sale of $491 million, which were immediately available for use in AEP’s continuing operations. The cash proceeds of $539 million were recorded in Discontinued Investing Activities on the statement of cash flows. These proceeds were reduced by a make whole payment on the extinguishment of AEPRO long-term debt of $32 million, which was recorded in Discontinued Financing Activities, and transaction costs of $16 million, which were recorded in Discontinued Operating Activities, on the statement of cash flows. The nonaffiliated party acquired AEPRO by purchasing all of the common stock of AEP Resources, Inc., the parent company of AEPRO.  The nonaffiliated party assumed certain assets and liabilities of AEPRO, excluding the equity method investment in IMT, pension and benefit assets and liabilities and debt obligations. Prior to the closing of the sale, AEP retired the debt obligations of AEPRO. AEP retained ownership of its captive barge fleet that delivers coal to the company’s regulated coal-fueled power plant units owned or leased by AEGCo, APCo, I&M, KPCo and WPCo.  AEP signed a contract with the nonaffiliated party to dispatch and schedule its captive barge fleet for the company’s regulated coal-fueled power plant units.  AEP also has a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2016.  

In the third quarter of 2015, AEPRO was determined to be discontinued operations and subsequently classified as held for sale. The assets and liabilities were classified as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on AEP’s balance sheet as of December 31, 2014 and as shown in the following table:

	December 31, 2014
Assets:	(in millions)
Accounts Receivable	$	90.6
Property, Plant and Equipment – Net	482.3
Other Classes of Assets That Are Not Major	52.0
Total Assets from Discontinued Operations on the Balance Sheet	$	624.9
Liabilities:
Long-term Debt	$	83.2
Obligations Under Capital Leases	189.0
Other Classes of Liabilities That Are Not Major	162.6
Total Liabilities from Discontinued Operations on the Balance Sheet	$	434.8

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Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of income for the years ended December 31, 2015, 2014 and 2013 as shown in the following table:

	Years Ended December 31,
	2015			2014			2013
	(in millions)
Other Revenues	$	447.1		$	641.6		$	543.6
Other Operation Expense	321.3			459.5			455.7
Maintenance Expense	21.5			32.6			15.7
Depreciation and Amortization Expense	26.9			31.5			30.5
Taxes Other Than Income Taxes	10.6			14.2			10.0
Total Expenses	380.3			537.8			511.9
Other Income (Expense)	(16.9		)	(17.1		)	(15.5		)
Pretax Income of Discontinued Operations	49.9			86.7			16.2
Income Tax Expense	19.4			39.0			5.9
Equity Earnings of Unconsolidated Subsidiaries	(0.1		)	(0.2		)	—
Income from Discontinued Operations of AEPRO	30.4			47.5			10.3
Gain on Sale of Discontinued Operations	240.1			—			—
Income Tax Expense (Benefit)	(13.2		)	—			—
Gain on Sale of Discontinued Operations, Net of Tax	253.3			—			—
Total Income on Discontinued Operations as Presented on the Statements of Income	$	283.7		$	47.5		$	10.3

Muskingum River Plant (Generation & Marketing segment) (Applies to AEP)

In August 2015, AGR sold its retired Muskingum River Plant site including its associated Asset Retirement Obligations (ARO) to a nonaffiliated party.  AGR paid $48 million and the nonaffiliated party took ownership of the Muskingum River Plant site assets and assumed responsibility for environmental liabilities and ARO, including ash pond closure, asbestos abatement and decommissioning and demolition.  As a result of the sale, a net gain of $32 million was recognized and recorded in Other Operation on the statement of income.  The cash paid was recorded in Operating Activities on the statements of cash flows.  

2013

Conesville Coal Preparation Company (Transmission and Distribution Utilities segment) (Applies to AEP and OPCo)

In April 2013, OPCo closed on the sale of its Conesville Coal Preparation Company.  This sale did not have a significant impact on OPCo’s financial statements.

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IMPAIRMENTS

2013

Amos Plant, Unit 3 (Vertically Integrated Utilities segment) (Applies to AEP and APCo)

In July 2013, the Virginia SCC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax.  The Virginia jurisdictional share of the reduced price was approximately $39 million.  As a result of the Virginia order, in the fourth quarter of 2013, management recorded a pretax impairment of $39 million in Asset Impairments and Other Related Charges on the statement of income.  No impairment was recorded for the West Virginia jurisdictional share as these amounts were approved for recovery in the 2014 West Virginia Base Rate Case.

Big Sandy Plant, Unit 2 FGD Project (Vertically Integrated Utilities segment) (Applies to AEP)

In the third quarter of 2013, KPCo recorded a pretax write-off of $33 million in Asset Impairments and Other Related Charges on the statement of income primarily related to the Big Sandy Plant, Unit 2 FGD project as disallowed by the KPSC.  

Muskingum River Plant, Unit 5 (Generation & Marketing segment) (Applies to AEP and OPCo)

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

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8.  BENEFIT PLANS

The disclosures in this note apply to all Registrants unless indicated otherwise.

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1.

AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans.  Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan.  AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees.

Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same.  This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant.

The Registrants recognize the funded status associated with defined benefit pension and OPEB plans in the balance sheets.  Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance.  The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost.  The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery.  The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

Actuarial Assumptions for Benefit Obligations

The weighted-average assumptions as of December 31 of each year used in the measurement of the Registrants’ benefit obligations are shown in the following tables:

	Pension Plans				Other Postretirement Benefit Plans
Assumption	2015		2014		2015		2014
Discount Rate	4.30	%	4.00	%	4.30	%	4.00	%

	Pension Plans
Assumption – Rate of Compensation Increase (a)	2015		2014
AEP	4.80	%	4.80	%
APCo	4.45	%	4.45	%
I&M	4.75	%	4.80	%
OPCo	4.85	%	4.80	%
PSO	4.85	%	4.80	%
SWEPCo	4.80	%	4.80	%

(a) Rates are for base pay only.  In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

A duration-based method is used to determine the discount rate for the plans.  A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.  The discount rate is the same for each Registrant.

132

For 2015, the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above.  The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan.

Actuarial Assumptions for Net Periodic Benefit Costs

The weighted-average assumptions as of January 1 of each year used in the measurement of each Registrants’ benefit costs are shown in the following tables:

	Pension Plans						Other Postretirement Benefit Plans
Assumptions	2015		2014		2013		2015		2014		2013
Discount Rate	4.00	%	4.70	%	3.95	%	4.00	%	4.70	%	3.95	%
Expected Return on Plan Assets	6.00	%	6.00	%	6.50	%	6.75	%	6.75	%	7.00	%

	Pension Plans
Assumption – Rate of Compensation Increase (a)	2015		2014		2013
AEP	4.80	%	4.85	%	4.95	%
APCo	4.45	%	4.60	%	4.70	%
I&M	4.80	%	4.90	%	5.00	%
OPCo	4.80	%	5.00	%	5.00	%
PSO	4.80	%	4.90	%	4.90	%
SWEPCo	4.80	%	4.85	%	4.75	%

(a) Rates are for base pay only.  In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation and current prospects for economic growth.  The expected return on plan assets is the same for each Registrant.

The health care trend rate assumptions as of January 1 of each year used for OPEB plans measurement purposes are shown below:

Health Care Trend Rates	2015		2014
Initial	6.25	%	6.50	%
Ultimate	5.00	%	5.00	%
Year Ultimate Reached	2020		2020

Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans.  A 1% change in assumed health care cost trend rates would have the following effects:

	AEP			APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost:
1% Increase	$	3.7		$	0.8		$	0.3		$	0.3		$	0.1		$	0.2
1% Decrease	(3.0		)	(0.6		)	(0.3		)	(0.2		)	(0.1		)	(0.1		)
Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation:
1% Increase	$	70.5		$	15.2		$	6.8		$	6.9		$	3.2		$	3.5
1% Decrease	(57.4		)	(12.3		)	(5.6		)	(5.7		)	(2.6		)	(2.9		)

133

Significant Concentrations of Risk within Plan Assets

In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets.  The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits.  The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment.  Management monitors the plans to control security diversification and ensure compliance with the investment policy.  As of December 31, 2015, the assets were invested in compliance with all investment limits.  See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details.

Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2015 and 2014

The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status as of December 31.  The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.

AEP	Pension Plans						Other Postretirement Benefit Plans
	2015			2014			2015			2014
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	5,224.9		$	4,841.7		$	1,439.0		$	1,455.5
Service Cost	93.5			71.9			12.2			14.2
Interest Cost	205.3			221.0			56.8			67.2
Actuarial (Gain) Loss	(200.6		)	387.0			37.2			(14.4		)
Benefit Payments	(330.2		)	(296.7		)	(128.7		)	(133.7		)
Participant Contributions	—			—			33.3			41.9
Medicare Subsidy	—			—			0.8			8.3
Benefit Obligation as of December 31,	$	4,992.9		$	5,224.9		$	1,450.6		$	1,439.0
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	4,967.5		$	4,711.2		$	1,693.9		$	1,698.7
Actual Gain (Loss) on Plan Assets	32.4			474.2			(34.0		)	82.7
Company Contributions	97.9			78.8			12.9			4.3
Participant Contributions	—			—			33.3			41.9
Benefit Payments	(330.2		)	(296.7		)	(128.7		)	(133.7		)
Fair Value of Plan Assets as of December 31,	$	4,767.6		$	4,967.5		$	1,577.4		$	1,693.9
Funded (Underfunded) Status as of December 31,	$	(225.3	)	$	(257.4	)	$	126.8		$	254.9

134

APCo	Pension Plans						Other Postretirement Benefit Plans
	2015			2014			2015			2014
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	702.8		$	663.2		$	267.1		$	279.9
Service Cost	8.7			7.0			1.1			1.4
Interest Cost	26.7			29.6			10.3			12.8
Actuarial (Gain) Loss	(41.4		)	41.7			2.5			(9.0		)
Benefit Payments	(43.4		)	(38.7		)	(24.7		)	(26.6		)
Participant Contributions	—			—			5.7			7.2
Medicare Subsidy	—			—			0.2			1.4
Benefit Obligation as of December 31,	$	653.4		$	702.8		$	262.2		$	267.1
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	642.3		$	628.0		$	280.6		$	284.8
Actual Gain (Loss) on Plan Assets	(5.7		)	44.0			(7.7		)	11.8
Company Contributions	10.0			9.0			2.8			3.4
Participant Contributions	—			—			5.7			7.2
Benefit Payments	(43.4		)	(38.7		)	(24.7		)	(26.6		)
Fair Value of Plan Assets as of December 31,	$	603.2		$	642.3		$	256.7		$	280.6
Funded (Underfunded) Status as of December 31,	$	(50.2	)	$	(60.5	)	$	(5.5	)	$	13.5

I&M	Pension Plans						Other Postretirement Benefit Plans
	2015			2014			2015			2014
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	617.9		$	574.7		$	161.7		$	166.5
Service Cost	12.9			10.0			1.6			1.9
Interest Cost	24.5			26.3			6.4			7.6
Actuarial (Gain) Loss	(28.4		)	38.5			7.7			(4.9		)
Benefit Payments	(35.4		)	(31.6		)	(15.2		)	(15.7		)
Participant Contributions	—			—			4.0			5.2
Medicare Subsidy	—			—			0.1			1.1
Benefit Obligation as of December 31,	$	591.5		$	617.9		$	166.3		$	161.7
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	591.7		$	559.1		$	202.4		$	206.2
Actual Gain (Loss) on Plan Assets	(0.9		)	55.3			(2.3		)	6.6
Company Contributions	14.6			8.9			0.1			0.1
Participant Contributions	—			—			4.0			5.2
Benefit Payments	(35.4		)	(31.6		)	(15.2		)	(15.7		)
Fair Value of Plan Assets as of December 31,	$	570.0		$	591.7		$	189.0		$	202.4
Funded (Underfunded) Status as of December 31,	$	(21.5	)	$	(26.2	)	$	22.7		$	40.7

135

OPCo	Pension Plans						Other Postretirement Benefit Plans
	2015			2014			2015			2014
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	526.3		$	523.6		$	164.7		$	171.2
Service Cost	6.7			5.2			0.9			1.0
Interest Cost	20.3			22.1			6.4			7.6
Actuarial (Gain) Loss	(19.5		)	6.8			8.7			(4.3		)
Benefit Payments	(36.3		)	(31.4		)	(16.3		)	(17.4		)
Participant Contributions	—			—			4.3			5.6
Medicare Subsidy	—			—			(0.1		)	1.0
Benefit Obligation as of December 31,	$	497.5		$	526.3		$	168.6		$	164.7
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	498.5		$	501.6		$	206.2		$	212.0
Actual Gain (Loss) on Plan Assets	2.2			21.7			(2.6		)	6.0
Company Contributions	7.7			6.6			—			—
Participant Contributions	—			—			4.3			5.6
Benefit Payments	(36.3		)	(31.4		)	(16.3		)	(17.4		)
Fair Value of Plan Assets as of December 31,	$	472.1		$	498.5		$	191.6		$	206.2
Funded (Underfunded) Status as of December 31,	$	(25.4	)	$	(27.8	)	$	23.0		$	41.5

PSO	Pension Plans						Other Postretirement Benefit Plans
	2015			2014			2015			2014
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	285.4		$	260.7		$	76.7		$	77.8
Service Cost	6.4			5.2			0.7			0.8
Interest Cost	10.9			12.1			3.0			3.6
Actuarial (Gain) Loss	(17.9		)	25.7			2.4			(1.0		)
Benefit Payments	(19.4		)	(18.3		)	(7.1		)	(7.3		)
Participant Contributions	—			—			1.9			2.3
Medicare Subsidy	—			—			0.1			0.5
Benefit Obligation as of December 31,	$	265.4		$	285.4		$	77.7		$	76.7
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	275.5		$	264.6		$	96.0		$	96.3
Actual Gain (Loss) on Plan Assets	0.1			24.6			(2.5		)	4.7
Company Contributions	5.9			4.6			—			—
Participant Contributions	—			—			1.9			2.3
Benefit Payments	(19.4		)	(18.3		)	(7.1		)	(7.3		)
Fair Value of Plan Assets as of December 31,	$	262.1		$	275.5		$	88.3		$	96.0
Funded (Underfunded) Status as of December 31,	$	(3.3	)	$	(9.9	)	$	10.6		$	19.3

136

SWEPCo	Pension Plans						Other Postretirement Benefit Plans
	2015			2014			2015			2014
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	298.2		$	270.6		$	85.0		$	87.0
Service Cost	8.3			6.6			0.8			1.0
Interest Cost	11.8			12.7			3.4			4.0
Actuarial (Gain) Loss	(16.2		)	27.5			2.1			(2.3		)
Benefit Payments	(19.3		)	(19.2		)	(7.4		)	(7.7		)
Participant Contributions	—			—			2.1			2.5
Medicare Subsidy	—			—			0.1			0.5
Benefit Obligation as of December 31,	$	282.8		$	298.2		$	86.1		$	85.0
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	290.2		$	279.0		$	106.4		$	107.7
Actual Gain (Loss) on Plan Assets	1.6			26.5			(3.3		)	3.9
Company Contributions	8.1			3.9			—			—
Participant Contributions	—			—			2.1			2.5
Benefit Payments	(19.3		)	(19.2		)	(7.4		)	(7.7		)
Fair Value of Plan Assets as of December 31,	$	280.6		$	290.2		$	97.8		$	106.4
Funded (Underfunded) Status as of December 31,	$	(2.2	)	$	(8.0	)	$	11.7		$	21.4

Amounts Recognized on the Balance Sheets as of December 31, 2015 and 2014

	Pension Plans						Other Postretirement Benefit Plans
	December 31,
AEP	2015			2014			2015			2014
	(in millions)
Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs	$	—		$	—		$	185.8		$	336.7
Other Current Liabilities – Accrued Short-term Benefit Liability	(6.3		)	(6.2		)	(3.3		)	(3.6		)
Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability	(219.0		)	(251.2		)	(55.7		)	(78.2		)
Funded (Underfunded) Status	$	(225.3	)	$	(257.4	)	$	126.8		$	254.9

	Pension Plans						Other Postretirement Benefit Plans
	December 31,
APCo	2015			2014			2015			2014
	(in millions)
Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs	$	—		$	—		$	30.8		$	56.5
Other Current Liabilities – Accrued Short-term Benefit Liability	—			—			(2.6		)	(2.9		)
Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability	(50.2		)	(60.5		)	(33.7		)	(40.1		)
Funded (Underfunded) Status	$	(50.2	)	$	(60.5	)	$	(5.5	)	$	13.5

137

	Pension Plans						Other Postretirement Benefit Plans
	December 31,
I&M	2015			2014			2015		2014
	(in millions)
Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs	$	—		$	—		$	22.7	$	40.7
Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability	(21.5		)	(26.2		)	—		—
Funded (Underfunded) Status	$	(21.5	)	$	(26.2	)	$	22.7	$	40.7

	Pension Plans						Other Postretirement Benefit Plans
	December 31,
OPCo	2015			2014			2015		2014
	(in millions)
Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs	$	—		$	—		$	23.0	$	41.5
Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability	(25.4		)	(27.8		)	—		—
Funded (Underfunded) Status	$	(25.4	)	$	(27.8	)	$	23.0	$	41.5

	Pension Plans						Other Postretirement Benefit Plans
	December 31,
PSO	2015			2014			2015		2014
	(in millions)
Employee Benefits and Pension Assets – Prepaid Benefit Costs	$	—		$	—		$	10.6	$	19.3
Other Current Liabilities – Accrued Short-term Benefit Liability	(0.2		)	(0.2		)	—		—
Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability	(3.1		)	(9.7		)	—		—
Funded (Underfunded) Status	$	(3.3	)	$	(9.9	)	$	10.6	$	19.3

	Pension Plans						Other Postretirement Benefit Plans
	December 31,
SWEPCo	2015			2014			2015		2014
	(in millions)
Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs	$	—		$	—		$	11.7	$	21.4
Other Current Liabilities – Accrued Short-term Benefit Liability	(0.1		)	(0.1		)	—		—
Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability	(2.1		)	(7.9		)	—		—
Funded (Underfunded) Status	$	(2.2	)	$	(8.0	)	$	11.7	$	21.4

138

Amounts Included in AOCI and Regulatory Assets as of December 31, 2015 and 2014

AEP	Pension Plans				Other Postretirement Benefit Plans
	December 31,
	2015		2014		2015			2014
Components	(in millions)
Net Actuarial Loss	$	1,546.1	$	1,611.4	$	577.4		$	419.9
Prior Service Cost (Credit)	3.3		5.5		(554.4		)	(623.5		)
Recorded as
Regulatory Assets	$	1,385.2	$	1,418.3	$	15.1		$	(148.5	)
Deferred Income Taxes	57.5		69.5		2.8			(19.3		)
Net of Tax AOCI	106.7		129.1		5.1			(35.8		)

APCo	Pension Plans				Other Postretirement Benefit Plans
	December 31,
	2015		2014		2015			2014
Components	(in millions)
Net Actuarial Loss	$	220.8	$	235.0	$	86.9		$	65.8
Prior Service Cost (Credit)	0.3		0.5		(80.6		)	(90.6		)
Recorded as
Regulatory Assets	$	218.3	$	232.8	$	(0.7	)	$	(20.3	)
Deferred Income Taxes	1.0		0.9		2.4			(1.6		)
Net of Tax AOCI	1.8		1.8		4.6			(2.9		)

I&M	Pension Plans				Other Postretirement Benefit Plans
	December 31,
	2015		2014		2015			2014
Components	(in millions)
Net Actuarial Loss	$	130.0	$	137.9	$	77.1		$	54.4
Prior Service Cost (Credit)	0.3		0.5		(75.7		)	(85.1		)
Recorded as
Regulatory Assets	$	125.3	$	134.1	$	1.1		$	(26.3	)
Deferred Income Taxes	1.8		1.5		0.1			(1.5		)
Net of Tax AOCI	3.2		2.8		0.2			(2.9		)

OPCo	Pension Plans				Other Postretirement Benefit Plans
	December 31,
	2015		2014		2015			2014
Components	(in millions)
Net Actuarial Loss	$	222.0	$	226.7	$	52.6		$	30.7
Prior Service Cost (Credit)	0.2		0.4		(55.4		)	(62.4		)
Recorded as
Regulatory Assets	$	222.2	$	227.1	$	(2.8	)	$	(31.7	)

139

PSO	Pension Plans				Other Postretirement Benefit Plans
	December 31,
	2015		2014		2015			2014
Components	(in millions)
Net Actuarial Loss	$	94.1	$	102.7	$	35.2		$	25.3
Prior Service Cost (Credit)	0.3		0.5		(34.5		)	(38.8		)
Recorded as
Regulatory Assets	$	94.4	$	103.2	$	0.7		$	(13.5	)

SWEPCo	Pension Plans				Other Postretirement Benefit Plans
	December 31,
	2015		2014		2015			2014
Components	(in millions)
Net Actuarial Loss	$	97.1	$	104.9	$	43.3		$	32.4
Prior Service Cost (Credit)	0.4		0.7		(41.6		)	(46.8		)
Recorded as
Regulatory Assets	$	97.5	$	105.6	$	1.2		$	(8.9	)
Deferred Income Taxes	—		—		0.2			(1.9		)
Net of Tax AOCI	—		—		0.3			(3.6		)

Components of the change in amounts included in AOCI and Regulatory Assets by Registrant during the years ended December 31, 2015 and 2014 are as follows:

AEP	Pension Plans						Other Postretirement Benefit Plans
	2015			2014			2015			2014
Components	(in millions)
Actuarial Loss During the Year	$	41.8		$	174.4		$	176.3		$	14.0
Amortization of Actuarial Loss	(107.1		)	(124.0		)	(18.8		)	(22.1		)
Amortization of Prior Service Credit (Cost)	(2.2		)	(2.5		)	69.1			69.0
Change for the Year Ended December 31,	$	(67.5	)	$	47.9		$	226.6		$	60.9

APCo	Pension Plans						Other Postretirement Benefit Plans
	2015			2014			2015			2014
Components	(in millions)
Actuarial (Gain) Loss During the Year	$	(0.3	)	$	31.6		$	24.7		$	(2.3	)
Amortization of Actuarial Loss	(13.9		)	(16.6		)	(3.6		)	(4.6		)
Amortization of Prior Service Credit (Cost)	(0.2		)	(0.2		)	10.0			10.1
Change for the Year Ended December 31,	$	(14.4	)	$	14.8		$	31.1		$	3.2

I&M	Pension Plans						Other Postretirement Benefit Plans
	2015			2014			2015			2014
Components	(in millions)
Actuarial Loss During the Year	$	4.7		$	14.2		$	24.7		$	1.9
Amortization of Actuarial Loss	(12.6		)	(14.6		)	(2.0		)	(2.4		)
Amortization of Prior Service Credit (Cost)	(0.2		)	(0.2		)	9.4			9.4
Change for the Year Ended December 31,	$	(8.1	)	$	(0.6	)	$	32.1		$	8.9

140

OPCo	Pension Plans						Other Postretirement Benefit Plans
	2015			2014			2015			2014
Components	(in millions)
Actuarial Loss During the Year	$	5.8		$	11.5		$	24.0		$	3.3
Amortization of Actuarial Loss	(10.5		)	(12.4		)	(2.1		)	(2.4		)
Amortization of Prior Service Credit (Cost)	(0.2		)	(0.2		)	7.0			6.9
Change for the Year Ended December 31,	$	(4.9	)	$	(1.1	)	$	28.9		$	7.8

PSO	Pension Plans						Other Postretirement Benefit Plans
	2015			2014			2015			2014
Components	(in millions)
Actuarial (Gain) Loss During the Year	$	(2.9	)	$	15.7		$	10.9		$	0.6
Amortization of Actuarial Loss	(5.7		)	(6.7		)	(1.0		)	(1.1		)
Amortization of Prior Service Credit (Cost)	(0.2		)	(0.3		)	4.3			4.3
Change for the Year Ended December 31,	$	(8.8	)	$	8.7		$	14.2		$	3.8

SWEPCo	Pension Plans						Other Postretirement Benefit Plans
	2015			2014			2015			2014
Components	(in millions)
Actuarial (Gain) Loss During the Year	$	(1.8	)	$	16.5		$	12.0		$	0.8
Amortization of Actuarial Loss	(6.0		)	(7.1		)	(1.1		)	(1.2		)
Amortization of Prior Service Credit (Cost)	(0.3		)	(0.3		)	5.2			5.2
Change for the Year Ended December 31,	$	(8.1	)	$	9.1		$	16.1		$	4.8

Pension and Other Postretirement Benefits Plans’ Assets

The fair value tables within Pension and Other Postretirement Benefits Plans’ Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries as of December 31, 2015 and 2014 using the percentages in the table below:

	Pension Plan				Other Postretirement Benefit Plans
Company	2015		2014		2015		2014
APCo	12.7	%	12.9	%	16.3	%	16.6	%
I&M	12.0	%	11.9	%	12.0	%	11.9	%
OPCo	9.9	%	10.0	%	12.1	%	12.2	%
PSO	5.5	%	5.5	%	5.6	%	5.7	%
SWEPCo	5.9	%	5.8	%	6.2	%	6.3	%

141

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2015:

Asset Class	Level 1		Level 2		Level 3		Other			Total			Year End Allocation
	(in millions)
Equities:
Domestic	$	315.7	$	—	$	—	$	—		$	315.7		6.6	%
International	402.3		—		—		—			402.3			8.4	%
Options	—		15.6		—		—			15.6			0.3	%
Real Estate Investment Trusts	4.0		—		—		—			4.0			0.1	%
Common Collective Trust – Global	—		369.7		—		—			369.7			7.8	%
Common Collective Trust – International	—		16.1		—		—			16.1			0.3	%
Subtotal – Equities	722.0		401.4		—		—			1,123.4			23.5	%
Fixed Income:
Common Collective Trust – Debt	—		34.2		—		—			34.2			0.7	%
United States Government and Agency Securities	—		421.9		—		—			421.9			8.9	%
Corporate Debt	—		1,983.2		—		—			1,983.2			41.6	%
Foreign Debt	—		421.4		0.1		—			421.5			8.8	%
State and Local Government	—		12.8		—		—			12.8			0.3	%
Other – Asset Backed	—		23.4		—		—			23.4			0.5	%
Subtotal – Fixed Income	—		2,896.9		0.1		—			2,897.0			60.8	%
Infrastructure	—		—		42.0		—			42.0			0.9	%
Real Estate	—		—		253.7		—			253.7			5.3	%
Alternative Investments	—		—		378.7		—			378.7			8.0	%
Securities Lending	—		263.0		—		—			263.0			5.5	%
Securities Lending Collateral (a)	—		—		—		(264.7		)	(264.7		)	(5.5	)%
Cash and Cash Equivalents	—		48.6		—		—			48.6			1.0	%
Other – Pending Transactions and Accrued Income (b)	—		—		—		25.9			25.9			0.5	%
Total	$	722.0	$	3,609.9	$	674.5	$	(238.8	)	$	4,767.6		100.0	%

(a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program.

(b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets:

	Foreign Debt		Infrastructure			Real Estate			Alternative Investments			Total Level 3
	(in millions)
Balance as of January 1, 2015	$	0.1	$	12.5		$	235.8		$	378.9		$	627.3
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date	—		(3.6		)	12.5			(25.9		)	(17.0		)
Relating to Assets Sold During the Period	—		0.3			23.8			37.6			61.7
Purchases and Sales	—		32.8			(18.4		)	(11.9		)	2.5
Transfers into Level 3	—		—			—			—			—
Transfers out of Level 3	—		—			—			—			—
Balance as of December 31, 2015	$	0.1	$	42.0		$	253.7		$	378.7		$	674.5

142

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2015:

Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities:
Domestic	$	465.1	$	—	$	—	$	—	$	465.1	29.5	%
International	484.3		—		—		—		484.3		30.7	%
Options	—		15.6		—		—		15.6		1.0	%
Common Collective Trust – Global	—		19.0		—		—		19.0		1.2	%
Common Collective Trust – International	—		12.6		—		—		12.6		0.8	%
Subtotal – Equities	949.4		47.2		—		—		996.6		63.2	%
Fixed Income:
Common Collective Trust – Debt	—		100.9		—		—		100.9		6.4	%
United States Government and Agency Securities	—		58.4		—		—		58.4		3.7	%
Corporate Debt	—		117.7		—		—		117.7		7.4	%
Foreign Debt	—		20.7		—		—		20.7		1.3	%
State and Local Government	—		4.2		—		—		4.2		0.3	%
Other – Asset Backed	—		8.4		—		—		8.4		0.5	%
Subtotal – Fixed Income	—		310.3		—		—		310.3		19.6	%
Trust Owned Life Insurance:
International Equities	—		28.3		—		—		28.3		1.8	%
United States Bonds	—		184.3		—		—		184.3		11.7	%
Subtotal – Trust Owned Life Insurance	—		212.6		—		—		212.6		13.5	%
Cash and Cash Equivalents	44.9		7.2		—		—		52.1		3.3	%
Other – Pending Transactions and Accrued Income (a)	—		—		—		5.8		5.8		0.4	%
Total	$	994.3	$	577.3	$	—	$	5.8	$	1,577.4	100.0	%

(a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

143

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2014:

Asset Class	Level 1		Level 2		Level 3		Other			Total			Year End Allocation
	(in millions)
Equities:
Domestic	$	588.6	$	—	$	—	$	—		$	588.6		11.9	%
International	502.2		—		—		—			502.2			10.1	%
Options	—		14.1		—		—			14.1			0.3	%
Real Estate Investment Trusts	54.3		—		—		—			54.3			1.1	%
Common Collective Trust – Global	—		377.0		—		—			377.0			7.6	%
Common Collective Trust – International	—		18.5		—		—			18.5			0.4	%
Subtotal – Equities	1,145.1		409.6		—		—			1,554.7			31.4	%
Fixed Income:
Common Collective Trust – Debt	—		30.2		—		—			30.2			0.6	%
United States Government and Agency Securities	—		449.8		—		—			449.8			9.0	%
Corporate Debt	—		1,799.5		—		—			1,799.5			36.2	%
Foreign Debt	—		400.5		0.1		—			400.6			8.1	%
State and Local Government	—		14.9		—		—			14.9			0.3	%
Other – Asset Backed	—		29.1		—		—			29.1			0.6	%
Subtotal – Fixed Income	—		2,724.0		0.1		—			2,724.1			54.8	%
Infrastructure	—		—		12.5		—			12.5			0.3	%
Real Estate	—		—		235.8		—			235.8			4.7	%
Alternative Investments	—		—		378.9		—			378.9			7.6	%
Securities Lending	—		219.8		—		—			219.8			4.4	%
Securities Lending Collateral (a)	—		—		—		(221.5		)	(221.5		)	(4.5	)%
Cash and Cash Equivalents	—		53.3		—		—			53.3			1.1	%
Other – Pending Transactions and Accrued Income (b)	—		—		—		9.9			9.9			0.2	%
Total	$	1,145.1	$	3,406.7	$	627.3	$	(211.6	)	$	4,967.5		100.0	%

(a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program.

(b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets:

	Foreign Debt		Infrastructure			Real Estate			Alternative Investments		Total Level 3
	(in millions)
Balance as of January 1, 2014	$	0.1	$	—		$	238.2		$	329.6	$	567.9
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date	—		(0.3		)	5.5			32.0		37.2
Relating to Assets Sold During the Period	—		0.1			19.0			15.8		34.9
Purchases and Sales	—		12.7			(26.9		)	1.5		(12.7		)
Transfers into Level 3	—		—			—			—		—
Transfers out of Level 3	—		—			—			—		—
Balance as of December 31, 2014	$	0.1	$	12.5		$	235.8		$	378.9	$	627.3

144

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2014:

Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities:
Domestic	$	466.1	$	—	$	—	$	—	$	466.1	27.5	%
International	566.6		—		—		—		566.6		33.5	%
Options	—		16.4		—		—		16.4		1.0	%
Common Collective Trust – Global	—		29.6		—		—		29.6		1.8	%
Subtotal – Equities	1,032.7		46.0		—		—		1,078.7		63.8	%
Fixed Income:
Common Collective Trust – Debt	—		103.7		—		—		103.7		6.1	%
United States Government and Agency Securities	—		71.1		—		—		71.1		4.2	%
Corporate Debt	—		125.5		—		—		125.5		7.4	%
Foreign Debt	—		21.3		—		—		21.3		1.3	%
State and Local Government	—		5.9		—		—		5.9		0.3	%
Other – Asset Backed	—		4.9		—		—		4.9		0.3	%
Subtotal – Fixed Income	—		332.4		—		—		332.4		19.6	%
Trust Owned Life Insurance:
International Equities	—		10.3		—		—		10.3		0.6	%
United States Bonds	—		212.1		—		—		212.1		12.5	%
Subtotal – Trust Owned Life Insurance	—		222.4		—		—		222.4		13.1	%
Cash and Cash Equivalents	46.8		9.6		—		—		56.4		3.3	%
Other – Pending Transactions and Accrued Income (a)	—		—		—		4.0		4.0		0.2	%
Total	$	1,079.5	$	610.4	$	—	$	4.0	$	1,693.9	100.0	%

(a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

Determination of Pension Expense

The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility.  This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return.

The accumulated benefit obligation for the pension plans is as follows:

Accumulated Benefit Obligation	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Qualified Pension Plan	$	4,757.1	$	641.4	$	571.3	$	484.1	$	252.0	$	267.7
Nonqualified Pension Plans	75.6		0.5		0.4		0.1		2.4		1.6
Total as of December 31, 2015	$	4,832.7	$	641.9	$	571.7	$	484.2	$	254.4	$	269.3
Accumulated Benefit Obligation	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Qualified Pension Plan	$	4,982.0	$	688.6	$	598.2	$	512.4	$	270.0	$	281.2
Nonqualified Pension Plans	76.0		0.5		0.5		0.1		2.8		1.8
Total as of December 31, 2014	$	5,058.0	$	689.1	$	598.7	$	512.5	$	272.8	$	283.0

145

For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans as of December 31, 2015 and 2014 were as follows:

	AEP			APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Projected Benefit Obligation	$	4,992.9		$	653.4		$	591.5		$	497.5		$	2.6		$	1.7
Accumulated Benefit Obligation	$	4,832.7		$	641.9		$	571.7		$	484.2		$	2.4		$	1.6
Fair Value of Plan Assets	4,767.6			603.2			570.0			472.1			—			—
Underfunded Accumulated Benefit Obligation as of December 31, 2015	$	(65.1	)	$	(38.7	)	$	(1.7	)	$	(12.1	)	$	(2.4	)	$	(1.6	)
	AEP			APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Projected Benefit Obligation	$	5,224.9		$	702.8		$	617.9		$	526.3		$	2.8		$	1.8
Accumulated Benefit Obligation	$	5,058.0		$	689.1		$	598.7		$	512.5		$	2.8		$	1.8
Fair Value of Plan Assets	4,967.5			642.3			591.7			498.5			—			—
Underfunded Accumulated Benefit Obligation as of December 31, 2014	$	(90.5	)	$	(46.8	)	$	(7.0	)	$	(14.0	)	$	(2.8	)	$	(1.8	)

Estimated Future Benefit Payments and Contributions

The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits.  For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan.   For OPEB plans, expected payments include the payment of unfunded benefits.  The following table provides the estimated contributions and payments by Registrant for 2016:

Company	Pension Plans		Other Postretirement Benefit Plans
	(in millions)
AEP	$	95.6	$	6.0
APCo	10.7		2.6
I&M	13.1		—
OPCo	7.5		—
PSO	5.7		—
SWEPCo	6.9		—

The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets.  The payments include the participants’ contributions to the plan for their share of the cost.  Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results.  The estimated payments for the pension benefits and OPEB are as follows:

Pension Plans	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2016	$	324.0	$	42.8	$	33.9	$	36.4	$	19.3	$	18.6
2017	335.5		43.2		35.6		36.0		20.2		20.2
2018	339.3		44.2		36.0		35.8		20.1		21.1
2019	348.7		44.6		38.6		36.1		20.9		21.8
2020	355.9		45.0		39.3		36.2		21.3		22.4
Years 2021 to 2025, in Total	1,844.3		232.3		213.1		174.3		109.1		120.2

146

Other Postretirement Benefit Plans: Benefit Payments	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2016	$	134.1	$	25.3	$	15.9	$	16.9	$	7.4	$	7.9
2017	136.7		25.4		16.2		17.1		7.6		8.1
2018	139.1		25.6		16.6		17.3		7.7		8.3
2019	140.3		25.3		16.8		17.3		7.9		8.4
2020	143.6		25.6		17.2		17.5		8.1		8.7
Years 2021 to 2025, in Total	749.7		127.9		90.4		87.6		42.7		47.6

Other Postretirement Benefit Plans: Medicare Subsidy Receipts	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2016	$	0.3	$	0.2	$	—	$	—	$	—	$	—
2017	0.3		0.2		—		—		—		—
2018	0.3		0.2		—		—		—		—
2019	0.3		0.2		—		—		—		—
2020	0.3		0.2		—		—		—		—
Years 2021 to 2025, in Total	1.8		1.1		—		—		—		—

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans for the years ended December 31, 2015, 2014 and 2013:

AEP	Pension Plans									Other Postretirement Benefit Plans
	Years Ended December 31,
	2015			2014			2013			2015			2014			2013
	(in millions)
Service Cost	$	93.5		$	71.9		$	69.2		$	12.2		$	14.2		$	22.9
Interest Cost	205.3			221.0			202.8			56.8			67.2			70.8
Expected Return on Plan Assets	(274.8		)	(261.6		)	(277.8		)	(111.0		)	(111.3		)	(106.6		)
Amortization of Prior Service Cost (Credit)	2.2			2.5			2.8			(69.1		)	(69.0		)	(69.0		)
Amortization of Net Actuarial Loss	107.1			124.0			183.1			18.8			22.1			64.7
Net Periodic Benefit Cost (Credit)	133.3			157.8			180.1			(92.3		)	(76.8		)	(17.2		)
Capitalized Portion	(48.4		)	(52.2		)	(56.4		)	33.5			25.3			5.4
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	84.9		$	105.6		$	123.7		$	(58.8	)	$	(51.5	)	$	(11.8	)

APCo	Pension Plans									Other Postretirement Benefit Plans
	Years Ended December 31,
	2015			2014			2013			2015			2014			2013
	(in millions)
Service Cost	$	8.7		$	7.0		$	6.2		$	1.1		$	1.4		$	2.6
Interest Cost	26.7			29.6			27.7			10.3			12.8			13.5
Expected Return on Plan Assets	(35.0		)	(33.9		)	(37.1		)	(18.1		)	(18.5		)	(18.1		)
Amortization of Prior Service Cost (Credit)	0.2			0.2			0.2			(10.0		)	(10.1		)	(10.1		)
Amortization of Net Actuarial Loss	13.9			16.6			25.0			3.6			4.6			12.2
Net Periodic Benefit Cost (Credit)	14.5			19.5			22.0			(13.1		)	(9.8		)	0.1
Capitalized Portion	(5.5		)	(6.8		)	(7.5		)	5.0			3.4			(0.1		)
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	9.0		$	12.7		$	14.5		$	(8.1	)	$	(6.4	)	$	—

147

I&M	Pension Plans									Other Postretirement Benefit Plans
	Years Ended December 31,
	2015			2014			2013			2015			2014			2013
	(in millions)
Service Cost	$	12.9		$	10.0		$	8.7		$	1.6		$	1.9		$	3.2
Interest Cost	24.5			26.3			24.1			6.4			7.6			8.2
Expected Return on Plan Assets	(32.6		)	(31.0		)	(32.8		)	(13.2		)	(13.4		)	(13.2		)
Amortization of Prior Service Cost (Credit)	0.2			0.2			0.2			(9.4		)	(9.4		)	(9.4		)
Amortization of Net Actuarial Loss	12.6			14.6			21.7			2.0			2.4			7.5
Net Periodic Benefit Cost (Credit)	17.6			20.1			21.9			(12.6		)	(10.9		)	(3.7		)
Capitalized Portion	(4.0		)	(4.6		)	(4.6		)	2.9			2.5			0.8
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	13.6		$	15.5		$	17.3		$	(9.7	)	$	(8.4	)	$	(2.9	)

OPCo	Pension Plans									Other Postretirement Benefit Plans
	Years Ended December 31,
	2015			2014			2013			2015			2014			2013
	(in millions)
Service Cost	$	6.7		$	5.2		$	5.3		$	0.9		$	1.0		$	2.9
Interest Cost	20.3			22.1			21.9			6.4			7.6			9.5
Expected Return on Plan Assets	(27.5		)	(26.5		)	(29.9		)	(13.4		)	(13.5		)	(13.5		)
Amortization of Prior Service Cost (Credit)	0.2			0.2			0.2			(7.0		)	(6.9		)	(6.9		)
Amortization of Net Actuarial Loss	10.5			12.4			19.8			2.1			2.4			8.6
Net Periodic Benefit Cost (Credit)	10.2			13.4			17.3			(11.0		)	(9.4		)	0.6
Capitalized Portion	(4.8		)	(5.5		)	(6.2		)	5.2			3.8			(0.2		)
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	5.4		$	7.9		$	11.1		$	(5.8	)	$	(5.6	)	$	0.4

PSO	Pension Plans									Other Postretirement Benefit Plans
	Years Ended December 31,
	2015			2014			2013			2015			2014			2013
	(in millions)
Service Cost	$	6.4		$	5.2		$	5.6		$	0.7		$	0.8		$	1.4
Interest Cost	10.9			12.1			11.0			3.0			3.6			3.8
Expected Return on Plan Assets	(15.1		)	(14.6		)	(15.7		)	(6.3		)	(6.3		)	(6.1		)
Amortization of Prior Service Cost (Credit)	0.2			0.3			0.3			(4.3		)	(4.3		)	(4.3		)
Amortization of Net Actuarial Loss	5.7			6.7			9.8			1.0			1.1			3.5
Net Periodic Benefit Cost (Credit)	8.1			9.7			11.0			(5.9		)	(5.1		)	(1.7		)
Capitalized Portion	(2.8		)	(3.3		)	(3.4		)	2.0			1.7			0.5
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	5.3		$	6.4		$	7.6		$	(3.9	)	$	(3.4	)	$	(1.2	)

SWEPCo	Pension Plans									Other Postretirement Benefit Plans
	Years Ended December 31,
	2015			2014			2013			2015			2014			2013
	(in millions)
Service Cost	$	8.3		$	6.6		$	7.0		$	0.8		$	1.0		$	1.7
Interest Cost	11.8			12.7			11.5			3.4			4.0			4.3
Expected Return on Plan Assets	(16.0		)	(15.4		)	(16.5		)	(6.9		)	(7.0		)	(6.9		)
Amortization of Prior Service Cost (Credit)	0.3			0.3			0.3			(5.2		)	(5.2		)	(5.1		)
Amortization of Net Actuarial Loss	6.0			7.1			10.2			1.1			1.2			3.9
Net Periodic Benefit Cost (Credit)	10.4			11.3			12.5			(6.8		)	(6.0		)	(2.1		)
Capitalized Portion	(3.2		)	(3.4		)	(3.5		)	2.1			1.8			0.6
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	7.2		$	7.9		$	9.0		$	(4.7	)	$	(4.2	)	$	(1.5	)

148

Estimated amounts expected to be amortized to net periodic benefit costs (credits) and the impact on each Registrants’ balance sheet during 2016 are shown in the following tables:

	AEP			APCo			I&M			OPCo			PSO			SWEPCo
Pension Plans – Components	(in millions)
Net Actuarial Loss	$	82.9		$	10.7		$	9.7		$	8.2		$	4.4		$	4.7
Prior Service Cost	2.2			0.2			0.2			0.1			0.2			0.3
Total Estimated 2016 Amortization	$	85.1		$	10.9		$	9.9		$	8.3		$	4.6		$	5.0
Pension Plans – Expected to be Recorded as
Regulatory Asset	$	73.8		$	10.9		$	9.3		$	8.3		$	4.6		$	5.0
Deferred Income Taxes	3.9			—			0.2			—			—			—
Net of Tax AOCI	7.4			—			0.4			—			—			—
Total	$	85.1		$	10.9		$	9.9		$	8.3		$	4.6		$	5.0
	AEP			APCo			I&M			OPCo			PSO			SWEPCo
Other Postretirement Benefit Plans – Components	(in millions)
Net Actuarial Loss	$	29.8		$	5.2		$	3.5		$	3.6		$	1.7		$	1.8
Prior Service Credit	(69.0		)	(10.1		)	(9.4		)	(6.9		)	(4.3		)	(5.1		)
Total Estimated 2016 Amortization	$	(39.2	)	$	(4.9	)	$	(5.9	)	$	(3.3	)	$	(2.6	)	$	(3.3	)
Other Postretirement Benefit Plans – Expected to be Recorded as
Regulatory Asset	$	(28.5	)	$	(2.6	)	$	(5.3	)	$	(3.3	)	$	(2.6	)	$	(2.1	)
Deferred Income Taxes	(3.7		)	(0.8		)	(0.2		)	—			—			(0.4		)
Net of Tax AOCI	(7.0		)	(1.5		)	(0.4		)	—			—			(0.8		)
Total	$	(39.2	)	$	(4.9	)	$	(5.9	)	$	(3.3	)	$	(2.6	)	$	(3.3	)

American Electric Power System Retirement Savings Plan

AEP sponsors the American Electric Power System Retirement Savings Plan, a defined contribution retirement savings plan for substantially all employees who are not covered by a retirement savings plan of the United Mine Workers of America (UMWA).  This qualified plan offers participants an opportunity to contribute a portion of their pay, includes features under Section 401(k) of the Internal Revenue Code and provides for company matching contributions.  The matching contributions to the plan are 100% of the first 1% of eligible employee contributions and 70% of the next 5% of contributions.

The following table provides the cost for matching contributions to the retirement savings plans by Registrant for the years ended December 31, 2015, 2014 and 2013:

	Year Ended December 31,
Company	2015		2014		2013
	(in millions)
AEP	$	73.6	$	70.5	$	66.6
APCo	7.2		7.3		7.4
I&M	10.6		10.5		10.0
OPCo	5.4		5.2		6.5
PSO	4.2		4.0		3.8
SWEPCo	5.7		5.3		5.0

149

UMWA Benefits (Applies to AEP and APCo)

AEP provides health and welfare benefits for certain unionized employees, retirees and their survivors who meet eligibility requirements. APCo also provides the same UMWA health and welfare benefits for certain unionized mining retirees and their survivors who meet eligibility requirements.  UMWA trustees make final interpretive determinations with regard to all benefits. AEP and APCo administer the health and welfare benefits and pay them from their general assets.

UMWA pension benefits are provided through the United Mine Workers of America 1974 Pension Plan (Employer Identification Number: 52-1050282, Plan Number 002), a multiemployer plan. The UMWA pension benefits are administered by a board of trustees appointed in equal numbers by the UMWA and the Bituminous Coal Operators’ Association (BCOA), an industry bargaining association. AEP makes contributions to the United Mine Workers of America 1974 Pension Plan based on provisions in its labor agreement. The UMWA pension plan is different from single-employer plans as an employer’s contributions may be used to provide benefits to employees of other participating employers.  Required contributions not made by an employer may result in other employers bearing a greater amount of the unfunded plan obligations, while a withdrawing employer may be subject to a withdrawal liability.  Under the Pension Protection Act of 2006 (PPA), the UMWA pension plan was in Critical and Declining Status for the plan year ending June 30, 2015 and in Critical Status for the plan year ending June 30, 2014, without utilization of extended amortization provisions.  The Plan adopted a Rehabilitation Plan in February 2015, as required under the PPA. The prior funding improvement plan is no longer in effect.

Contributions to the UMWA pension plan in 2015, 2014 and 2013 were made under a collective bargaining agreement that is set to expire December 31, 2017. AEP contributed immaterial amounts that represent less than 5% of the total contributions in the plan’s latest annual report for the years ended June 30, 2015, 2014 and 2013.  UMWA pension contributions included a surcharge of 5% from December 2014 through June 2015. Beginning July 2015, the surcharge on contributions was increased to 10%.  Under the terms of the UMWA pension plan, contributions will be required to continue beyond the expiration of the current collective bargaining agreement, whether or not the term of that agreement is extended or a subsequent agreement is entered, so long as both the UMWA pension plan remains in effect and an AEP affiliate continues to operate the facility covered by the current collective bargaining agreement. The contribution rate applicable would be determined by reference to the National Bituminous Coal Wage Agreement between the UMWA and the BCOA. If the UMWA pension plan would terminate or an AEP affiliate would cease operation of the facility without arranging for a successor operator to assume its liability, the withdrawal liability obligation would be triggered.

Based upon the plan to retrofit the Rockport Plant with dry sorbent injection technology to meet environmental emission control requirements and the timing of the closure of Cook Coal Terminal expected to be in or after 2025, AEP records a UMWA pension withdrawal liability on the balance sheet. The UMWA pension withdrawal liability is re-measured annually and is based on the company’s proportionate share of the plan’s unfunded vested liabilities. As of December 31, 2015 and 2014, the liability balance was $31 million and $40 million, respectively. AEP also records a related UMWA pension withdrawal regulatory asset on the balance sheet which is being recovered through billings for transloading services and should be fully collected before the planned closure. As of December 31, 2015 and 2014, the regulatory asset balance was $14 million and $25 million, respectively.

150

9.  BUSINESS SEGMENTS

The disclosures in this note apply to all Registrants unless indicated otherwise.

AEP’s Reportable Segments

AEP’s primary business is the generation, transmission and distribution of electricity.  Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manage its 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.

AEP’s 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 and capacity to serve SSO customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

• Development, construction and operation of transmission facilities through investments in AEP’s 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, SPP and MISO.

The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.

151

The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2015, 2014 and 2013and reportable segment balance sheet information as of December 31, 2015 and 2014.  These amounts include certain estimates and allocations where necessary.

	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco			Generation & Marketing		Corporate and Other(a)			Reconciling Adjustments				Consolidated
	(in millions)
2015
Revenues from:
External Customers	$	9,069.9	$	4,392.0	$	100.6		$	2,866.7	$	24.0		$	—			$	16,453.2
Other Operating Segments	102.3		164.6		228.6			546.0		75.0			(1,116.5		)		—
Total Revenues	$	9,172.2	$	4,556.6	$	329.2		$	3,412.7	$	99.0		$	(1,116.5	)		$	16,453.2
Depreciation and Amortization	$	1,062.6	$	686.2	$	43.0		$	201.4	$	1.0		$	15.5		(d)	2,009.7
Interest and Investment Income	4.6		6.1		0.2			2.8		9.5			(15.3		)		7.9
Carrying Costs Income	11.8		11.8		(0.2		)	—		—			0.1				23.5
Interest Expense	517.4		275.8		37.2			40.0		30.7			(27.2		)	(d)	873.9
Income Tax Expense (Credit)	449.3		185.5		91.3			194.6		(1.1		)	—				919.6
Income (Loss) from Continuing Operations	$	900.2	$	351.7	$	192.7		$	366.0	$	(42.0	)	$	—			1,768.6
Income from Discontinued Operations, Net of Tax	—		—		—			—		283.7			—				283.7
Net Income	$	900.2	$	351.7	$	192.7		$	366.0	$	241.7		$	—			$	2,052.3
Gross Property Additions	$	2,222.3	$	1,048.3	$	1,121.3		$	134.3	$	4.9		$	(17.8	)		$	4,513.3
Total Property, Plant and Equipment	$	40,130.3	$	13,840.5	$	3,977.6		$	7,461.3	$	350.9		$	(279.2	)	(d)	$	65,481.4
Accumulated Depreciation and Amortization	12,335.0		3,529.2		52.3			3,367.0		176.9			(112.2		)	(d)	19,348.2
Total Property, Plant and Equipment – Net	$	27,795.3	$	10,311.3	$	3,925.3		$	4,094.3	$	174.0		$	(167.0	)	(d)	$	46,133.2
Total Assets	$	35,792.3	$	14,640.2	$	5,012.1		$	5,414.5	$	21,907.4		$	(21,083.4	)	(d) (e)	$	61,683.1
Investments in Equity Method Investees	31.9		0.9		630.8			0.1		56.8			—				720.5
Long-term Debt Due Within One Year:
Affiliated	$	—	$	—	$	—		$	—	$	—		$	—			$	—
Non-Affiliated	935.4		824.7		—			71.6		0.1			—				1,831.8
Long-term Debt:
Affiliated	20.0		—		—			32.2		—			(52.2		)		—
Non-Affiliated	9,833.0		4,776.8		1,648.4			639.5		843.2			—				17,740.9
Total Long-term Debt	$	10,788.4	$	5,601.5	$	1,648.4		$	743.3	$	843.3		$	(52.2	)		$	19,572.7

152

	Vertically Integrated Utilities			Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing			Corporate and Other(a)		Reconciling Adjustments				Consolidated
	(in millions)
2014
Revenues from:
External Customers	$	9,396.8	(b)	$	4,552.6	$	73.9	$	2,384.3	(b)	$	22.2	$	(51.2	)	(c)	$	16,378.6
Other Operating Segments	87.6		(b)	261.0		118.0		1,465.3		(b)	73.2		(2,005.1		)		—
Total Revenues	$	9,484.4		$	4,813.6	$	191.9	$	3,849.6		$	95.4	$	(2,056.3	)		$	16,378.6
Depreciation and Amortization	$	1,033.0		$	657.8	$	23.7	$	226.8		$	—	$	(43.7	)	(d)	$	1,897.6
Interest and Investment Income	3.4			11.4		—		4.7			7.3		(19.4		)		7.4
Carrying Costs Income	6.7			26.5		—		—			—		—				33.2
Interest Expense	525.5			279.9		23.5		45.3			25.5		(31.7		)	(d)	868.0
Income Tax Expense	433.5			211.1		62.9		179.3			15.8		—				902.6
Income from Continuing Operations	$	711.8		$	354.6	$	150.8	$	367.4		$	5.9	$	—			$	1,590.5
Income from Discontinued Operations, Net of Tax	—			—		—		—			47.5		—				47.5
Net Income	$	711.8		$	354.6	$	150.8	$	367.4		$	53.4	$	—			$	1,638.0
Gross Property Additions	$	2,054.7		$	1,037.7	$	948.3	$	164.9		$	17.2	$	(28.0	)		$	4,194.8
Total Property, Plant and Equipment	$	39,402.4		$	13,023.8	$	2,714.2	$	8,394.3		$	342.7	$	(271.5	)	(d)	$	63,605.9
Accumulated Depreciation and Amortization	12,772.8			3,480.7		24.5		3,602.9			188.1		(98.2		)	(d)	19,970.8
Total Property, Plant and Equipment – Net	$	26,629.6		$	9,543.1	$	2,689.7	$	4,791.4		$	154.6	$	(173.3	)	(d)	$	43,635.1
Assets from Discontinued Operations	$	—		$	—	$	—	$	—		$	624.9	$	—			$	624.9
Total Assets	33,705.1			14,463.4		3,570.0		6,326.2			21,826.5		(20,346.6		)	(d) (e)	59,544.6
Investments in Equity Method Investees	26.2			1.1		548.0		0.1			73.0		—				648.4
Long-term Debt Due Within One Year:
Affiliated	$	111.0		$	—	$	—	$	86.0		$	—	$	(197.0	)		$	—
Non-Affiliated	1,352.4			405.2		—		740.0			2.8		—				2,500.4
Long-term Debt:
Affiliated	20.0			—		—		32.2			—		(52.2		)		—
Non-Affiliated	8,589.2			5,224.2		1,147.5		214.8			836.3		—				16,012.0
Total Long-term Debt	$	10,072.6		$	5,629.4	$	1,147.5	$	1,073.0		$	839.1	$	(249.2	)		$	18,512.4
Liabilities from Discontinued Operations	$	—		$	—	$	—	$	—		$	434.8	$	—			$	434.8	(f)

153

	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other(a)			Reconciling Adjustments				Consolidated
	(in millions)
2013
Revenues from:
External Customers	$	9,346.6	$	4,279.1	$	26.8	$	1,208.0	$	32.5		$	(79.5	)	(c)	$	14,813.5
Other Operating Segments	645.9		199.3		50.9		2,457.2		56.3			(3,409.6		)		—
Total Revenues	$	9,992.5	$	4,478.4	$	77.7	$	3,665.2	$	88.8		$	(3,489.1	)		$	14,813.5
Asset Impairments and Other Related Charges	$	72.1	$	—	$	—	$	154.3	$	—		$	—			$	226.4
Depreciation and Amortization	941.5		591.3		10.1		236.1		0.3			(66.8		)	(d)	1,712.5
Interest and Investment Income	7.2		1.6		—		2.1		68.8			(21.8		)		57.9
Carrying Costs Income	13.8		16.3		0.1		—		—			—				30.2
Interest Expense	540.1		291.0		10.0		55.5		26.9			(33.5		)	(d)	890.0
Income Tax Expense (Credit)	398.1		198.3		29.0		112.2		(59.9		)	—				677.7
Income from Continuing Operations	$	681.7	$	357.8	$	79.4	$	227.9	$	127.1		$	—			$	1,473.9
Income from Discontinued Operations, Net of Tax	—		—		—		—		10.3			—				10.3
Net Income	$	681.7	$	357.8	$	79.4	$	227.9	$	137.4		$	—			$	1,484.2
Gross Property Additions	$	1,822.0	$	870.9	$	842.6	$	185.2	$	9.1		$	(81.4	)		$	3,648.4
Total Assets	32,745.5		14,127.3		2,241.5		6,424.0		20,312.9			(19,530.2		)	(d) (e)	56,321.0

(a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO 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 in Ohio.

(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.

(f) Amount includes debt related to AEPRO. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.

Registrant Subsidiaries’ Reportable Segments

The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business starting in 2014.  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.

154

10.  DERIVATIVES AND HEDGING

The disclosures in this note apply to all Registrants unless indicated otherwise.

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries.

The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets.  These risks include commodity price risks which may be subject to capacity 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 Registrants due to changes in the underlying market prices or rates.  Management utilizes derivative instruments to manage these risks.

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 which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities.  To accomplish these objectives, the Registrants 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.

The Registrants utilize power, capacity, 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.  The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio.  For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities.  The Registrants also utilize derivative contracts to manage 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, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.

155

The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts as of December 31, 2015 and 2014:

Notional Volume of Derivative Instruments

December 31, 2015

Primary Risk Exposure	Unit of Measure	AEP		APCo		I&M		OPCo		PSO		SWEPCo
		(in millions)
Commodity:
Power	MWhs	317.8		40.9		22.8		13.3		11.3		14.0
Coal	Tons	4.4		—		1.6		—		—		2.8
Natural Gas	MMBtus	38.2		0.3		0.2		—		0.2		0.2
Heating Oil and Gasoline	Gallons	7.4		1.4		0.7		1.6		0.8		0.9
Interest Rate	USD	$	113.5	$	2.4	$	1.6	$	—	$	—	$	—
Interest Rate and Foreign Currency	USD	$	560.3	$	—	$	—	$	—	$	—	$	—

Notional Volume of Derivative Instruments

December 31, 2014

Primary Risk Exposure	Unit of Measure	AEP		APCo		I&M		OPCo		PSO		SWEPCo
		(in millions)
Commodity:
Power	MWhs	333.7		32.5		23.8		20.3		16.8		20.5
Coal	Tons	3.1		0.3		0.5		—		—		1.5
Natural Gas	MMBtus	105.9		0.4		0.3		—		—		—
Heating Oil and Gasoline	Gallons	5.5		1.1		0.5		1.1		0.6		0.7
Interest Rate	USD	$	152.0	$	5.1	$	3.5	$	—	$	—	$	—
Interest Rate and Foreign Currency	USD	$	815.2	$	—	$	—	$	—	$	—	$	—

Fair Value Hedging Strategies (Applies to AEP)

Parent 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 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

The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales.  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 purchases.  The Registrants do not hedge all commodity price risk.

The Registrants’ vehicle fleet is exposed to gasoline and diesel fuel price volatility.  The Registrants utilize 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. The Registrants do not hedge all fuel price risk.

156

The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure.  The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt.  The Registrants do not hedge all interest rate exposure.

At times, the Registrants 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, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar.  The Registrants 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 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 the derivative instruments, the Registrants 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 Registrants 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 Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the December 31, 2015 and 2014 balance sheets, the Registrants 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:

	December 31,
	2015				2014
Company	Cash Collateral Received Netted Against Risk Management Assets		Cash Collateral Paid Netted Against Risk Management Liabilities		Cash Collateral Received Netted Against Risk Management Assets		Cash Collateral Paid Netted Against Risk Management Liabilities
	(in millions)
AEP	$	5.8	$	44.4	$	3.5	$	35.2
APCo	—		3.1		0.1		0.1
I&M	—		0.6		0.2		—
OPCo	—		0.5		—		0.1
PSO	—		0.3		—		0.1
SWEPCo	—		0.3		—		0.1

157

The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets as of December 31, 2015 and 2014:

AEP

Fair Value of Derivative Instruments

December 31, 2015

	Risk Management Contracts		Hedging Contracts						Gross Amounts of Risk Management Assets/ Liabilities Recognized		Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)		Commodity (a)			Interest Rate and Foreign Currency (a)
	(in millions)
Current Risk Management Assets	$	368.8	$	8.2		$	0.1		$	377.1	$	(242.7	)	$	134.4
Long-term Risk Management Assets	364.8		11.7			—			376.5		(54.7		)	321.8
Total Assets	733.6		19.9			0.1			753.6		(297.4		)	456.2
Current Risk Management Liabilities	347.0		9.1			0.3			356.4		(269.3		)	87.1
Long-term Risk Management Liabilities	223.3		19.3			3.2			245.8		(66.7		)	179.1
Total Liabilities	570.3		28.4			3.5			602.2		(336.0		)	266.2
Total MTM Derivative Contract Net Assets (Liabilities)	$	163.3	$	(8.5	)	$	(3.4	)	$	151.4	$	38.6		$	190.0

AEP

Fair Value of Derivative Instruments

December 31, 2014

	Risk Management Contracts		Hedging Contracts					Gross Amounts of Risk Management Assets/ Liabilities Recognized		Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)		Commodity (a)		Interest Rate and Foreign Currency (a)
	(in millions)
Current Risk Management Assets	$	392.6	$	30.0	$	2.6		$	425.2	$	(247.3	)	$	177.9
Long-term Risk Management Assets	366.7		3.8		—			370.5		(76.3		)	294.2
Total Assets	759.3		33.8		2.6			795.7		(323.6		)	472.1
Current Risk Management Liabilities	328.6		23.4		0.7			352.7		(261.1		)	91.6
Long-term Risk Management Liabilities	208.0		7.9		9.2			225.1		(94.2		)	130.9
Total Liabilities	536.6		31.3		9.9			577.8		(355.3		)	222.5
Total MTM Derivative Contract Net Assets (Liabilities)	$	222.7	$	2.5	$	(7.3	)	$	217.9	$	31.7		$	249.6

(a) Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the 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.”

(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.

158

APCo

Fair Value of Derivative Instruments

December 31, 2015

	Risk Management Contracts		Hedging Contracts				Gross Amounts of Risk Management Assets/ Liabilities Recognized		Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)		Commodity (a)		Interest Rate and Foreign Currency (a)
	(in millions)
Current Risk Management Assets - Nonaffiliated and Affiliated	$	25.9	$	—	$	—	$	25.9	$	(10.3	)	$	15.6
Long-term Risk Management Assets - Nonaffiliated	0.3		—		—		0.3		(0.2		)	0.1
Total Assets	26.2		—		—		26.2		(10.5		)	15.7
Current Risk Management Liabilities - Nonaffiliated	18.1		—		—		18.1		(13.3		)	4.8
Long-term Risk Management Liabilities - Nonaffiliated	0.3		—		—		0.3		(0.2		)	0.1
Total Liabilities	18.4		—		—		18.4		(13.5		)	4.9
Total MTM Derivative Contract Net Assets (Liabilities)	$	7.8	$	—	$	—	$	7.8	$	3.0		$	10.8

APCo

Fair Value of Derivative Instruments

December 31, 2014

	Risk Management Contracts		Hedging Contracts				Gross Amounts of Risk Management Assets/ Liabilities Recognized		Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)		Commodity (a)		Interest Rate and Foreign Currency (a)
	(in millions)
Current Risk Management Assets - Nonaffiliated	$	32.9	$	—	$	—	$	32.9	$	(9.1	)	$	23.8
Long-term Risk Management Assets - Nonaffiliated	5.2		—		—		5.2		(0.3		)	4.9
Total Assets	38.1		—		—		38.1		(9.4		)	28.7
Current Risk Management Liabilities - Nonaffiliated	20.2		—		—		20.2		(9.2		)	11.0
Long-term Risk Management Liabilities - Nonaffiliated	2.3		—		—		2.3		(0.2		)	2.1
Total Liabilities	22.5		—		—		22.5		(9.4		)	13.1
Total MTM Derivative Contract Net Assets (Liabilities)	$	15.6	$	—	$	—	$	15.6	$	—		$	15.6

(a) Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the 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.

159

I&M

Fair Value of Derivative Instruments

December 31, 2015

	Risk Management Contracts		Hedging Contracts				Gross Amounts of Risk Management Assets/ Liabilities Recognized		Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)		Commodity (a)		Interest Rate and Foreign Currency (a)
	(in millions)
Current Risk Management Assets - Nonaffiliated and Affiliated	$	22.8	$	—	$	—	$	22.8	$	(10.5	)	$	12.3
Long-term Risk Management Assets - Nonaffiliated	0.6		—		—		0.6		(0.6		)	—
Total Assets	23.4		—		—		23.4		(11.1		)	12.3
Current Risk Management Liabilities - Nonaffiliated	17.0		—		—		17.0		(10.7		)	6.3
Long-term Risk Management Liabilities - Nonaffiliated	2.6		—		—		2.6		(1.0		)	1.6
Total Liabilities	19.6		—		—		19.6		(11.7		)	7.9
Total MTM Derivative Contract Net Assets (Liabilities)	$	3.8	$	—	$	—	$	3.8	$	0.6		$	4.4

I&M

Fair Value of Derivative Instruments

December 31, 2014

	Risk Management Contracts		Hedging Contracts				Gross Amounts of Risk Management Assets/ Liabilities Recognized		Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)		Commodity (a)		Interest Rate and Foreign Currency (a)
	(in millions)
Current Risk Management Assets - Nonaffiliated	$	28.5	$	—	$	—	$	28.5	$	(6.2	)	$	22.3
Long-term Risk Management Assets - Nonaffiliated	3.5		—		—		3.5		(0.2		)	3.3
Total Assets	32.0		—		—		32.0		(6.4		)	25.6
Current Risk Management Liabilities - Nonaffiliated	11.3		—		—		11.3		(6.1		)	5.2
Long-term Risk Management Liabilities - Nonaffiliated	1.6		—		—		1.6		(0.2		)	1.4
Total Liabilities	12.9		—		—		12.9		(6.3		)	6.6
Total MTM Derivative Contract Net Assets (Liabilities)	$	19.1	$	—	$	—	$	19.1	$	(0.1	)	$	19.0

(a) Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the 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.

160

OPCo

Fair Value of Derivative Instruments

December 31, 2015

	Risk Management Contracts		Hedging Contracts				Gross Amounts of Risk Management Assets/ Liabilities Recognized		Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)		Commodity (a)		Interest Rate and Foreign Currency (a)
	(in millions)
Current Risk Management Assets	$	—	$	—	$	—	$	—	$	—		$	—
Long-term Risk Management Assets	19.2		—		—		19.2		—			19.2
Total Assets	19.2		—		—		19.2		—			19.2
Current Risk Management Liabilities	4.1		—		—		4.1		(0.5		)	3.6
Long-term Risk Management Liabilities	—		—		—		—		—			—
Total Liabilities	4.1		—		—		4.1		(0.5		)	3.6
Total MTM Derivative Contract Net Assets (Liabilities)	$	15.1	$	—	$	—	$	15.1	$	0.5		$	15.6

OPCo

Fair Value of Derivative Instruments

December 31, 2014

	Risk Management Contracts		Hedging Contracts				Gross Amounts of Risk Management Assets/ Liabilities Recognized		Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)		Commodity (a)		Interest Rate and Foreign Currency (a)
	(in millions)
Current Risk Management Assets	$	7.2	$	—	$	—	$	7.2	$	—		$	7.2
Long-term Risk Management Assets	45.1		—		—		45.1		—			45.1
Total Assets	52.3		—		—		52.3		—			52.3
Current Risk Management Liabilities	2.0		—		—		2.0		(0.1		)	1.9
Long-term Risk Management Liabilities	3.0		—		—		3.0		—			3.0
Total Liabilities	5.0		—		—		5.0		(0.1		)	4.9
Total MTM Derivative Contract Net Assets (Liabilities)	$	47.3	$	—	$	—	$	47.3	$	0.1		$	47.4

(a) Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the 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

PSO

Fair Value of Derivative Instruments

December 31, 2015

	Risk Management Contracts		Hedging Contracts				Gross Amounts of Risk Management Assets/ Liabilities Recognized		Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)		Commodity (a)		Interest Rate and Foreign Currency (a)
	(in millions)
Current Risk Management Assets	$	0.6	$	—	$	—	$	0.6	$	—		$	0.6
Long-term Risk Management Assets	—		—		—		—		—			—
Total Assets	0.6		—		—		0.6		—			0.6
Current Risk Management Liabilities	0.5		—		—		0.5		(0.3		)	0.2
Long-term Risk Management Liabilities	—		—		—		—		—			—
Total Liabilities	0.5		—		—		0.5		(0.3		)	0.2
Total MTM Derivative Contract Net Assets (Liabilities)	$	0.1	$	—	$	—	$	0.1	$	0.3		$	0.4

PSO

Fair Value of Derivative Instruments

December 31, 2014

	Risk Management Contracts			Hedging Contracts				Gross Amounts of Risk Management Assets/ Liabilities Recognized			Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)			Commodity (a)		Interest Rate and Foreign Currency (a)
	(in millions)
Current Risk Management Assets	$	0.4		$	—	$	—	$	0.4		$	(0.4	)	$	—
Long-term Risk Management Assets	—			—		—		—			—			—
Total Assets	0.4			—		—		0.4			(0.4		)	—
Current Risk Management Liabilities	1.3			—		—		1.3			(0.4		)	0.9
Long-term Risk Management Liabilities	—			—		—		—			—			—
Total Liabilities	1.3			—		—		1.3			(0.4		)	0.9
Total MTM Derivative Contract Net Assets (Liabilities)	$	(0.9	)	$	—	$	—	$	(0.9	)	$	—		$	(0.9	)

(a) Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the 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.

162

SWEPCo

Fair Value of Derivative Instruments

December 31, 2015

	Risk Management Contracts			Hedging Contracts				Gross Amounts of Risk Management Assets/ Liabilities Recognized			Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)			Commodity (a)		Interest Rate and Foreign Currency (a)
	(in millions)
Current Risk Management Assets	$	0.8		$	—	$	—	$	0.8		$	—		$	0.8
Long-term Risk Management Assets	—			—		—		—			—			—
Total Assets	0.8			—		—		0.8			—			0.8
Current Risk Management Liabilities	3.4			—		—		3.4			(0.3		)	3.1
Long-term Risk Management Liabilities	2.1			—		—		2.1			—			2.1
Total Liabilities	5.5			—		—		5.5			(0.3		)	5.2
Total MTM Derivative Contract Net Assets (Liabilities)	$	(4.7	)	$	—	$	—	$	(4.7	)	$	0.3		$	(4.4	)

SWEPCo

Fair Value of Derivative Instruments

December 31, 2014

	Risk Management Contracts			Hedging Contracts				Gross Amounts of Risk Management Assets/ Liabilities Recognized			Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)			Commodity (a)		Interest Rate and Foreign Currency (a)
	(in millions)
Current Risk Management Assets	$	0.5		$	—	$	—	$	0.5		$	(0.5	)	$	—
Long-term Risk Management Assets	—			—		—		—			—			—
Total Assets	0.5			—		—		0.5			(0.5		)	—
Current Risk Management Liabilities	1.6			—		—		1.6			(0.5		)	1.1
Long-term Risk Management Liabilities	—			—		—		—			—			—
Total Liabilities	1.6			—		—		1.6			(0.5		)	1.1
Total MTM Derivative Contract Net Assets (Liabilities)	$	(1.1	)	$	—	$	—	$	(1.1	)	$	—		$	(1.1	)

(a) Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the 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.

163

The tables below present the Registrants’ activity of derivative risk management contracts for the years ended December 31, 2015, 2014 and 2013:

Amount of Gain (Loss) Recognized on

Risk Management Contracts

 Year Ended December 31, 2015

Location of Gain (Loss)	AEP			APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	6.7		$	—		$	—		$	—		$	—		$	—
Transmission and Distribution Utilities Revenues	(4.3		)	—			—			—			—			—
Generation & Marketing Revenues	54.9			—			—			—			—			—
Electric Generation, Transmission and Distribution Revenues	—			1.1			3.3			(4.3		)	—			—
Sales to AEP Affiliates	—			2.4			8.2			—			—			—
Purchased Electricity for Resale	6.4			2.0			0.4			—			—			—
Other Operation Expense	(3.3		)	(0.4		)	(0.4		)	(0.6		)	(0.4		)	(0.5		)
Maintenance Expense	(3.3		)	(0.7		)	(0.4		)	(0.5		)	(0.4		)	(0.4		)
Regulatory Assets (a)	(0.9		)	3.4			(2.7		)	—			0.6			(4.3		)
Regulatory Liabilities (a)	30.2			28.7			7.5			(24.7		)	4.4			15.1
Total Gain (Loss) on Risk Management Contracts	$	86.4		$	36.5		$	15.9		$	(30.1	)	$	4.2		$	9.9

Amount of Gain (Loss) Recognized on

Risk Management Contracts

 Year Ended December 31, 2014

Location of Gain (Loss)	AEP			APCo			I&M			OPCo		PSO			SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	35.4		$	—		$	—		$	—	$	—		$	—
Generation & Marketing Revenues	52.5			—			—			—		—			—
Electric Generation, Transmission and Distribution Revenues	—			8.7			13.2			—		0.2			—
Sales to AEP Affiliates	—			—			(0.9		)	—		0.9			—
Regulatory Assets (a)	(11.4		)	(4.1		)	(0.5		)	—		(1.0		)	(1.1		)
Regulatory Liabilities (a)	193.2			49.6			37.4			86.0		0.3			16.9
Total Gain on Risk Management Contracts	$	269.7		$	54.2		$	49.2		$	86.0	$	0.4		$	15.8

Amount of Gain (Loss) Recognized on

Risk Management Contracts

 Year Ended December 31, 2013

Location of Gain (Loss)	AEP			APCo			I&M			OPCo			PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	15.1		$	—		$	—		$	—		$	—	$	—
Generation & Marketing Revenues	49.2			—			—			—			—		—
Electric Generation, Transmission and Distribution Revenues	—			2.0			10.6			4.9			0.4		0.6
Regulatory Assets (a)	(2.4		)	—			—			(5.8		)	2.9		0.4
Regulatory Liabilities (a)	(5.0		)	(0.3		)	(9.1		)	2.9			1.0		1.5
Total Gain on Risk Management Contracts	$	56.9		$	1.7		$	1.5		$	2.0		$	4.3	$	2.5

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

164

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 statements of income on an accrual basis.

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

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes.  Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the 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 statements of income depending on the relevant facts and circumstances.  Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. 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.”

In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale.

Accounting for Fair Value Hedging Strategies (Applies to AEP)

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.

AEP records 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 statements of income.  The following table shows the results of hedging gains (losses) during 2015, 2014, and 2013:

	Years Ended December 31,
	2015			2014			2013
	(in millions)
Gain (Loss) on Fair Value Hedging Instruments	$	3.2		$	3.8		$	(10.4	)
Gain (Loss) on Fair Value Portion of Long-term Debt	(3.3		)	(3.9		)	10.4

For 2015, 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 that is attributable to a particular risk), the Registrants 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 balance sheets until the period the hedged item affects Net Income.  The Registrants 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).

165

Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged.  During 2015, 2014 and 2013, AEP applied cash flow hedging to outstanding power derivatives. During 2015, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. During 2014, APCo and I&M applied cash flow hedging to outstanding power derivatives. During 2013, APCo, I&M and OPCo applied cash flow hedging to outstanding power derivatives.

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

The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur.  During 2015, 2014 and 2013, AEP applied cash flow hedging to outstanding interest rate derivatives. During 2015 and 2014, the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives.  During 2013, I&M applied cash flow hedging to outstanding interest rate derivatives.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.  During 2015, 2014 and 2013, the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives.

During 2015, 2014 and 2013, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3.

166

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets as of December 31, 2015 and 2014 were:

Impact of Cash Flow Hedges on the Registrants’ Balance Sheets

December 31, 2015

	Hedging Assets (a)				Hedging Liabilities (a)				AOCI Gain (Loss) Net of Tax
Company	Commodity		Interest Rate and Foreign Currency		Commodity		Interest Rate and Foreign Currency		Commodity			Interest Rate and Foreign Currency
	(in millions)
AEP	$	17.6	$	—	$	26.1	$	0.4	$	(5.2	)	$	(17.2	)
APCo	—		—		—		—		—			3.6
I&M	—		—		—		—		—			(13.3		)
OPCo	—		—		—		—		—			4.3
PSO	—		—		—		—		—			4.2
SWEPCo	—		—		—		—		—			(9.1		)

	Expected to be Reclassified to Net Income During the Next Twelve Months
Company	Commodity			Interest Rate and Foreign Currency			Maximum Term for Exposure to Variability of Future Cash Flows
	(in millions)						(in months)
AEP	$	(0.4	)	$	(1.5	)	144
APCo	—			0.7			0
I&M	—			(1.3		)	0
OPCo	—			1.2			0
PSO	—			0.8			0
SWEPCo	—			(1.7		)	0

Impact of Cash Flow Hedges on the Registrants’ Balance Sheets

December 31, 2014

	Hedging Assets (a)				Hedging Liabilities (a)				AOCI Gain (Loss) Net of Tax
Company	Commodity		Interest Rate and Foreign Currency		Commodity		Interest Rate and Foreign Currency		Commodity		Interest Rate and Foreign Currency
	(in millions)
AEP	$	16.8	$	—	$	14.3	$	1.0	$	1.6	$	(19.1	)
APCo	—		—		—		—		—		3.9
I&M	—		—		—		—		—		(14.4		)
OPCo	—		—		—		—		—		5.6
PSO	—		—		—		—		—		5.0
SWEPCo	—		—		—		—		—		(11.1		)

	Expected to be Reclassified to Net Income During the Next Twelve Months
Company	Commodity		Interest Rate and Foreign Currency
	(in millions)
AEP	$	4.3	$	(2.0	)
APCo	—		0.3
I&M	—		(1.1		)
OPCo	—		1.4
PSO	—		0.8
SWEPCo	—		(2.0		)

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

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

167

Credit Risk

Management limits credit risk in 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.  Management 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 management 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 Registrants are obligated to post an additional amount of collateral if certain credit ratings decline below a specified rating threshold.  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 Registrants have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral.  The following tables represent the Registrants’ exposure if credit ratings were to decline below a specified rating threshold as of December 31, 2015 and 2014:

	December 31, 2015
Company	Fair Value  of Contracts with Credit Downgrade Triggers		Amount of Collateral the Registrants Would Have Been Required to Post for Derivative Contracts as well as Non- Derivative Contracts Subject to the Same Master Netting Arrangement		Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs		Amount of Collateral Attributable to Other Contracts
	(in millions)
AEP	$	—	$	—	$	17.5	$	297.8	(a)
APCo	—		—		4.9		0.1
I&M	—		—		3.3		0.1
OPCo	—		—		—		—
PSO	—		—		—		3.2
SWEPCo	—		—		—		0.1

	December 31, 2014
Company	Fair Value of Contracts with Credit Downgrade Triggers		Amount of Collateral the Registrants Would Have Been Required to Post for Derivative Contracts as well as Non- Derivative Contracts Subject to the Same Master Netting Arrangement		Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs		Amount of Collateral Attributable to Other Contracts
	(in millions)
AEP	$	—	$	—	$	36.0	$	280.6	(a)
APCo	—		—		6.3		0.1
I&M	—		—		4.3		—
OPCo	—		—		—		—
PSO	—		—		0.7		4.1
SWEPCo	—		—		0.9		0.2

(a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.

168

In addition, a majority of the Registrants’ 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 Registrants and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrants’ contractual netting arrangements as of December 31, 2015 and 2014:

	December 31, 2015
Company	Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		Amount of Cash Collateral Posted		Additional Settlement Liability if Cross Default Provision is Triggered
	(in millions)
AEP	$	300.1	$	0.8	$	240.6
APCo	3.7		—		3.7
I&M	2.5		—		2.5
OPCo	—		—		—
PSO	—		—		—
SWEPCo	—		—		—

	December 31, 2014
Company	Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		Amount of Cash Collateral Posted		Additional Settlement Liability if Cross Default Provision is Triggered
	(in millions)
AEP	$	235.2	$	8.5	$	178.2
APCo	9.0		—		9.0
I&M	6.1		—		6.1
OPCo	—		—		—
PSO	—		—		—
SWEPCo	—		—		—

169

11.  FAIR VALUE MEASUREMENTS

The disclosures in this note apply to all Registrants unless indicated otherwise.

Fair Value Measurements of Long-term Debt

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

The book values and fair values of Long-term Debt for the Registrants as of December 31, 2015 and 2014 are summarized in the following table:

	December 31,
	2015				2014
Company	Book Value		Fair Value		Book Value			Fair Value
	(in millions)
AEP	$	19,572.7	$	21,201.3	$	18,512.4	(a)	$	20,960.5	(b)
APCo	3,930.7		4,416.7		3,958.7			4,711.2
I&M	2,000.0		2,193.6		2,019.6			2,255.1
OPCo	2,157.7		2,472.7		2,286.8			2,709.5
PSO	1,286.1		1,402.9		1,036.7			1,216.2
SWEPCo	2,273.5		2,417.2		2,132.4			2,402.6

(a) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information.

(b) Amount excludes $114 million of fair value of Long-term Debt related to AEPRO.

Fair Value Measurements of Other Temporary Investments (Applies to AEP)

Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by its protected cell of EIS.  See “Other Temporary Investments” section of Note 1.

The following is a summary of Other Temporary Investments:

	December 31, 2015
Other Temporary Investments	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(in millions)
Restricted Cash (a)	$	271.0	$	—	$	—		$	271.0
Fixed Income Securities – Mutual Funds	91.1		—		(0.7		)	90.4
Equity Securities – Mutual Funds	13.7		11.7		—			25.4
Total Other Temporary Investments	$	375.8	$	11.7	$	(0.7	)	$	386.8

170

	December 31, 2014
Other Temporary Investments	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(in millions)
Restricted Cash (a)	$	279.7	$	—	$	—	$	279.7
Fixed Income Securities – Mutual Funds	80.5		—		—		80.5
Equity Securities – Mutual Funds	13.1		12.3		—		25.4
Total Other Temporary Investments	$	373.3	$	12.3	$	—	$	385.6

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

The following table provides the activity for fixed income and equity securities within Other Temporary Investments for the years ended December 31, 2015, 2014 and 2013:

	Years Ended December 31,
	2015		2014		2013
	(in millions)
Proceeds from Investment Sales	$	—	$	—	$	—
Purchases of Investments	10.7		1.6		17.4
Gross Realized Gains on Investment Sales	—		—		—
Gross Realized Losses on Investment Sales	—		—		—

As of December 31, 2015 and 2014, AEP had no Other Temporary Investments with an unrealized loss position.  As of December 31, 2015, 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 years ended December 31, 2015 and 2014, see Note 3.

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M)

Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value.  See “Nuclear Trust Funds” section of Note 1.

The following is a summary of nuclear trust fund investments as of December 31, 2015 and 2014:

	December 31,
	2015							2014
	Fair Value		Gross Unrealized Gains		Other-Than- Temporary Impairments			Fair Value		Gross Unrealized Gains		Other-Than- Temporary Impairments
	(in millions)
Cash and Cash Equivalents	$	168.3	$	—	$	—		$	20.0	$	—	$	—
Fixed Income Securities:
United States Government	731.1		35.9		(2.6		)	697.0		44.6		(5.0		)
Corporate Debt	57.9		3.2		(1.1		)	47.8		4.5		(1.0		)
State and Local Government	22.2		1.1		(0.3		)	208.5		1.2		(0.3		)
Subtotal Fixed Income Securities	811.2		40.2		(4.0		)	953.3		50.3		(6.3		)
Equity Securities – Domestic	1,126.9		571.6		(79.3		)	1,122.4		598.8		(79.2		)
Spent Nuclear Fuel and Decommissioning Trusts	$	2,106.4	$	611.8	$	(83.3	)	$	2,095.7	$	649.1	$	(85.5	)

171

The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2015, 2014 and 2013:

	Years Ended December 31,
	2015		2014		2013
	(in millions)
Proceeds from Investment Sales	$	2,218.4	$	1,031.8	$	858.4
Purchases of Investments	2,272.0		1,086.4		910.0
Gross Realized Gains on Investment Sales	69.1		32.3		18.3
Gross Realized Losses on Investment Sales	53.0		15.4		8.1

The adjusted cost of fixed income securities was $771 million and $903 million as of December 31, 2015 and 2014, respectively.  The adjusted cost of equity securities was $555 million and $524 million as of December 31, 2015 and 2014, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2015 was as follows:

	Fair Value of Fixed Income Securities
	(in millions)
Within 1 year	$	167.2
1 year – 5 years	361.0
5 years – 10 years	129.4
After 10 years	153.6
Total	$	811.2

172

Fair Value Measurements of Financial Assets and Liabilities

For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1.

The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014.  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.

AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2015
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Cash and Cash Equivalents (a)	$	3.9	$	4.3	$	—	$	168.2		$	176.4
Other Temporary Investments
Restricted Cash (a)	230.0		7.7		—		33.3			271.0
Fixed Income Securities – Mutual Funds	90.4		—		—		—			90.4
Equity Securities – Mutual Funds (b)	25.4		—		—		—			25.4
TotalOther Temporary Investments	345.8		7.7		—		33.3			386.8
Risk Management Assets
Risk Management Commodity Contracts (c) (d)	11.5		495.0		219.7		(287.7		)	438.5
Cash Flow Hedges:
Commodity Hedges (c)	—		15.9		1.0		0.7			17.6
Fair Value Hedges	—		—		—		0.1			0.1
Total Risk Management Assets	11.5		510.9		220.7		(286.9		)	456.2
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	160.5		—		—		7.8			168.3
Fixed Income Securities:
United States Government	—		731.1		—		—			731.1
Corporate Debt	—		57.9		—		—			57.9
State and Local Government	—		22.2		—		—			22.2
Subtotal Fixed Income Securities	—		811.2		—		—			811.2
Equity Securities – Domestic (b)	1,126.9		—		—		—			1,126.9
TotalSpent Nuclear Fuel and Decommissioning Trusts	1,287.4		811.2		—		7.8			2,106.4
Total Assets	$	1,648.6	$	1,334.1	$	220.7	$	(77.6	)	$	3,125.8
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)	$	24.1	$	471.5	$	67.3	$	(326.3	)	$	236.6
Cash Flow Hedges:
Commodity Hedges (c)	—		18.9		6.5		0.7			26.1
Interest Rate/Foreign Currency Hedges	—		0.4		—		—			0.4
Fair Value Hedges	—		3.0		—		0.1			3.1
Total Risk Management Liabilities	$	24.1	$	493.8	$	73.8	$	(325.5	)	$	266.2

173

AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2014
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Cash and Cash Equivalents (a)	$	17.2	$	0.9	$	—	$	144.4		$	162.5
Other Temporary Investments
Restricted Cash (a)	233.8		9.1		—		36.8			279.7
Fixed Income Securities – Mutual Funds	80.5		—		—		—			80.5
Equity Securities – Mutual Funds (b)	25.4		—		—		—			25.4
TotalOther Temporary Investments	339.7		9.1		—		36.8			385.6
Risk Management Assets
Risk Management Commodity Contracts (c) (f)	37.7		528.4		190.3		(303.7		)	452.7
Cash Flow Hedges:
Commodity Hedges (c)	—		31.9		—		(15.1		)	16.8
Fair Value Hedges	—		0.6		—		2.0			2.6
Total Risk Management Assets	37.7		560.9		190.3		(316.8		)	472.1
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	9.4		—		—		10.6			20.0
Fixed Income Securities:
United States Government	—		697.0		—		—			697.0
Corporate Debt	—		47.8		—		—			47.8
State and Local Government	—		208.5		—		—			208.5
Subtotal Fixed Income Securities	—		953.3		—		—			953.3
Equity Securities – Domestic (b)	1,122.4		—		—		—			1,122.4
TotalSpent Nuclear Fuel and Decommissioning Trusts	1,131.8		953.3		—		10.6			2,095.7
Total Assets	$	1,526.4	$	1,524.2	$	190.3	$	(125.0	)	$	3,115.9
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)	$	65.3	$	431.9	$	36.7	$	(335.5	)	$	198.4
Cash Flow Hedges:
Commodity Hedges (c)	—		26.6		2.8		(15.1		)	14.3
Interest Rate/Foreign Currency Hedges	—		1.0		—		—			1.0
Fair Value Hedges	—		6.8		—		2.0			8.8
Total Risk Management Liabilities	$	65.3	$	466.3	$	39.5	$	(348.6	)	$	222.5

174

APCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2015

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Restricted Cash for Securitized Funding (a)	$	14.8	$	—	$	—	$	0.1		$	14.9
Risk Management Assets – Nonaffiliated and Affiliated
Risk Management Commodity Contracts (c) (g)	0.2		13.9		12.2		(10.6		)	15.7
Total Assets	$	15.0	$	13.9	$	12.2	$	(10.5	)	$	30.6
Liabilities:
Risk Management Liabilities – Nonaffiliated
Risk Management Commodity Contracts (c) (g)	$	0.2	$	17.8	$	0.5	$	(13.6	)	$	4.9

APCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2014

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Restricted Cash for Securitized Funding (a)	$	15.6	$	—	$	—	$	—		$	15.6
Risk Management Assets – Nonaffiliated
Risk Management Commodity Contracts (c) (g)	0.2		20.2		17.7		(9.4		)	28.7
Total Assets	$	15.8	$	20.2	$	17.7	$	(9.4	)	$	44.3
Liabilities:
Risk Management Liabilities – Nonaffiliated
Risk Management Commodity Contracts (c) (g)	$	0.2	$	20.4	$	1.9	$	(9.4	)	$	13.1

175

I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2015

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Risk Management Assets – Nonaffiliated and Affiliated
Risk Management Commodity Contracts (c) (g)	$	0.1	$	17.0	$	6.3	$	(11.1	)	$	12.3
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	160.5		—		—		7.8			168.3
Fixed Income Securities:
United States Government	—		731.1		—		—			731.1
Corporate Debt	—		57.9		—		—			57.9
State and Local Government	—		22.2		—		—			22.2
Subtotal Fixed Income Securities	—		811.2		—		—			811.2
Equity Securities – Domestic (b)	1,126.9		—		—		—			1,126.9
TotalSpent Nuclear Fuel and Decommissioning Trusts	1,287.4		811.2		—		7.8			2,106.4
Total Assets	$	1,287.5	$	828.2	$	6.3	$	(3.3	)	$	2,118.7
Liabilities:
Risk Management Liabilities – Nonaffiliated
Risk Management Commodity Contracts (c) (g)	$	0.1	$	17.5	$	2.0	$	(11.7	)	$	7.9

I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2014

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Risk Management Assets – Nonaffiliated
Risk Management Commodity Contracts (c) (g)	$	0.1	$	15.9	$	16.0	$	(6.4	)	$	25.6
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	9.4		—		—		10.6			20.0
Fixed Income Securities:
United States Government	—		697.0		—		—			697.0
Corporate Debt	—		47.8		—		—			47.8
State and Local Government	—		208.5		—		—			208.5
Subtotal Fixed Income Securities	—		953.3		—		—			953.3
Equity Securities – Domestic (b)	1,122.4		—		—		—			1,122.4
TotalSpent Nuclear Fuel and Decommissioning Trusts	1,131.8		953.3		—		10.6			2,095.7
Total Assets	$	1,131.9	$	969.2	$	16.0	$	4.2		$	2,121.3
Liabilities:
Risk Management Liabilities – Nonaffiliated
Risk Management Commodity Contracts (c) (g)	$	0.2	$	11.4	$	1.3	$	(6.3	)	$	6.6

176

OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2015

	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)
Restricted Cash for Securitized Funding (a)	$	—	$	—	$	—	$	27.7	$	27.7
Risk Management Assets
Risk Management Commodity Contracts (c) (g)	—		—		16.0		3.2		19.2
Total Assets	$	—	$	—	$	16.0	$	30.9	$	46.9
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.8	$	0.1	$	2.7	$	3.6

OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2014

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Restricted Cash for Securitized Funding (a)	$	0.4	$	—	$	—	$	28.3		$	28.7
Risk Management Assets
Risk Management Commodity Contracts (c) (g)	—		—		52.3		—			52.3
Total Assets	$	0.4	$	—	$	52.3	$	28.3		$	81.0
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	1.1	$	3.9	$	(0.1	)	$	4.9

177

PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2015

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	0.7	$	(0.1	)	$	0.6
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.5	$	0.1	$	(0.4	)	$	0.2

PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2014

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	0.4	$	(0.4	)	$	—
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.6	$	0.7	$	(0.4	)	$	0.9

178

SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2015

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Cash and Cash Equivalents (a)	$	3.6	$	—	$	—	$	1.6		$	5.2
Risk Management Assets
Risk Management Commodity Contracts (c) (g)	—		—		0.9		(0.1		)	0.8
Total Assets	$	3.6	$	—	$	0.9	$	1.5		$	6.0
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	5.5	$	0.1	$	(0.4	)	$	5.2

SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2014

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Cash and Cash Equivalents (a)	$	12.7	$	—	$	—	$	1.7		$	14.4
Risk Management Assets
Risk Management Commodity Contracts (c) (g)	—		—		0.4		(0.4		)	—
Total Assets	$	12.7	$	—	$	0.4	$	1.3		$	14.4
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.7	$	0.9	$	(0.5	)	$	1.1

(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 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 December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. Risk management commodity contracts are substantially comprised of power contracts.

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

(f) The December 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018;  Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030;  Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030.  Risk management commodity contracts are substantially comprised of power contracts.

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

There have been no transfers between Level 1 and Level 2 during the years ended December 31, 2015, 2014 and 2013.

179

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:

Year Ended December 31, 2015	AEP			APCo (a)			I&M (a)			OPCo			PSO			SWEPCo
	(in millions)
Balance as of December 31, 2014	$	150.8		$	15.8		$	14.7		$	48.4		$	(0.3	)	$	(0.5	)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c)	13.5			2.1			0.2			0.5			(0.2		)	9.2
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b)	53.7			—			—			—			—			—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	(4.9		)	—			—			—			—			—
Purchases, Issuances and Settlements (d)	(63.0		)	(17.2		)	(14.2		)	(6.7		)	0.6			(8.7		)
Transfers into Level 3 (e) (f)	28.7			—			—			—			—			—
Transfers out of Level 3 (f) (g)	(18.9		)	1.2			0.8			—			—			—
Changes in Fair Value Allocated to Regulated Jurisdictions (h)	(13.0		)	9.8			2.8			(26.3		)	0.5			0.8
Balance as of December 31, 2015	$	146.9		$	11.7		$	4.3		$	15.9		$	0.6		$	0.8

Year Ended December 31, 2014	AEP			APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Balance as of December 31, 2013	$	117.9		$	10.6		$	7.2		$	2.9		$	—		$	—
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c)	90.0			29.7			18.6			30.8			—			—
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b)	0.7			—			—			—			—			—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	5.7			—			—			—			—			—
Purchases, Issuances and Settlements (d)	(108.7		)	(32.6		)	(20.6		)	(33.7		)	—			—
Transfers into Level 3 (e) (f)	(7.6		)	(3.6		)	(2.5		)	—			—			—
Transfers out of Level 3 (f) (g)	(21.5		)	—			—			—			—			—
Changes in Fair Value Allocated to Regulated Jurisdictions (h)	74.3			11.7			12.0			48.4			(0.3		)	(0.5		)
Balance as of December 31, 2014	$	150.8		$	15.8		$	14.7		$	48.4		$	(0.3	)	$	(0.5	)

180

Year Ended December 31, 2013	AEP			APCo			I&M			OPCo			PSO		SWEPCo
	(in millions)
Balance as of December 31, 2012	$	85.4		$	11.0		$	7.5		$	15.4		$	—	$	—
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c)	(9.2		)	(3.6		)	(2.4		)	(5.0		)	—		—
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b)	37.5			—			—			0.3			—		—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	(2.5		)	—			—			—			—		—
Purchases, Issuances and Settlements (d)	(15.8		)	0.5			0.4			0.8			—		—
Transfers into Level 3 (e) (f)	19.0			1.3			0.9			1.9			—		—
Transfers out of Level 3 (f) (g)	(3.6		)	(0.9		)	(0.6		)	(1.3		)	—		—
Transfer of OPCo Generation to Parent	—			—			—			(12.1		)	—		—
Changes in Fair Value Allocated to Regulated Jurisdictions (h)	7.1			2.3			1.4			2.9			—		—
Balance as of December 31, 2013	$	117.9		$	10.6		$	7.2		$	2.9		$	—	$	—

(a) Includes both affiliated and nonaffiliated transactions.

(b) Included in revenues on the statements of income.

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

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

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

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

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

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

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of December 31, 2015 and 2014:

Significant Unobservable Inputs

December 31, 2015

AEP

						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input	Low			High		Average
	(in millions)
Energy Contracts	$	212.3	$	70.3	Discounted Cash Flow	Forward Market Price (a)	$	9.69		$	165.36	$	36.35
						Counterparty Credit Risk (b)	670
FTRs	8.4		3.5		Discounted Cash Flow	Forward Market Price (a)	(6.99		)	10.34		1.10
Total	$	220.7	$	73.8

181

Significant Unobservable Inputs

December 31, 2014

AEP

						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input	Low			High		Average
	(in millions)
Energy Contracts	$	157.3	$	37.0	Discounted Cash Flow	Forward Market Price (a)	$	11.37		$	159.92	$	57.18
						Counterparty Credit Risk (b)	303
FTRs	33.0		2.5		Discounted Cash Flow	Forward Market Price (a)	(14.63		)	20.02		0.96
Total	$	190.3	$	39.5

Significant Unobservable Inputs

December 31, 2015

APCo

						Significant	Forward Price Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average
	(in millions)
Energy Contracts	$	7.9	$	0.2	Discounted Cash Flow	Forward Market Price	$	12.61		$	47.24	$	32.38
FTRs	4.3		0.3		Discounted Cash Flow	Forward Market Price	(6.96		)	8.43		1.34
Total	$	12.2	$	0.5

Significant Unobservable Inputs

December 31, 2014

APCo

						Significant	Forward Price Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average
	(in millions)
Energy Contracts	$	5.8	$	1.8	Discounted Cash Flow	Forward Market Price	$	13.43		$	123.02	$	52.47
FTRs	11.9		0.1		Discounted Cash Flow	Forward Market Price	(14.63		)	20.02		1.01
Total	$	17.7	$	1.9

182

Significant Unobservable Inputs

December 31, 2015

I&M

						Significant	Forward Price Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input(a)	Low			High		Average
	(in millions)
Energy Contracts	$	6.0	$	0.2	Discounted Cash Flow	Forward Market Price	$	12.61		$	47.24	$	32.38
FTRs	0.3		1.8		Discounted Cash Flow	Forward Market Price	(6.96		)	8.43		1.34
Total	$	6.3	$	2.0

Significant Unobservable Inputs

December 31, 2014

I&M

						Significant	Forward Price Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input(a)	Low			High		Average
	(in millions)
Energy Contracts	$	6.4	$	1.2	Discounted Cash Flow	Forward Market Price	$	13.43		$	123.02	$	52.47
FTRs	9.6		0.1		Discounted Cash Flow	Forward Market Price	(14.63		)	20.02		1.01
Total	$	16.0	$	1.3

Significant Unobservable Inputs

December 31, 2015

OPCo

Significant

Forward Price Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average

(in millions)

Energy Contracts

$

16.0

$

0.1

Discounted Cash Flow

Forward Market Price

$

41.61

$

165.36

$

86.84

Significant Unobservable Inputs

December 31, 2014

OPCo

						Significant	Forward Price Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average
	(in millions)
Energy Contracts	$	45.1	$	3.9	Discounted Cash Flow	Forward Market Price	$	48.25		$	159.92	$	84.04
FTRs	7.2		—		Discounted Cash Flow	Forward Market Price	(14.63		)	20.02		1.01
Total	$	52.3	$	3.9

183

Significant Unobservable Inputs

December 31, 2015

PSO

Significant

Forward Price Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average

(in millions)

FTRs

$

0.7

$

0.1

Discounted Cash Flow

Forward Market Price

$

(6.96

)

$

8.43

$

1.34

Significant Unobservable Inputs

December 31, 2014

PSO

Significant

Forward Price Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average

(in millions)

FTRs

$

0.4

$

0.7

Discounted Cash Flow

Forward Market Price

$

(14.63

)

$

20.02

$

1.01

Significant Unobservable Inputs

December 31, 2015

SWEPCo

Significant

Forward Price Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average

(in millions)

FTRs

$

0.9

$

0.1

Discounted Cash Flow

Forward Market Price

$

(6.96

)

$

8.43

$

1.34

Significant Unobservable Inputs

December 31, 2014

SWEPCo

Significant

Forward Price Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average

(in millions)

FTRs

$

0.4

$

0.9

Discounted Cash Flow

Forward Market Price

$

(14.63

)

$

20.02

$

1.01

(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.

184

The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of December 31, 2015 and 2014:

Sensitivity of Fair Value Measurements

Significant Unobservable Input	Position	Change in Input	Impact on Fair Value Measurement
Forward Market Price	Buy	Increase (Decrease)	Higher (Lower)
Forward Market Price	Sell	Increase (Decrease)	Lower (Higher)
Counterparty Credit Risk	Loss	Increase (Decrease)	Higher (Lower)
Counterparty Credit Risk	Gain	Increase (Decrease)	Lower (Higher)

185

12.  INCOME TAXES

The disclosures in this note apply to all Registrants unless indicated otherwise.

Income Tax Expense

The details of the Registrants’ income taxes before discontinued operations as reported are as follows:

AEP	Years Ended December 31,
	2015		2014		2013
	(in millions)
Federal:
Current	$	107.3	$	22.8	$	(53.4	)
Deferred	774.8		800.1		678.6
Total Federal	882.1		822.9		625.2
State and Local:
Current	14.5		22.8		28.7
Deferred	23.0		56.9		23.8
Total State and Local	37.5		79.7		52.5
Income Tax Expense Before Discontinued Operations	$	919.6	$	902.6	$	677.7

Year Ended December 31, 2015	APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Income Tax Expense (Credit):
Current	$	(32.9	)	$	5.2		$	89.0		$	(6.4	)	$	44.3
Deferred	227.5			94.2			37.6			58.3			41.9
Deferred Investment Tax Credits	(0.3		)	(3.3		)	(0.1		)	(0.6		)	(1.4		)
Income Tax Expense	$	194.3		$	96.1		$	126.5		$	51.3		$	84.8

Year Ended December 31, 2014	APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Income Tax Expense (Credit):
Current	$	10.9		$	14.3		$	58.1		$	(24.2	)	$	(171.6	)
Deferred	144.7			70.2			74.4			74.7			239.4
Deferred Investment Tax Credits	(0.7		)	(4.9		)	(0.3		)	0.1			(1.4		)
Income Tax Expense	$	154.9		$	79.6		$	132.2		$	50.6		$	66.4

Year Ended December 31, 2013	APCo			I&M			OPCo			PSO		SWEPCo
	(in millions)
Income Tax Expense (Credit):
Current	$	58.4		$	(49.1	)	$	92.6		$	7.7	$	(10.9	)
Deferred	75.7			129.1			134.5			53.8		81.9
Deferred Investment Tax Credits	(1.2		)	(4.9		)	(1.4		)	4.4		(1.5		)
Income Tax Expense	$	132.9		$	75.1		$	225.7		$	65.9	$	69.5

186

The following is a reconciliation for each Registrant of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported:

AEP	Years Ended December 31,
	2015				2014				2013
	(in millions)
Net Income	$	2,052.3			$	1,638.0			$	1,484.2
Discontinued Operations (Net of Income Tax of $6.2, $39 and $5.9 in 2015, 2014 and 2013, Respectively)	(283.7			)	(47.5			)	(10.3			)
Income Tax Expense Before Discontinued Operations	919.6				902.6				677.7
Pretax Income	$	2,688.2			$	2,493.1			$	2,151.6
Income Taxes on Pretax Income at Statutory Rate (35%)	$	940.9			$	872.6			$	753.1
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Depreciation	53.6				54.0				46.6
Investment Tax Credits, Net	(11.6			)	(12.8			)	(14.0			)
State and Local Income Taxes, Net	24.4				54.3				29.1
Removal Costs	(28.8			)	(23.9			)	(20.9			)
AFUDC	(51.6			)	(41.8			)	(30.5			)
Valuation Allowance	17.2				(2.5			)	5.1
U.K. Windfall Tax	—				—				(79.5			)
Other	(24.5			)	2.7				(11.3			)
Income Tax Expense Before Discontinued Operations	$	919.6			$	902.6			$	677.7
Effective Income Tax Rate	34.2		%		36.2		%		31.5		%

APCo	Years Ended December 31,
	2015				2014				2013
	(in millions)
Net Income	$	340.6			$	215.4			$	193.2
Income Tax Expense	194.3				154.9				132.9
Pretax Income	$	534.9			$	370.3			$	326.1
Income Taxes on Pretax Income at Statutory Rate (35%)	$	187.2			$	129.6			$	114.1
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Depreciation	19.8				23.5				20.3
Investment Tax Credits, Net	(0.3			)	(0.6			)	(1.2			)
State and Local Income Taxes, Net	7.2				6.5				2.7
Removal Costs	(9.9			)	(6.8			)	(6.5			)
AFUDC	(7.0			)	(3.8			)	(1.4			)
Valuation Allowance	1.7				(2.5			)	5.1
Other	(4.4			)	9.0				(0.2			)
Income Tax Expense	$	194.3			$	154.9			$	132.9
Effective Income Tax Rate	36.3		%		41.8		%		40.8		%

187

I&M	Years Ended December 31,
	2015				2014				2013
	(in millions)
Net Income	$	204.8			$	155.6			$	177.5
Income Tax Expense	96.1				79.6				75.1
Pretax Income	$	300.9			$	235.2			$	252.6
Income Taxes on Pretax Income at Statutory Rate (35%)	$	105.3			$	82.3			$	88.4
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Depreciation	9.5				12.9				10.1
Investment Tax Credits, Net	(3.3			)	(4.9			)	(4.9			)
State and Local Income Taxes, Net	5.8				7.7				(0.9			)
Removal Costs	(12.6			)	(11.3			)	(9.4			)
AFUDC	(6.2			)	(10.0			)	(10.6			)
Other	(2.4			)	2.9				2.4
Income Tax Expense	$	96.1			$	79.6			$	75.1
Effective Income Tax Rate	31.9		%		33.8		%		29.7		%

OPCo	Years Ended December 31,
	2015				2014				2013
	(in millions)
Net Income	$	232.7			$	216.4			$	410.0
Income Tax Expense	126.5				132.2				225.7
Pretax Income	$	359.2			$	348.6			$	635.7
Income Taxes on Pretax Income at Statutory Rate (35%)	$	125.7			$	122.0			$	222.5
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Depreciation	8.2				6.7				6.8
Investment Tax Credits, Net	(0.1			)	(0.2			)	(1.4			)
State and Local Income Taxes, Net	0.7				8.8				3.3
Other	(8.0			)	(5.1			)	(5.5			)
Income Tax Expense	$	126.5			$	132.2			$	225.7
Effective Income Tax Rate	35.2		%		37.9		%		35.5		%

PSO	Years Ended December 31,
	2015				2014				2013
	(in millions)
Net Income	$	92.5			$	86.9			$	97.8
Income Tax Expense	51.3				50.6				65.9
Pretax Income	$	143.8			$	137.5			$	163.7
Income Taxes on Pretax Income at Statutory Rate (35%)	$	50.3			$	48.1			$	57.3
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Depreciation	0.5				0.2				0.2
Investment Tax Credits, Net	(1.8			)	(0.8			)	(0.8			)
State and Local Income Taxes, Net	5.1				4.8				5.4
AFUDC	(3.1			)	(1.1			)	(1.5			)
Tax Adjustments	(0.3			)	(1.2			)	5.3
Other	0.6				0.6				—
Income Tax Expense	$	51.3			$	50.6			$	65.9
Effective Income Tax Rate	35.7		%		36.8		%		40.3		%

188

SWEPCo	Years Ended December 31,
	2015				2014				2013
	(in millions)
Net Income	$	196.0			$	144.6			$	153.8
Income Tax Expense	84.8				66.4				69.5
Pretax Income	$	280.8			$	211.0			$	223.3
Income Taxes on Pretax Income at Statutory Rate (35%)	$	98.3			$	73.8			$	78.1
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Depreciation	3.1				2.9				3.1
Depletion	(5.5			)	(4.1			)	(3.5			)
Investment Tax Credits, Net	(1.4			)	(1.4			)	(1.5			)
State and Local Income Taxes, Net	4.8				3.1				(1.4			)
AFUDC	(9.2			)	(4.2			)	(2.4			)
Other	(5.3			)	(3.7			)	(2.9			)
Income Tax Expense	$	84.8			$	66.4			$	69.5
Effective Income Tax Rate	30.2		%		31.5		%		31.1		%

Net Deferred Tax Liability

The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant:

AEP	December 31,
	2015			2014
	(in millions)
Deferred Tax Assets	$	2,503.9		$	2,650.7
Deferred Tax Liabilities	(14,237.1		)	(13,503.1		)
Net Deferred Tax Liabilities	$	(11,733.2	)	$	(10,852.4	)
Property Related Temporary Differences	$	(8,533.3	)	$	(7,883.4	)
Amounts Due from Customers for Future Federal Income Taxes	(263.5		)	(255.2		)
Deferred State Income Taxes	(872.0		)	(796.9		)
Securitized Assets	(633.2		)	(753.2		)
Regulatory Assets	(873.6		)	(694.1		)
Deferred Income Taxes on Other Comprehensive Loss	72.2			59.7
Accrued Nuclear Decommissioning	(614.6		)	(611.0		)
Net Operating Loss Carryforward	39.6			46.4
Tax Credit Carryforward	85.0			144.3
Valuation Allowance	(130.0		)	(55.6		)
All Other, Net	(9.8		)	(53.4		)
Net Deferred Tax Liabilities	$	(11,733.2	)	$	(10,852.4	)

189

APCo	December 31,
	2015			2014
	(in millions)
Deferred Tax Assets	$	412.9		$	446.4
Deferred Tax Liabilities	(2,939.9		)	(2,711.2		)
Net Deferred Tax Liabilities	$	(2,527.0	)	$	(2,264.8	)
Property Related Temporary Differences	$	(1,866.0	)	$	(1,801.9	)
Amounts Due from Customers for Future Federal Income Taxes	(68.2		)	(70.4		)
Deferred State Income Taxes	(308.7		)	(239.7		)
Regulatory Assets	(169.1		)	(113.7		)
Securitized Assets	(114.8		)	(122.6		)
Deferred Income Taxes on Other Comprehensive Loss	1.5			(2.7		)
Net Operating Loss Carryforward	1.0			9.8
Tax Credit Carryforward	19.2			46.2
All Other, Net	(21.9		)	30.2
Net Deferred Tax Liabilities	$	(2,527.0	)	$	(2,264.8	)

I&M	December 31,
	2015			2014
	(in millions)
Deferred Tax Assets	$	837.4		$	911.8
Deferred Tax Liabilities	(2,198.9		)	(2,190.0		)
Net Deferred Tax Liabilities	$	(1,361.5	)	$	(1,278.2	)
Property Related Temporary Differences	$	(521.6	)	$	(418.7	)
Amounts Due from Customers for Future Federal Income Taxes	(42.7		)	(40.6		)
Deferred State Income Taxes	(124.8		)	(138.9		)
Deferred Income Taxes on Other Comprehensive Loss	9.0			7.7
Accrued Nuclear Decommissioning	(614.6		)	(611.0		)
Regulatory Assets	(70.2		)	(74.7		)
All Other, Net	3.4			(2.0		)
Net Deferred Tax Liabilities	$	(1,361.5	)	$	(1,278.2	)

OPCo	December 31,
	2015			2014
	(in millions)
Deferred Tax Assets	$	162.4		$	171.8
Deferred Tax Liabilities	(1,545.6		)	(1,528.1		)
Net Deferred Tax Liabilities	$	(1,383.2	)	$	(1,356.3	)
Property Related Temporary Differences	$	(1,022.8	)	$	(926.5	)
Amounts Due from Customers for Future Federal Income Taxes	(44.6		)	(47.6		)
Deferred State Income Taxes	(34.4		)	(34.2		)
Regulatory Assets	(220.0		)	(242.4		)
Deferred Income Taxes on Other Comprehensive Loss	(2.3		)	(3.0		)
Deferred Fuel and Purchased Power	(117.4		)	(145.5		)
All Other, Net	58.3			42.9
Net Deferred Tax Liabilities	$	(1,383.2	)	$	(1,356.3	)

190

PSO	December 31,
	2015			2014
	(in millions)
Deferred Tax Assets	$	141.2		$	110.7
Deferred Tax Liabilities	(1,113.0		)	(1,016.7		)
Net Deferred Tax Liabilities	$	(971.8	)	$	(906.0	)
Property Related Temporary Differences	$	(861.9	)	$	(805.2	)
Amounts Due from Customers for Future Federal Income Taxes	(2.2		)	(0.7		)
Deferred State Income Taxes	(117.0		)	(109.3		)
Regulatory Assets	(54.3		)	(39.6		)
Deferred Income Taxes on Other Comprehensive Loss	(2.3		)	(2.7		)
Deferred Federal Income Taxes on Deferred State Income Taxes	46.6			43.9
Net Operating Loss Carryforward	7.1			6.4
Tax Credit Carryforward	0.6			0.7
All Other, Net	11.6			0.5
Net Deferred Tax Liabilities	$	(971.8	)	$	(906.0	)

SWEPCo	December 31,
	2015			2014
	(in millions)
Deferred Tax Assets	$	194.7		$	186.1
Deferred Tax Liabilities	(1,594.5		)	(1,528.2		)
Net Deferred Tax Liabilities	$	(1,399.8	)	$	(1,342.1	)
Property Related Temporary Differences	$	(1,275.1	)	$	(1,235.1	)
Amounts Due from Customers for Future Federal Income Taxes	(47.8		)	(44.1		)
Deferred State Income Taxes	(132.3		)	(124.1		)
Regulatory Assets	(26.1		)	(19.4		)
Deferred Income Taxes on Other Comprehensive Loss	5.0			4.0
Impairment Loss - Turk Plant	20.7			21.1
Net Operating Loss Carryforward	19.7			21.9
All Other, Net	36.1			33.6
Net Deferred Tax Liabilities	$	(1,399.8	)	$	(1,342.1	)

AEP System Tax Allocation Agreement

AEP and subsidiaries join in the filing of 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 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.

Valuation Allowance (Applies to AEP)

AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions.

191

On the basis of this evaluation, AEP recorded a valuation allowance of $17 million in the fourth quarter of 2015 related to the expected expiration of charitable contribution carryforward deductions and realized capital losses. In the fourth quarter of 2015 AEP also reversed a valuation allowance originally recorded in the third quarter of 2015 of $156 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of AEP’s investment in the operations of AEPRO. With the sale of AEPRO in the fourth quarter of 2015, AEP recorded a valuation allowance of $48 million attributable to realized capital losses from the sale.

A valuation allowance of $130 million and $56 million was recorded against AEP’s deferred tax asset balance as of December 31, 2015 and 2014, respectively. The valuation allowance reflects management’s assessment of the amount of its deferred tax assets that are more than likely not to be realized. The amount of the deferred tax assets realizable, however, could be adjusted if estimates of future taxable income are materially impacted during the carryforward period.

Federal and State Income Tax Audit Status

AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011.  The IRS examination of years 2011, 2012 and 2013 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 Registrants 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.

AEP and subsidiaries file income tax returns in various state, local and foreign jurisdictions.  These taxing authorities routinely examine their tax returns. AEP and 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 Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.

Net Income Tax Operating Loss Carryforward

In 2012 and 2011, AEP recognized federal net income tax operating losses of $366 million and $226 million, respectively, and in 2011, APCo and I&M recognized federal net income tax operating losses of $313 million and $123 million, respectively. The losses for AEP, APCo and I&M were driven primarily by bonus depreciation, pension plan contributions and other book versus tax temporary differences.  In 2012, SWEPCo recognized federal net income tax operating losses of $858 million which were driven primarily by bonus depreciation.  As of December 31, 2013, AEP had $156 million of unrealized federal net operating loss carryforward tax benefits.  Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full. AEP recognized deferred state and local income tax benefits in 2012 and 2011. AEP, APCo, OPCo, PSO and SWEPCo also have state net income tax operating loss carryforwards as of December 31, 2015 as indicated in the table below:

Company	State	State Net Income Tax Operating Loss Carryforward		Year of Expiration
		(in millions)
AEP	Kentucky	$	80.7	2035
AEP	Louisiana	376.3		2030
AEP	Oklahoma	378.1		2035
AEP	West Virginia	49.9		2033
APCo	West Virginia	24.8		2033
OPCo	West Virginia	25.2		2033
PSO	Oklahoma	181.8		2035
SWEPCo	Louisiana	375.7		2030
SWEPCo	Oklahoma	3.2		2035

192

As a result, APCo, OPCo, PSO and SWEPCo recognized deferred state and local income tax benefits in 2011, and/or 2012, and/or 2013, and/or 2014 and/or 2015.  At the end of 2013, APCo, I&M and SWEPCo had $12 million, $13 million and $167 million, respectively, of unrealized federal net operating loss carryforward.  Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full.  Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state.

As of December 31, 2013, AEP had $121 million of uncertain tax positions netted against the federal net income tax operating loss carryforward tax benefits. Due to the utilization of the net operating loss carryforward in 2014, $69 million is presented as a non-current uncertain tax position. As of December 31, 2015 and 2014, AEP had $59 million and $52 million, respectively, of uncertain tax positions netted against deferred tax liabilities.

Tax Credit Carryforward

Federal and state net income tax operating losses sustained in 2012, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits.  As of December 31, 2015, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below.  If these credits are not utilized, federal general business tax credits will expire in the years 2030 through 2035.

Company	Total Federal Tax Credit Carryforward		Federal Tax Credit Carryforward Subject to Expiration		Total State Tax Credit Carryforward		State Tax Credit Carryforward Subject to Expiration
	(in millions)
AEP	$	85.0	$	47.8	$	23.4	$	23.4
APCo	19.1		5.8		—		—
I&M	3.7		3.2		—		—
OPCo	19.3		1.0		—		—
PSO	0.6		0.6		23.4		23.4
SWEPCo	0.7		0.6		—		—

The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused.  In November 2014, APCo received an order from the Virginia SCC for its 2014 Virginia Biennial Base Rate Case (see Note 4). As a result of the final determination pertaining to the ability to realize future tax benefits for certain state net income tax operating loss and credit carryforwards, management determined that APCo is subject to the Virginia Minimum Tax on electric suppliers and the Virginia State Income Tax is no longer applicable. As a result, management derecognized the related state income tax benefits, which had been subject to valuation allowances.

Uncertain Tax Positions

In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes.  AEP filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case.  As a result of the favorable U.S. Supreme Court decision, AEP recognized a tax benefit of $80 million, plus $43 million of pretax interest income in the second quarter of 2013.  The tax benefit and interest income resulted in an increase in net income of $108 million, but did not result in the receipt of cash as of December 31, 2015. Due to the timing of the IRS audit cycle, receipt of cash is not expected within the next 12 months.

The Registrants recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.”

193

The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense:

	Years Ended December 31,
	2015						2014
Company	Interest Expense		Interest Income		Reversal of Prior Period Interest Expense		Interest Expense		Interest Income		Reversal of Prior Period Interest Expense
	(in millions)
AEP	$	2.7	$	0.8	$	—	$	2.9	$	1.2	$	2.0
APCo	0.4		—		—		—		—		0.2
I&M	0.2		—		—		—		—		0.3
OPCo	1.0		—		—		0.1		—		0.2
PSO	0.1		—		—		0.1		—		0.1
SWEPCo	0.4		—		—		0.2		—		0.2

	Year Ended December 31, 2013
Company	Interest Expense		Interest Income		Reversal of Prior Period Interest Expense
	(in millions)
AEP	$	1.5	$	51.8	$	—
APCo	—		1.1		—
I&M	—		0.6		—
OPCo	—		1.9		—
PSO	—		0.1		—
SWEPCo	0.2		—		—

The following table shows balances for amounts accrued for the receipt of interest:

	December 31,
Company	2015		2014
	(in millions)
AEP	$	44.7	$	44.0
APCo	—		—
I&M	—		—
OPCo	—		—
PSO	—		—
SWEPCo	—		—

The following table shows balances for amounts accrued for the payment of interest and penalties:

	December 31,
Company	2015		2014
	(in millions)
AEP	$	7.2	$	5.9
APCo	—		—
I&M	0.6		0.5
OPCo	0.6		0.4
PSO	0.4		0.3
SWEPCo	1.4		1.0

194

The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows:

	AEP			APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Balance as of January 1, 2015	$	182.0		$	—	$	2.3	$	6.9	$	1.3	$	7.5
Increase – Tax Positions Taken During a Prior Period	5.4			0.3		0.1		—		—		1.8
Decrease – Tax Positions Taken During a Prior Period	(0.4		)	—		—		—		—		—
Increase – Tax Positions Taken During the Current Year	—			—		—		—		—		—
Decrease – Tax Positions Taken During the Current Year	—			—		—		—		—		—
Increase – Settlements with Taxing Authorities	—			—		—		—		—		—
Decrease – Settlements with Taxing Authorities	—			—		—		—		—		—
Decrease – Lapse of the Applicable Statute of Limitations	—			—		—		—		—		—
Balance as of December 31, 2015	$	187.0		$	0.3	$	2.4	$	6.9	$	1.3	$	9.3

	AEP			APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Balance as of January 1, 2014	$	175.2		$	1.2		$	3.2		$	2.1		$	2.2		$	7.6
Increase – Tax Positions Taken During a Prior Period	18.2			—			1.4			6.4			—			1.6
Decrease – Tax Positions Taken During a Prior Period	(1.5		)	—			—			—			—			(0.8		)
Increase – Tax Positions Taken During the Current Year	—			—			—			—			—			—
Decrease – Tax Positions Taken During the Current Year	—			—			—			—			—			—
Increase – Settlements with Taxing Authorities	—			—			—			—			—			—
Decrease – Settlements with Taxing Authorities	(0.6		)	—			(0.7		)	—			—			—
Decrease – Lapse of the Applicable Statute of Limitations	(9.3		)	(1.2		)	(1.6		)	(1.6		)	(0.9		)	(0.9		)
Balance as of December 31, 2014	$	182.0		$	—		$	2.3		$	6.9		$	1.3		$	7.5

	AEP			APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Balance as of January 1, 2013	$	267.2		$	5.3		$	15.1		$	11.1		$	2.3		$	9.5
Increase – Tax Positions Taken During a Prior Period	—			—			—			—			—			—
Decrease – Tax Positions Taken During a Prior Period	(93.6		)	(4.1		)	(11.9		)	(9.0		)	(0.1		)	(3.2		)
Increase – Tax Positions Taken During the Current Year	1.8			—			—			—			—			1.3
Decrease – Tax Positions Taken During the Current Year	—			—			—			—			—			—
Decrease – Settlements with Taxing Authorities	—			—			—			—			—			—
Decrease – Lapse of the Applicable Statute of Limitations	(0.2		)	—			—			—			—			—
Balance as of December 31, 2013	$	175.2		$	1.2		$	3.2		$	2.1		$	2.2		$	7.6

195

Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date.  The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant was as follows:

Company	2015		2014		2013
	(in millions)
AEP	$	100.2	$	97.2	$	86.9
APCo	0.2		—		—
I&M	1.6		1.6		1.2
OPCo	4.5		4.5		0.7
PSO	0.9		0.9		0.8
SWEPCo	6.0		4.9		4.4

Federal Tax Legislation

The American Taxpayer Relief Act of 2012 (the 2012 Act) was enacted in January 2013.  Included in the 2012 Act was a one-year extension of the 50% bonus depreciation.  The 2012 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2011.  The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2013.

The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2015.

The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 and with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit. The enacted provisions did not materially impact the Registrants’ net income or financial condition but will have a favorable impact on future cash flows.

Federal Tax Regulations

In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014.  In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry.  These final regulations did not materially impact the Registrants’ net income, cash flows or financial condition.

State Tax Legislation

Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5%.  The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012, with the final reduction occurring in years beginning after June 30, 2015.

During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds.  As a result, the West Virginia corporate income tax rate was reduced from 7% to 6.5% in 2014.  

House Bill 32 was passed by the state of Texas in June 2015, permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016.

The enacted provisions did not materially impact net income, cash flows or financial condition.

196

13.   LEASES

The disclosures in this note apply to all Registrants unless indicated otherwise.

Leases of property, plant and equipment are for remaining periods up to 34 years and require payments of related property taxes, maintenance and operating costs.  The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.

Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations.  Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period.  Capital leases for nonregulated property are accounted for as if the assets were owned and financed.  The components of rental costs are as follows:

Year Ended December 31, 2015	AEP			APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Net Lease Expense on Operating Leases	$	292.6		$	16.4	$	88.3	$	7.6	$	5.4	$	6.7
Amortization of Capital Leases	108.5			5.6		40.7		3.9		3.5		13.7
Interest on Capital Leases	25.1			0.8		3.3		0.6		0.7		6.2
Total Lease Rental Costs	$	426.2	(a)	$	22.8	$	132.3	$	12.1	$	9.6	$	26.6

Year Ended December 31, 2014	AEP			APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Net Lease Expense on Operating Leases	$	303.9		$	18.3	$	93.4	$	6.6	$	3.2	$	5.5
Amortization of Capital Leases	109.4			5.5		44.4		5.7		4.2		14.9
Interest on Capital Leases	26.1			1.0		2.8		1.2		0.7		7.4
Total Lease Rental Costs	$	439.4	(a)	$	24.8	$	140.6	$	13.5	$	8.1	$	27.8

Year Ended December 31, 2013	AEP			APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Net Lease Expense on Operating Leases	$	326.6		$	17.5	$	95.6	$	57.8	$	4.1	$	6.3
Amortization of Capital Leases	73.9			6.3		11.3		7.8		4.1		15.5
Interest on Capital Leases	28.3			1.4		1.9		4.1		0.8		8.1
Total Lease Rental Costs	$	428.8	(a)	$	25.2	$	108.8	$	69.7	$	9.0	$	29.9

(a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million, $96 million and $103 million for the Years Ended December 31, 2015, 2014 and 2013, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.

197

The following table shows the property, plant and equipment under capital leases and related obligations recorded on the Registrants’ balance sheets.  Unless shown as a separate line on the balance sheets due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets.

December 31, 2015	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Property, Plant and Equipment Under Capital Leases:
Generation	$	128.2	$	43.4	$	14.5	$	—	$	9.6	$	34.5
Other Property, Plant and Equipment	439.3		17.6		68.2		23.4		18.6		165.1
Total Property, Plant and Equipment	567.5		61.0		82.7		23.4		28.2		199.6
Accumulated Amortization	214.1		15.6		19.7		10.2		13.6		91.3
Net Property, Plant and Equipment Under Capital Leases	$	353.4	$	45.4	$	63.0	$	13.2	$	14.6	$	108.3
Obligations Under Capital Leases:
Noncurrent Liability	$	247.3	$	39.1	$	30.2	$	9.3	$	10.9	$	75.6
Liability Due Within One Year	96.2		6.3		32.8		3.9		3.7		21.9
Total Obligations Under Capital Leases	$	343.5	$	45.4	$	63.0	$	13.2	$	14.6	$	97.5

December 31, 2014	AEP			APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Property, Plant and Equipment Under Capital Leases:
Generation	$	104.4		$	14.1	$	18.7	$	—	$	9.6	$	35.4
Other Property, Plant and Equipment	683.0			19.4		100.4		22.6		16.5		159.5
Total Property, Plant and Equipment	787.4			33.5		119.1		22.6		26.1		194.9
Accumulated Amortization	240.0			14.0		15.9		8.0		11.8		80.1
Net Property, Plant and Equipment Under Capital Leases	$	547.4	(a)	$	19.5	$	103.2	$	14.6	$	14.3	$	114.8
Obligations Under Capital Leases:
Noncurrent Liability	$	440.4		$	14.4	$	61.1	$	11.0	$	10.9	$	91.0
Liability Due Within One Year	111.4			5.1		42.1		3.6		3.4		17.6
Total Obligations Under Capital Leases	$	551.8	(a)	$	19.5	$	103.2	$	14.6	$	14.3	$	108.6

(a) Amounts include Net Property Under Capital Leases that have been classified as Assets from Discontinued Operations in the amount of $179 million and Total Obligations Under Capital Leases that have been classified as Liabilities from Discontinued Operations in the amount of $189 million on the December 31, 2014 balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.

198

Future minimum lease payments consisted of the following as of December 31, 2015:

Capital Leases	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2016	$	112.9	$	9.8	$	36.6	$	4.4	$	4.3	$	26.1
2017	76.2		9.4		12.1		4.0		4.1		18.2
2018	54.9		8.4		6.5		3.1		2.9		12.7
2019	38.7		6.4		3.0		1.0		1.6		11.4
2020	27.7		5.7		2.7		0.6		1.0		9.7
Later Years	110.7		26.5		20.3		1.4		2.6		40.3
Total Future Minimum Lease Payments	421.1		66.2		81.2		14.5		16.5		118.4
Less Estimated Interest Element	77.6		20.8		18.2		1.3		1.9		20.9
Estimated Present Value of Future Minimum Lease Payments	$	343.5	$	45.4	$	63.0	$	13.2	$	14.6	$	97.5
Noncancelable Operating Leases	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2016	$	239.1	$	15.6	$	92.7	$	8.8	$	4.8	$	6.3
2017	228.7		15.2		90.9		8.3		3.9		5.3
2018	219.9		13.8		89.7		6.9		3.5		4.8
2019	211.2		12.4		88.5		5.4		2.9		4.5
2020	202.8		11.8		85.1		4.5		2.4		4.2
Later Years	452.3		36.0		173.8		20.2		4.7		16.5
Total Future Minimum Lease Payments	$	1,554.0	$	104.8	$	620.7	$	54.1	$	22.2	$	41.6

Master Lease Agreements

The Registrants 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 Registrants 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 December 31, 2015, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows:

Company	Maximum Potential Loss
	(in millions)
AEP	$	33.4
APCo	4.8
I&M	3.2
OPCo	5.3
PSO	2.8
SWEPCo	3.4

199

Rockport Lease (Applies to AEP and I&M)

AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant).  The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022.  The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M.  The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note.  The lease term is for 33 years with potential renewal options.  At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant.  AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt.  The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2015 are as follows:

Future Minimum Lease Payments	AEP (a)		I&M
	(in millions)
2016	$	147.8	$	73.9
2017	147.8		73.9
2018	147.8		73.9
2019	147.8		73.9
2020	147.8		73.9
Later Years	295.0		147.5
Total Future Minimum Lease Payments	$	1,034.0	$	517.0

(a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M.

Railcar Lease (Applies to AEP, I&M and SWEPCo)

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 $10 million and $11 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2015.  These obligations are included in the future minimum lease payments schedule earlier in this note.

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 83% of the projected fair value of the equipment under the current five-year lease term to 77% at the end of the 20-year term.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  The maximum potential losses related to the guarantee are $9 million and $10 million for I&M and SWEPCo, respectively, as of December 31, 2015, 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.

AEPRO Boat and Barge Leases (Applies to AEP)

In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. See “AEPRO (Corporate and Other)” section of Note 7. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2026. As of December 31, 2015,

200

the maximum potential amount of future payments required under the guaranteed leases was $94 million. In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of December 31, 2015, AEP’s boat and barge lease guarantee liability was $16 million.

Sabine Dragline Lease (Applies to AEP and SWEPCo)

During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million.  The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational.  These capital lease assets are included in Other Property, Plant and Equipment on the balance sheets.  The short-term and long-term capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on SWEPCo’s balance sheets.  The future payment obligations are included in SWEPCo’s future minimum lease payments schedule earlier in this note.

I&M Nuclear Fuel Lease (Applies to AEP and I&M)

In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant.  In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million.  The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months.  The future payment obligations of $35 million are included in I&M’s future minimum lease payments schedule earlier in this note.  The net capital lease asset is included in Other Property, Plant and Equipment on the balance sheets.  The short-term capital lease obligations are included in Other Current Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on I&M’s balance sheets.  The long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets.  The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2015 are as follows, based on estimated fuel burn:

Future Minimum Lease Payments	I&M
	(in millions)
2016	$	26.9
2017	5.8
2018	2.4
Total Future Minimum Lease Payments	$	35.1

201

14.  FINANCING ACTIVITIES

The disclosures in this note apply to all Registrants unless indicated otherwise.

Common Stock (Applies to AEP)

Listed below is a reconciliation of common stock share activity for the years ended December 31, 2015, 2014 and 2013:

Shares of AEP Common Stock	Issued	Held in Treasury
Balance, December 31, 2012	506,004,962	20,336,592
Issued	2,109,002	—
Balance, December 31, 2013	508,113,964	20,336,592
Issued	1,625,195	—
Balance, December 31, 2014	509,739,159	20,336,592
Issued	1,650,014	—
Balance, December 31, 2015	511,389,173	20,336,592

202

Long-term Debt

The following details long-term debt outstanding as of December 31, 2015 and 2014:

		Weighted
		Average
		Interest
		Rate as of	Interest Rate Ranges as of		Outstanding as of
		December 31,	December 31,		December 31,
Company	Maturity	2015	2015	2014	2015		2014
AEP					(in millions)
Senior Unsecured Notes	2015-2045	5.09%	1.65%-8.13%	1.65%-8.13%	$	13,629.1	$	12,562.1
Pollution Control Bonds (a)	2015-2038 (b)	2.71%	0.01%-6.30%	0.04%-6.30%	1,784.8		1,951.8
Notes Payable – Nonaffiliated (c)	2016-2032	2.47%	0.925%-6.60%	0.983%-8.03%	264.7		274.1		(d)
Securitization Bonds	2015-2031	3.66%	0.88%-6.25%	0.88%-6.25%	2,024.0		2,360.9
Spent Nuclear Fuel Obligation (e)					265.6		265.5
Other Long-term Debt	2015-2059	1.62%	1.15%-13.718%	1.15%-13.718%	1,604.5		1,098.0
Total Long-term Debt Outstanding					$	19,572.7	$	18,512.4	(d)
APCo
Senior Unsecured Notes	2015-2045	5.39%	3.40%-7.00%	3.40%-7.95%	$	2,970.4	$	2,976.1
Pollution Control Bonds (a)	2015-2038 (b)	1.70%	0.01%-5.375%	0.04%-5.375%	616.5		530.6
Notes Payable – Affiliated	2015			3.125%	—		86.0
Securitization Bonds	2024-2031	2.85%	2.008%-3.772%	2.008%-3.772%	341.5		363.7
Other Long-term Debt	2026	13.718%	13.718%	13.718%	2.3		2.3
Total Long-term Debt Outstanding					$	3,930.7	$	3,958.7
I&M
Senior Unsecured Notes	2015-2037	5.82%	3.20%-7.00%	3.20%-7.00%	$	1,117.0	$	1,240.8
Pollution Control Bonds (a)	2015-2025 (b)	1.79%	0.01%-4.625%	0.04%-4.625%	225.1		224.8
Notes Payable – Nonaffiliated (c)	2016-2019	1.02%	0.925%-2.12%	0.983%-2.12%	175.5		176.7
Spent Nuclear Fuel Obligation (e)					265.6		265.5
Other Long-term Debt	2015-2025	2.14%	1.81%-6.00%	1.55%-6.00%	216.8		111.8
Total Long-term Debt Outstanding					$	2,000.0	$	2,019.6
OPCo
Senior Unsecured Notes	2016-2035	5.98%	5.375%-6.60%	5.375%-6.60%	$	1,938.9	$	1,937.3
Pollution Control Bonds (a)	2015-2038 (b)	5.80%	5.80%	3.125%-5.80%	32.2		118.2
Securitization Bonds	2018-2020	1.56%	0.958%-2.049%	0.958%-2.049%	185.3		229.9
Other Long-term Debt	2028	1.15%	1.15%	1.15%	1.3		1.4
Total Long-term Debt Outstanding					$	2,157.7	$	2,286.8
PSO
Senior Unsecured Notes	2016-2045	5.11%	3.17%-6.625%	4.40%-6.625%	$	1,142.7	$	893.0
Pollution Control Bonds (a)	2020	4.45%	4.45%	4.45%	12.6		12.6
Other Long-term Debt	2016-2027	1.80%	1.587%-3.00%	1.482%-3.00%	130.8		131.1
Total Long-term Debt Outstanding					$	1,286.1	$	1,036.7
SWEPCo
Senior Unsecured Notes	2015-2045	5.28%	3.55%-6.45%	3.55%-6.45%	$	1,961.0	$	1,816.9
Pollution Control Bonds (a)	2015-2019 (b)	3.62%	1.60%-4.95%	3.25%-4.95%	134.5		134.4
Notes Payable – Nonaffiliated (c)	2024-2032	5.15%	4.58%-6.37%	4.58%-6.37%	78.6		81.9
Other Long-term Debt	2017	1.82%	1.82%	1.73%	99.4		99.2
Total Long-term Debt Outstanding					$	2,273.5	$	2,132.4

203

(a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment.  Certain series may be purchased on demand at periodic interest adjustment dates.  Letters of credit from banks and insurance policies support certain series.

(b) Certain pollution control bonds are subject to redemption earlier than the maturity date.  Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets.

(c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates.

(d) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.

(e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6).

Long-term debt outstanding as of December 31, 2015 is payable as follows:

	AEP			APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
2016	$	1,831.8		$	318.0		$	162.9		$	395.9		$	275.4		$	3.3
2017	2,689.6			273.5			68.5			46.4			0.5			353.3
2018	1,726.9			124.0			318.0			397.0			0.5			384.9
2019	1,813.2			180.4			484.1			48.0			250.5			456.7
2020	368.2			24.9			1.8			0.1			13.1			3.3
After 2020	11,262.4			3,045.0			975.1			1,283.1			753.5			1,087.4
Principal Amount	19,692.1			3,965.8			2,010.4			2,170.5			1,293.5			2,288.9
Unamortized Discount, Net and Debt Issuance Costs	(119.4		)	(35.1		)	(10.4		)	(12.8		)	(7.4		)	(15.4		)
Total Long-term Debt Outstanding	$	19,572.7		$	3,930.7		$	2,000.0		$	2,157.7		$	1,286.1		$	2,273.5

In January 2016 and February 2016, I&M retired $14 million and $8 million, respectively, of Notes Payable related to DCC Fuel.

In January 2016, APCo retired $75 million of variable rate Pollution Control Bonds due in 2016 and issued $75 million of variable rate Pollution Control Bonds due on demand.

In January 2016, OPCo retired $23 million of Securitization Bonds.

In January 2016, TCC retired $128 million of Securitization Bonds.

In February 2016, APCo retired $11 million of Securitization Bonds.

In February 2016, Transource Missouri drew $3 million on an existing $300 million variable rate credit facility due in 2018.

As of December 31, 2015, trustees held, on behalf of AEP, $554 million of their reacquired Pollution Control Bonds. Of this total, $40 million and $345 million related to I&M and OPCo, respectively.

Dividend Restrictions

Parent Restrictions (Applies to AEP)

The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends.  Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries.

Pursuant to the leverage restrictions in credit agreements, AEP 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.  As of December 31, 2015, none of AEP’s retained earnings were restricted for the purpose of the payment of dividends.

204

Utility Subsidiaries’ Restrictions

AEP utility 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 subsidiaries to transfer funds to Parent in the form of dividends.  

Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%. As of December 31, 2015, the amount of restricted net assets of AEP’s subsidiaries that may not be distributed to Parent in the form of a loan, advance or dividend was $8.1 billion. As of December 31, 2015, none of APCo’s retained earnings had restrictions related to the payment of dividends to Parent, while $92 million, $105 million and $354 million of I&M’s, PSO’s and SWEPCo’s retained earnings, respectively, had restrictions related to the payment of dividends to Parent.

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.” As of December 31, 2015, this restriction did not limit the ability of the utility subsidiaries to pay dividends out of retained earnings.

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

Lines of Credit and Short-term Debt (Applies to AEP)

AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain 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.  As of December 31, 2015, AEP had credit facilities totaling $3.5 billion to support its commercial paper program.  The maximum amount of commercial paper outstanding during 2015 was $788 million and the weighted average interest rate of commercial paper outstanding during 2015 was 0.46%.  AEP’s outstanding short-term debt was as follows:

	December 31,
	2015				2014
Type of Debt	Outstanding Amount		Interest Rate (a)		Outstanding Amount		Interest Rate (a)
	(in millions)				(in millions)
Securitized Debt for Receivables (b)	$	675.0	0.30	%	$	744.0	0.22	%
Commercial Paper	125.0		0.81	%	602.0		0.59	%
Total Short-term Debt	$	800.0			$	1,346.0

(a) Weighted average rate.

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

205

Corporate Borrowing Program – AEP System (Applies to Registrant Subsidiaries)

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 certain AEP 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 December 31, 2015 and 2014 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets.  The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the years ended December 31, 2015 and 2014 are described in the following tables:

Year Ended December 31, 2015:

	Maximum				Average				Net Loans to
	Borrowings		Maximum		Borrowings		Average		(Borrowings from)			Authorized
	from the		Loans to the		from the		Loans to the		the Utility Money			Short-term
	Utility		Utility		Utility		Utility		Pool as of			Borrowing
Company	Money Pool		Money Pool		Money Pool		Money Pool		December 31, 2015			Limit
	(in millions)
APCo	$	211.2	$	694.8	$	82.0	$	79.0	$	(155.4	)	$	600.0
I&M	297.3		13.5		152.6		13.5		(282.6		)	500.0
OPCo	—		367.5		—		266.6		331.1			400.0
PSO	165.9		152.5		113.1		86.8		80.6			300.0
SWEPCo	112.5		299.9		48.1		103.4		(58.3		)	350.0

Year Ended December 31, 2014:

	Maximum				Average				Net Loans to
	Borrowings		Maximum		Borrowings		Average		(Borrowings from)			Authorized
	from the		Loans to the		from the		Loans to the		the Utility Money			Short-term
	Utility		Utility		Utility		Utility		Pool as of			Borrowing
Company	Money Pool		Money Pool		Money Pool		Money Pool		December 31, 2014			Limit
	(in millions)
APCo	$	44.2	$	542.2	$	12.6	$	104.5	$	48.5		$	600.0
I&M	150.7		158.9		73.2		39.1		(129.0		)	500.0
OPCo	120.3		405.4		34.8		107.3		312.5			400.0
PSO	177.0		—		93.7		—		(154.2		)	300.0
SWEPCo	153.5		51.3		71.0		24.4		41.0			350.0

The activity in the above tables does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2015 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the year ended December 31, 2015, Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool:

Maximum		Average		Loans
Loans		Loans		to the
to the		to the		Nonutility
Nonutility		Nonutility		Money Pool as of
Money Pool		Money Pool		December 31, 2015
(in millions)
$	2.0	$	2.0	$	2.0

206

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

	Years Ended December 31,
	2015		2014		2013
Maximum Interest Rate	0.87	%	0.59	%	0.43	%
Minimum Interest Rate	0.37	%	0.24	%	0.24	%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the years ended December 31, 2015, 2014 and 2013 are summarized for all Registrant Subsidiaries in the following table:

	Average Interest Rate  for Funds Borrowed from the Utility Money Pool for Years Ended December 31,						Average Interest Rate  for Funds Loaned to the Utility Money Pool for Years Ended December 31,
Company	2015		2014		2013		2015		2014		2013
APCo	0.53	%	0.29	%	0.33	%	0.47	%	0.29	%	0.33	%
I&M	0.49	%	0.31	%	0.36	%	0.48	%	0.30	%	0.32	%
OPCo	—	%	0.27	%	0.33	%	0.48	%	0.34	%	0.32	%
PSO	0.49	%	0.29	%	0.34	%	0.48	%	—	%	0.33	%
SWEPCo	0.53	%	0.29	%	0.34	%	0.48	%	0.32	%	0.36	%

Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool for the year ended December 31, 2015 are summarized for Mutual Energy SWEPCo, LLC in the following table:

	Maximum		Minimum		Average
	Interest Rate		Interest Rate		Interest Rate
	for Funds		for Funds		for Funds
	Loaned to		Loaned to		Loaned to
Year Ended	the Nonutility		the Nonutility		the Nonutility
December 31,	Money Pool		Money Pool		Money Pool
2015	0.87	%	0.37	%	0.48	%

Interest expense related to short-term borrowing activities with the Utility Money Pool and the Nonutility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ statements of income.  The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows:

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
APCo	$	0.2	$	—	$	0.4
I&M	0.8		0.1		0.1
OPCo	—		—		0.5
PSO	0.1		0.3		—
SWEPCo	0.1		0.2		—

207

Interest income related to short-term lending activities with the Utility Money Pool and the Nonutility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ statements of income.  The Registrant Subsidiaries earned interest income for all short-term lending activities as follows:

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
APCo	$	0.4	$	0.3	$	0.1
I&M	0.1		0.1		0.9
OPCo	1.3		0.2		0.2
PSO	0.4		—		0.1
SWEPCo	0.4		—		0.1

Interest expense and interest income related to the Nonutility Money Pool are included in Interest Expense and Interest Income, respectively, in SWEPCo’s statements of income.  For amounts borrowed from and advanced to the Nonutility Money Pool, SWEPCo incurred $4 thousand of interest income for the year ended December 31, 2015.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 6.

Sale of Receivables – AEP Credit (Applies to AEP)

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.  These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.

AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables.  The agreement was increased in June 2014 from $700 million and expires in June 2017.

Accounts receivable information for AEP Credit is as follows:

	Years Ended December 31,
	2015			2014			2013
	(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable	0.30		%	0.22		%	0.23		%
Net Uncollectible Accounts Receivable Written Off	$	34.1		$	40.1		$	34.9

	December 31,
	2015		2014
	(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts	$	924.8	$	974.5
Total Principal Outstanding	675.0		744.0
Delinquent Securitized Accounts Receivable	48.3		43.9
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable	17.5		12.9
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable	357.8		335.4

AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.

208

Sale of Receivables – AEP Credit (Applies to Registrant Subsidiaries)

Under this 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’ statements of income.  The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of December 31, 2015 and 2014 was as follows:

	December 31,
Company	2015		2014
	(in millions)
APCo	$	135.4	$	159.8
I&M	134.8		137.5
OPCo	351.4		365.8
PSO	116.1		112.9
SWEPCo	151.8		148.7

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

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
APCo	$	7.6	$	8.9	$	6.5
I&M	8.4		7.9		6.5
OPCo	30.7		28.8		21.6
PSO	5.8		5.9		5.6
SWEPCo	7.0		6.8		5.9

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

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
APCo	$	1,453.8	$	1,519.3	$	1,443.0
I&M	1,553.0		1,488.6		1,458.8
OPCo	2,569.4		2,647.6		2,620.5
PSO	1,326.1		1,321.1		1,232.4
SWEPCo	1,597.8		1,655.8		1,533.8

209

15.  STOCK-BASED COMPENSATION

The disclosures in this note apply to AEP only. The impact of AEP’s share-based compensation plans is insignificant to the financial statements of the Registrant Subsidiaries.

AEP’s long-term incentive plan available for eligible employees and directors, the Amended and Restated American Electric Power System Long-Term Incentive Plan (the “Prior Plan”), was replaced prospectively for new grants by the American Electric Power System 2015 Long-Term Incentive Plan (the “2015 LTIP”) effective in April 2015. The 2015 LTIP provides for a maximum of 10 million common shares to be available for grant to eligible employees and directors. As of December 31, 2015, 9,964,153 shares remained available for issuance under the 2015 LTIP plan. No new awards may be granted under the Prior Plan. To the extent the issuance of a share that is subject to an outstanding award under the Prior Plan, the issuance of that share will take place under the Prior Plan. The 2015 LTIP awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards and other stock-based awards. If a share is issued pursuant to a stock option or a stock appreciation right, it will reduce the aggregate amount authorized under the 2015 LTIP by 0.286 of a share. If a share is issued for any other award, it will reduce the aggregate amount authorized under the 2015 LTIP by one share. The following sections provide further information regarding each type of stock-based compensation award granted by the Human Resources Committee of AEP’s Board of Directors (HR Committee).

Stock Options

AEP did not grant stock options in 2015, 2014 or 2013. AEP did have outstanding stock options from grants in earlier periods that were exercised in 2013.  As of December 31, 2015, AEP has no outstanding stock options.  AEP recorded compensation cost for stock options over the vesting period based on the fair value on the grant date.  The 2015 LTIP specifies a maximum contractual term of 10 years for stock options.

The total intrinsic value of options exercised is as follows:

	Years Ended December 31,
Stock Options	2015		2014		2013
	(in millions)
Intrinsic Value of Options Exercised (a)	$	—	$	—	$	3.1

(a) Intrinsic value is calculated as market price at exercise dates less the option exercise price.

A summary of AEP stock option transactions during the years ended December 31, 2015, 2014 and 2013 is as follows:

	2015		2014		2013
	Options	Weighted Average Exercise Price	Options	Weighted Average Exercise Price	Options		Weighted Average Exercise Price
	(in thousands)		(in thousands)		(in thousands)
Outstanding as of January 1,	—	NA	—	NA	188.5		$	30.17
Granted	—	NA	—	NA	—		NA
Exercised/Converted	—	NA	—	NA	(187.5	)	30.18
Forfeited/Expired	—	NA	—	NA	(1.0	)	27.95
Outstanding as of December 31,	—	NA	—	NA	—		NA
Options Exercisable as of December 31,	—	NA	—	NA	—		NA
NA   Not applicable.

AEP includes the proceeds received from exercised stock options in common stock and paid-in capital.

210

Performance Units

Pursuant to the 2015 LTIP, AEP’s performance units are paid out in cash rather than AEP shares. For that reason, AEP’s performance units no longer reduce the aggregate share authorization. AEP’s performance units have a fair value upon vesting equal to the average closing market price of AEP common stock for the last 20 trading days of the performance period.  The number of performance units held at the end of the three year performance period is multiplied by the performance score to determine the actual number of performance units realized.  The performance score can range from 0% to 200% and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the HR Committee.  Certain employees must satisfy stock ownership requirements. If those employees have not met their stock ownership requirements, their performance units are mandatorily deferred as AEP career shares.  AEP career shares are a form of non-qualified deferred compensation that has a value equivalent to shares of AEP common stock.  AEP career shares are paid in cash after the participant’s termination of employment.  Amounts equivalent to cash dividends on both performance units and AEP career shares accrue as additional units.  Management records compensation cost for performance units over a three-year vesting period.  The liability for both the performance units and AEP career shares, recorded in Employee Benefits and Pension Obligations on the balance sheets, is adjusted for changes in value. 

The HR Committee awarded performance units and reinvested dividends on outstanding performance units and AEP career shares for the years ended December 31, 2015, 2014 and 2013 as follows:

	Years Ended December 31,
Performance Units	2015		2014		2013
Awarded Units (in thousands)	575.0		16.9		1,284.2
Weighted Average Unit Fair Value at Grant Date	$	59.19	$	49.73	$	46.23
Vesting Period (in years)	3		3		3

Performance Units and AEP Career Shares (Reinvested Dividends Portion)	Years Ended December 31,
	2015		2014		2013
Awarded Units (in thousands)	103.6		98.9		100.9
Weighted Average Fair Value at Grant Date	$	54.35	$	53.35	$	45.42
Vesting Period (in years)	(a)		(a)		(a)

(a) The vesting period for the reinvested dividends on performance units is equal to the remaining life of the related performance units.  Dividends on AEP career shares vest immediately when the dividend is awarded but are not paid in cash until after the participant’s employment ends.

Performance scores and final awards are determined and certified by the HR Committee in accordance with the pre-established performance measures within approximately a month after the end of the performance period. The performance scores for all open performance periods are dependent on two equally-weighted performance measures: (a) three-year total shareholder return measured relative to the Standard and Poor’s 500 Electric Utilities Index and (b) three-year cumulative earnings per share measured relative to a target approved by AEP’s Board of Directors.

The certified performance scores and units earned for the three-year periods ended December 31, 2015, 2014 and 2013 were as follows:

	Years Ended December 31,
Performance Units	2015		2014		2013
Certified Performance Score	176.3	%	147.8	%	118.8	%
Performance Units Earned	1,202,107		889,697		749,219
Performance Units Mandatorily Deferred as AEP Career Shares	41,707		40,831		72,883
Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program	54,074		39,526		39,691
Performance Units to be Paid in Cash	1,106,326		809,340		636,645

211

The cash payouts for the years ended December 31, 2015, 2014 and 2013 were as follows:

	Years Ended December 31,
Performance Units and AEP Career Shares	2015		2014		2013
	(in millions)
Cash Payouts for Performance Units	$	48.1	$	29.3	$	43.9
Cash Payouts for AEP Career Share Distributions	3.0		4.3		3.7

Restricted Stock Units

The HR Committee grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments.  The RSUs accrue dividends. Additional RSUs granted as dividends vest on the same date as the underlying RSUs. RSUs are converted into a share of AEP common stock upon vesting, except for AEP’s officers subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934, who are paid in cash.  In 2014, there were no RSUs granted to Section 16 officers due to a change that deferred granting these and other awards until February 2015. For RSUs paid in shares, compensation cost is measured at fair value on the grant date and recorded over the vesting period.  Fair value is determined by multiplying the number of RSUs granted by the grant date market closing price.  For RSUs paid in cash, compensation cost is recorded over the vesting period and adjusted for changes in fair value until vested.  The fair value at vesting is determined by multiplying the number of RSUs vested by the 20-day average closing price of AEP common stock.  The maximum contractual term of outstanding RSUs is approximately 40 months from the grant date.

In 2010, the HR Committee granted a total of 165,520 RSUs to four Chief Executive Officer succession candidates as a retention incentive for these candidates.  These grants vested in three approximately equal installments on August 3, 2013, August 3, 2014 and August 3, 2015.  

The HR Committee awarded RSUs, including additional units awarded as dividends, for the years ended December 31, 2015, 2014 and 2013 as follows:

	Years Ended December 31,
Restricted Stock Units	2015		2014		2013
Awarded Units (in thousands)	397.5		64.1		644.4
Weighted Average Grant Date Fair Value	$	58.56	$	50.36	$	46.24

The total fair value and total intrinsic value of restricted stock units vested during the years ended December 31, 2015, 2014 and 2013 were as follows:

	Years Ended December 31,
Restricted Stock Units	2015		2014		2013
	(in millions)
Fair Value of Restricted Stock Units Vested	$	18.3	$	18.7	$	15.3
Intrinsic Value of Restricted Stock Units Vested (a)	24.2		24.9		20.4

(a) Intrinsic value is calculated as market price at exercise date.

212

A summary of the status of AEP’s nonvested RSUs as of December 31, 2015 and changes during the year ended December 31, 2015 are as follows:

Nonvested Restricted Stock Units	Shares/Units		Weighted Average Grant Date Fair Value
	(in thousands)
Nonvested as of January 1, 2015	783.0		$	44.59
Granted	397.5		58.56
Vested	(425.4	)	42.94
Forfeited	(33.8	)	51.07
Nonvested as of December 31, 2015	721.3		52.48

The total aggregate intrinsic value of nonvested RSUs as of December 31, 2015 was $41 million and the weighted average remaining contractual life was 1.9 years.

Other Stock-Based Plans

AEP also has a Stock Unit Accumulation Plan for Non-Employee Directors providing each non-employee director with AEP stock units as a substantial portion of their quarterly compensation for their services as a director.  The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned.  Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units.  The stock units granted to Non-Employee Directors are fully vested upon grant date.  Stock units are paid in cash upon termination of board service or up to 10 years later if the participant so elects.  Cash payments for stock units are calculated based on the average closing price of AEP common stock for the last 20 trading days prior to the distribution date. After five years of service on the Board of Directors, non-employee directors receive contributions to an AEP stock fund awarded under the Stock Unit Accumulation Plan.

Management records compensation cost for stock units when the units are awarded and adjusts the liability for changes in value based on the current 20-day average closing price of AEP common stock on the valuation date.

The cash payouts for stock unit distributions for the years ended December 31, 2015, 2014 and 2013 were $1 million, $5 million and $2 million, respectively.

The Board of Directors awarded stock units, including units awarded for dividends, for the years ended December 31, 2015, 2014 and 2013 as follows:

	Years Ended December 31,
Stock Unit Accumulation Plan for Non-Employee Directors	2015		2014		2013
Awarded Units (in thousands)	24.9		25.4		32.7
Weighted Average Grant Date Fair Value	$	55.46	$	54.08	$	45.81

213

Share-based Compensation Plans

Compensation cost for share-based payment arrangements, the actual tax benefit realized from the tax deductions for compensation cost for share-based payment arrangements recognized in income and total compensation cost capitalized in relation to the cost of an asset for the years ended December 31, 2015, 2014 and 2013 were as follows:

	Years Ended December 31,
Share-based Compensation Plans	2015		2014		2013
	(in millions)
Compensation Cost for Share-based Payment Arrangements (a)	$	63.8	$	85.4	$	56.4
Actual Tax Benefit Realized	22.3		29.9		19.7
Total Compensation Cost Capitalized	20.3		23.1		13.2

(a) Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.

During the years ended December 31, 2015, 2014 and 2013, there were no significant modifications affecting any of the AEP’s share-based payment arrangements.

As of December 31, 2015, there was $72 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the 2015 LTIP and Prior Plan. Unrecognized compensation cost related to unvested share-based arrangements will change as the fair value of performance units and AEP career shares is adjusted each period and as forfeitures for all award types are realized.  AEP’s unrecognized compensation cost will be recognized over a weighted-average period of 1.4 years.

Cash received from stock options exercised and actual tax benefit realized for the tax deductions from stock options exercised during the years ended December 31, 2015, 2014 and 2013 were as follows:

	Years Ended December 31,
Share-based Compensation Plans	2015		2014		2013
	(in millions)
Cash Received from Stock Options Exercised	$	—	$	—	$	5.7
Actual Tax Benefit Realized for the Tax Deductions from Stock Options Exercised	—		—		1.0

AEP’s practice is to use authorized but unissued shares to fulfill share commitments for stock option exercises and RSU vesting.  Although management does not currently anticipate any changes to this practice, management is permitted to use treasury shares, shares acquired in the open market specifically for distribution under the 2015 LTIP and Prior Plan or any combination thereof for this purpose.  The number of new shares issued to fulfill vesting RSUs is generally reduced to offset AEP’s tax withholding obligation.

214

16.  RELATED PARTY TRANSACTIONS

The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise.

For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 14.

Interconnection Agreement

In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO₂ emission allowances associated with transactions under the Interconnection Agreement was also terminated.

APCo, I&M, KPCo, OPCo and AEPSC were parties to the Interconnection Agreement which defined the sharing of costs and benefits associated with the respective generation plants.  This sharing was based upon each AEP utility subsidiary’s MLR and was calculated monthly on the basis of each AEP utility subsidiary’s maximum peak demand in relation to the sum of the maximum peak demands of all four AEP utility subsidiaries during the preceding 12 months.

Effective January 1, 2014, the FERC approved the following agreements. See “Corporate Separation” section of Note 1.

• A Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo.

• A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent to address open commitments related to the termination of the Interconnection Agreement and responsibilities to PJM.

• A Power Supply Agreement between AGR and OPCo for AGR to supply capacity and the energy needs of OPCo’s retail load.

AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Effective January 1, 2014 and revised in May 2015, power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. Prior to January 1, 2014, power and natural gas risk management activities were allocated under the SIA to former members of the Interconnection Agreement, PSO and SWEPCo. Risk management activities primarily include power and natural gas physical transactions, financially-settled swaps and exchange-traded futures.  AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts. Effective January 1, 2014 and with the transfer of OPCo’s generation assets to AGR, AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf.

Operating Agreement (Applies to PSO and SWEPCo)

PSO, SWEPCo and AEPSC are parties to the Operating Agreement which was approved by the FERC.  The Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies as capacity commitments. In January 2014, the FERC approved a modification of the Operating Agreement to address changes resulting from an anticipated March 2014 SPP power market change. Subsequently and in March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In alignment with the new SPP integrated power market and according to the modified Operating Agreement, PSO and SWEPCo operate as standalone entities and offer their respective generation into the SPP power market. SPP then economically dispatches resources. By offering their resources separately, PSO and SWEPCo no longer purchase or sell energy to each other to serve their respective internal load or off-system sales.

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System Integration Agreement (SIA) (Applies to APCo, I&M, PSO and SWEPCo)

Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM and MISO generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo.  Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies.

The SIA was designed to function as an umbrella agreement in addition to the Interconnection Agreement (prior to January 1, 2014) and the Operating Agreement, each of which controlled the distribution of revenues and expenses.

Affiliated Revenues and Purchases

The following tables show the revenues derived from sales under the Interconnection Agreement, direct sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2015, 2014 and 2013:

Related Party Revenues	APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Year Ended December 31, 2015
Direct Sales to East Affiliates	$	132.1	$	—	$	—	$	—	$	—
Auction Sales to OPCo (a)	10.6		17.1		—		—		—
Direct Sales to AEPEP	—		—		29.7		—		(0.2		)
Transmission Agreement and Transmission Coordination Agreement Sales	0.7		8.4		35.5		0.2		15.2
Other Revenues	4.4		1.9		18.9		4.4		1.6
Total Affiliated Revenues	$	147.8	$	27.4	$	84.1	$	4.6	$	16.6

Related Party Revenues	APCo			I&M		OPCo		PSO		SWEPCo
	(in millions)
Year Ended December 31, 2014
Sales under Interconnection Agreement (b)	$	0.2		$	0.5	$	1.1	$	—	$	—
Direct Sales to East Affiliates	141.7			—		—		3.8		10.1
Direct Sales to West Affiliates	0.6			0.4		—		—		0.3
Direct Sales to AEPEP	—			—		44.1		—		—
Transmission Agreement and Transmission Coordination Agreement Sales	(1.6		)	1.7		104.1		—		14.1
Other Revenues	3.6			1.6		15.9		3.3		1.8
Total Affiliated Revenues	$	144.5		$	4.2	$	165.2	$	7.1	$	26.3

Related Party Revenues	APCo		I&M			OPCo		PSO		SWEPCo
	(in millions)
Year Ended December 31, 2013
Sales under Interconnection Agreement	$	193.7	$	218.2		$	924.3	$	—	$	—
Direct Sales to East Affiliates	129.0		—			152.7		—		—
Direct Sales to West Affiliates	0.6		0.4			0.8		10.8		35.4
Direct Sales to AEPEP	—		—			—		—		(0.1		)
Transmission Agreement and Transmission Coordination Agreement Sales	0.4		(0.7		)	53.4		—		14.7
Other Revenues	23.8		1.5			35.7		3.4		1.8
Total Affiliated Revenues	$	347.5	$	219.4		$	1,166.9	$	14.2	$	51.8

(a)    Refer to the Ohio Auctions section below for further information regarding these amounts.

(b)    Includes December 2013 true-up activity subsequent to agreement termination.

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The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and from affiliates for the years ended December 31, 2015, 2014 and 2013:

Related Party Purchases	APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Year Ended December 31, 2015
Direct Purchases from AGR	$	—	$	—	$	238.5	$	—	$	—
Auction Purchases from AEPEP (a)	—		—		225.2		—		—
Auction Purchases from AEPSC (a)	—		—		32.7		—		—
Direct Purchases from AEGCo	—		232.1		—		—		—
Total Affiliated Purchases	$	—	$	232.1	$	496.4	$	—	$	—

Related Party Purchases	APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Year Ended December 31, 2014
Purchases under Interconnection Agreement (b)	$	4.7	$	1.6	$	0.1	$	—	$	—
Direct Purchases from East Affiliates	—		—		—		1.0		—
Direct Purchases from West Affiliates	—		—		—		10.0		3.8
Direct Purchases from AGR	—		—		1,148.2		—		—
Direct Purchases from AEPEP	—		—		44.4		—		—
Direct Purchases from AEGCo	—		268.4		—		—		—
Total Affiliated Purchases	$	4.7	$	270.0	$	1,192.7	$	11.0	$	3.8

Related Party Purchases	APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Year Ended December 31, 2013
Purchases under Interconnection Agreement	$	830.9	$	181.7	$	199.3	$	—	$	—
Direct Purchases from East Affiliates	—		—		—		1.5		0.4
Direct Purchases from West Affiliates	—		—		—		35.4		10.8
Direct Purchases from AEGCo	—		251.5		148.4		—		—
Natural Gas Purchases from AEPES	—		—		2.0		—		—
Total Affiliated Purchases	$	830.9	$	433.2	$	349.7	$	36.9	$	11.2

(a)    Refer to the Ohio Auctions section below for further information regarding this amount.

(b)    Includes December 2013 true-up activity subsequent to agreement termination.

The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income.  Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses.

System Transmission Integration Agreement (STIA)

AEP’s STIA provided for the integration and coordination of the planning, operation and maintenance of transmission facilities. Since the FERC approved the cancellation of the STIA effective June 1, 2014, the coordinated planning, operation and maintenance of transmission facilities are the responsibility of the RTOs and the STIA is no longer necessary. Similar to the SIA, the STIA functioned as an umbrella agreement in addition to the Transmission Agreement (TA) and the Transmission Coordination Agreement (TCA). The TA and TCA are both still active. The STIA contained two service schedules that governed:

• The allocation of transmission costs and revenues.

• The allocation of third-party transmission costs and revenues and AEP System dispatch costs.

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APCo, I&M, KGPCo, KPCo, OPCo and WPCo are parties to the TA, effective November 2010, which defines how transmission costs through PJM OATT are allocated among the AEP East Companies, KGPCo and WPCo on a 12-month average coincident peak basis.

The following table shows the net charges recorded by the Registrant Subsidiaries for the years ended December 31, 2015, 2014 and 2013 related to the TA:

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
APCo	$	92.7	$	84.7	$	40.6
I&M	38.0		39.7		19.9
OPCo	81.0		17.0		8.9

The charges shown above are recorded in Other Operation expenses on the statements of income.

PSO, SWEPCo and AEPSC are parties to the TCA, dated January 1, 1997, by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries.  The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement.  This includes the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff.

Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf.  The allocations have been governed by the FERC-approved OATT for the SPP.

The following table shows the net (revenues) expenses allocated among parties to the TCA pursuant to the SPP OATT protocols as described above for the years ended December 31, 2015, 2014 and 2013:

	Years Ended December 31,
Company	2015			2014			2013
	(in millions)
PSO	$	15.0		$	14.1		$	14.7
SWEPCo	(15.0		)	(14.1		)	(14.7		)

The net (revenues) expenses shown above are recorded in Sales to AEP Affiliates on SWEPCo’s statements of income and Other Operation expenses on PSO’s statements of income.

Ohio Auctions (Applies to APCo, I&M and OPCo)

In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEPEP, APCo, KPCo, I&M and WPCo participated in the auction process and were awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. See Note 10 - Derivatives and Hedging for further information.

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Unit Power Agreements (UPA) (Applies to I&M and OPCo)

Lawrenceburg UPA

In March 2007, OPCo and AEGCo entered into a 10-year UPA for the entire output from the Lawrenceburg Generating Station effective with AEGCo’s purchase of the plant in May 2007.  Effective January 1, 2014, the Lawrenceburg UPA was assigned by OPCo to AGR. AGR has an option to extend the UPA for an additional two years.  I&M operates the plant under an agreement with AEGCo.  Under the UPA, AGR pays AEGCo for the capacity, depreciation, fuel, operation and maintenance and tax expenses.  These payments are due regardless of whether the plant is operating.  The fuel and operation and maintenance payments are based on actual costs incurred.  All expenses are trued up periodically.

UPA between AEGCo and I&M

A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility.  Subsequently, I&M assigns 30% of the power to KPCo.  See the “UPA between AEGCo and KPCo” section below.  I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC.  The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances.

UPA between AEGCo and KPCo

Pursuant to an assignment between I&M and KPCo and a UPA between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant.  KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement.  The KPCo UPA ends in December 2022.

Cook Coal Terminal (Applies to I&M, OPCo, PSO and SWEPCo)

On August 1, 2013, OPCo transferred its interest in Cook Coal Terminal to AEGCo.  Cook Coal Terminal performs coal transloading and storage services at cost for I&M and OPCo.  OPCo included revenues for these services in Other Revenues – Affiliated and expenses in Other Operation expenses on the statements of income.  The coal transloading expenses in 2015, 2014 and 2013 were as follows:

AEGCo

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
I&M	$	15.8	$	16.2	$	6.8
OPCo	—		—		0.3

OPCo

	Years Ended December 31,
Company	2013
	(in millions)
I&M	$	15.6	(a)

(a) Includes $7 million in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013.

I&M and OPCo recorded the cost of transloading services in Fuel on the balance sheet.

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Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo.  Beginning August 1, 2013 and through corporate separation in Ohio on December 31, 2013, Cook Coal Terminal also performed railcar maintenance services at cost for OPCo.  OPCo included revenues for these services in Sales to AEP Affiliates and expenses in Other Operation expenses on the statements of income.  The railcar maintenance revenues in 2015, 2014 and 2013 were as follows:

AEGCo

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
I&M	$	2.0	$	2.5	$	1.1
PSO	0.2		0.3		0.1
SWEPCo	2.8		3.3		1.2

OPCo

	Years Ended December 31,
Company	2013
	(in millions)
I&M	$	1.3	(a)
PSO	0.1
SWEPCo	1.2

(a) Includes $608 thousand in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013.

I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets.

I&M Barging, Urea Transloading and Other Services (Applies to APCo, I&M and OPCo)

I&M provides barging, urea transloading and other transportation services to affiliates.  Urea is a chemical used to control NO_x emissions at certain generation plants in the AEP System.  I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income.  The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses.  The amounts of affiliated expenses were:

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
AEGCo	$	16.1	$	22.7	$	19.7
AGR	4.9		5.2		—
APCo	37.7		36.1		30.9
KPCo	4.6		5.0		0.1
OPCo	—		—		40.6
AEP River Operations LLC – (Nonutility Subsidiary of AEP)	15.5		25.3		22.6

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Services Provided by AEP River Operations LLC (Applies to I&M)

AEP River Operations LLC provided services for barge towing, chartering and general and administrative expenses to I&M.  The costs are recorded by I&M as Other Operation expenses.  In October 2015, AEP signed a Purchase and Sale Agreement to sell AEP River Operations LLC to a nonaffiliated party. The sale closed in November 2015. For the years ended December 31, 2015, 2014 and 2013, I&M recorded expenses of $19 million, $24 million and $24 million, respectively, for these activities.

Central Machine Shop

APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System.  APCo defers the cost of performing these services on the balance sheet, then transfers the cost to the affiliate for reimbursement.  The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received.  These billings are recoverable from customers.  The following table provides the amounts billed by APCo to the following affiliates:

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
AEGCo	$	0.1	$	0.1	$	—
AGR	2.7		2.8		—
I&M	2.5		1.7		2.5
KPCo	1.3		1.2		0.7
OPCo	—		—		4.7
PSO	0.2		0.3		0.6
SWEPCo	0.8		0.1		0.2

Affiliate Railcar Agreement (Applies to APCo, I&M, PSO and SWEPCo)

Certain AEP subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available.  The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar.  The AEP subsidiaries recorded these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on the balance sheets and such costs are recoverable from customers.  The following tables show the net effect of the railcar agreement on the balance sheets:

	December 31, 2015
	Billing Company
Billed Company	APCo		I&M		PSO		SWEPCo
	(in millions)
APCo	$	—	$	—	$	0.3	$	0.3
I&M	—		—		0.4		1.2
PSO	—		0.6		—		0.6
SWEPCo	—		1.8		0.6		—

	December 31, 2014
	Billing Company
Billed Company	APCo		I&M		PSO		SWEPCo
	(in millions)
I&M	$	0.3	$	—	$	0.1	$	1.1
PSO	0.1		1.3		—		0.7
SWEPCo	0.1		2.2		0.2		—

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OVEC (Applies to APCo, I&M and OPCo)

AEP and several nonaffiliated utility companies jointly own OVEC.  As of December 31, 2015, the ownership and investment in OVEC were as follows:

	December 31, 2015
Company	Ownership		Investment
			(in millions)
Parent	39.17	%	$	4.0
OPCo	4.30	%	0.4
Total	43.47	%	$	4.4

OVEC’s owners, along with APCo and I&M, are members to an intercompany power agreement.  Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios.  The aggregate power participation ratio of certain AEP utility subsidiaries, including APCo, I&M and OPCo, is 43.47%.  The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and provide a return on capital.  The intercompany power agreement ends in June 2040.

AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures totaling $1.3 billion in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants.  These environmental projects were funded through debt issuances.  As of December 31, 2015, both generation plants were operating with environmental controls.

Purchased Power from OVEC

The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2015, 2014 and 2013 were:

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
APCo	$	87.2	$	96.9	$	104.4
I&M	43.7		48.5		52.2
OPCo	110.8		123.1		132.6

The amounts above are included in Purchased Electricity for Resale on the statements of income.

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Sales and Purchases of Property

Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property.  There were no gains or losses recorded on the transactions.  The following tables show the sales and purchases, recorded at net book value, for the years ended December 31, 2015, 2014 and 2013:

Sales

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
APCo	$	9.4	$	3.0	$	3.2
I&M	3.0		1.3		5.0
OPCo	2.4		0.5		59.8
PSO	7.1		0.5		5.7
SWEPCo	0.8		1.2		1.6

Purchases

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
APCo	$	8.6	$	0.9	$	5.2
I&M	8.1		1.4		1.0
OPCo	2.1		1.9		5.3
PSO	0.6		2.1		1.7
SWEPCo	7.4		4.0		8.4

The amounts above are recorded in Property, Plant and Equipment on the balance sheets.

Intercompany Billings

The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical.  The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies.  The billings for services are made at cost and include no compensation for the use of equity capital.

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17.  VARIABLE INTEREST ENTITIES

The disclosures in this note apply to all Registrants unless indicated otherwise.

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 AEP is the primary beneficiary of a VIE, management considers factors such as equity at risk, the amount of the VIE’s variability AEP 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. 

AEP is the primary beneficiary of Sabine, DCC Fuel, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, AEP Credit, a protected cell of EIS and Transource Energy. In addition, AEP has not provided material financial or other support to any of these entities that was not previously contractually required. AEP holds a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series).

Consolidated Variable Interests Entities

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 years ended December 31, 2015, 2014 and 2013 were $152 million, $151 million and $155 million, respectively.  See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets.

I&M has nuclear fuel lease agreements with DCC Fuel, which 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 DCC Fuel 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 years ended December 31, 2015, 2014 and 2013 were $115 million, $109 million and $153 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. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s balance sheets.

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 $1.5 billion and $1.8 billion as of December 31, 2015 and 2014, respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Transition Funding has securitized transition assets of $1.3 billion and $1.6 billion as of December 31, 2015 and 2014, respectively, which are presented separately on the face of the balance sheets. The securitized transition assets represent the right to impose and collect

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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 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 $185 million and $230 million as of December 31, 2015 and 2014, respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $86 million and $110 million as of December 31, 2015 and 2014, respectively, which are presented separately on the face of the 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. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s balance sheets.

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 $342 million and $364 million as of December 31, 2015 and 2014, respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $328 million and $350 million as of December 31, 2015 and 2014, respectively, which are presented separately on the face of the balance sheets. 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 APCo’s balance sheets.

AEP Credit is a wholly-owned subsidiary of Parent. 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 AEP’s control of AEP Credit, management concluded that AEP is the primary beneficiary and is required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets. See “Securitized Accounts Receivables - AEP Credit” section of Note 14.

AEP’s 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. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the

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structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and are required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2015, 2014 and 2013 were $29 million, $32 million and $31 million, respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets.

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 and AEP’s equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. In January 2014, Transource Missouri (a wholly-owned subsidiary of Transource Energy) acquired transmission assets from the non-controlling owner and issued debt and received a capital contribution to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, construction projects, debt issuance and capital contribution. AEP has provided capital contributions to Transource Energy of $47 million and $23 million, in 2015 and 2014, respectively. AEP and the other owner of Transource Energy are required to ensure a specific equity level in Transource Missouri upon completion of projects or if a project is abandoned by the RTO. See the tables below for the classification of Transource Energy’s assets and liabilities on the 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
December 31, 2015
	Registrant Subsidiaries										Other Consolidated VIEs
	SWEPCo Sabine		I&M DCC Fuel		OPCo Ohio Phase-in- Recovery Funding			APCo Appalachian Consumer Rate Relief Funding			AEP Credit		TCC Transition Funding			Protected Cell of EIS		Transource Energy
	(in millions)
ASSETS
Current Assets	$	61.7	$	91.1	$	31.2		$	18.5		$	925.7	$	234.1		$	165.3	$	10.8
Net Property, Plant and Equipment	147.0		159.9		—			—			—		—			—		227.2
Other Noncurrent Assets	61.8		84.6		162.0		(a)	332.0		(b)	6.4		1,365.7		(c)	1.9		5.5
Total Assets	$	270.5	$	335.6	$	193.2		$	350.5		$	932.1	$	1,599.8		$	167.2	$	243.5
LIABILITIES AND EQUITY
Current Liabilities	$	47.7	$	84.8	$	47.3		$	27.1		$	855.1	$	291.7		$	41.8	$	36.6
Noncurrent Liabilities	222.3		250.8		144.6			321.5			0.3		1,290.0			83.9		113.0
Equity	0.5		—		1.3			1.9			76.7		18.1			41.5		93.9
Total Liabilities and Equity	$	270.5	$	335.6	$	193.2		$	350.5		$	932.1	$	1,599.8		$	167.2	$	243.5

(a) Includes an intercompany item eliminated in consolidation of $76 million.

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

(c) Includes an intercompany item eliminated in consolidation of $68 million.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2014
	Registrant Subsidiaries										Other Consolidated VIEs
	SWEPCo Sabine		I&M DCC Fuel		OPCo Ohio Phase-in- Recovery Funding			APCo Appalachian Consumer Rate Relief			AEP Credit		TCC Transition Funding			Protected Cell of EIS		Transource Energy
	(in millions)
ASSETS
Current Assets	$	68.0	$	97.4	$	32.7		$	18.1		$	979.9	$	238.5		$	149.0	$	2.4
Net Property, Plant and Equipment	145.5		158.1		—			—			—		—			—		98.0
Other Noncurrent Assets	51.1		79.7		207.3		(a)	354.4		(b)	0.5		1,641.5		(c)	1.9		3.7
Total Assets	$	264.6	$	335.2	$	240.0		$	372.5		$	980.4	$	1,880.0		$	150.9	$	104.1
LIABILITIES AND EQUITY
Current Liabilities	$	36.3	$	86.0	$	47.1		$	26.8		$	894.5	$	321.5		$	44.3	$	20.8
Noncurrent Liabilities	227.9		249.2		191.6			343.8			0.3		1,540.4			61.4		54.7
Equity	0.4		—		1.3			1.9			85.6		18.1			45.2		28.6
Total Liabilities and Equity	$	264.6	$	335.2	$	240.0		$	372.5		$	980.4	$	1,880.0		$	150.9	$	104.1

(a) Includes an intercompany item eliminated in consolidation of $97 million.

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

(c) Includes an intercompany item eliminated in consolidation of $75 million.

Non-Consolidated Significant Variable Interests

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 years ended December 31, 2015, 2014 and 2013 were $93 million, $56 million and $60 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 balance sheets.

SWEPCo’s investment in DHLC was:

	December 31,
	2015				2014
	As Reported on the Balance Sheet		Maximum Exposure		As Reported on the Balance Sheet		Maximum Exposure
	(in millions)
Capital Contribution from SWEPCo	$	7.6	$	7.6	$	7.6	$	7.6
Retained Earnings	7.7		7.7		3.8		3.8
Advance Due to Parent	—		—		56.0		56.0
SWEPCo’s Guarantee of Debt	—		82.9		—		48.3
Total Investment in DHLC	$	15.3	$	98.2	$	67.4	$	115.7

AEP 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.  AEP has no interest or control in the “Allegheny Series”.  AEP is not required to consolidate PATH-WV as AEP is not the primary beneficiary, although

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AEP holds a significant variable interest in PATH-WV.  AEP’s equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the balance sheets.  AEP and FirstEnergy share the returns and losses equally in PATH-WV.  AEP’s 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, the transmission project that PATH was intended to develop 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 and in March 2014, settlement judge procedures were terminated.  Hearings at FERC were held in March and April 2015. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, with recommendations on various issues in the case. The Initial Decision has no binding effect. Additional briefing was submitted during the fourth quarter of 2015. The case is currently pending before FERC.

AEP’s investment in PATH-WV was:

	December 31,
	2015				2014
	As Reported on the Balance Sheet		Maximum Exposure		As Reported on the Balance Sheet		Maximum Exposure
	(in millions)
Capital Contribution from Parent	$	18.8	$	18.8	$	18.8	$	18.8
Retained Earnings	2.2		2.2		2.2		2.2
Total Investment in PATH-WV	$	21.0	$	21.0	$	21.0	$	21.0

As of December 31, 2015, AEP’s $21 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet.  If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows.

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

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Total AEPSC billings to the Registrant Subsidiaries were as follows:

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
APCo	$	227.5	$	216.5	$	174.4
I&M	139.5		133.2		119.3
OPCo	177.8		169.0		255.5
PSO	107.3		101.4		86.0
SWEPCo	141.4		140.3		125.4

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

	December 31,
	2015				2014
Company	As Reported on the Balance Sheet		Maximum Exposure		As Reported on the Balance Sheet		Maximum Exposure
	(in millions)
APCo	$	25.8	$	25.8	$	30.7	$	30.7
I&M	16.6		16.6		22.5		22.5
OPCo	23.3		23.3		24.7		24.7
PSO	12.6		12.6		15.3		15.3
SWEPCo	16.4		16.4		20.8		20.8

AEGCo, a wholly-owned subsidiary of Parent, 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. Total billings to I&M from AEGCo for the years ended December 31, 2015, 2014 and 2013 were $232 million, $268 million and $252 million. Total billings to OPCo from AEGCo for the year ended December 31, 2013 was $148 million. The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2015 and 2014 was $17 million and $20 million, respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 13.

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18.  PROPERTY, PLANT AND EQUIPMENT

The disclosures in this note apply to all Registrants unless indicated otherwise.

Property, plant and equipment is shown functionally on the face of the Registrants’ balance sheets. The following tables include the Registrants’ total plant balances for the years ended December 31, 2015 and 2014:

Year Ended December 31, 2015	AEP			APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Regulated Property, Plant and Equipment
Generation	$	19,082.8	(a)	$	6,200.8	$	3,841.7	$	—	$	1,302.6	$	3,943.5	(a)
Transmission	14,219.0			2,408.1		1,406.9		2,235.6		815.4		1,387.8
Distribution	18,046.9			3,402.5		1,790.8		4,287.7		2,206.7		1,957.3
Other	3,066.7			310.1		511.6		397.8		400.5		582.2
CWIP	3,774.4		(a)	475.1		519.8		171.9		315.3		744.7		(a)
Less: Accumulated Depreciation	16,076.9			3,395.5		2,908.3		2,047.9		1,352.5		2,445.0
Total Regulated Property, Plant and Equipment - Net	42,112.9			9,401.1		5,162.5		5,045.1		3,688.0		6,170.5
Nonregulated Property, Plant and Equipment - Net	4,020.3			23.3		41.0		9.6		5.2		150.6
Total Property, Plant and Equipment - Net	$	46,133.2		$	9,424.4	$	5,203.5	$	5,054.7	$	3,693.2	$	6,321.1

Year Ended December 31, 2014	AEP			APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Regulated Property, Plant and Equipment
Generation	$	18,394.1	(a)	$	6,824.0	$	3,741.9	$	—	$	1,264.7	$	3,864.5	(a)
Transmission	12,394.9			2,228.0		1,358.4		2,104.6		788.9		1,300.7
Distribution	17,156.6			3,258.3		1,698.4		4,087.6		2,080.2		1,894.6
Other	4,360.4			339.2		1,342.8		380.5		416.4		587.1
CWIP	3,087.8		(a)	321.5		537.2		218.7		204.8		471.7		(a)
Less: Accumulated Depreciation	16,461.8			3,811.2		3,302.2		2,037.3		1,319.6		2,360.3
Total Regulated Property, Plant and Equipment - Net	38,932.0			9,159.8		5,376.5		4,754.1		3,435.4		5,758.3
Nonregulated Property, Plant and Equipment - Net	4,703.1		(b)	21.9		39.9		9.5		5.2		149.0
Total Property, Plant and Equipment - Net	$	43,635.1	(b)	$	9,181.7	$	5,416.4	$	4,763.6	$	3,440.6	$	5,907.3

(a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.

(b) Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.

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Depreciation, Depletion and Amortization

The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.  The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants:

AEP
	2015						2014						2013
Functional Class of Property	Annual Composite Depreciation Rate Ranges			Depreciable Life Ranges			Annual Composite Depreciation Rate Ranges			Depreciable Life Ranges			Annual Composite Depreciation Rate Ranges			Depreciable Life Ranges
				(in years)						(in years)						(in years)
Generation	0.4%	-	3.1%	35	-	132	1.7%	-	3.5%	31	-	132	1.7%	-	3.7%	31	-	132
Transmission	1.4%	-	2.7%	15	-	81	1.4%	-	2.7%	15	-	87	1.1%	-	2.7%	25	-	87
Distribution	2.5%	-	3.7%	7	-	75	2.4%	-	3.7%	7	-	75	2.3%	-	3.8%	11	-	75
Other	2.9%	-	11.8%	5	-	75	2.1%	-	8.6%	5	-	75	2.0%	-	7.9%	5	-	75

APCo
	2015				2014				2013
Functional Class of Property	Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges
		(in years)				(in years)				(in years)
Generation	3.1%	35	-	121	3.1%	40	-	121	3.0%	40	-	121
Transmission	1.6%	15	-	68	1.7%	15	-	87	1.6%	25	-	87
Distribution	3.6%	10	-	57	3.5%	13	-	57	3.5%	11	-	52
Other	8.3%	5	-	55	6.9%	24	-	55	7.3%	24	-	55

I&M
	2015				2014				2013
Functional Class of Property	Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges
		(in years)				(in years)				(in years)
Generation	2.5%	59	-	132	2.0%	59	-	132	1.9%	59	-	132
Transmission	1.7%	50	-	75	1.7%	50	-	75	1.5%	50	-	75
Distribution	2.8%	10	-	70	2.8%	15	-	70	2.8%	15	-	70
Other	11.8%	5	-	45	6.1%	14	-	45	4.9%	14	-	45

OPCo
	2015				2014				2013
Functional Class of Property	Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges
		(in years)				(in years)				(in years)
Transmission	2.3%	39	-	60	2.3%	39	-	60	2.3%	39	-	60
Distribution	2.8%	7	-	57	2.7%	7	-	57	2.7%	12	-	60
Other	7.2%	5	-	50	7.0%	7	-	50	7.5%	25	-	50

PSO
	2015				2014				2013
Functional Class of Property	Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges
		(in years)				(in years)				(in years)
Generation	1.7%	35	-	70	1.7%	35	-	70	1.7%	35	-	70
Transmission	1.9%	40	-	75	1.9%	40	-	75	1.9%	40	-	75
Distribution	2.5%	7	-	65	2.4%	30	-	65	2.3%	30	-	65
Other	4.6%	5	-	40	4.1%	5	-	40	4.1%	5	-	40

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SWEPCo
	2015				2014				2013
Functional Class of Property	Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges
		(in years)				(in years)				(in years)
Generation	2.2%	40	-	70	2.2%	40	-	70	2.2%	40	-	70
Transmission	2.3%	50	-	70	2.2%	50	-	70	2.3%	50	-	70
Distribution	2.6%	25	-	65	2.7%	25	-	65	2.6%	25	-	65
Other	5.5%	5	-	51	4.8%	7	-	51	5.0%	7	-	51

The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are Not Meaningful (NM) for APCo, I&M, OPCo and PSO for 2015, 2014 and 2013.

AEP
	2015							2014							2013
Functional Class of Property	Annual Composite Depreciation Rate Ranges			Depreciable Life Ranges				Annual Composite Depreciation Rate Ranges			Depreciable Life Ranges				Annual Composite Depreciation Rate Ranges			Depreciable Life Ranges
				(in years)							(in years)							(in years)
Generation	2.5%	-	3.4%	35	-	66		2.6%	-	3.4%	35	-	66		2.6%	-	3.3%	35	-	66
Transmission	2.3%			43	-	55		2.3%			43	-	55		2.5%			43	-	55
Other	2.7%			5	-	50	(a)	17.1%			25	-	50	(a)	NM			NM			(a)

(a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years.

SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment.  SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages.  SWEPCo includes these costs in fuel expense.

For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization.  Actual removal costs incurred are charged to Accumulated Depreciation and Amortization.  Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability.  For nonregulated operations, non-ARO removal costs are expensed as incurred. 

Asset Retirement Obligations (ARO)

The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities.  I&M records ARO for the decommissioning of the Cook Plant.  The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned.  Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use.  The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely.  The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.

As of December 31, 2015 and 2014, I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.18 billion and $1.27 billion, respectively.  These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets.  As of December 31, 2015 and 2014, the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.80 billion and $1.79 billion, respectively.  These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets.

232

The Registrants recorded an increase in asset retirement obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants.  The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2015 and 2014 aggregate carrying amounts of ARO by Registrant, including a $95 million second quarter increase and other adjustments recorded in 2015:

Company	ARO as of December 31, 2014		Accretion Expense		Liabilities Incurred		Liabilities Settled				Revisions in Cash Flow Estimates				ARO as of December 31, 2015
	(in millions)
AEP (c)(d)(e)(f)	$	2,019.6	$	101.4	$	58.0	$	(147.2	)	(a)	$	(115.5	)	(b)	$	1,916.3
APCo (c)(f)	148.4		8.3		—		(34.0		)		17.5				140.2
I&M (c)(d)(f)	1,342.5		64.3		—		(5.7		)		(147.3		)		1,253.8
OPCo (f)	1.4		—		—		—				—				1.4
PSO (c)(f)	38.1		2.6		5.6		(0.4		)		1.9				47.8
SWEPCo (c)(e)(f)	94.4		5.9		17.1		(5.0		)		13.0				125.4

Company	ARO as of December 31, 2013		Accretion Expense		Liabilities Incurred		Liabilities Settled			Revisions in Cash Flow Estimates		ARO as of December 31, 2014
	(in millions)
AEP (c)(d)(e)(f)	$	1,835.0	$	95.0	$	42.8	$	(34.2	)	$	81.0	$	2,019.6
APCo (c)(f)	152.6		9.1		—		(24.0		)	10.7		148.4
I&M (c)(d)(f)	1,255.2		60.0		—		(1.4		)	28.7		1,342.5
OPCo (f)	1.3		0.1		—		—			—		1.4
PSO (c)(f)	22.9		1.8		—		(0.7		)	14.1		38.1
SWEPCo (c)(e)(f)	87.6		5.2		—		(1.1		)	2.7		94.4

(a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7.

(b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party.

(c) Includes ARO related to ash disposal facilities.

(d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.18 billion and $1.27 billion as of December 31, 2015 and 2014.

(e) Includes ARO related to Sabine and DHLC.

(f) Includes ARO related to asbestos removal.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

The Registrants’ amounts of allowance for equity funds used during construction are summarized in the following table:

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
AEP	$	131.9	$	102.9	$	72.7
APCo	13.8		7.1		2.3
I&M	11.6		18.9		19.9
OPCo	8.8		6.9		5.0
PSO	8.8		3.1		4.2
SWEPCo	26.4		11.9		7.4

233

The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table:

	Years Ended December 31,
Company	2015		2014		2013
	(in millions)
AEP	$	61.3	$	44.5	$	39.8
APCo	6.9		3.8		1.5
I&M	5.0		8.0		9.8
OPCo	4.8		4.4		10.1
PSO	5.0		1.8		2.3
SWEPCo	14.8		6.9		4.3

Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo)

The Registrants have electric facilities that are jointly-owned with affiliated and non-affiliated companies.  Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest.  Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows:

				Registrant’s Share as of December 31, 2015
	Fuel Type	Percent of Ownership		Utility Plant in Service		Construction Work in Progress		Accumulated Depreciation
				(in millions)
AEP
Conesville Generating Station, Unit 4 (a)	Coal	43.5	%	$	337.4	$	2.4	$	76.1
J.M. Stuart Generating Station (b)	Coal	26.0	%	565.5		12.9		221.8
Wm. H. Zimmer Generating Station (c)	Coal	25.4	%	815.5		6.4		421.7
Dolet Hills Generating Station, Unit 1 (i)	Lignite	40.2	%	332.4		3.9		205.9
Flint Creek Generating Station, Unit 1 (j)	Coal	50.0	%	131.4		195.0		70.0
Pirkey Generating Station, Unit 1 (j)	Lignite	85.9	%	572.1		5.9		389.1
Oklaunion Generating Station, Unit 1 (h)	Coal	70.3	%	445.5		7.2		236.2
Turk Generating Plant (j)	Coal	73.33	%	1,649.0		5.5		104.1
Transmission	NA	(d)		68.5		0.4		48.1
Total				$	4,917.3	$	239.6	$	1,773.0
I&M
Rockport Generating Plant (e)(f)(g)	Coal	50.0	%	$	926.7	$	58.5	$	512.4
PSO
Oklaunion Generating Station, Unit 1 (h)	Coal	15.6	%	$	103.0	$	1.8	$	58.2
SWEPCo
Dolet Hills Generating Station, Unit 1 (i)	Lignite	40.2	%	$	332.4	$	3.9	$	205.9
Flint Creek Generating Station, Unit 1 (j)	Coal	50.0	%	131.4		195.0		70.0
Pirkey Generating Station, Unit 1 (j)	Lignite	85.9	%	572.1		5.9		389.1
Turk Generating Plant (j)	Coal	73.33	%	1,649.0		5.5		104.1
Total				$	2,684.9	$	210.3	$	769.1

234

				Registrant’s Share as of December 31, 2014
	Fuel Type	Percent of Ownership		Utility Plant in Service		Construction Work in Progress		Accumulated Depreciation
				(in millions)
AEP
W.C. Beckjord Generating Station, Unit 6 (c)	Coal	12.5	%	$	—	$	—	$	—
Conesville Generating Station, Unit 4 (a)	Coal	43.5	%	335.7		2.4		65.9
J.M. Stuart Generating Station (b)	Coal	26.0	%	552.7		11.5		205.8
Wm. H. Zimmer Generating Station (c)	Coal	25.4	%	812.0		4.0		410.2
Dolet Hills Generating Station, Unit 1 (i)	Lignite	40.2	%	329.7		3.7		201.3
Flint Creek Generating Station, Unit 1 (j)	Coal	50.0	%	125.1		119.6		67.9
Pirkey Generating Station, Unit 1 (j)	Lignite	85.9	%	531.1		36.5		381.1
Oklaunion Generating Station, Unit 1 (h)	Coal	70.3	%	409.1		10.3		227.8
Turk Generating Plant (j)	Coal	73.33	%	1,647.0		0.9		69.8
Transmission	NA	(d)		81.8		0.8		49.2
Total				$	4,824.2	$	189.7	$	1,679.0
I&M
Rockport Generating Plant (e)(f)(g)	Coal	50.0	%	$	801.5	$	119.9	$	492.2
PSO
Oklaunion Generating Station, Unit 1 (h)	Coal	15.6	%	$	94.7	$	2.6	$	57.5
SWEPCo
Dolet Hills Generating Station, Unit 1 (i)	Lignite	40.2	%	$	329.7	$	3.7	$	201.3
Flint Creek Generating Station, Unit 1 (j)	Coal	50.0	%	125.1		119.6		67.9
Pirkey Generating Station, Unit 1 (j)	Lignite	85.9	%	531.1		36.5		381.1
Turk Generating Plant (j)	Coal	73.33	%	1,647.0		0.9		69.8
Total				$	2,632.9	$	160.7	$	720.1

(a) Operated by AGR.

(b) Operated by The Dayton Power & Light Company, a non-affiliated company.

(c) Operated by Dynegy Corporation, a non-affiliated company. AEP’s portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012.

(d) Varying percentages of ownership.

(e) Operated by I&M.

(f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13.

(g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2.

(h) Operated by PSO, which owns 15.6%. Also jointly-owned (54.7%) by TNC and various non-affiliated companies.

(i) Operated by CLECO, a non-affiliated company.

(j) Operated by SWEPCo.

NA Not applicable.

235

19.  COST REDUCTION PROGRAMS

The disclosures in this note apply to all Registrants unless indicated otherwise.

2014 Disposition Plant Severance

Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits.

The Registrants’ disposition plant severance activity for the twelve months endedDecember 31, 2015 is described in the following table:

			Expense										Remaining
	Balance as of		Allocation from		Incurred by								Balance as of
Company	December 31, 2014		AEPSC		Registrants		Settled			Adjustments			December 31, 2015
(in millions)
AEP	$	29.2	$	—	$	2.7	$	22.6		$	—		$	9.3
APCo	9.3		—		0.9		7.0		(a)	(0.1		)	3.1
I&M	8.0		—		0.3		5.4			—			2.9
PSO	0.1		—		0.3		0.2			—			0.2
SWEPCo	0.1		—		—		0.1			—			—

(a) Includes amounts received from affiliates for expenses related to jointly-owned plant.

The Registrants recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants.  The total amounts incurred in 2014 by the Registrants were as follows:

Company	Total Cost Incurred
	(in millions)
AEP	$	29.2
APCo	7.1
I&M	8.2
OPCo	0.1
PSO	0.3
SWEPCo	0.3

These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the statements of income.  Of AEP’s cumulative expense, approximately 33% was within the Generation & Marketing segment and 67% was within the Vertically Integrated Utilities segment.  The remaining liability is included in Other Current Liabilities on the balance sheets.  The Registrants incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired.  Management does not expect additional severance costs to be incurred related to this initiative.

236

2012 Sustainable Cost Reductions

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

The Registrants recorded charges to Other Operation expense for the year ended December 31, 2013 primarily related to severance benefits as a result of the sustainable cost reductions initiative. The amounts incurred by Registrants were as follows:

Company	Total Cost Incurred
	(in millions)
AEP	$	7.7
APCo	0.3
I&M	0.4
OPCo	5.8
PSO	(0.1		)
SWEPCo	1.0

237

20.  UNAUDITED QUARTERLY FINANCIAL INFORMATION

The disclosures in this note apply to all Registrants unless indicated otherwise.

In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods.  Quarterly results are not necessarily indicative of a full year’s operations because of various factors.  The unaudited quarterly financial information for each Registrant is as follows:

Quarterly Periods Ended:	AEP				APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
March 31, 2015
Total Revenues	$	4,580.4			$	899.0	$	586.3	$	918.4	$	306.8	$	431.7
Operating Income	1,102.8				273.5		124.4		122.9		34.9		92.3
Income from Continuing Operations	620.2				—		—		—		—		—
Income from Discontinued Operations, Net of Tax	10.5				—		—		—		—		—
Net Income	630.7				141.8		72.7		65.4		13.7		46.7
June 30, 2015
Total Revenues	$	3,826.7			$	682.0	$	544.3	$	705.8	$	319.5	$	438.1
Operating Income	804.1				145.7		91.4		96.5		55.5		110.1
Income from Continuing Operations	431.4				—		—		—		—		—
Income (Loss) from Discontinued Operations, Net of Tax	(0.1		)		—		—		—		—		—
Net Income	431.3				59.0		50.6		47.7		27.1		59.5
September 30, 2015
Total Revenues	$	4,431.4			$	727.5	$	568.3	$	782.3	$	420.3	$	532.5
Operating Income	960.2				157.9		103.4		140.9		84.5		141.2
Income from Continuing Operations	511.8				—		—		—		—		—
Income from Discontinued Operations, Net of Tax	7.8				—		—		—		—		—
Net Income	519.6				74.6		56.6		71.6		44.7		82.1
December 31, 2015
Total Revenues	$	3,614.7			$	655.0	$	487.3	$	692.2	$	292.6	$	378.6
Operating Income	466.4				133.7		50.7		100.5		18.3		25.6
Income from Continuing Operations	205.2				—		—		—		—		—
Income from Discontinued Operations, Net of Tax	265.5			(a)	—		—		—		—		—
Net Income	470.7				65.2		24.9		48.0		7.0		7.7

238

Quarterly Periods Ended:	AEP			APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
March 31, 2014
Total Revenues	$	4,497.5		$	913.4	$	641.8	$	880.2	$	301.4	$	440.6
Operating Income	1,032.3			220.0		146.0		115.7		25.3		64.7
Income from Continuing Operations	558.3			—		—		—		—		—
Income from Discontinued Operations, Net of Tax	2.7			—		—		—		—		—
Net Income	561.0			101.8		87.1		60.8		8.4		23.0
June 30, 2014
Total Revenues	$	3,900.6		$	694.7	$	533.9	$	786.1	$	318.8	$	449.3
Operating Income	760.7			110.7		57.1		114.0		48.9		78.8
Income from Continuing Operations	388.4			—		—		—		—		—
Income from Discontinued Operations, Net of Tax	2.7			—		—		—		—		—
Net Income	391.1			36.2		27.3		56.5		22.5		32.8
September 30, 2014
Total Revenues	$	4,161.4		$	709.9	$	542.9	$	839.2	$	417.0	$	531.8
Operating Income	904.9			130.2		62.9		104.7		87.4		133.2
Income from Continuing Operations	484.2			—		—		—		—		—
Income from Discontinued Operations, Net of Tax	10.2			—		—		—		—		—
Net Income	494.4			48.8		26.6		54.1		45.1		74.6
December 31, 2014
Total Revenues	$	3,819.1		$	735.1	$	531.1	$	871.4	$	314.4	$	424.7
Operating Income	429.5		(b)	107.3		39.2		99.1		27.2		46.0
Income from Continuing Operations	159.6			—		—		—		—		—
Income from Discontinued Operations, Net of Tax	31.9			—		—		—		—		—
Net Income	191.5		(b)	28.6		14.6		45.0		10.9		14.2

(a) Includes sale of AEPRO (see Note 7).

(b) Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4).

239

AEP

The unaudited quarterly financial information relating to Common Shareholders is as follows:

	2015 Quarterly Periods Ended
	March 31		June 30		September 30		December 31
Earnings Attributable to AEP Common Shareholders	$	629.2	$	430.0	$	518.3	$	469.6
Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (a)	1.27		0.88		1.04		0.41
Basic Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (b)	0.02		—		0.02		0.54
Total Basic Earnings per Share Attributable to AEP Common Shareholders (a)	1.29		0.88		1.06		0.95
Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (a)	1.27		0.88		1.04		0.41
Diluted Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (b)	0.02		—		0.02		0.54
Total Diluted Earnings per Share Attributable to AEP Common Shareholders (a)	1.29		0.88		1.06		0.95

	2014 Quarterly Periods Ended
	March 31		June 30		September 30		December 31
Earnings Attributable to AEP Common Shareholders	$	559.8	$	389.9	$	493.2	$	190.9
Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations	1.14		0.79		0.99		0.32
Basic Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (a)(b)	0.01		0.01		0.02		0.07
Total Basic Earnings per Share Attributable to AEP Common Shareholders (a)	1.15		0.80		1.01		0.39
Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations	1.14		0.79		0.99		0.32
Diluted Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (a)(b)	0.01		0.01		0.02		0.07
Total Diluted Earnings per Share Attributable to AEP Common Shareholders (a)	1.15		0.80		1.01		0.39

(a) Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding.

(b) Relates to sale of AEPRO (see Note 7).

240

21.  GOODWILL AND OTHER INTANGIBLE ASSETS

The disclosures in this note apply to AEP only.

Goodwill

The changes in AEP’s carrying amount of goodwill for the years ended December 31, 2015 and 2014 by operating segment are as follows:

		Corporate and Other				Generation and Marketing		AEP Consolidated
	(in millions)
Balance as of December 31, 2013		$	75.9			$	15.4	$	91.3
Impairment Losses		—				—		—
Balance as of December 31, 2014		75.9				15.4		91.3
Impairment Losses		—				—		—
Goodwill Written Off Related to Sale of AEPRO		(38.8		)	(a)	—		(38.8		)
Balance as of December 31, 2015		$	37.1			$	15.4	$	52.5

(a) The goodwill of $38.8 million related to AEPRO is included in Other Classes of Assets That Are Not Major as of December 31, 2014 in Note 7. See “Dispositions” section of Note 7 for additional information.

In the fourth quarters of 2015 and 2014, annual impairment tests were performed.  The fair values of the operations with goodwill were estimated using cash flow projections and other market value indicators.  There were no goodwill impairment losses.  AEP does not have any accumulated impairment on existing goodwill.

Other Intangible Assets

Acquired intangible assets subject to amortization were $2 million and $5 million as of December 31, 2015 and 2014, respectively, net of accumulated amortization and are included in Deferred Charges and Other Noncurrent Assets on the balance sheets.  The amortization life, gross carrying amount and accumulated amortization by major asset class are as follows:

		December 31,
		2015				2014
	Amortization Life	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
	(in years)	(in millions)
Acquired Customer Contracts	5	$	58.3	$	56.5	$	58.3	$	53.4

Amortization of intangible assets was $3 million, $5 million and $14 million for the years ended December 31, 2015, 2014 and 2013, respectively.  The estimated total amortization is $2 million for 2016.

241

CORPORATE AND SHAREHOLDER INFORMATION

Corporate Headquarters

1 Riverside Plaza

Columbus, OH 43215-2373

614-716-1000

AEP is incorporated in the State of New York.

Stock Exchange Listing - The Company’s common stock is traded principally on the New York Stock Exchange under the ticker symbol AEP.

Internet Home Page - Information about AEP, including financial documents, Securities and Exchange Commission (SEC) filings, news releases, investor presentations, shareholder information and customer service information, is available on the Company’s home page on the Internet at www.AEP.com/investors.

Inquiries Regarding Your Stock Holdings - Registered shareholders (shares that you own, in your name) should contact the Company’s transfer agent, listed below, if you have questions about your account, address changes, stock transfer, lost certificates, direct deposits, dividend checks and other administrative matters. You should have your Social Security number or account number ready; the transfer agent will not speak to third parties about an account without the shareholder’s approval or appropriate documents.

Transfer Agent & Registrar

Computershare Trust Company, N.A.

P.O. Box 43078

Providence, RI 02940-3078

For overnight deliveries:

Computershare Trust Company, N.A.

250 Royall Street

Canton, MA 02021-1011

Telephone Response Group:1-800-328-6955

Internet address: www.computershare.com/investor

Hearing Impaired #: TDD: 1-800-952-9245

Beneficial Holders - (Stock held in a bank or brokerage account) - When you purchase stock and it is held for you by your broker, it is listed with the Company in the broker’s name, and this is sometimes referred to as “street name” or a “beneficial owner.” AEP does not know the identity of individual shareholders who hold their shares in this manner; we simply know that a broker holds a certain number of shares which may be for any number of customers. If you hold your stock in street name, you receive all dividend payments, annual reports and proxy materials through your broker. Therefore, questions about your account should be directed to your broker.

Dividend Reinvestment and Direct Stock Purchase Plan - A Dividend Reinvestment and Direct Stock Purchase Plan is available to all investors. It is an economical and convenient method of purchasing shares of AEP common stock, through initial cash investments, cash dividends and/or additional optional cash purchases. You may obtain the Plan prospectus and enrollment authorization form by contacting the transfer agent or by visiting www.AEP.com/investors/buyandmanagestock.

Financial Community Inquiries - Institutional investors or securities analysts who have questions about the Company should direct inquiries to Bette Jo Rozsa, 614-716-2840, bjrozsa@AEP.com; Individual shareholders should contact Kathleen Kozero, 614-716-2819, klkozero@AEP.com.

Number of Shareholders - As of February 29, 2015, there were approximately 70,000 registered shareholders and approximately 510,000 shareholders holding stock in street name through a bank or broker. There were 511,411,480 shares outstanding as of February 29, 2015.

Form 10-K - Upon request, we will provide without charge a copy of our Form 10-K for the fiscal year ended December 31, 2015. A copy can be obtained via mail with a written request to AEP Investor Relations, by telephone at 1-800-237-2667 or electronically at klkozero@AEP.com.

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Executive Leadership Team

Name	Age	Office
Nicholas K. Akins	55	Chairman of the Board, President and Chief Executive Officer
Lisa M. Barton	50	Executive Vice President - Transmission
David M. Feinberg	46	Executive Vice President, General Counsel and Secretary
Lana L. Hillebrand	55	Senior Vice President and Chief Administrative Officer
Mark C. McCullough	56	Executive Vice President - Generation
Robert P. Powers	62	Executive Vice President and Chief Operating Officer
Brian X. Tierney	48	Executive Vice President and Chief Financial Officer
Charles E. Zebula	55	Executive Vice President - Energy Supply

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